10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017

or

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

For the transition period from  to 

Commission file number: 1-34776

Oasis Petroleum Inc.

(Exact name of registrant as specified in its charter)

Delaware	80-0554627
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 1500 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(281) 404-9500

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	¨
		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨

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

Number of shares of the registrant’s common stock outstanding at May 4, 2017: 237,432,612 shares.

OASIS PETROLEUM INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31,2017

TABLE OF CONTENTS

	Page
PART I — FINANCIAL INFORMATION	1
Item 1. — Financial Statements (Unaudited)	1
Condensed Consolidated Balance Sheet at March 31, 2017 and December 31, 2016	1
Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2017 and 2016	2
Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2017	3
Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2017 and 2016	4
Notes to Condensed Consolidated Financial Statements	5
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. — Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. — Controls and Procedures	38
PART II — OTHER INFORMATION	40
Item 1. — Legal Proceedings	40
Item 1A. — Risk Factors	40
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6. — Exhibits	41
SIGNATURES	42
EXHIBIT INDEX	43

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Oasis Petroleum Inc. Condensed Consolidated Balance Sheet (Unaudited)
	March 31, 2017			December 31, 2016
	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	13,785		$	11,226
Accounts receivable, net	226,427			204,335
Inventory	14,327			10,648
Prepaid expenses	7,176			7,623
Derivative instruments	3,026			362
Other current assets	4,452			4,355
Total current assets	269,193			238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)	7,390,299			7,296,568
Other property and equipment	632,318			618,790
Less: accumulated depreciation, depletion, amortization and impairment	(2,126,136		)	(1,995,791		)
Total property, plant and equipment, net	5,896,481			5,919,567
Derivative instruments	3,815			—
Other assets	20,139			20,516
Total assets	$	6,189,628		$	6,178,632
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	8,837		$	4,645
Revenues and production taxes payable	160,265			139,737
Accrued liabilities	128,241			119,173
Accrued interest payable	20,268			39,004
Derivative instruments	14,627			60,469
Advances from joint interest partners	6,838			7,597
Other current liabilities	13,435			10,490
Total current liabilities	352,511			381,115
Long-term debt	2,305,879			2,297,214
Deferred income taxes	524,842			513,529
Asset retirement obligations	50,088			48,985
Derivative instruments	—			11,714
Other liabilities	2,834			2,918
Total liabilities	3,236,154			3,255,475
Commitments and contingencies (Note 13)
Stockholders’ equity
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding at March 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016	2,344			2,331
Treasury stock, at cost: 1,229,568 and 856,892 shares at March 31, 2017 and December 31, 2016, respectively	(21,369		)	(15,950		)
Additional paid-in capital	2,354,485			2,345,271
Retained earnings	618,014			591,505
Total stockholders’ equity	2,953,474			2,923,157
Total liabilities and stockholders’ equity	$	6,189,628		$	6,178,632

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

1

Oasis Petroleum Inc.

Condensed Consolidated Statement of Operations

(Unaudited)

	Three Months Ended March 31,
	2017			2016
	(In thousands, except per share data)
Revenues
Oil and gas revenues	$	237,252		$	117,315
Bulk oil sales	27,631			—
Midstream revenues	14,606			6,983
Well services revenues	5,627			5,985
Total revenues	285,116			130,283
Operating expenses
Lease operating expenses	43,872			31,064
Midstream operating expenses	3,327			1,738
Well services operating expenses	3,902			2,651
Marketing, transportation and gathering expenses	10,951			8,552
Bulk oil purchases	28,002			—
Production taxes	20,299			10,753
Depreciation, depletion and amortization	126,666			122,449
Exploration expenses	1,489			363
Impairment	2,682			3,562
General and administrative expenses	23,834			24,366
Total operating expenses	265,024			205,498
Operating income (loss)	20,092			(75,215		)
Other income (expense)
Net gain on derivative instruments	56,075			14,375
Interest expense, net of capitalized interest	(36,321		)	(38,739		)
Gain on extinguishment of debt	—			7,016
Other income	16			479
Total other income (expense)	19,770			(16,869		)
Income (loss) before income taxes	39,862			(92,084		)
Income tax benefit (expense)	(16,037		)	27,629
Net income (loss)	$	23,825		$	(64,455	)
Earnings (loss) per share:
Basic (Note 11)	$	0.10		$	(0.40	)
Diluted (Note 11)	0.10			(0.40		)
Weighted average shares outstanding:
Basic (Note 11)	233,068			162,922
Diluted (Note 11)	237,900			162,922

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

2

Oasis Petroleum Inc.

Condensed Consolidated Statement of Changes in Stockholders’ Equity

(Unaudited)

	Common Stock				Treasury Stock				Additional Paid-in Capital			Retained Earnings		Total Stockholders’ Equity
	Shares		Amount		Shares	Amount
	(In thousands)
Balance at December 31, 2016	236,344		$	2,331	857	$	(15,950	)	$	2,345,271		$	591,505	$	2,923,157
Cumulative-effect adjustment for adoption of ASU 2016-09 (Note 2)	—		—		—	—			2,040			2,684		4,724
Fees (2016 issuance of common stock)	—		—		—	—			(55		)	—		(55		)
Stock-based compensation	1,490		13		—	—			7,229			—		7,242
Treasury stock – tax withholdings	(373	)	—		373	(5,419		)	—			—		(5,419		)
Net income	—		—		—	—			—			23,825		23,825
Balance at March 31, 2017	237,461		$	2,344	1,230	$	(21,369	)	$	2,354,485		$	618,014	$	2,953,474

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

3

Oasis Petroleum Inc.

Condensed Consolidated Statement of Cash Flows

(Unaudited)

	Three Months Ended March 31,
	2017			2016
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	23,825		$	(64,455	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	126,666			122,449
Gain on extinguishment of debt	—			(7,016		)
Impairment	2,682			3,562
Deferred income taxes	16,037			(27,629		)
Derivative instruments	(56,075		)	(14,375		)
Stock-based compensation expenses	6,708			6,730
Deferred financing costs amortization and other	4,940			5,066
Working capital and other changes:
Change in accounts receivable	(22,478		)	(995		)
Change in inventory	(3,679		)	349
Change in prepaid expenses	282			241
Change in other current assets	(110		)	4
Change in other assets	(4		)	77
Change in accounts payable, interest payable and accrued liabilities	6,060			(64,056		)
Change in other current liabilities	2,945			(6,000		)
Change in other liabilities	—			(3		)
Net cash provided by (used in) operating activities	107,799			(46,051		)
Cash flows from investing activities:
Capital expenditures	(96,047		)	(103,411		)
Derivative settlements	(7,960		)	73,313
Advances from joint interest partners	(759		)	(257		)
Net cash used in investing activities	(104,766		)	(30,355		)
Cash flows from financing activities:
Proceeds from revolving credit facility	246,000			214,000
Principal payments on revolving credit facility	(241,000		)	(287,000		)
Repurchase of senior unsecured notes	—			(22,308		)
Deferred financing costs	—			(751		)
Proceeds from sale of common stock	—			183,164
Purchases of treasury stock	(5,419		)	(1,032		)
Other	(55		)	—
Net cash provided by (used in) financing activities	(474		)	86,073
Increase in cash and cash equivalents	2,559			9,667
Cash and cash equivalents:
Beginning of period	11,226			9,730
End of period	$	13,785		$	19,397
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	8,396		$	(19,230	)
Change in asset retirement obligations	787			1,212

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

4

OASIS PETROLEUM INC.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Organization and Operations of the Company

Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties. The Company also operates a midstream services business through Oasis Midstream Services LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to its primary development and production activities.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The accompanying condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2016 is derived from audited financial statements. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement, have been included. Management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”).

Risks and Uncertainties

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

Significant Accounting Policies

There have been no material changes to the Company’s critical accounting policies and estimates from those disclosed in the 2016 Annual Report, other than as noted below.

Stock-based compensation. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. In accordance with the new guidance, the Company recorded a $2.7 million cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet as of March 31, 2017, which included recognition of excess tax benefits and deficiencies and the removal of the estimated forfeiture rate. ASU 2016-09 was applied on a modified retrospective basis and prior periods were not retrospectively adjusted.

Inventory. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), which changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 was

5

applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of March 31, 2017.

Recent Accounting Pronouncements

Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Financial instruments. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Statement of cash flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations, but could result in presentation changes on the Company’s statement of cash flows.

Business combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

3. Inventory

Crude oil inventory includes oil in tank and linefill. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Inventory is stated at the lower of cost and net realizable value with cost determined on an average cost method. Inventory consists of the following:

	March 31, 2017		December 31, 2016
	(In thousands)
Crude oil inventory	$	10,302	$	7,086
Equipment and materials	4,025		3,562
Total inventory	$	14,327	$	10,648

6

4. Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations (“ARO”) and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.

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

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

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

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

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

Financial Assets and Liabilities

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 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:

	Fair value at March 31, 2017
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	141	$	—	$	—	$	141
Commodity derivative instruments (see Note 5)	—		6,841		—		6,841
Total assets	$	141	$	6,841	$	—	$	6,982
Liabilities:
Commodity derivative instruments (see Note 5)	$	—	$	14,627	$	—	$	14,627
Total liabilities	$	—	$	14,627	$	—	$	14,627

7

	Fair value at December 31, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	141	$	—	$	—	$	141
Commodity derivative instruments (see Note 5)	—		362		—		362
Total assets	$	141	$	362	$	—	$	503
Liabilities:
Commodity derivative instruments (see Note 5)	$	—	$	72,183	$	—	$	72,183
Total liabilities	$	—	$	72,183	$	—	$	72,183

The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheet at March 31, 2017 and December 31, 2016. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.

The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil and natural gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts, as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to reduce the fair value of its net derivative liability by $0.2 million and $2.0 million at March 31, 2017 and December 31, 2016, respectively.

There were no transfers between fair value levels during the three months ended March 31, 2017 and 2016.

5. Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. The Company’s crude oil and natural gas contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“WTI”) and the average NYMEX Henry Hub natural gas index price (“Henry Hub”), respectively. At March 31, 2017, the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor). A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract.

All derivative instruments are recorded on the Company’s Condensed Consolidated Balance Sheet as either assets or liabilities measured at fair value (see Note 4 – Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the Company’s Condensed Consolidated Statement of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or

8

modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Condensed Consolidated Statement of Cash Flows.

At March 31, 2017, the Company had the following outstanding commodity derivative instruments:

Commodity	Settlement Period	Derivative Instrument	Volumes		Weighted Average Prices								Fair Value Asset (Liability)
					Swap		Sub-Floor		Floor		Ceiling
													(In thousands)
Crude oil	2017	Swaps	5,225,000	Bbl	$	49.60							$	(9,309	)
Crude oil	2017	Two-way collar	2,200,000	Bbl					$	46.25	$	54.37	(1,707		)
Crude oil	2017	Three-way collar	1,650,000	Bbl			$	31.67	$	45.83	$	59.94	562
Crude oil	2018	Swaps	2,440,000	Bbl	$	52.93							2,375
Crude oil	2018	Two-way collar	582,000	Bbl					$	48.40	$	55.13	28
Crude oil	2018	Three-way collar	186,000	Bbl			$	31.67	$	45.83	$	59.94	58
Crude oil	2019	Swaps	155,000	Bbl	$	53.88							351
Crude oil	2019	Two-way collar	31,000	Bbl					$	50.00	$	55.70	32
Natural gas	2017	Swaps	4,675,000	MMBtu	$	3.30							(55		)
Natural gas	2018	Swaps	3,650,000	MMBtu	$	3.00							(121		)
													$	(7,786	)

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

	Three Months Ended March 31,
Statement of Operations Location	2017		2016
	(In thousands)
Net gain on derivative instruments	$	56,075	$	14,375

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Condensed Consolidated Balance Sheet.

9

The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheet:

		March 31, 2017
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	5,178	$	(2,152	)	$	3,026
Commodity contracts	Derivative instruments — non-current assets	5,148		(1,333		)	3,815
Total derivatives assets		$	10,326	$	(3,485	)	$	6,841
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	21,480	$	(6,853	)	$	14,627
Total derivatives liabilities		$	21,480	$	(6,853	)	$	14,627
		December 31, 2016
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	482	$	(120	)	$	362
Total derivatives assets		$	482	$	(120	)	$	362
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	66,838	$	(6,369	)	$	60,469
Commodity contracts	Derivative instruments — non-current liabilities	14,164		(2,450		)	11,714
Total derivatives liabilities		$	81,002	$	(8,819	)	$	72,183

6. Property, Plant and Equipment

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

	March 31, 2017			December 31, 2016
	(In thousands)
Proved oil and gas properties(1)	$	6,570,588		$	6,476,833
Less: accumulated depreciation, depletion, amortization and impairment	(2,009,356		)	(1,886,732		)
Proved oil and gas properties, net	4,561,232			4,590,101
Unproved oil and gas properties	819,711			819,735
Other property and equipment	632,318			618,790
Less: accumulated depreciation	(116,780		)	(109,059		)
Other property and equipment, net	515,538			509,731
Total property, plant and equipment, net	$	5,896,481		$	5,919,567

__________________

(1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $43.0 millionand $42.9 million at March 31, 2017 and December 31, 2016, respectively.

10

7. Long-Term Debt

The Company’s long-term debt consists of the following:

	March 31, 2017			December 31, 2016
	(In thousands)
Senior secured revolving line of credit	$	368,000		$	363,000
Senior unsecured notes
7.25% senior unsecured notes due February 1, 2019	54,275			54,275
6.5% senior unsecured notes due November 1, 2021	395,501			395,501
6.875% senior unsecured notes due March 15, 2022	937,080			937,080
6.875% senior unsecured notes due January 15, 2023	366,094			366,094
2.625% senior unsecured convertible notes due September 15, 2023	300,000			300,000
Total principal of senior unsecured notes	2,052,950			2,052,950
Less: unamortized deferred financing costs on senior unsecured notes	(26,958		)	(28,268		)
Less: unamortized debt discount on senior unsecured convertible notes	(88,113		)	(90,468		)
Total long-term debt	$	2,305,879		$	2,297,214

The carrying amount of the Company’s long-term debt reported in the Condensed Consolidated Balance Sheet at March 31, 2017 was $2,305.9 million, which included $2,053.0 million of senior unsecured notes, a reduction for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and a reduction for the unamortized deferred financing costs on the senior unsecured notes of $88.1 million and $27.0 million, respectively, and $368.0 million of borrowings under the revolving credit facility. The Company’s revolving credit facility is recorded at a value that approximates its fair value since its variable interest rate is tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $2,187.1 million at March 31, 2017.

Senior secured revolving line of credit. The Company has a senior secured revolving line of credit (the “Credit Facility”) of $2,500.0 million as of March 31, 2017, which has a maturity date of April 13, 2020, provided that the 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”), of which $54.3 million is outstanding, are retired or refinanced 90 days prior to their maturity. The Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year.

As of March 31, 2017, the Company had $368.0 million of LIBOR loans and $10.0 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base committed capacity of $772.0 million. The weighted average interest rate on borrowings outstanding under the Credit Facility was 2.5% as of March 31, 2017. On a quarterly basis, the Company also pays a 0.375% (as of March 31, 2017) annualized commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

The Company was in compliance with the financial covenants of the Credit Facility as of March 31, 2017.

Senior unsecured notes. At March 31, 2017, the Company had $1,753.0 million principal amount of senior unsecured notes outstanding with maturities ranging from February 2019 to January 2023 and coupons ranging from 6.50% to 7.25% (the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par. The Company estimates that the fair value of these redemption options is immaterial at March 31, 2017 and December 31, 2016.

Senior unsecured convertible notes. In September 2016, the Company issued $300.0 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the measurement period is less than

11

98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of March 31, 2017, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.

Upon issuance, the Company separately accounted for the liability and equity components of the Senior Convertible Notes in accordance with Accounting Standards Codification 470-20. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Senior Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 8.97% per annum. The fair value of the Senior Convertible Notes as of the issuance date was estimated at $206.8 million, resulting in a debt discount at inception of $93.2 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Senior Convertible Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital and will not be remeasured as long as it continues to meet the conditions for equity classification. 

Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default as well as covenants that place restrictions on the Company and certain of its subsidiaries.

8. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the three months ended March 31, 2017:

	(In thousands)
Balance at December 31, 2016	$	49,687
Liabilities incurred during period	351
Liabilities settled during period	(89		)
Accretion expense during period(1)	655
Revisions to estimates	(215		)
Balance at March 31, 2017	$	50,389

___________________

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

At March 31, 2017, the current portion of the total ARO balance was approximately $0.3 million and was included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

9. Income Taxes

The Company’s effective tax rate for the three months ended March 31, 2017 and 2016 was 40.2% and 30.0%, respectively. The effective tax rate for the three months ended March 31, 2017 was higher than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the impact of permanent differences on pre-tax income for the period, while the effective tax rate for the three months ended March 31, 2016 was lower than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the impact of permanent differences on pre-tax loss for the period. During both the three months ended March 31, 2017 and 2016, the permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to compensation, including stock-based compensation vesting at different prices than the grant date values.

12

10. Stock-Based Compensation

Restricted stock awards.The Company has granted restricted stock awards to employees and directors under its Amended and Restated 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 closing sales price of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.

During the three months ended March 31, 2017, employees and non-employee directors of the Company were granted restricted stock awards equal to 1,551,560 shares of common stock with a $15.35 weighted average grant date per share value. Stock-based compensation expense recorded for restricted stock awards for the three months ended March 31, 2017 and 2016 was $5.4 million and $5.8 million, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statement of Operations.

Performance share units. The Company has granted performance share units (“PSUs”) to officers of the Company under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock.

During the three months ended March 31, 2017, officers of the Company were granted 509,800 PSUs with a $16.89 weighted average grant date per share value. Stock-based compensation expense recorded for PSUs for the three months ended March 31, 2017 and 2016 was $1.3 million and $0.9 million, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statement of Operations.

The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 200% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.

The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility was calculated from the daily historical returns of 30-day volume weighted average stock prices over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the PSUs granted during the three months ended March 31, 2017:

Risk-free interest rate	1.18% - 1.66%
Oasis volatility	17.16	%

13

11. Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable 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, PSUs outstanding, and contingently issuable shares of convertible notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to the income (loss) available to common stockholders in the calculation of diluted earnings (loss) per share.

The following is a calculation of the basic and diluted weighted average shares outstanding for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017	2016
	(In thousands)
Basic weighted average common shares outstanding	233,068	162,922
Dilution effect of stock awards at end of period	3,238	—
Dilution effect of senior convertible notes at end of period(1)	1,594	—
Diluted weighted average common shares outstanding	237,900	162,922

__________________ 

(1) The Company issued its Senior Convertible Notes in September 2016 (see Note 7 – Long-Term Debt).

The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect:

	Three Months Ended March 31,
	2017	2016
	(In thousands)
Anti-dilutive effect of stock awards excluded from diluted earnings (loss) per share due to net loss	—	4,668
Anti-dilutive effect of stock awards excluded from diluted earnings (loss) per share calculated using the treasury stock method	2,884	—

12. Business Segment Information

The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The Company’s midstream services business segment (OMS) performs salt water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from salt water pipeline transport, salt water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering, blending, stabilization and transportation. The Company’s well services business segment (OWS) performs completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s Condensed Consolidated Statement of Operations. These segments represent the Company’s three operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly.

Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses, including depreciation, depletion and amortization. The following table summarizes financial information for the Company’s three business segments for the periods presented:

14

	Exploration and Production			Midstream Services			Well Services			Eliminations			Consolidated
	(In thousands)
Three months ended March 31, 2017:
Revenues from non-affiliates	$	264,883		$	14,606		$	5,627		$	—		$	285,116
Inter-segment revenues	—			23,035			15,352			(38,387		)	—
Total revenues	264,883			37,641			20,979			(38,387		)	285,116
Operating income (loss)	968			20,763			(3,592		)	1,953			20,092
Other income (expense)	19,768			(2		)	4			—			19,770
Income (loss) before income taxes	$	20,736		$	20,761		$	(3,588	)	$	1,953		$	39,862
Three months ended March 31, 2016:
Revenues from non-affiliates	$	117,315		$	6,983		$	5,985		$	—		$	130,283
Inter-segment revenues	—			22,835			24,903			(47,738		)	—
Total revenues	117,315			29,818			30,888			(47,738		)	130,283
Operating income (loss)	(88,877		)	15,144			4,006			(5,488		)	(75,215		)
Other income (expense)	(16,887		)	13			5			—			(16,869		)
Income (loss) before income taxes	$	(105,764	)	$	15,157		$	4,011		$	(5,488	)	$	(92,084	)
At March 31, 2017:
Property, plant and equipment, net	$	5,589,014		$	433,867		$	44,025		$	(170,425	)	$	5,896,481
Total assets(1)	5,871,573			440,548			47,932			(170,425		)	6,189,628
At December 31, 2016:
Property, plant and equipment, net	$	5,620,558		$	424,197		$	47,189		$	(172,377	)	$	5,919,567
Total assets(1)	5,868,747			431,095			51,167			(172,377		)	6,178,632

___________________

(1) Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

15

13. Commitments and Contingencies

The Company has various contractual obligations in the normal course of its operations. As of March 31, 2017, there have been no material changes to the Company’s future commitments described under “Lease obligations” and “Volume commitment agreements” as disclosed in Note 16 in the Company’s 2016 Annual Report.

Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

Mirada litigation.On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”

The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims. Discovery is ongoing. Trial is currently scheduled for July 2018. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin.

14. Condensed Consolidating Financial Information

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

The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), and its Guarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors.

16

Condensed Consolidating Balance Sheet

	March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	177		$	13,608		$	—		$	13,785
Accounts receivable, net	—			226,427			—			226,427
Accounts receivable – affiliates	200,770			33,093			(233,863		)	—
Inventory	—			14,327			—			14,327
Prepaid expenses	334			6,842			—			7,176
Derivative instruments	—			3,026			—			3,026
Other current assets	2			4,450			—			4,452
Total current assets	201,283			301,773			(233,863		)	269,193
Property, plant and equipment
Oil and gas properties (successful efforts method)	—			7,390,299			—			7,390,299
Other property and equipment	—			632,318			—			632,318
Less: accumulated depreciation, depletion, amortization and impairment	—			(2,126,136		)	—			(2,126,136		)
Total property, plant and equipment, net	—			5,896,481			—			5,896,481
Investments in and advances to subsidiaries	4,503,650			—			(4,503,650		)	—
Derivative instruments	—			3,815			—			3,815
Deferred income taxes	239,419			—			(239,419		)	—
Other assets	—			20,139			—			20,139
Total assets	$	4,944,352		$	6,222,208		$	(4,976,932	)	$	6,189,628
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	—		$	8,837		$	—		$	8,837
Accounts payable – affiliates	33,093			200,770			(233,863		)	—
Revenues and production taxes payable	—			160,265			—			160,265
Accrued liabilities	34			128,207			—			128,241
Accrued interest payable	19,872			396			—			20,268
Derivative instruments	—			14,627			—			14,627
Advances from joint interest partners	—			6,838			—			6,838
Other current liabilities	—			13,435			—			13,435
Total current liabilities	52,999			533,375			(233,863		)	352,511
Long-term debt	1,937,879			368,000			—			2,305,879
Deferred income taxes	—			764,261			(239,419		)	524,842
Asset retirement obligations	—			50,088			—			50,088
Other liabilities	—			2,834			—			2,834
Total liabilities	1,990,878			1,718,558			(473,282		)	3,236,154
Stockholders’ equity
Capital contributions from affiliates	—			3,392,248			(3,392,248		)	—
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding	2,344			—			—			2,344
Treasury stock, at cost: 1,229,568 shares	(21,369		)	—			—			(21,369		)
Additional paid-in-capital	2,354,485			8,743			(8,743		)	2,354,485
Retained earnings	618,014			1,102,659			(1,102,659		)	618,014
Total stockholders’ equity	2,953,474			4,503,650			(4,503,650		)	2,953,474
Total liabilities and stockholders’ equity	$	4,944,352		$	6,222,208		$	(4,976,932	)	$	6,189,628

17

Condensed Consolidating Balance Sheet

	December 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	166		$	11,060		$	—		$	11,226
Accounts receivable, net	—			204,335			—			204,335
Accounts receivable – affiliates	252,000			27,619			(279,619		)	—
Inventory	—			10,648			—			10,648
Prepaid expenses	275			7,348			—			7,623
Derivative instruments	—			362			—			362
Other current assets	—			4,355			—			4,355
Total current assets	252,441			265,727			(279,619		)	238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)	—			7,296,568			—			7,296,568
Other property and equipment	—			618,790			—			618,790
Less: accumulated depreciation, depletion, amortization and impairment	—			(1,995,791		)	—			(1,995,791		)
Total property, plant and equipment, net	—			5,919,567			—			5,919,567
Investments in and advances to subsidiaries	4,451,192			—			(4,451,192		)	—
Deferred income taxes	220,058			—			(220,058		)	—
Other assets	—			20,516			—			20,516
Total assets	$	4,923,691		$	6,205,810		$	(4,950,869	)	$	6,178,632
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	—		$	4,645		$	—		$	4,645
Accounts payable – affiliates	27,619			252,000			(279,619		)	—
Revenue and production taxes payable	—			139,737			—			139,737
Accrued liabilities	12			119,161			—			119,173
Accrued interest payable	38,689			315			—			39,004
Derivative instruments	—			60,469			—			60,469
Advances from joint interest partners	—			7,597			—			7,597
Other current liabilities	—			10,490			—			10,490
Total current liabilities	66,320			594,414			(279,619		)	381,115
Long-term debt	1,934,214			363,000			—			2,297,214
Deferred income taxes	—			733,587			(220,058		)	513,529
Asset retirement obligations	—			48,985			—			48,985
Derivative instruments	—			11,714			—			11,714
Other liabilities	—			2,918			—			2,918
Total liabilities	2,000,534			1,754,618			(499,677		)	3,255,475
Stockholders’ equity
Capital contributions from affiliates	—			3,388,893			(3,388,893		)	—
Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding	2,331			—			—			2,331
Treasury stock, at cost: 856,892 shares	(15,950		)	—			—			(15,950		)
Additional paid-in-capital	2,345,271			8,743			(8,743		)	2,345,271
Retained earnings	591,505			1,053,556			(1,053,556		)	591,505
Total stockholders’ equity	2,923,157			4,451,192			(4,451,192		)	2,923,157
Total liabilities and stockholders’ equity	$	4,923,691		$	6,205,810		$	(4,950,869	)	$	6,178,632

18

Condensed Consolidating Statement of Operations

	Three Months Ended March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Revenues
Oil and gas revenues	$	—		$	237,252		$	—		$	237,252
Bulk oil sales	—			27,631			—			27,631
Midstream revenues	—			14,606			—			14,606
Well services revenues	—			5,627			—			5,627
Total revenues	—			285,116			—			285,116
Operating expenses
Lease operating expenses	—			43,872			—			43,872
Midstream operating expenses	—			3,327			—			3,327
Well services operating expenses	—			3,902			—			3,902
Marketing, transportation and gathering expenses	—			10,951			—			10,951
Bulk oil purchases	—			28,002			—			28,002
Production taxes	—			20,299			—			20,299
Depreciation, depletion and amortization	—			126,666			—			126,666
Exploration expenses	—			1,489			—			1,489
Impairment	—			2,682			—			2,682
General and administrative expenses	7,065			16,769			—			23,834
Total operating expenses	7,065			257,959			—			265,024
Operating income (loss)	(7,065		)	27,157			—			20,092
Other income (expense)
Equity in earnings of subsidiaries	49,103			—			(49,103		)	—
Net gain on derivative instruments	—			56,075			—			56,075
Interest expense, net of capitalized interest	(32,851		)	(3,470		)	—			(36,321		)
Other income	—			16			—			16
Total other income (expense)	16,252			52,621			(49,103		)	19,770
Income before income taxes	9,187			79,778			(49,103		)	39,862
Income tax benefit (expense)	14,638			(30,675		)	—			(16,037		)
Net income	$	23,825		$	49,103		$	(49,103	)	$	23,825

19

Condensed Consolidating Statement of Operations

	Three Months Ended March 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(In thousands)
Revenues
Oil and gas revenues	$	—		$	117,315		$	—	$	117,315
Midstream revenues	—			6,983			—		6,983
Well services revenues	—			5,985			—		5,985
Total revenues	—			130,283			—		130,283
Operating expenses
Lease operating expenses	—			31,064			—		31,064
Midstream operating expenses	—			1,738			—		1,738
Well services operating expenses	—			2,651			—		2,651
Marketing, transportation and gathering expenses	—			8,552			—		8,552
Production taxes	—			10,753			—		10,753
Depreciation, depletion and amortization	—			122,449			—		122,449
Exploration expenses	—			363			—		363
Impairment	—			3,562			—		3,562
General and administrative expenses	7,451			16,915			—		24,366
Total operating expenses	7,451			198,047			—		205,498
Operating loss	(7,451		)	(67,764		)	—		(75,215		)
Other income (expense)
Equity in loss of subsidiaries	(37,327		)	—			37,327		—
Net gain on derivative instruments	—			14,375			—		14,375
Interest expense, net of capitalized interest	(34,832		)	(3,907		)	—		(38,739		)
Gain on extinguishment of debt	7,016			—			—		7,016
Other income	43			436			—		479
Total other income (expense)	(65,100		)	10,904			37,327		(16,869		)
Loss before income taxes	(72,551		)	(56,860		)	37,327		(92,084		)
Income tax benefit	8,096			19,533			—		27,629
Net loss	$	(64,455	)	$	(37,327	)	$	37,327	$	(64,455	)

20

Condensed Consolidating Statement of Cash Flows

	Three Months Ended March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net income	$	23,825		$	49,103		$	(49,103	)	$	23,825
Adjustments to reconcile net income to cash provided by operating activities:
Equity in loss of subsidiaries	(49,103		)	—			49,103			—
Depreciation, depletion and amortization	—			126,666			—			126,666
Impairment	—			2,682			—			2,682
Deferred income taxes	(14,638		)	30,675			—			16,037
Derivative instruments	—			(56,075		)	—			(56,075		)
Stock-based compensation expenses	6,498			210			—			6,708
Deferred financing costs amortization and other	3,665			1,275			—			4,940
Working capital and other changes:
Change in accounts receivable	51,230			(27,952		)	(45,756		)	(22,478		)
Change in inventory	—			(3,679		)	—			(3,679		)
Change in prepaid expenses	(59		)	341			—			282
Change in other current assets	(2		)	(108		)	—			(110		)
Change in other assets	—			(4		)	—			(4		)
Change in accounts payable, interest payable and accrued liabilities	(13,321		)	(26,375		)	45,756			6,060
Change in other current liabilities	—			2,945			—			2,945
Net cash provided by operating activities	8,095			99,704			—			107,799
Cash flows from investing activities:
Capital expenditures	—			(96,047		)	—			(96,047		)
Derivative settlements	—			(7,960		)	—			(7,960		)
Advances from joint interest partners	—			(759		)	—			(759		)
Net cash used in investing activities	—			(104,766		)	—			(104,766		)
Cash flows from financing activities:
Proceeds from revolving credit facility	—			246,000			—			246,000
Principal payments on revolving credit facility	—			(241,000		)	—			(241,000		)
Purchases of treasury stock	(5,419		)	—			—			(5,419		)
Investment in / capital contributions from subsidiaries	(2,610		)	2,610			—			—
Other	(55		)	—			—			(55		)
Net cash provided by (used in) financing activities	(8,084		)	7,610			—			(474		)
Increase in cash and cash equivalents	11			2,548			—			2,559
Cash and cash equivalents at beginning of period	166			11,060			—			11,226
Cash and cash equivalents at end of period	$	177		$	13,608		$	—		$	13,785

21

Condensed Consolidating Statement of Cash Flows

	Three Months Ended March 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net loss	$	(64,455	)	$	(37,327	)	$	37,327		$	(64,455	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	37,327			—			(37,327		)	—
Depreciation, depletion and amortization	—			122,449			—			122,449
Gain on extinguishment of debt	(7,016		)	—			—			(7,016		)
Impairment	—			3,562			—			3,562
Deferred income taxes	(8,096		)	(19,533		)	—			(27,629		)
Derivative instruments	—			(14,375		)	—			(14,375		)
Stock-based compensation expenses	6,547			183			—			6,730
Deferred financing costs amortization and other	1,701			3,365			—			5,066
Working capital and other changes:
Change in accounts receivable	(85		)	96,353			(97,263		)	(995		)
Change in inventory	—			349			—			349
Change in prepaid expenses	139			102			—			241
Change in other current assets	—			4			—			4
Change in other assets	77			—			—			77
Change in accounts payable, interest payable and accrued liabilities	(122,242		)	(39,077		)	97,263			(64,056		)
Change in other current liabilities	—			(6,000		)	—			(6,000		)
Change in other liabilities	—			(3		)	—			(3		)
Net cash provided by (used in) operating activities	(156,103		)	110,052			—			(46,051		)
Cash flows from investing activities:
Capital expenditures	—			(103,411		)	—			(103,411		)
Derivative settlements	—			73,313			—			73,313
Advances from joint interest partners	—			(257		)	—			(257		)
Net cash used in investing activities	—			(30,355		)	—			(30,355		)
Cash flows from financing activities:
Proceeds from revolving credit facility	—			214,000			—			214,000
Principal payments on revolving credit facility	—			(287,000		)	—			(287,000		)
Repurchase of senior unsecured notes	(22,308		)	—			—			(22,308		)
Deferred financing costs	—			(751		)	—			(751		)
Proceeds from sale of common stock	183,164			—			—			183,164
Purchases of treasury stock	(1,032		)	—			—			(1,032		)
Investment in / capital contributions from subsidiaries	(4,408		)	4,408			—			—
Net cash provided by (used in) financing activities	155,416			(69,343		)	—			86,073
Increase (decrease) in cash and cash equivalents	(687		)	10,354			—			9,667
Cash and cash equivalents at beginning of period	777			8,953			—			9,730
Cash and cash equivalents at end of period	$	90		$	19,307		$	—		$	19,397

22

15. Subsequent Events

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

Derivative instruments.In April 2017, the Company entered into a new swap for crude oil with a weighted average price of $54.12 per barrel. The commodity contract included a total notional amount of 668,000 barrels and 62,000 barrels, which settle based on WTI in 2018 and 2019, respectively. This derivative instrument does not qualify for and was not designated as a hedging instrument for accounting purposes.

Credit facility.On April 10, 2017, the Company entered into an amendment to its Credit Facility in connection with the scheduled redetermination of the Company’s borrowing base. Following the redetermination, the borrowing base was increased to $1,600.0 million from $1,150.0 million; however, the Company did not increase the elected commitments above the current amount of $1,150.0 million. The next redetermination of the Company’s borrowing base is scheduled for October 1, 2017.

23

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under Part II, Item 1A. “Risk Factors” in our 2016 Annual Report could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about:

• our business strategy;

• estimated future net reserves and present value thereof;

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

• drilling and completion of wells;

• estimated inventory of wells remaining to be drilled and completed;

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

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

• availability of qualified personnel;

• owning and operating a midstream company;

• owning and operating a well services company;

• infrastructure for salt water gathering and disposal;

• gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and other regions in the United States;

• property acquisitions, including our recent acquisition of oil and gas properties in the Williston Basin;

• integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;

• the amount, nature and timing of capital expenditures;

• availability and terms of capital;

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

• cash flows and liquidity;

• oil and natural gas realized prices;

• general economic conditions;

• operating environment, including inclement weather conditions;

• effectiveness of risk management activities;

• competition in the oil and natural gas industry;

• counterparty credit risk;

• environmental liabilities;

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

24

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

• technology;

• uncertainty regarding future operating results; and

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

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We are an independent exploration and production (“E&P”) company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the North Dakota and Montana regions of the Williston Basin. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations. Oasis Petroleum North America LLC (“OPNA”) conducts our domestic oil and natural gas E&P activities. We also operate a midstream services business through Oasis Midstream Services LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to our primary development and production activities. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. We built our Williston Basin assets through acquisitions and development activities, which were financed with a combination of capital from private investors, borrowings under our revolving credit facility, cash flows provided by operating activities, proceeds from our senior unsecured notes, proceeds from our public equity offerings, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided an entry into a new area of interest or complemented our existing operations. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.

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

• commodity prices for oil and natural gas;

• transportation capacity;

• availability and cost of services; and

• availability of qualified personnel.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and may fluctuate widely in the future. As a

25

result of current oil prices, we have increased our planned 2017 capital expenditures as compared to 2016, excluding acquisitions, and we are continuing to concentrate our drilling activities in certain areas that are the most economic in the Williston Basin. Extended periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. We enter into crude oil and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. Currently, 89% and 98% of our gross operated oil and natural gas production, respectively, are connected to these gathering systems, and price differentials have improved to less than $4.00 per barrel primarily due to the commissioning and start-up of the Dakota Access Pipeline.

Highlights:

• We increased production to63,192 Boe per day during the three months ended March 31, 2017 from 50,315 Boe per day during the three months ended March 31, 2016;

• We completed and placed on production 13 gross (9.7 net) operated wells in the Williston Basin in the first quarter of 2017 and ended the quarter with 82 gross operated wells waiting on completion;

• Total capital expenditures were $109.8 million for the three months ended March 31, 2017;

• We increased our borrowing base from $1,150.0 million to $1,600.0 million on April 10, 2017 while leaving elected commitments at $1,150.0 million.

• At March 31, 2017, we had $13.8 million of cash and cash equivalents and had total liquidity of $785.8 million, including the availability under our revolving credit facility;

• Net cash provided by operating activities was $107.8 million for the three months ended March 31, 2017. Adjusted EBITDA, a non-GAAP financial measure, was $150.6 million for the three months ended March 31, 2017. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.

Results of Operations

Revenues

Our oil and gas revenues are derived from the sale of oil and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our bulk oil sales are derived from the sale of oil purchased through our marketing activities primarily for blending. Our midstream revenues are primarily derived from salt water pipeline transport, salt water disposal, natural gas gathering and processing, fresh water sales and crude oil gathering and transportation. Our well services revenues are derived from well services, product sales and equipment rentals. Substantially all of our midstream revenues and well services revenues are from services for third-party working interest owners in OPNA’s operated wells. Intercompany revenues for work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and are therefore not included in midstream and well services revenues.

26

The following table summarizes our revenues and production data for the periods presented:

	Three Months Ended March 31,
	2017		2016		Change
Operating results (in thousands):
Revenues
Oil	$	208,594	$	111,206	$	97,388
Natural gas	28,658		6,109		22,549
Bulk oil sales	27,631		—		27,631
Midstream	14,606		6,983		7,623
Well services	5,627		5,985		(358		)
Total revenues	$	285,116	$	130,283	$	154,833
Production data:
Oil (MBbls)	4,435		3,870		565
Natural gas (MMcf)	7,512		4,253		3,259
Oil equivalents (MBoe)	5,687		4,579		1,108
Average daily production (Boe per day)	63,192		50,315		12,877
Average sales prices:
Oil, without derivative settlements (per Bbl)	$	47.03	$	28.74	$	18.29
Oil, with derivative settlements (per Bbl)(1)	45.15		47.68		(2.53		)
Natural gas (per Mcf)(2)	3.81		1.44		2.37

____________________

(1) Realized prices include gains or losses on cash settlements for commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

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

Three months ended March 31, 2017 as compared to three months ended March 31, 2016

Oil and gas revenues. Our oil and gas revenues increased$119.9 million or 102%, to $237.3 million during the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. The higher oil and natural gas sales prices increased revenues by $80.9 million coupled with a $39.0 million increase due to higher oil and natural gas production amounts sold during the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. Average oil sales prices, without derivative settlements, increased by $18.29 per barrel to an average of $47.03 per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids, increased by $2.37 per Mcf to an average of $3.81 per Mcf for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. Average daily production sold increased by 12,877 Boe per day to 63,192 Boe per day during the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. The increase in average daily production sold was primarily a result of our acquisition completed on December 1, 2016 of approximately 55,000 net acres in the Williston Basin (the “Williston Basin Acquisition”).

Bulk oil sales. During the three months ended March 31, 2017, bulk oil sales were $27.6 million, which represents the sale of crude oil purchased primarily for blending at our crude oil terminal that began in late 2016. There were no bulk oil sales during the three months ended March 31, 2016.

Midstream revenues. Midstream revenues increased$7.6 million to $14.6 million during the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. This increase was driven by a $6.3 million increase related to higher natural gas volumes gathered and processed coupled with a $2.2 million increase related to higher oil volumes gathered, stabilized and transported as a result of the start up of our natural gas processing plant and our oil gathering system in the second half of 2016, respectively. These increases were offset by a decrease of $0.7 million related to lower freshwater sales.

Well services revenues. In response to the low commodity price environment, we decreased the pace of our well completions and reduced OWS to one fracturing fleet during the first quarter of 2016. Our well services revenues decreased by 6% to $5.6 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016, primarily due to a decrease in well completion activity and equipment rentals, offset by well completion product sales in the first quarter of 2017.

27

Expenses and other income

The following table summarizes our operating expenses and other income and expenses for the periods presented:

	Three Months Ended March 31,
	2017			2016			Change
	(In thousands, except per Boe of production)
Operating expenses:
Lease operating expenses	$	43,872		$	31,064		$	12,808
Midstream operating expenses	3,327			1,738			1,589
Well services operating expenses	3,902			2,651			1,251
Marketing, transportation and gathering expenses	10,951			8,552			2,399
Bulk oil purchases	28,002			—			28,002
Production taxes	20,299			10,753			9,546
Depreciation, depletion and amortization	126,666			122,449			4,217
Exploration expenses	1,489			363			1,126
Impairment	2,682			3,562			(880		)
General and administrative expenses	23,834			24,366			(532		)
Total operating expenses	265,024			205,498			59,526
Operating income (loss)	20,092			(75,215		)	95,307
Other income (expense):
Net gain on derivative instruments	56,075			14,375			41,700
Interest expense, net of capitalized interest	(36,321		)	(38,739		)	2,418
Gain on extinguishment of debt	—			7,016			(7,016		)
Other income	16			479			(463		)
Total other income (expense)	19,770			(16,869		)	36,639
Income (loss) before income taxes	39,862			(92,084		)	131,946
Income tax benefit (expense)	(16,037		)	27,629			(43,666		)
Net income (loss)	$	23,825		$	(64,455	)	$	88,280
Costs and expenses (per Boe of production):
Lease operating expenses	$	7.71		$	6.78		$	0.93
Marketing, transportation and gathering expenses	1.93			1.87			0.06
Production taxes	3.57			2.35			1.22
Depreciation, depletion and amortization	22.27			26.74			(4.47		)
General and administrative expenses	4.19			5.32			(1.13		)

Three months ended March 31, 2017 as compared to three months ended March 31, 2016

Lease operating expenses. Lease operating expenses increased$12.8 million to $43.9 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. The increase was primarily due to higher costs associated with operating an increased number of producing wells as a result of our well completions and the Williston Basin Acquisition coupled with an increase in workover costs during the three months ended March 31, 2017. Lease operating expenses increased from $6.78 per Boe for the three months ended March 31, 2016 to $7.71 per Boe for the three months ended March 31, 2017 primarily due to the higher aforementioned costs.

Midstream operating expenses. Midstream operating expenses represent operating expenses incurred by OMS associated with volumes for third-party working interest owners. The $1.6 million increase for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 was primarily related to the start up of our natural gas processing plant, additional saltwater infrastructure and our oil gathering system during 2016, partially offset by a decrease in fresh water purchases.

Well services operating expenses. Well services operating expenses represent operating expenses incurred by OWS for third-party working interest owners’ share of completion services. The $1.3 million increase for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 was primarily attributable to well completion product sales coupled with increased maintenance and trucking costs, partially offset by lower well completion activity.

Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $2.4 million, or $0.06 per Boe, for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016, which was primarily attributable to a $2.7 million increase in natural gas gathering and processing expenses coupled with

28

higher oil gathering and transportation expenses related to additional well connections on OMS infrastructure and the start up of our natural gas processing plant and our oil gathering system, respectively, in the second half of 2016. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $1.77 during the three months ended March 31, 2017 as compared to $1.60 during the three months ended March 31, 2016.

Bulk oil purchases. For the three months ended March 31, 2017, we incurred $28.0 million of bulk oil purchase costs related to blending. We did not incur similar charges during the three months ended March 31, 2016.

Production taxes. Our production taxes as a percentage of oil and natural gas sales were 8.6% and 9.2% for the three months ended March 31, 2017 and 2016, respectively. The production tax rate decreased period over period primarily due to a lower oil production mix. North Dakota’s natural gas production tax is $0.0601 per Mcf.

Depreciation, depletion and amortization (“DD&A”). DD&A expense increased$4.2 million to $126.7 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. This increase in DD&A expense for the three months ended March 31, 2017 was a result of production increases from our wells completed during the twelve months ended March 31, 2017 coupled with the Williston Basin Acquisition, offset by a decrease in the DD&A rate to $22.27 per Boe for the three months ended March 31, 2017 as compared to $26.74 per Boe for the three months ended March 31, 2016. The decrease in the DD&A rate was primarily due to lower well costs and higher recoverable reserves.

Impairment. For the three months ended March 31, 2017 and 2016, we recorded total impairment charges of $2.7 million and $3.6 million, respectively. As a result of periodic assessments of unproved properties not held-by-production, we recorded an impairment charge on our unproved oil and natural gas properties of $2.7 million for the three months ended March 31, 2017 related to acreage expiring in future periods because there were no current plans to drill or extend the leases prior to their expiration. For the three months ended March 31, 2016, we recorded total impairment loss of $3.6 million to further adjust the carrying value of our properties held for sale to their estimated fair value, determined based on the expected sales price, less costs to sell. No impairment charges of proved oil and gas or other properties were recorded for the three months ended March 31, 2017.

General and administrative expenses (“G&A”). Our G&Adecreased$0.5 millionto$23.8 millionfor the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. E&P and OWS G&A decreased $1.0 million and $0.3 million, respectively, for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. The decreases in E&P and OWS G&A were primarily due to lower compensation expenses due to severance expenses paid in 2016. OMS G&A increased $0.7 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 primarily due to increased employee compensation as a result of organizational growth within this segment due to the start up of our natural gas processing plant in the third quarter of 2016. Our total company full-time employee headcount increased to 493 at March 31, 2017 from 462 at March 31, 2016.

Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip oil price changes, we incurred a $56.1 million net gain on derivative instruments, including net cash settlement payments of $8.0 million, for the three months ended March 31, 2017, and a $14.4 million net gain on derivative instruments, including net cash settlement receipts of $73.3 million, for the three months ended March 31, 2016. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

Interest expense. Interest expense decreased $2.4 million from $38.7 million for the three months ended March 31, 2016 to $36.3 million for the three months ended March 31, 2017 primarily due to the repurchase of an aggregate principal amount of $447.0 million of outstanding senior unsecured notes in 2016, which resulted in a $7.7 million decrease in interest costs. This decrease was partially offset by interest expense related to our senior unsecured convertible notes issued in September 2016, which includes debt discount amortization, and our revolving credit facility coupled with a decrease in capitalized interest due to lower work in progress as a result of the completion of our natural gas processing plant in the third quarter of 2016. For the three months ended March 31, 2017 and 2016, the weighted average debt outstanding under our revolving credit facility was $400.8 million and $108.0 million, respectively. The weighted average interest rate incurred on the outstanding borrowings under our revolving credit facility was 2.5% and 1.9% for the three months ended March 31, 2017 and March 31, 2016, respectively. Interest capitalized during the three months ended March 31, 2017 and 2016 was $2.8 million and $4.5 million, respectively.

Gain on extinguishment of debt. For the three months ended March 31, 2017, we did not repurchase any portion of our outstanding senior unsecured notes. During the three months ended March 31, 2016, we repurchased an aggregate principal amount of $29.8 million of our outstanding senior unsecured notes for an aggregate cost of $22.3 million, including accrued interest and fees. For the three months ended March 31, 2016, we recognized a pre-tax loss related to the repurchase of $7.0 million, which included unamortized deferred financing costs write-offs of $0.5 million.

Income taxes. The income tax expense for the three months ended March 31, 2017 was recorded at 40.2% of pre-tax income, and the income tax benefit for the three months ended March 31, 2016 was recorded at 30.0% of pre-tax net loss. The

29

effective tax rate for the three months ended March 31, 2017 was higher than the combined federal statutory rate and the statutory rates for the states in which we conduct business due to the impact of permanent differences on pre-tax income for the period, while the effective tax rate for the three months ended March 31, 2016 was lower than the combined federal statutory rate and the statutory rates for the states in which we conduct business due to the impact of permanent differences on pre-tax loss for the period. The permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to compensation, including stock-based compensation vesting, during the three months ended March 31, 2017 and 2016.

Liquidity and Capital Resources

Our primary sources of liquidity as of the date of this report have been proceeds from our senior unsecured notes, borrowings under our revolving credit facility, proceeds from public equity offerings, cash flows from operations, the sale of certain non-core oil and gas properties and cash settlements of derivative contracts. Our primary uses of capital have been for the acquisition and development of oil and natural gas properties and midstream infrastructure, payment of operating and general and administrative costs, interest payments on outstanding debt and repurchases of our senior unsecured notes. We continually monitor potential capital sources, including equity and debt financings and potential asset monetizations, in order to enhance liquidity and decrease leverage. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Our cash flows for the three months ended March 31, 2017 and 2016 are presented below:

	Three Months Ended March 31,
	2017			2016
	(In thousands)
Net cash provided by (used in) operating activities	$	107,799		$	(46,051	)
Net cash used in investing activities	(104,766		)	(30,355		)
Net cash provided by (used in) financing activities	(474		)	86,073
Increase in cash and cash equivalents	$	2,559		$	9,667

Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oil and natural gas prices on a portion of our production, thereby mitigating our exposure to oil and natural gas price declines, but these transactions may also limit our cash flow in periods of rising oil and natural gas prices. For additional information on the impact of changing prices on our financial position, see Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows provided by operating activities

Net cash provided by operating activities was $107.8 million and net cash used in operating activities was $46.1 million for the three months ended March 31, 2017 and 2016, respectively. The change in cash flows from operating activities for the period ended March 31, 2017 as compared to 2016 was primarily the result of higher realized oil and natural gas sales prices.

Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes, capital spending to fund our exploratory and development initiatives and acquisitions, and the impact of our outstanding derivative instruments. We had a working capital deficit of $83.3 million at March 31, 2017 primarily due to increases in our current liabilities, including accrued liabilities for drilling and development costs and revenues payable. As of March 31, 2017, we had $785.8 million of liquidity available, including $13.8 million in cash and cash equivalents and $772.0 million of unused borrowing base committed capacity available under our revolving credit facility. At March 31, 2016, we had a working capital surplus of $43.9 million.

Cash flows used in investing activities

Net cash used in investing activities was $104.8 million and $30.4 million during the three months ended March 31, 2017 and 2016, respectively. Net cash used in investing activities during the three months ended March 31, 2017 was primarily attributable to $96.0 million in capital expenditures primarily for drilling and development costs. Net cash used in investing activities during the three months ended March 31, 2016 was primarily attributable to $103.4 million in capital expenditures primarily for drilling and development costs, partially offset by $73.3 million of derivative settlements received as a result of lower crude oil pricing.

30

Our capital expenditures are summarized in the following table:

	Three Months Ended March 31, 2017
	(In thousands)
Capital expenditures:
E&P	$	90,780
OMS	13,144
OWS	—
Other capital expenditures(1)	5,871
Total capital expenditures(2)	$	109,795

___________________

(1) Other capital expenditures include such items as administrative capital and capitalized interest.

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

Our total 2017 capital expenditure budget is $605.0 million, which includes $410.0 million of drilling and completion capital expenditures (including expected savings from services provided by OMS and OWS), $110.0 million for midstream infrastructure and $85.0 million of other capital expenditures, including other E&P capital, capitalized interest, OWS and administrative capital.

While we have budgeted $605.0 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Furthermore, if we acquire additional acreage, our capital expenditures may be higher than budgeted. We believe that cash on hand, including cash flows from operating activities, proceeds from cash settlements under our derivative contracts and availability under our revolving credit facility should be sufficient to fund our 2017 capital expenditure budget and to meet our future obligations. However, because the operated wells funded by our 2017 drilling plan represent only a small percentage of our potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drilling locations should we elect to do so.

Our capital budget may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil prices decline for an extended period of time, 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. We actively review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Cash flows provided by financing activities

Net cash used in financing activities was $0.5 million and net cash provided by financing activities was $86.1 million for the three months ended March 31, 2017 and 2016, respectively. For the three months ended March 31, 2017, cash used in financing activities was primarily due to principal payments on our revolving credit facility coupled with purchases of treasury stock for shares that employees surrendered back to us to pay tax withholdings upon the vesting of restricted stock awards, partially offset by proceeds from the borrowings under our revolving credit facility. Net cash provided by financing activities during the three months ended March 31, 2016 was primarily due to proceeds from borrowings under our revolving credit facility and net proceeds from the issuance of our common stock, partially offset by principal payments on our revolving credit facility and the repurchase of a portion of our outstanding senior unsecured notes.

Senior secured revolving line of credit. We have a revolving credit facility (the “Credit Facility”) with an overall senior secured line of credit of $2,500.0 million as of March 31, 2017. The Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. The maturity date of the Credit Facility is April 13, 2020, provided that the 7.25% senior unsecured notes due February 2019 (the “2019 Notes”) are retired or refinanced 90 days prior to their maturity date. On April 10, 2017, the lenders under the Credit Facility (the “Lenders”) completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2017, resulting in an increase in the borrowing base from $1,150.0 million to $1,600.0 million; however, we did not increase the elected commitments above the current amount of $1,150.0 million. The next redetermination of the borrowing base is scheduled for October 1, 2017.

31

At March 31, 2017, we had $368.0 million of borrowings at a weighted average interest rate of 2.7% and $10.0 million of outstanding letters of credit issued under the Credit Facility. At March 31, 2017, we had an unused borrowing base committed capacity of $772.0 million.

The 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 our assets and our 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 we maintain a ratio of consolidated EBITDAX (as defined in the Credit Facility) to consolidated Interest Expense (as defined in the Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter; and

• a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the Credit Facility) to consolidated current liabilities (with exclusions as described in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.

The 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 Credit Facility to be immediately due and payable. We were in compliance with the financial covenants of the Credit Facility at March 31, 2017. At March 31, 2017, our consolidated EBITDAX was $518.0 million and our consolidated Interest Expense was $140.5 million, resulting in a ratio of 3.7 as compared to a minimum required ratio of 2.5. In addition, as of March 31, 2017, our consolidated current assets and consolidated current liabilities (as described above) were $1,052.7 million and $352.4 million, respectively, resulting in a Current Ratio of 3.0 as compared to a minimum required ratio of 1.0. Given the possible fluctuation in commodity prices, we continue to closely monitor our financial covenants and do not anticipate a covenant violation in the next twelve months.

Senior unsecured notes. At March 31, 2017, our long-term debt includes outstanding obligations of $1,753.0 million for senior unsecured notes (the “Senior Notes”), including $54.3 million of the 2019 Notes, $395.5 million of the 6.5% senior unsecured notes due November 2021 (the “2021 Notes”), $937.1 million of the 6.875% senior unsecured notes due March 2022 (the “2022 Notes”) and $366.1 million of the 6.875% senior unsecured notes due January 2023 (the “2023 Notes”).

Prior to certain dates, we have the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par plus accrued and unpaid interest to the redemption date. We may from time to time seek to retire or purchase our outstanding Senior Notes through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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

Senior unsecured convertible notes. In September 2016, we issued $300.0 million of 2.625% Senior Convertible Notes due September 2023. We have the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at our election. Our intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the

32

“measurement period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding the September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, we will increase the conversion rate for a holder who elects to convert the Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of March 31, 2017, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.

Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by our material subsidiaries.

Non-GAAP Financial Measures

Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP measures should not be considered in isolation or as a substitute for interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities, earnings (loss) per share or any other measures prepared under GAAP. Because Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.

Cash Interest

We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.

The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented:

	Three Months Ended March 31,
	2017			2016
	(In thousands)
Interest expense	$	36,321		$	38,739
Capitalized interest	2,820			4,468
Amortization of deferred financing costs	(1,690		)	(3,917		)
Amortization of debt discount	(2,355		)	—
Cash Interest	$	35,096		$	39,290

Adjusted EBITDA and Free Cash Flow

We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or nonrecurring charges. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our debt covenants.

We define Free Cash Flow as Adjusted EBITDA less Cash Interest and capital expenditures, excluding capitalized interest. Free Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Free Cash Flow provides useful additional information to investors and analysts for assessing our financial performance as compared to our peers and our ability to generate cash from our business operations after interest and capital spending. In addition, Free Cash Flow excludes changes in operating assets and liabilities that relate to the timing of cash receipts and disbursements, which we may not control, and changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

33

The following table presents reconciliations of the GAAP financial measures of net income (loss) and net cash provided by (used in) operating activities to the non-GAAP financial measures of Adjusted EBITDA and Free Cash Flow for the periods presented:

	Three Months Ended March 31,
	2017			2016
	(In thousands)
Net income (loss)	$	23,825		$	(64,455	)
Gain on extinguishment of debt	—			(7,016		)
Net gain on derivative instruments	(56,075		)	(14,375		)
Derivative settlements(1)	(7,960		)	73,313
Interest expense, net of capitalized interest	36,321			38,739
Depreciation, depletion and amortization	126,666			122,449
Impairment	2,682			3,562
Exploration expenses	1,489			363
Stock-based compensation expenses	6,708			6,730
Income tax (benefit) expense	16,037			(27,629		)
Other non-cash adjustments	912			1,207
Adjusted EBITDA	150,605			132,888
Cash Interest	(35,096		)	(39,290		)
Capital expenditures(2)	(109,795		)	(87,955		)
Capitalized interest	2,820			4,468
Free Cash Flow	$	8,534		$	10,111
Net cash provided by (used in) operating activities	$	107,799		$	(46,051	)
Derivative settlements(1)	(7,960		)	73,313
Interest expense, net of capitalized interest	36,321			38,739
Exploration expenses	1,489			363
Deferred financing costs amortization and other	(4,940		)	(5,066		)
Changes in working capital	16,984			70,383
Other non-cash adjustments	912			1,207
Adjusted EBITDA	150,605			132,888
Cash Interest	(35,096		)	(39,290		)
Capital expenditures(2)	(109,795		)	(87,955		)
Capitalized interest	2,820			4,468
Free Cash Flow	$	8,534		$	10,111

___________________

(1) Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

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

The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes to the non-GAAP financial measure of Adjusted EBITDA for our three reportable business segments on a gross basis for the periods presented:

34

Exploration and Production
	Three Months Ended March 31,
	2017			2016
	(In thousands)
Income (loss) before income taxes	$	20,736		$	(105,764	)
Gain on extinguishment of debt	—			(7,016		)
Net gain on derivative instruments	(56,075		)	(14,375		)
Derivative settlements(1)	(7,960		)	73,313
Interest expense, net of capitalized interest	36,321			38,739
Depreciation, depletion and amortization	124,409			120,842
Impairment	2,682			1,131
Exploration expenses	1,489			363
Stock-based compensation expenses	6,499			6,547
Other non-cash adjustments	912			1,207
Adjusted EBITDA	$	129,013		$	114,987

___________________

(1) Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

Midstream Services
	Three Months Ended March 31,
	2017		2016
	(In thousands)
Income before income taxes	$	20,761	$	15,157
Depreciation, depletion and amortization	3,458		1,684
Impairment	—		2,431
Stock-based compensation expenses	348		219
Adjusted EBITDA	$	24,567	$	19,491

Well Services
	Three Months Ended March 31,
	2017			2016
	(In thousands)
Income (loss) before income taxes	$	(3,588	)	$	4,011
Depreciation, depletion and amortization	3,164			4,248
Stock-based compensation expenses	396			664
Adjusted EBITDA	$	(28	)	$	8,923

Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share

We define Adjusted Net Income (Loss) as net income (loss) after adjusting first for (1) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash charges, or non-recurring items and then (2) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items in the same period. Adjusted Net Income (Loss) is not a measure of net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings (Loss) Per Share as Adjusted Net Income (Loss) divided by diluted weighted average shares outstanding. Management believes that the presentation of Adjusted Net Income (Loss) and Adjusted Diluted Earnings (Loss) Per Share provides useful additional information to investors and analysts for evaluating our operational trends and performance in comparison to our peers. This measure is more comparable to earnings estimates provided by securities analysts, and charges or amounts excluded cannot be reasonably estimated and is excluded from guidance provided by the Company.

35

The following table presents reconciliations of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted Net Income (Loss) and the GAAP financial measure of diluted earnings (loss) per share to the non-GAAP financial measure of Adjusted Diluted Earnings (Loss) Per Share for the periods presented:

	Three Months Ended March 31,
	2017			2016
	(In thousands, except per share data)
Net income (loss)	$	23,825		$	(64,455	)
Gain on extinguishment of debt	—			(7,016		)
Net gain on derivative instruments	(56,075		)	(14,375		)
Derivative settlements(1)	(7,960		)	73,313
Impairment	2,682			3,562
Amortization of deferred financing costs(2)	1,690			3,917
Amortization of debt discount	2,355			—
Other non-cash adjustments	912			1,207
Tax impact(3)	21,103			(22,655		)
Adjusted Net Loss	$	(11,468	)	$	(26,502	)
Diluted earnings (loss) per share	$	0.10		$	(0.40	)
Gain on extinguishment of debt	—			(0.04		)
Net gain on derivative instruments	(0.24		)	(0.09		)
Derivative settlements(1)	(0.03		)	0.45
Impairment	0.01			0.02
Amortization of deferred financing costs(2)	0.01			0.02
Amortization of debt discount	0.01			—
Other non-cash adjustments	—			0.01
Tax impact(3)	0.09			(0.13		)
Adjusted Diluted Loss Per Share	$	(0.05	)	$	(0.16	)
Diluted weighted average shares outstanding	237,900			162,922
Effective tax rate applicable to adjustment items	37.4		%	37.4		%

___________________

(1) Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.

(2) As of March 31, 2017, Adjusted Net Income (Loss) includes the non-cash adjustment for amortization of deferred financing costs. Comparative periods have been conformed. The amortization of deferred financing costs is included in interest expense on our Condensed Consolidated Statement of Operations.

(3) The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items.

Fair Value of Financial Instruments

See Note 4 to our unaudited condensed consolidated financial statements for a discussion of our money market funds and derivative instruments and their related fair value measurements. See also Item 3. “Quantitative and Qualitative Disclosures About Market Risk” below.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2016 Annual Report. See Note 2 to our unaudited condensed consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

36

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See Note 13 to our unaudited condensed consolidated financial statements for a description of our commitments and contingencies.

Item 3. — Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, natural gas liquids, and oil prices, and interest rates.  The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2016 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

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

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

We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. Our crude oil and natural gas contracts will settle monthly based on the average WTI and the average NYMEX Henry Hub natural gas index price, respectively. As of March 31, 2017, we utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of our future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor), which we will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract.

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

The following is a summary of our derivative contracts as of March 31, 2017:

Commodity	Settlement Period	Derivative Instrument	Volumes		Weighted Average Prices								Fair Value Asset (Liability)
					Swap		Sub-Floor		Floor		Ceiling
													(In thousands)
Crude oil	2017	Swaps	5,225,000	Bbl	$	49.60							$	(9,309	)
Crude oil	2017	Two-way collar	2,200,000	Bbl					$	46.25	$	54.37	(1,707		)
Crude oil	2017	Three-way collar	1,650,000	Bbl			$	31.67	$	45.83	$	59.94	562
Crude oil	2018	Swaps	2,440,000	Bbl	$	52.93							2,375
Crude oil	2018	Two-way collar	582,000	Bbl					$	48.40	$	55.13	28
Crude oil	2018	Three-way collar	186,000	Bbl			$	31.67	$	45.83	$	59.94	58
Crude oil	2019	Swaps	155,000	Bbl	$	53.88							351
Crude oil	2019	Two-way collar	31,000	Bbl					$	50.00	$	55.70	32
Natural gas	2017	Swaps	4,675,000	MMBtu	$	3.30							(55		)
Natural gas	2018	Swaps	3,650,000	MMBtu	$	3.00							(121		)
													$	(7,786	)

37

A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $52.6 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $51.4 million.

Interest rate risk. We had (i) $54.3 million of senior unsecured notes at a fixed cash interest rate of 7.25% per annum, (ii) $395.5 million of senior unsecured notes at a fixed cash interest rate of 6.5% per annum, (iii) $1,303.2 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum and (iv) $300.0 million of senior unsecured convertible notes as a fixed cash interest rate of 2.625% per annum outstanding at March 31, 2017. At March 31, 2017, we had $368.0 million of borrowings and $10.0 million letters of credit outstanding under our Credit Facility, which were 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 LIBOR loan or a domestic bank prime interest rate loan (defined in the Credit Facility as an Alternate Based Rate or “ABR” loan). At March 31, 2017, the outstanding borrowings under our Credit Facility bore interest at LIBOR plus a 1.5% margin. We do not currently, but may in the future, utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to debt issued under our Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk.  Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. No bad debt expense was recorded during the three months ended March 31, 2017. 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.

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

In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions, most of which are Lenders under our Credit Facility. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. We are likely to enter into future derivative instruments with these or other Lenders under our Credit Facility, which also carry investment grade ratings. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. We had a net derivative asset position of $6.8 million and a net derivative liability position of $14.6 million at March 31, 2017.

As permitted under our investments policy, we may purchase commercial paper instruments from high credit quality counterparties. These counterparties may include issuers in a variety of industries including the domestic and foreign financial sector. This risk is managed by our investment policy including minimum credit ratings thresholds and maximum counterparty exposure values. Although we do not anticipate any of our commercial paper issuers failing to pay us upon maturity, we take a risk in purchasing the commercial paper instruments available in the marketplace. If an issuer fails to repay us at maturity from commercial paper proceeds, it could take a significant amount of time to recover a portion of or all of the assets originally invested. Our commercial paper balance was $36,000 at March 31, 2017.

Item 4. — Controls and Procedures

Evaluation of disclosure controls and procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our 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 March 31, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective at March 31, 2017.

38

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

39

PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

Mirada litigation.On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis Petroleum Inc., OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area”.

The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims. Discovery is ongoing. Trial is currently scheduled for July 2018. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin.

Hegstad notice.On February 5, 2016, the North Dakota Department of Health issued a Notice of Violation to OPNA in respect of a release that occurred on or about May 4, 2015 on a pipeline serving the Hegstad SWD 6092 41-20.  The pipeline experienced a release of produced water and some crude oil. The North Dakota Department of Health has proposed a penalty of approximately $0.1 million as a result of the release.

Item 1A. — Risk Factors

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

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2016 Annual Report. There have been no material changes in our risk factors from those described in our 2016 Annual Report.

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

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

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended March 31, 2017:

40

Period	Total Number of Shares Exchanged(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
January 1 - January 31, 2017	327,428	$	14.55	—	—
February 1 - February 28, 2017	45,165	14.49		—	—
March 1 - March 31, 2017	83	15.40		—	—
Total	372,676	$	14.54	—	—

___________________ 

(1) Represent shares that employees surrendered back to us to pay tax withholdings upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.

Item 6. — Exhibits

Exhibit No.	Description of Exhibit
10.1	Eighth Amendment to Second Amended and Restated Credit Agreement dated as of April 10, 2017 among Oasis Petroleum North America LLC, as Borrower, the Guarantors party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 13, 2017, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

___________________

(a) Filed herewith.

(b) Furnished herewith.

41

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:	May 9, 2017	By:	/s/ Thomas B. Nusz
			Thomas B. Nusz
			Chairman and Chief Executive Officer (Principal Executive Officer)

By:	/s/ Michael H. Lou
	Michael H. Lou
	Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

42

EXHIBIT INDEX

Exhibit No.	Description of Exhibit
10.1	Eighth Amendment to Second Amended and Restated Credit Agreement dated as of April 10, 2017 among Oasis Petroleum North America LLC, as Borrower, the Guarantors party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 13, 2017, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS (a)	XBRL Instance Document.
101.SCH (a)	XBRL Schema Document.
101.CAL (a)	XBRL Calculation Linkbase Document.
101.DEF (a)	XBRL Definition Linkbase Document.
101.LAB (a)	XBRL Labels Linkbase Document.
101.PRE (a)	XBRL Presentation Linkbase Document.

___________________

(a) Filed herewith.

(b) Furnished herewith.

43

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Thomas B. Nusz, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Oasis Petroleum Inc. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 9, 2017	/s/ Thomas B. Nusz
		Thomas B. Nusz
		Chairman and Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Michael H. Lou, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Oasis Petroleum Inc. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 9, 2017	/s/ Michael H. Lou
		Michael H. Lou
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Oasis Petroleum Inc. (the “Company”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas B. Nusz, Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 9, 2017	/s/ Thomas B. Nusz
		Thomas B. Nusz
		Chairman and Chief Executive Officer
		(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Oasis Petroleum Inc. (the “Company”) on Form 10-Q for the quarter ended March 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael H. Lou, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 9, 2017	/s/ Michael H. Lou
		Michael H. Lou
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 04, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Trading Symbol	OAS
Entity Registrant Name	Oasis Petroleum Inc.
Entity Central Index Key	0001486159
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		237,432,612

XML

Condensed Consolidated Balance Sheet (Unaudited) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents		$ 13,785	$ 11,226
Accounts receivable, net		226,427	204,335
Inventory		14,327	10,648
Prepaid expenses		7,176	7,623
Derivative instruments		3,026	362
Other current assets		4,452	4,355
Total current assets		269,193	238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)		7,390,299	7,296,568
Other property and equipment		632,318	618,790
Less: accumulated depreciation, depletion, amortization and impairment		(2,126,136)	(1,995,791)
Total property, plant and equipment, net		5,896,481	5,919,567
Derivative instruments		3,815	0
Other assets		20,139	20,516
Total assets	[1]	6,189,628	6,178,632
Current liabilities
Accounts payable		8,837	4,645
Revenues and production taxes payable		160,265	139,737
Accrued liabilities		128,241	119,173
Accrued interest payable		20,268	39,004
Derivative instruments		14,627	60,469
Advances from joint interest partners		6,838	7,597
Other current liabilities		13,435	10,490
Total current liabilities		352,511	381,115
Long-term debt		2,305,879	2,297,214
Deferred income taxes		524,842	513,529
Asset retirement obligations		50,088	48,985
Derivative instruments		0	11,714
Other liabilities		2,834	2,918
Total liabilities		3,236,154	3,255,475
Commitments and contingencies
Stockholders’ equity
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding at March 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016		2,344	2,331
Treasury stock, at cost: 1,229,568 and 856,892 shares at March 31, 2017 and December 31, 2016, respectively		(21,369)	(15,950)
Additional paid-in capital		2,354,485	2,345,271
Retained earnings		618,014	591,505
Total stockholders’ equity		2,953,474	2,923,157
Total liabilities and stockholders’ equity		$ 6,189,628	$ 6,178,632

[1] Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

XML

Condensed Consolidated Balance Sheet (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	238,691,038	237,201,064
Common stock, shares outstanding (in shares)	237,461,470	236,344,172
Treasury stock, shares (in shares)	1,229,568	856,892

XML

Condensed Consolidated Statement of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues
Oil and gas revenues	$ 237,252	$ 117,315
Bulk oil sales	27,631	0
Midstream revenues	14,606	6,983
Well services revenues	5,627	5,985
Total revenues	285,116	130,283
Operating expenses
Lease operating expenses	43,872	31,064
Midstream operating expenses	3,327	1,738
Well services operating expenses	3,902	2,651
Marketing, transportation and gathering expenses	10,951	8,552
Bulk oil purchases	28,002	0
Production taxes	20,299	10,753
Depreciation, depletion and amortization	126,666	122,449
Exploration expenses	1,489	363
Impairment	2,682	3,562
General and administrative expenses	23,834	24,366
Total operating expenses	265,024	205,498
Operating income (loss)	20,092	(75,215)
Other income (expense)
Net gain on derivative instruments	56,075	14,375
Interest expense, net of capitalized interest	(36,321)	(38,739)
Gain on extinguishment of debt	0	7,016
Other income	16	479
Total other income (expense)	19,770	(16,869)
Income (loss) before income taxes	39,862	(92,084)
Income tax benefit (expense)	(16,037)	27,629
Net income (loss)	$ 23,825	$ (64,455)
Earnings (loss) per share:
Basic (in dollars per share)	$ 0.10	$ (0.40)
Diluted (in dollars per share)	$ 0.10	$ (0.40)
Weighted average shares outstanding:
Basic (in shares)	233,068	162,922
Diluted (in shares)	237,900	162,922

XML

Condensed Consolidated Statement of Changes in Stockholders' Equity (Unaudited) - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in-Capital [Member]	Retained Earnings [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative-effect adjustment for adoption of ASU 2016-09	$ 4,724			$ 2,040	$ 2,684
Balance (shares) at Dec. 31, 2016		236,344	857
Balance at Dec. 31, 2016	2,923,157	$ 2,331	$ (15,950)	2,345,271	591,505
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Fees (2016 issuance of common stock) (shares)		0
Fees (2016 issuance of common stock)	(55)	$ 0		(55)
Stock-based compensation, shares		1,490
Stock-based compensation	7,242	$ 13		7,229
Treasury stock - tax withholdings (shares)		(373)	373
Treasury stock – tax withholdings	(5,419)		$ (5,419)
Net income	23,825				23,825
Balance (shares) at Mar. 31, 2017		237,461	1,230
Balance at Mar. 31, 2017	$ 2,953,474	$ 2,344	$ (21,369)	$ 2,354,485	$ 618,014

XML

Condensed Consolidated Statement of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 23,825	$ (64,455)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	126,666	122,449
Gain on extinguishment of debt	0	(7,016)
Impairment	2,682	3,562
Deferred income taxes	16,037	(27,629)
Derivative instruments	(56,075)	(14,375)
Stock-based compensation expenses	6,708	6,730
Deferred financing costs amortization and other	4,940	5,066
Working capital and other changes:
Change in accounts receivable	(22,478)	(995)
Change in inventory	(3,679)	349
Change in prepaid expenses	282	241
Change in other current assets	(110)	4
Change in other assets	(4)	77
Change in accounts payable, interest payable and accrued liabilities	6,060	(64,056)
Change in other current liabilities	2,945	(6,000)
Change in other liabilities	0	(3)
Net cash provided by (used in) operating activities	107,799	(46,051)
Cash flows from investing activities:
Capital expenditures	(96,047)	(103,411)
Derivative settlements	(7,960)	73,313
Advances from joint interest partners	(759)	(257)
Net cash used in investing activities	(104,766)	(30,355)
Cash flows from financing activities:
Proceeds from revolving credit facility	246,000	214,000
Principal payments on revolving credit facility	(241,000)	(287,000)
Repurchase of senior unsecured notes	0	(22,308)
Deferred financing costs	0	(751)
Proceeds from sale of common stock	0	183,164
Purchases of treasury stock	(5,419)	(1,032)
Other	(55)	0
Net cash provided by (used in) financing activities	(474)	86,073
Increase in cash and cash equivalents	2,559	9,667
Cash and cash equivalents:
Beginning of period	11,226	9,730
End of period	13,785	19,397
Supplemental non-cash transactions:
Change in accrued capital expenditures	8,396	(19,230)
Change in asset retirement obligations	$ 787	$ 1,212

XML

Organization and Operations of the Company

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Organization and Operations of the Company

Organization and Operations of the Company

Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the North Dakota and Montana regions of the Williston Basin. Oasis Petroleum North America LLC (“OPNA”) conducts the Company’s exploration and production activities and owns its proved and unproved oil and natural gas properties. The Company also operates a midstream services business through Oasis Midstream Services LLC (“OMS”) and a well services business through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to its primary development and production activities.

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Basis of Presentation

The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The accompanying condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2016 is derived from audited financial statements. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement, have been included. Management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”).

Risks and Uncertainties

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

Significant Accounting Policies

There have been no material changes to the Company’s critical accounting policies and estimates from those disclosed in the 2016 Annual Report, other than as noted below.

Stock-based compensation. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. In accordance with the new guidance, the Company recorded a $2.7 million cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet as of March 31, 2017, which included recognition of excess tax benefits and deficiencies and the removal of the estimated forfeiture rate. ASU 2016-09 was applied on a modified retrospective basis and prior periods were not retrospectively adjusted.

Inventory. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), which changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of March 31, 2017.

Recent Accounting Pronouncements

Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Financial instruments. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Statement of cash flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations, but could result in presentation changes on the Company’s statement of cash flows.

Business combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

XML

Inventory

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

Inventory

Inventory

Crude oil inventory includes oil in tank and linefill. Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment. Inventory is stated at the lower of cost and net realizable value with cost determined on an average cost method. Inventory consists of the following:

	March 31, 2017		December 31, 2016
	(In thousands)
Crude oil inventory	$	10,302	$	7,086
Equipment and materials	4,025		3,562
Total inventory	$	14,327	$	10,648

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations (“ARO”) and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.

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

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

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

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

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

Financial Assets and Liabilities

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 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:

	Fair value at March 31, 2017
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	141	$	—	$	—	$	141
Commodity derivative instruments (see Note 5)	—		6,841		—		6,841
Total assets	$	141	$	6,841	$	—	$	6,982
Liabilities:
Commodity derivative instruments (see Note 5)	$	—	$	14,627	$	—	$	14,627
Total liabilities	$	—	$	14,627	$	—	$	14,627

	Fair value at December 31, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	141	$	—	$	—	$	141
Commodity derivative instruments (see Note 5)	—		362		—		362
Total assets	$	141	$	362	$	—	$	503
Liabilities:
Commodity derivative instruments (see Note 5)	$	—	$	72,183	$	—	$	72,183
Total liabilities	$	—	$	72,183	$	—	$	72,183

The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheet at March 31, 2017 and December 31, 2016. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.

The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include oil and natural gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts, as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to reduce the fair value of its net derivative liability by $0.2 million and $2.0 million at March 31, 2017 and December 31, 2016, respectively.

There were no transfers between fair value levels during the three months ended March 31, 2017 and 2016.

XML

Derivative Instruments

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil and natural gas prices. The Company’s crude oil and natural gas contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“WTI”) and the average NYMEX Henry Hub natural gas index price (“Henry Hub”), respectively. At March 31, 2017, the Company utilized swaps and two-way and three-way costless collar options to reduce the volatility of oil and natural gas prices on a significant portion of its future expected oil and natural gas production. A swap is a sold call and a purchased put established at the same price (both ceiling and floor). A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract.

All derivative instruments are recorded on the Company’s Condensed Consolidated Balance Sheet as either assets or liabilities measured at fair value (see Note 4 – Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the Company’s Condensed Consolidated Statement of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Condensed Consolidated Statement of Cash Flows.

At March 31, 2017, the Company had the following outstanding commodity derivative instruments:

Commodity	Settlement Period	Derivative Instrument	Volumes		Weighted Average Prices								Fair Value Asset (Liability)
					Swap		Sub-Floor		Floor		Ceiling
													(In thousands)
Crude oil	2017	Swaps	5,225,000	Bbl	$	49.60							$	(9,309	)
Crude oil	2017	Two-way collar	2,200,000	Bbl					$	46.25	$	54.37	(1,707		)
Crude oil	2017	Three-way collar	1,650,000	Bbl			$	31.67	$	45.83	$	59.94	562
Crude oil	2018	Swaps	2,440,000	Bbl	$	52.93							2,375
Crude oil	2018	Two-way collar	582,000	Bbl					$	48.40	$	55.13	28
Crude oil	2018	Three-way collar	186,000	Bbl			$	31.67	$	45.83	$	59.94	58
Crude oil	2019	Swaps	155,000	Bbl	$	53.88							351
Crude oil	2019	Two-way collar	31,000	Bbl					$	50.00	$	55.70	32
Natural gas	2017	Swaps	4,675,000	MMBtu	$	3.30							(55		)
Natural gas	2018	Swaps	3,650,000	MMBtu	$	3.00							(121		)
													$	(7,786	)

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

	Three Months Ended March 31,
Statement of Operations Location	2017		2016
	(In thousands)
Net gain on derivative instruments	$	56,075	$	14,375

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Condensed Consolidated Balance Sheet.

The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheet:

		March 31, 2017
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	5,178	$	(2,152	)	$	3,026
Commodity contracts	Derivative instruments — non-current assets	5,148		(1,333		)	3,815
Total derivatives assets		$	10,326	$	(3,485	)	$	6,841
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	21,480	$	(6,853	)	$	14,627
Total derivatives liabilities		$	21,480	$	(6,853	)	$	14,627
		December 31, 2016
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	482	$	(120	)	$	362
Total derivatives assets		$	482	$	(120	)	$	362
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	66,838	$	(6,369	)	$	60,469
Commodity contracts	Derivative instruments — non-current liabilities	14,164		(2,450		)	11,714
Total derivatives liabilities		$	81,002	$	(8,819	)	$	72,183

XML

Property, Plant and Equipment

3 Months Ended

Mar. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

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

	March 31, 2017			December 31, 2016
	(In thousands)
Proved oil and gas properties(1)	$	6,570,588		$	6,476,833
Less: accumulated depreciation, depletion, amortization and impairment	(2,009,356		)	(1,886,732		)
Proved oil and gas properties, net	4,561,232			4,590,101
Unproved oil and gas properties	819,711			819,735
Other property and equipment	632,318			618,790
Less: accumulated depreciation	(116,780		)	(109,059		)
Other property and equipment, net	515,538			509,731
Total property, plant and equipment, net	$	5,896,481		$	5,919,567

__________________

(1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $43.0 millionand $42.9 million at March 31, 2017 and December 31, 2016, respectively.

XML

Long-Term Debt

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

The Company’s long-term debt consists of the following:

	March 31, 2017			December 31, 2016
	(In thousands)
Senior secured revolving line of credit	$	368,000		$	363,000
Senior unsecured notes
7.25% senior unsecured notes due February 1, 2019	54,275			54,275
6.5% senior unsecured notes due November 1, 2021	395,501			395,501
6.875% senior unsecured notes due March 15, 2022	937,080			937,080
6.875% senior unsecured notes due January 15, 2023	366,094			366,094
2.625% senior unsecured convertible notes due September 15, 2023	300,000			300,000
Total principal of senior unsecured notes	2,052,950			2,052,950
Less: unamortized deferred financing costs on senior unsecured notes	(26,958		)	(28,268		)
Less: unamortized debt discount on senior unsecured convertible notes	(88,113		)	(90,468		)
Total long-term debt	$	2,305,879		$	2,297,214

The carrying amount of the Company’s long-term debt reported in the Condensed Consolidated Balance Sheet at March 31, 2017 was $2,305.9 million, which included $2,053.0 million of senior unsecured notes, a reduction for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and a reduction for the unamortized deferred financing costs on the senior unsecured notes of $88.1 million and $27.0 million, respectively, and $368.0 million of borrowings under the revolving credit facility. The Company’s revolving credit facility is recorded at a value that approximates its fair value since its variable interest rate is tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $2,187.1 million at March 31, 2017.

Senior secured revolving line of credit. The Company has a senior secured revolving line of credit (the “Credit Facility”) of $2,500.0 million as of March 31, 2017, which has a maturity date of April 13, 2020, provided that the 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”), of which $54.3 million is outstanding, are retired or refinanced 90 days prior to their maturity. The Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year.

As of March 31, 2017, the Company had $368.0 million of LIBOR loans and $10.0 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base committed capacity of $772.0 million. The weighted average interest rate on borrowings outstanding under the Credit Facility was 2.5% as of March 31, 2017. On a quarterly basis, the Company also pays a 0.375% (as of March 31, 2017) annualized commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

The Company was in compliance with the financial covenants of the Credit Facility as of March 31, 2017.

Senior unsecured notes. At March 31, 2017, the Company had $1,753.0 million principal amount of senior unsecured notes outstanding with maturities ranging from February 2019 to January 2023 and coupons ranging from 6.50% to 7.25% (the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The 2019 Notes are currently redeemable for cash at a redemption price equal to par. The Company estimates that the fair value of these redemption options is immaterial at March 31, 2017 and December 31, 2016.

Senior unsecured convertible notes. In September 2016, the Company issued $300.0 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of March 31, 2017, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met.

Upon issuance, the Company separately accounted for the liability and equity components of the Senior Convertible Notes in accordance with Accounting Standards Codification 470-20. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Senior Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 8.97% per annum. The fair value of the Senior Convertible Notes as of the issuance date was estimated at $206.8 million, resulting in a debt discount at inception of $93.2 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Senior Convertible Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital and will not be remeasured as long as it continues to meet the conditions for equity classification. 

Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default as well as covenants that place restrictions on the Company and certain of its subsidiaries.

XML

Asset Retirement Obligations

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the three months ended March 31, 2017:

	(In thousands)
Balance at December 31, 2016	$	49,687
Liabilities incurred during period	351
Liabilities settled during period	(89		)
Accretion expense during period(1)	655
Revisions to estimates	(215		)
Balance at March 31, 2017	$	50,389

___________________

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

At March 31, 2017, the current portion of the total ARO balance was approximately $0.3 million and was included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

XML

Income Taxes

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company’s effective tax rate for the three months ended March 31, 2017 and 2016 was 40.2% and 30.0%, respectively. The effective tax rate for the three months ended March 31, 2017 was higher than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the impact of permanent differences on pre-tax income for the period, while the effective tax rate for the three months ended March 31, 2016 was lower than the combined federal statutory rate and the statutory rates for the states in which the Company conducts business due to the impact of permanent differences on pre-tax loss for the period. During both the three months ended March 31, 2017 and 2016, the permanent differences were primarily between amounts expensed for book purposes versus the amounts deductible for income tax purposes related to compensation, including stock-based compensation vesting at different prices than the grant date values.

XML

Stock-Based Compensation

3 Months Ended

Mar. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

Stock-Based Compensation

Restricted stock awards.The Company has granted restricted stock awards to employees and directors under its Amended and Restated 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 closing sales price of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.

During the three months ended March 31, 2017, employees and non-employee directors of the Company were granted restricted stock awards equal to 1,551,560 shares of common stock with a $15.35 weighted average grant date per share value. Stock-based compensation expense recorded for restricted stock awards for the three months ended March 31, 2017 and 2016 was $5.4 million and $5.8 million, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statement of Operations.

Performance share units. The Company has granted performance share units (“PSUs”) to officers of the Company under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units, and each PSU that is earned represents the right to receive one share of the Company’s common stock.

During the three months ended March 31, 2017, officers of the Company were granted 509,800 PSUs with a $16.89 weighted average grant date per share value. Stock-based compensation expense recorded for PSUs for the three months ended March 31, 2017 and 2016 was $1.3 million and $0.9 million, respectively. Stock-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statement of Operations.

The Company accounted for these PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 200% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.

The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility was calculated from the daily historical returns of 30-day volume weighted average stock prices over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the PSUs granted during the three months ended March 31, 2017:

Risk-free interest rate	1.18% - 1.66%
Oasis volatility	17.16	%

XML

Earnings (Loss) Per Share

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Earnings (Loss) Per Share

Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable 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, PSUs outstanding, and contingently issuable shares of convertible notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to the income (loss) available to common stockholders in the calculation of diluted earnings (loss) per share.

The following is a calculation of the basic and diluted weighted average shares outstanding for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017	2016
	(In thousands)
Basic weighted average common shares outstanding	233,068	162,922
Dilution effect of stock awards at end of period	3,238	—
Dilution effect of senior convertible notes at end of period(1)	1,594	—
Diluted weighted average common shares outstanding	237,900	162,922

__________________ 

(1) The Company issued its Senior Convertible Notes in September 2016 (see Note 7 – Long-Term Debt).

The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect:

	Three Months Ended March 31,
	2017	2016
	(In thousands)
Anti-dilutive effect of stock awards excluded from diluted earnings (loss) per share due to net loss	—	4,668
Anti-dilutive effect of stock awards excluded from diluted earnings (loss) per share calculated using the treasury stock method	2,884	—

XML

Business Segment Information

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Business Segment Information

Business Segment Information

The Company’s exploration and production segment is engaged in the acquisition and development of oil and natural gas properties. Revenues for the exploration and production segment are derived from the sale of oil and natural gas production. The Company’s midstream services business segment (OMS) performs salt water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the midstream segment are primarily derived from salt water pipeline transport, salt water disposal, fresh water sales, natural gas gathering and processing and crude oil gathering, blending, stabilization and transportation. The Company’s well services business segment (OWS) performs completion services for the Company’s oil and natural gas wells operated by OPNA. Revenues for the well services segment are derived from providing well services, product sales and equipment rentals. The revenues and expenses related to work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated working interest owners are included in the Company’s Condensed Consolidated Statement of Operations. These segments represent the Company’s three operating units, each offering different products and services. The Company’s corporate activities have been allocated to the supported business segments accordingly.

Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses, including depreciation, depletion and amortization. The following table summarizes financial information for the Company’s three business segments for the periods presented:

	Exploration and Production			Midstream Services			Well Services			Eliminations			Consolidated
	(In thousands)
Three months ended March 31, 2017:
Revenues from non-affiliates	$	264,883		$	14,606		$	5,627		$	—		$	285,116
Inter-segment revenues	—			23,035			15,352			(38,387		)	—
Total revenues	264,883			37,641			20,979			(38,387		)	285,116
Operating income (loss)	968			20,763			(3,592		)	1,953			20,092
Other income (expense)	19,768			(2		)	4			—			19,770
Income (loss) before income taxes	$	20,736		$	20,761		$	(3,588	)	$	1,953		$	39,862
Three months ended March 31, 2016:
Revenues from non-affiliates	$	117,315		$	6,983		$	5,985		$	—		$	130,283
Inter-segment revenues	—			22,835			24,903			(47,738		)	—
Total revenues	117,315			29,818			30,888			(47,738		)	130,283
Operating income (loss)	(88,877		)	15,144			4,006			(5,488		)	(75,215		)
Other income (expense)	(16,887		)	13			5			—			(16,869		)
Income (loss) before income taxes	$	(105,764	)	$	15,157		$	4,011		$	(5,488	)	$	(92,084	)
At March 31, 2017:
Property, plant and equipment, net	$	5,589,014		$	433,867		$	44,025		$	(170,425	)	$	5,896,481
Total assets(1)	5,871,573			440,548			47,932			(170,425		)	6,189,628
At December 31, 2016:
Property, plant and equipment, net	$	5,620,558		$	424,197		$	47,189		$	(172,377	)	$	5,919,567
Total assets(1)	5,868,747			431,095			51,167			(172,377		)	6,178,632

___________________

(1) Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

XML

Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

The Company has various contractual obligations in the normal course of its operations. As of March 31, 2017, there have been no material changes to the Company’s future commitments described under “Lease obligations” and “Volume commitment agreements” as disclosed in Note 16 in the Company’s 2016 Annual Report.

Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

Mirada litigation.On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) by overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”

The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to the Company. The Company filed an answer denying Mirada’s claims on April 21, 2017, and intends to vigorously defend against Mirada’s claims. Discovery is ongoing. Trial is currently scheduled for July 2018. However, the Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, results of operations and financial condition. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin.

XML

Condensed Consolidating Financial Information

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Consolidating Financial Information

Condensed Consolidating Financial Information

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

The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), and its Guarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors.

Condensed Consolidating Balance Sheet

	March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	177		$	13,608		$	—		$	13,785
Accounts receivable, net	—			226,427			—			226,427
Accounts receivable – affiliates	200,770			33,093			(233,863		)	—
Inventory	—			14,327			—			14,327
Prepaid expenses	334			6,842			—			7,176
Derivative instruments	—			3,026			—			3,026
Other current assets	2			4,450			—			4,452
Total current assets	201,283			301,773			(233,863		)	269,193
Property, plant and equipment
Oil and gas properties (successful efforts method)	—			7,390,299			—			7,390,299
Other property and equipment	—			632,318			—			632,318
Less: accumulated depreciation, depletion, amortization and impairment	—			(2,126,136		)	—			(2,126,136		)
Total property, plant and equipment, net	—			5,896,481			—			5,896,481
Investments in and advances to subsidiaries	4,503,650			—			(4,503,650		)	—
Derivative instruments	—			3,815			—			3,815
Deferred income taxes	239,419			—			(239,419		)	—
Other assets	—			20,139			—			20,139
Total assets	$	4,944,352		$	6,222,208		$	(4,976,932	)	$	6,189,628
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	—		$	8,837		$	—		$	8,837
Accounts payable – affiliates	33,093			200,770			(233,863		)	—
Revenues and production taxes payable	—			160,265			—			160,265
Accrued liabilities	34			128,207			—			128,241
Accrued interest payable	19,872			396			—			20,268
Derivative instruments	—			14,627			—			14,627
Advances from joint interest partners	—			6,838			—			6,838
Other current liabilities	—			13,435			—			13,435
Total current liabilities	52,999			533,375			(233,863		)	352,511
Long-term debt	1,937,879			368,000			—			2,305,879
Deferred income taxes	—			764,261			(239,419		)	524,842
Asset retirement obligations	—			50,088			—			50,088
Other liabilities	—			2,834			—			2,834
Total liabilities	1,990,878			1,718,558			(473,282		)	3,236,154
Stockholders’ equity
Capital contributions from affiliates	—			3,392,248			(3,392,248		)	—
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding	2,344			—			—			2,344
Treasury stock, at cost: 1,229,568 shares	(21,369		)	—			—			(21,369		)
Additional paid-in-capital	2,354,485			8,743			(8,743		)	2,354,485
Retained earnings	618,014			1,102,659			(1,102,659		)	618,014
Total stockholders’ equity	2,953,474			4,503,650			(4,503,650		)	2,953,474
Total liabilities and stockholders’ equity	$	4,944,352		$	6,222,208		$	(4,976,932	)	$	6,189,628

Condensed Consolidating Balance Sheet

	December 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	166		$	11,060		$	—		$	11,226
Accounts receivable, net	—			204,335			—			204,335
Accounts receivable – affiliates	252,000			27,619			(279,619		)	—
Inventory	—			10,648			—			10,648
Prepaid expenses	275			7,348			—			7,623
Derivative instruments	—			362			—			362
Other current assets	—			4,355			—			4,355
Total current assets	252,441			265,727			(279,619		)	238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)	—			7,296,568			—			7,296,568
Other property and equipment	—			618,790			—			618,790
Less: accumulated depreciation, depletion, amortization and impairment	—			(1,995,791		)	—			(1,995,791		)
Total property, plant and equipment, net	—			5,919,567			—			5,919,567
Investments in and advances to subsidiaries	4,451,192			—			(4,451,192		)	—
Deferred income taxes	220,058			—			(220,058		)	—
Other assets	—			20,516			—			20,516
Total assets	$	4,923,691		$	6,205,810		$	(4,950,869	)	$	6,178,632
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	—		$	4,645		$	—		$	4,645
Accounts payable – affiliates	27,619			252,000			(279,619		)	—
Revenue and production taxes payable	—			139,737			—			139,737
Accrued liabilities	12			119,161			—			119,173
Accrued interest payable	38,689			315			—			39,004
Derivative instruments	—			60,469			—			60,469
Advances from joint interest partners	—			7,597			—			7,597
Other current liabilities	—			10,490			—			10,490
Total current liabilities	66,320			594,414			(279,619		)	381,115
Long-term debt	1,934,214			363,000			—			2,297,214
Deferred income taxes	—			733,587			(220,058		)	513,529
Asset retirement obligations	—			48,985			—			48,985
Derivative instruments	—			11,714			—			11,714
Other liabilities	—			2,918			—			2,918
Total liabilities	2,000,534			1,754,618			(499,677		)	3,255,475
Stockholders’ equity
Capital contributions from affiliates	—			3,388,893			(3,388,893		)	—
Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding	2,331			—			—			2,331
Treasury stock, at cost: 856,892 shares	(15,950		)	—			—			(15,950		)
Additional paid-in-capital	2,345,271			8,743			(8,743		)	2,345,271
Retained earnings	591,505			1,053,556			(1,053,556		)	591,505
Total stockholders’ equity	2,923,157			4,451,192			(4,451,192		)	2,923,157
Total liabilities and stockholders’ equity	$	4,923,691		$	6,205,810		$	(4,950,869	)	$	6,178,632

Condensed Consolidating Statement of Operations

	Three Months Ended March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Revenues
Oil and gas revenues	$	—		$	237,252		$	—		$	237,252
Bulk oil sales	—			27,631			—			27,631
Midstream revenues	—			14,606			—			14,606
Well services revenues	—			5,627			—			5,627
Total revenues	—			285,116			—			285,116
Operating expenses
Lease operating expenses	—			43,872			—			43,872
Midstream operating expenses	—			3,327			—			3,327
Well services operating expenses	—			3,902			—			3,902
Marketing, transportation and gathering expenses	—			10,951			—			10,951
Bulk oil purchases	—			28,002			—			28,002
Production taxes	—			20,299			—			20,299
Depreciation, depletion and amortization	—			126,666			—			126,666
Exploration expenses	—			1,489			—			1,489
Impairment	—			2,682			—			2,682
General and administrative expenses	7,065			16,769			—			23,834
Total operating expenses	7,065			257,959			—			265,024
Operating income (loss)	(7,065		)	27,157			—			20,092
Other income (expense)
Equity in earnings of subsidiaries	49,103			—			(49,103		)	—
Net gain on derivative instruments	—			56,075			—			56,075
Interest expense, net of capitalized interest	(32,851		)	(3,470		)	—			(36,321		)
Other income	—			16			—			16
Total other income (expense)	16,252			52,621			(49,103		)	19,770
Income before income taxes	9,187			79,778			(49,103		)	39,862
Income tax benefit (expense)	14,638			(30,675		)	—			(16,037		)
Net income	$	23,825		$	49,103		$	(49,103	)	$	23,825

Condensed Consolidating Statement of Operations

	Three Months Ended March 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(In thousands)
Revenues
Oil and gas revenues	$	—		$	117,315		$	—	$	117,315
Midstream revenues	—			6,983			—		6,983
Well services revenues	—			5,985			—		5,985
Total revenues	—			130,283			—		130,283
Operating expenses
Lease operating expenses	—			31,064			—		31,064
Midstream operating expenses	—			1,738			—		1,738
Well services operating expenses	—			2,651			—		2,651
Marketing, transportation and gathering expenses	—			8,552			—		8,552
Production taxes	—			10,753			—		10,753
Depreciation, depletion and amortization	—			122,449			—		122,449
Exploration expenses	—			363			—		363
Impairment	—			3,562			—		3,562
General and administrative expenses	7,451			16,915			—		24,366
Total operating expenses	7,451			198,047			—		205,498
Operating loss	(7,451		)	(67,764		)	—		(75,215		)
Other income (expense)
Equity in loss of subsidiaries	(37,327		)	—			37,327		—
Net gain on derivative instruments	—			14,375			—		14,375
Interest expense, net of capitalized interest	(34,832		)	(3,907		)	—		(38,739		)
Gain on extinguishment of debt	7,016			—			—		7,016
Other income	43			436			—		479
Total other income (expense)	(65,100		)	10,904			37,327		(16,869		)
Loss before income taxes	(72,551		)	(56,860		)	37,327		(92,084		)
Income tax benefit	8,096			19,533			—		27,629
Net loss	$	(64,455	)	$	(37,327	)	$	37,327	$	(64,455	)

Condensed Consolidating Statement of Cash Flows

	Three Months Ended March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net income	$	23,825		$	49,103		$	(49,103	)	$	23,825
Adjustments to reconcile net income to cash provided by operating activities:
Equity in loss of subsidiaries	(49,103		)	—			49,103			—
Depreciation, depletion and amortization	—			126,666			—			126,666
Impairment	—			2,682			—			2,682
Deferred income taxes	(14,638		)	30,675			—			16,037
Derivative instruments	—			(56,075		)	—			(56,075		)
Stock-based compensation expenses	6,498			210			—			6,708
Deferred financing costs amortization and other	3,665			1,275			—			4,940
Working capital and other changes:
Change in accounts receivable	51,230			(27,952		)	(45,756		)	(22,478		)
Change in inventory	—			(3,679		)	—			(3,679		)
Change in prepaid expenses	(59		)	341			—			282
Change in other current assets	(2		)	(108		)	—			(110		)
Change in other assets	—			(4		)	—			(4		)
Change in accounts payable, interest payable and accrued liabilities	(13,321		)	(26,375		)	45,756			6,060
Change in other current liabilities	—			2,945			—			2,945
Net cash provided by operating activities	8,095			99,704			—			107,799
Cash flows from investing activities:
Capital expenditures	—			(96,047		)	—			(96,047		)
Derivative settlements	—			(7,960		)	—			(7,960		)
Advances from joint interest partners	—			(759		)	—			(759		)
Net cash used in investing activities	—			(104,766		)	—			(104,766		)
Cash flows from financing activities:
Proceeds from revolving credit facility	—			246,000			—			246,000
Principal payments on revolving credit facility	—			(241,000		)	—			(241,000		)
Purchases of treasury stock	(5,419		)	—			—			(5,419		)
Investment in / capital contributions from subsidiaries	(2,610		)	2,610			—			—
Other	(55		)	—			—			(55		)
Net cash provided by (used in) financing activities	(8,084		)	7,610			—			(474		)
Increase in cash and cash equivalents	11			2,548			—			2,559
Cash and cash equivalents at beginning of period	166			11,060			—			11,226
Cash and cash equivalents at end of period	$	177		$	13,608		$	—		$	13,785

Condensed Consolidating Statement of Cash Flows

	Three Months Ended March 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net loss	$	(64,455	)	$	(37,327	)	$	37,327		$	(64,455	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	37,327			—			(37,327		)	—
Depreciation, depletion and amortization	—			122,449			—			122,449
Gain on extinguishment of debt	(7,016		)	—			—			(7,016		)
Impairment	—			3,562			—			3,562
Deferred income taxes	(8,096		)	(19,533		)	—			(27,629		)
Derivative instruments	—			(14,375		)	—			(14,375		)
Stock-based compensation expenses	6,547			183			—			6,730
Deferred financing costs amortization and other	1,701			3,365			—			5,066
Working capital and other changes:
Change in accounts receivable	(85		)	96,353			(97,263		)	(995		)
Change in inventory	—			349			—			349
Change in prepaid expenses	139			102			—			241
Change in other current assets	—			4			—			4
Change in other assets	77			—			—			77
Change in accounts payable, interest payable and accrued liabilities	(122,242		)	(39,077		)	97,263			(64,056		)
Change in other current liabilities	—			(6,000		)	—			(6,000		)
Change in other liabilities	—			(3		)	—			(3		)
Net cash provided by (used in) operating activities	(156,103		)	110,052			—			(46,051		)
Cash flows from investing activities:
Capital expenditures	—			(103,411		)	—			(103,411		)
Derivative settlements	—			73,313			—			73,313
Advances from joint interest partners	—			(257		)	—			(257		)
Net cash used in investing activities	—			(30,355		)	—			(30,355		)
Cash flows from financing activities:
Proceeds from revolving credit facility	—			214,000			—			214,000
Principal payments on revolving credit facility	—			(287,000		)	—			(287,000		)
Repurchase of senior unsecured notes	(22,308		)	—			—			(22,308		)
Deferred financing costs	—			(751		)	—			(751		)
Proceeds from sale of common stock	183,164			—			—			183,164
Purchases of treasury stock	(1,032		)	—			—			(1,032		)
Investment in / capital contributions from subsidiaries	(4,408		)	4,408			—			—
Net cash provided by (used in) financing activities	155,416			(69,343		)	—			86,073
Increase (decrease) in cash and cash equivalents	(687		)	10,354			—			9,667
Cash and cash equivalents at beginning of period	777			8,953			—			9,730
Cash and cash equivalents at end of period	$	90		$	19,307		$	—		$	19,397

XML

Subsequent Events

3 Months Ended

Mar. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

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

Derivative instruments.In April 2017, the Company entered into a new swap for crude oil with a weighted average price of $54.12 per barrel. The commodity contract included a total notional amount of 668,000 barrels and 62,000 barrels, which settle based on WTI in 2018 and 2019, respectively. This derivative instrument does not qualify for and was not designated as a hedging instrument for accounting purposes.

Credit facility.On April 10, 2017, the Company entered into an amendment to its Credit Facility in connection with the scheduled redetermination of the Company’s borrowing base. Following the redetermination, the borrowing base was increased to $1,600.0 million from $1,150.0 million; however, the Company did not increase the elected commitments above the current amount of $1,150.0 million. The next redetermination of the Company’s borrowing base is scheduled for October 1, 2017.

XML

Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The accompanying condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2016 is derived from audited financial statements. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement, have been included. Management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”).

Risks and Uncertainties

Risks and Uncertainties

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

Recent Accounting Pronouncements

Stock-based compensation. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which updates several aspects of the accounting for share-based payment transactions, including recognition of excess tax benefits and deficiencies, the classification of those excess tax benefits on the statement of cash flows, an accounting policy election for forfeitures, the amount an employer can withhold to cover income taxes and still qualify for equity classification and the classification of those taxes paid on the statement of cash flows. In accordance with the new guidance, the Company recorded a $2.7 million cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet as of March 31, 2017, which included recognition of excess tax benefits and deficiencies and the removal of the estimated forfeiture rate. ASU 2016-09 was applied on a modified retrospective basis and prior periods were not retrospectively adjusted.

Inventory. In the first quarter of 2017, the Company adopted Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), which changes the inventory measurement principle from lower of cost or market to lower of cost and net realizable value for entities using the first-in, first-out or average cost methods. ASU 2015-11 was applied on a prospective basis and prior periods were not retrospectively adjusted. There was no material impact as a result of adoption as of March 31, 2017.

Recent Accounting Pronouncements

Revenue recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model to recognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issued Accounting Standards Update No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 defers the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Financial instruments. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”), which requires that most equity instruments be measured at fair value with subsequent changes in fair value recognized in net income. ASU 2016-01 also impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. ASU 2016-01 does not apply to equity method investments or investments in consolidated subsidiaries. ASU 2016-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”), which requires a lessee to recognize lease payment obligations and a corresponding right-of-use asset to be measured at fair value on the balance sheet. ASU 2016-02 also requires certain qualitative and quantitative disclosures about the amount, timing and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Statement of cash flows. In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations, but could result in presentation changes on the Company’s statement of cash flows.

Business combinations. In January 2017, the FASB issued Accounting Standards Update No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

XML

Inventory (Tables)

3 Months Ended

Mar. 31, 2017

Inventory Disclosure [Abstract]

Components of Inventory

Inventory is stated at the lower of cost and net realizable value with cost determined on an average cost method. Inventory consists of the following:

	March 31, 2017		December 31, 2016
	(In thousands)
Crude oil inventory	$	10,302	$	7,086
Equipment and materials	4,025		3,562
Total inventory	$	14,327	$	10,648

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Hierarchy of Fair Value, Assets and Liabilities Measured on Recurring Basis

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:

	Fair value at March 31, 2017
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	141	$	—	$	—	$	141
Commodity derivative instruments (see Note 5)	—		6,841		—		6,841
Total assets	$	141	$	6,841	$	—	$	6,982
Liabilities:
Commodity derivative instruments (see Note 5)	$	—	$	14,627	$	—	$	14,627
Total liabilities	$	—	$	14,627	$	—	$	14,627

	Fair value at December 31, 2016
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Money market funds	$	141	$	—	$	—	$	141
Commodity derivative instruments (see Note 5)	—		362		—		362
Total assets	$	141	$	362	$	—	$	503
Liabilities:
Commodity derivative instruments (see Note 5)	$	—	$	72,183	$	—	$	72,183
Total liabilities	$	—	$	72,183	$	—	$	72,183

XML

Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Outstanding Commodity Derivative Instruments

At March 31, 2017, the Company had the following outstanding commodity derivative instruments:

Commodity	Settlement Period	Derivative Instrument	Volumes		Weighted Average Prices								Fair Value Asset (Liability)
					Swap		Sub-Floor		Floor		Ceiling
													(In thousands)
Crude oil	2017	Swaps	5,225,000	Bbl	$	49.60							$	(9,309	)
Crude oil	2017	Two-way collar	2,200,000	Bbl					$	46.25	$	54.37	(1,707		)
Crude oil	2017	Three-way collar	1,650,000	Bbl			$	31.67	$	45.83	$	59.94	562
Crude oil	2018	Swaps	2,440,000	Bbl	$	52.93							2,375
Crude oil	2018	Two-way collar	582,000	Bbl					$	48.40	$	55.13	28
Crude oil	2018	Three-way collar	186,000	Bbl			$	31.67	$	45.83	$	59.94	58
Crude oil	2019	Swaps	155,000	Bbl	$	53.88							351
Crude oil	2019	Two-way collar	31,000	Bbl					$	50.00	$	55.70	32
Natural gas	2017	Swaps	4,675,000	MMBtu	$	3.30							(55		)
Natural gas	2018	Swaps	3,650,000	MMBtu	$	3.00							(121		)
													$	(7,786	)

Gains and Losses from Commodity Derivative Instruments

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

	Three Months Ended March 31,
Statement of Operations Location	2017		2016
	(In thousands)
Net gain on derivative instruments	$	56,075	$	14,375

Summary of Gross and Net Information about Commodity Derivative Assets

The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheet:

		March 31, 2017
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	5,178	$	(2,152	)	$	3,026
Commodity contracts	Derivative instruments — non-current assets	5,148		(1,333		)	3,815
Total derivatives assets		$	10,326	$	(3,485	)	$	6,841
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	21,480	$	(6,853	)	$	14,627
Total derivatives liabilities		$	21,480	$	(6,853	)	$	14,627
		December 31, 2016
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	482	$	(120	)	$	362
Total derivatives assets		$	482	$	(120	)	$	362
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	66,838	$	(6,369	)	$	60,469
Commodity contracts	Derivative instruments — non-current liabilities	14,164		(2,450		)	11,714
Total derivatives liabilities		$	81,002	$	(8,819	)	$	72,183

Summary of Gross and Net Information about Commodity Derivative Liabilities

The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheet:

		March 31, 2017
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	5,178	$	(2,152	)	$	3,026
Commodity contracts	Derivative instruments — non-current assets	5,148		(1,333		)	3,815
Total derivatives assets		$	10,326	$	(3,485	)	$	6,841
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	21,480	$	(6,853	)	$	14,627
Total derivatives liabilities		$	21,480	$	(6,853	)	$	14,627
		December 31, 2016
Commodity	Balance Sheet Location	Gross Recognized Asset/Liabilities		Gross Amount Offset			Net Recognized Fair Value Asset/Liability
		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	482	$	(120	)	$	362
Total derivatives assets		$	482	$	(120	)	$	362
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	66,838	$	(6,369	)	$	60,469
Commodity contracts	Derivative instruments — non-current liabilities	14,164		(2,450		)	11,714
Total derivatives liabilities		$	81,002	$	(8,819	)	$	72,183

XML

Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2017

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

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

	March 31, 2017			December 31, 2016
	(In thousands)
Proved oil and gas properties(1)	$	6,570,588		$	6,476,833
Less: accumulated depreciation, depletion, amortization and impairment	(2,009,356		)	(1,886,732		)
Proved oil and gas properties, net	4,561,232			4,590,101
Unproved oil and gas properties	819,711			819,735
Other property and equipment	632,318			618,790
Less: accumulated depreciation	(116,780		)	(109,059		)
Other property and equipment, net	515,538			509,731
Total property, plant and equipment, net	$	5,896,481		$	5,919,567

__________________

(1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $43.0 millionand $42.9 million at March 31, 2017 and December 31, 2016, respectively.

XML

Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

The Company’s long-term debt consists of the following:

	March 31, 2017			December 31, 2016
	(In thousands)
Senior secured revolving line of credit	$	368,000		$	363,000
Senior unsecured notes
7.25% senior unsecured notes due February 1, 2019	54,275			54,275
6.5% senior unsecured notes due November 1, 2021	395,501			395,501
6.875% senior unsecured notes due March 15, 2022	937,080			937,080
6.875% senior unsecured notes due January 15, 2023	366,094			366,094
2.625% senior unsecured convertible notes due September 15, 2023	300,000			300,000
Total principal of senior unsecured notes	2,052,950			2,052,950
Less: unamortized deferred financing costs on senior unsecured notes	(26,958		)	(28,268		)
Less: unamortized debt discount on senior unsecured convertible notes	(88,113		)	(90,468		)
Total long-term debt	$	2,305,879		$	2,297,214

XML

Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes in Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the three months ended March 31, 2017:

	(In thousands)
Balance at December 31, 2016	$	49,687
Liabilities incurred during period	351
Liabilities settled during period	(89		)
Accretion expense during period(1)	655
Revisions to estimates	(215		)
Balance at March 31, 2017	$	50,389

___________________

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

XML

Stock-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Stock Based Compensation Assumptions

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the PSUs granted during the three months ended March 31, 2017:

Risk-free interest rate	1.18% - 1.66%
Oasis volatility	17.16	%

XML

Earnings (Loss) Per Share (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Share [Abstract]

Schedule of Weighted-Average Number of Shares Outstanding

The following is a calculation of the basic and diluted weighted average shares outstanding for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017	2016
	(In thousands)
Basic weighted average common shares outstanding	233,068	162,922
Dilution effect of stock awards at end of period	3,238	—
Dilution effect of senior convertible notes at end of period(1)	1,594	—
Diluted weighted average common shares outstanding	237,900	162,922

__________________ 

(1) The Company issued its Senior Convertible Notes in September 2016 (see Note 7 – Long-Term Debt).

Schedule of Common Shares Excluded From Diluted Earnings (Loss) per Share Calculation

The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect:

	Three Months Ended March 31,
	2017	2016
	(In thousands)
Anti-dilutive effect of stock awards excluded from diluted earnings (loss) per share due to net loss	—	4,668
Anti-dilutive effect of stock awards excluded from diluted earnings (loss) per share calculated using the treasury stock method	2,884	—

XML

Business Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Summarized Financial Information of Segments

The following table summarizes financial information for the Company’s three business segments for the periods presented:

	Exploration and Production			Midstream Services			Well Services			Eliminations			Consolidated
	(In thousands)
Three months ended March 31, 2017:
Revenues from non-affiliates	$	264,883		$	14,606		$	5,627		$	—		$	285,116
Inter-segment revenues	—			23,035			15,352			(38,387		)	—
Total revenues	264,883			37,641			20,979			(38,387		)	285,116
Operating income (loss)	968			20,763			(3,592		)	1,953			20,092
Other income (expense)	19,768			(2		)	4			—			19,770
Income (loss) before income taxes	$	20,736		$	20,761		$	(3,588	)	$	1,953		$	39,862
Three months ended March 31, 2016:
Revenues from non-affiliates	$	117,315		$	6,983		$	5,985		$	—		$	130,283
Inter-segment revenues	—			22,835			24,903			(47,738		)	—
Total revenues	117,315			29,818			30,888			(47,738		)	130,283
Operating income (loss)	(88,877		)	15,144			4,006			(5,488		)	(75,215		)
Other income (expense)	(16,887		)	13			5			—			(16,869		)
Income (loss) before income taxes	$	(105,764	)	$	15,157		$	4,011		$	(5,488	)	$	(92,084	)
At March 31, 2017:
Property, plant and equipment, net	$	5,589,014		$	433,867		$	44,025		$	(170,425	)	$	5,896,481
Total assets(1)	5,871,573			440,548			47,932			(170,425		)	6,189,628
At December 31, 2016:
Property, plant and equipment, net	$	5,620,558		$	424,197		$	47,189		$	(172,377	)	$	5,919,567
Total assets(1)	5,868,747			431,095			51,167			(172,377		)	6,178,632

___________________

(1) Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

XML

Condensed Consolidating Financial Information (Tables)

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Consolidating Balance Sheet

Condensed Consolidating Balance Sheet

	March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	177		$	13,608		$	—		$	13,785
Accounts receivable, net	—			226,427			—			226,427
Accounts receivable – affiliates	200,770			33,093			(233,863		)	—
Inventory	—			14,327			—			14,327
Prepaid expenses	334			6,842			—			7,176
Derivative instruments	—			3,026			—			3,026
Other current assets	2			4,450			—			4,452
Total current assets	201,283			301,773			(233,863		)	269,193
Property, plant and equipment
Oil and gas properties (successful efforts method)	—			7,390,299			—			7,390,299
Other property and equipment	—			632,318			—			632,318
Less: accumulated depreciation, depletion, amortization and impairment	—			(2,126,136		)	—			(2,126,136		)
Total property, plant and equipment, net	—			5,896,481			—			5,896,481
Investments in and advances to subsidiaries	4,503,650			—			(4,503,650		)	—
Derivative instruments	—			3,815			—			3,815
Deferred income taxes	239,419			—			(239,419		)	—
Other assets	—			20,139			—			20,139
Total assets	$	4,944,352		$	6,222,208		$	(4,976,932	)	$	6,189,628
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	—		$	8,837		$	—		$	8,837
Accounts payable – affiliates	33,093			200,770			(233,863		)	—
Revenues and production taxes payable	—			160,265			—			160,265
Accrued liabilities	34			128,207			—			128,241
Accrued interest payable	19,872			396			—			20,268
Derivative instruments	—			14,627			—			14,627
Advances from joint interest partners	—			6,838			—			6,838
Other current liabilities	—			13,435			—			13,435
Total current liabilities	52,999			533,375			(233,863		)	352,511
Long-term debt	1,937,879			368,000			—			2,305,879
Deferred income taxes	—			764,261			(239,419		)	524,842
Asset retirement obligations	—			50,088			—			50,088
Other liabilities	—			2,834			—			2,834
Total liabilities	1,990,878			1,718,558			(473,282		)	3,236,154
Stockholders’ equity
Capital contributions from affiliates	—			3,392,248			(3,392,248		)	—
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding	2,344			—			—			2,344
Treasury stock, at cost: 1,229,568 shares	(21,369		)	—			—			(21,369		)
Additional paid-in-capital	2,354,485			8,743			(8,743		)	2,354,485
Retained earnings	618,014			1,102,659			(1,102,659		)	618,014
Total stockholders’ equity	2,953,474			4,503,650			(4,503,650		)	2,953,474
Total liabilities and stockholders’ equity	$	4,944,352		$	6,222,208		$	(4,976,932	)	$	6,189,628

Condensed Consolidating Balance Sheet

	December 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	166		$	11,060		$	—		$	11,226
Accounts receivable, net	—			204,335			—			204,335
Accounts receivable – affiliates	252,000			27,619			(279,619		)	—
Inventory	—			10,648			—			10,648
Prepaid expenses	275			7,348			—			7,623
Derivative instruments	—			362			—			362
Other current assets	—			4,355			—			4,355
Total current assets	252,441			265,727			(279,619		)	238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)	—			7,296,568			—			7,296,568
Other property and equipment	—			618,790			—			618,790
Less: accumulated depreciation, depletion, amortization and impairment	—			(1,995,791		)	—			(1,995,791		)
Total property, plant and equipment, net	—			5,919,567			—			5,919,567
Investments in and advances to subsidiaries	4,451,192			—			(4,451,192		)	—
Deferred income taxes	220,058			—			(220,058		)	—
Other assets	—			20,516			—			20,516
Total assets	$	4,923,691		$	6,205,810		$	(4,950,869	)	$	6,178,632
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	—		$	4,645		$	—		$	4,645
Accounts payable – affiliates	27,619			252,000			(279,619		)	—
Revenue and production taxes payable	—			139,737			—			139,737
Accrued liabilities	12			119,161			—			119,173
Accrued interest payable	38,689			315			—			39,004
Derivative instruments	—			60,469			—			60,469
Advances from joint interest partners	—			7,597			—			7,597
Other current liabilities	—			10,490			—			10,490
Total current liabilities	66,320			594,414			(279,619		)	381,115
Long-term debt	1,934,214			363,000			—			2,297,214
Deferred income taxes	—			733,587			(220,058		)	513,529
Asset retirement obligations	—			48,985			—			48,985
Derivative instruments	—			11,714			—			11,714
Other liabilities	—			2,918			—			2,918
Total liabilities	2,000,534			1,754,618			(499,677		)	3,255,475
Stockholders’ equity
Capital contributions from affiliates	—			3,388,893			(3,388,893		)	—
Common stock, $0.01 par value: 450,000,000 shares authorized; 237,201,064 shares issued and 236,344,172 shares outstanding	2,331			—			—			2,331
Treasury stock, at cost: 856,892 shares	(15,950		)	—			—			(15,950		)
Additional paid-in-capital	2,345,271			8,743			(8,743		)	2,345,271
Retained earnings	591,505			1,053,556			(1,053,556		)	591,505
Total stockholders’ equity	2,923,157			4,451,192			(4,451,192		)	2,923,157
Total liabilities and stockholders’ equity	$	4,923,691		$	6,205,810		$	(4,950,869	)	$	6,178,632

Condensed Consolidating Statement of Operations

Condensed Consolidating Statement of Operations

	Three Months Ended March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Revenues
Oil and gas revenues	$	—		$	237,252		$	—		$	237,252
Bulk oil sales	—			27,631			—			27,631
Midstream revenues	—			14,606			—			14,606
Well services revenues	—			5,627			—			5,627
Total revenues	—			285,116			—			285,116
Operating expenses
Lease operating expenses	—			43,872			—			43,872
Midstream operating expenses	—			3,327			—			3,327
Well services operating expenses	—			3,902			—			3,902
Marketing, transportation and gathering expenses	—			10,951			—			10,951
Bulk oil purchases	—			28,002			—			28,002
Production taxes	—			20,299			—			20,299
Depreciation, depletion and amortization	—			126,666			—			126,666
Exploration expenses	—			1,489			—			1,489
Impairment	—			2,682			—			2,682
General and administrative expenses	7,065			16,769			—			23,834
Total operating expenses	7,065			257,959			—			265,024
Operating income (loss)	(7,065		)	27,157			—			20,092
Other income (expense)
Equity in earnings of subsidiaries	49,103			—			(49,103		)	—
Net gain on derivative instruments	—			56,075			—			56,075
Interest expense, net of capitalized interest	(32,851		)	(3,470		)	—			(36,321		)
Other income	—			16			—			16
Total other income (expense)	16,252			52,621			(49,103		)	19,770
Income before income taxes	9,187			79,778			(49,103		)	39,862
Income tax benefit (expense)	14,638			(30,675		)	—			(16,037		)
Net income	$	23,825		$	49,103		$	(49,103	)	$	23,825

Condensed Consolidating Statement of Operations

	Three Months Ended March 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(In thousands)
Revenues
Oil and gas revenues	$	—		$	117,315		$	—	$	117,315
Midstream revenues	—			6,983			—		6,983
Well services revenues	—			5,985			—		5,985
Total revenues	—			130,283			—		130,283
Operating expenses
Lease operating expenses	—			31,064			—		31,064
Midstream operating expenses	—			1,738			—		1,738
Well services operating expenses	—			2,651			—		2,651
Marketing, transportation and gathering expenses	—			8,552			—		8,552
Production taxes	—			10,753			—		10,753
Depreciation, depletion and amortization	—			122,449			—		122,449
Exploration expenses	—			363			—		363
Impairment	—			3,562			—		3,562
General and administrative expenses	7,451			16,915			—		24,366
Total operating expenses	7,451			198,047			—		205,498
Operating loss	(7,451		)	(67,764		)	—		(75,215		)
Other income (expense)
Equity in loss of subsidiaries	(37,327		)	—			37,327		—
Net gain on derivative instruments	—			14,375			—		14,375
Interest expense, net of capitalized interest	(34,832		)	(3,907		)	—		(38,739		)
Gain on extinguishment of debt	7,016			—			—		7,016
Other income	43			436			—		479
Total other income (expense)	(65,100		)	10,904			37,327		(16,869		)
Loss before income taxes	(72,551		)	(56,860		)	37,327		(92,084		)
Income tax benefit	8,096			19,533			—		27,629
Net loss	$	(64,455	)	$	(37,327	)	$	37,327	$	(64,455	)

Condensed Consolidating Statement of Cash Flows

Condensed Consolidating Statement of Cash Flows

	Three Months Ended March 31, 2017
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net income	$	23,825		$	49,103		$	(49,103	)	$	23,825
Adjustments to reconcile net income to cash provided by operating activities:
Equity in loss of subsidiaries	(49,103		)	—			49,103			—
Depreciation, depletion and amortization	—			126,666			—			126,666
Impairment	—			2,682			—			2,682
Deferred income taxes	(14,638		)	30,675			—			16,037
Derivative instruments	—			(56,075		)	—			(56,075		)
Stock-based compensation expenses	6,498			210			—			6,708
Deferred financing costs amortization and other	3,665			1,275			—			4,940
Working capital and other changes:
Change in accounts receivable	51,230			(27,952		)	(45,756		)	(22,478		)
Change in inventory	—			(3,679		)	—			(3,679		)
Change in prepaid expenses	(59		)	341			—			282
Change in other current assets	(2		)	(108		)	—			(110		)
Change in other assets	—			(4		)	—			(4		)
Change in accounts payable, interest payable and accrued liabilities	(13,321		)	(26,375		)	45,756			6,060
Change in other current liabilities	—			2,945			—			2,945
Net cash provided by operating activities	8,095			99,704			—			107,799
Cash flows from investing activities:
Capital expenditures	—			(96,047		)	—			(96,047		)
Derivative settlements	—			(7,960		)	—			(7,960		)
Advances from joint interest partners	—			(759		)	—			(759		)
Net cash used in investing activities	—			(104,766		)	—			(104,766		)
Cash flows from financing activities:
Proceeds from revolving credit facility	—			246,000			—			246,000
Principal payments on revolving credit facility	—			(241,000		)	—			(241,000		)
Purchases of treasury stock	(5,419		)	—			—			(5,419		)
Investment in / capital contributions from subsidiaries	(2,610		)	2,610			—			—
Other	(55		)	—			—			(55		)
Net cash provided by (used in) financing activities	(8,084		)	7,610			—			(474		)
Increase in cash and cash equivalents	11			2,548			—			2,559
Cash and cash equivalents at beginning of period	166			11,060			—			11,226
Cash and cash equivalents at end of period	$	177		$	13,608		$	—		$	13,785

Condensed Consolidating Statement of Cash Flows

	Three Months Ended March 31, 2016
	Parent/ Issuer			Combined Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(In thousands)
Cash flows from operating activities:
Net loss	$	(64,455	)	$	(37,327	)	$	37,327		$	(64,455	)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	37,327			—			(37,327		)	—
Depreciation, depletion and amortization	—			122,449			—			122,449
Gain on extinguishment of debt	(7,016		)	—			—			(7,016		)
Impairment	—			3,562			—			3,562
Deferred income taxes	(8,096		)	(19,533		)	—			(27,629		)
Derivative instruments	—			(14,375		)	—			(14,375		)
Stock-based compensation expenses	6,547			183			—			6,730
Deferred financing costs amortization and other	1,701			3,365			—			5,066
Working capital and other changes:
Change in accounts receivable	(85		)	96,353			(97,263		)	(995		)
Change in inventory	—			349			—			349
Change in prepaid expenses	139			102			—			241
Change in other current assets	—			4			—			4
Change in other assets	77			—			—			77
Change in accounts payable, interest payable and accrued liabilities	(122,242		)	(39,077		)	97,263			(64,056		)
Change in other current liabilities	—			(6,000		)	—			(6,000		)
Change in other liabilities	—			(3		)	—			(3		)
Net cash provided by (used in) operating activities	(156,103		)	110,052			—			(46,051		)
Cash flows from investing activities:
Capital expenditures	—			(103,411		)	—			(103,411		)
Derivative settlements	—			73,313			—			73,313
Advances from joint interest partners	—			(257		)	—			(257		)
Net cash used in investing activities	—			(30,355		)	—			(30,355		)
Cash flows from financing activities:
Proceeds from revolving credit facility	—			214,000			—			214,000
Principal payments on revolving credit facility	—			(287,000		)	—			(287,000		)
Repurchase of senior unsecured notes	(22,308		)	—			—			(22,308		)
Deferred financing costs	—			(751		)	—			(751		)
Proceeds from sale of common stock	183,164			—			—			183,164
Purchases of treasury stock	(1,032		)	—			—			(1,032		)
Investment in / capital contributions from subsidiaries	(4,408		)	4,408			—			—
Net cash provided by (used in) financing activities	155,416			(69,343		)	—			86,073
Increase (decrease) in cash and cash equivalents	(687		)	10,354			—			9,667
Cash and cash equivalents at beginning of period	777			8,953			—			9,730
Cash and cash equivalents at end of period	$	90		$	19,307		$	—		$	19,397

XML

Inventory- Schedule of Inventory (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Inventory
Crude oil inventory	$ 10,302	$ 7,086
Equipment and materials	4,025	3,562
Total inventory	$ 14,327	$ 10,648

XML

Fair Value Measurements - Hierarchy of Fair Value, Assets and Liabilities Measured on Recurring Basis (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Assets:
Total assets	$ 6,982	$ 503
Liabilities:
Total liabilities	14,627	72,183
Money market funds [Member]
Assets:
Total assets	141	141
Commodity derivative instruments [Member]
Assets:
Total assets	6,841	362
Liabilities:
Total liabilities	14,627	72,183
Level 1 [Member]
Assets:
Total assets	141	141
Liabilities:
Total liabilities	0
Level 1 [Member] | Money market funds [Member]
Assets:
Total assets	141	141
Level 1 [Member] | Commodity derivative instruments [Member]
Assets:
Total assets	0	0
Liabilities:
Total liabilities	0
Level 2 [Member]
Assets:
Total assets	6,841	362
Liabilities:
Total liabilities	14,627	72,183
Level 2 [Member] | Money market funds [Member]
Assets:
Total assets	0	0
Level 2 [Member] | Commodity derivative instruments [Member]
Assets:
Total assets	6,841	362
Liabilities:
Total liabilities	14,627	72,183
Level 3 [Member]
Assets:
Total assets	0	0
Liabilities:
Total liabilities	0	0
Level 3 [Member] | Money market funds [Member]
Assets:
Total assets	0	0
Level 3 [Member] | Commodity derivative instruments [Member]
Assets:
Total assets	0	0
Liabilities:
Total liabilities	$ 0	$ 0

XML

Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Derivative credit risk valuation adjustment, derivative assets	$ 0.2	$ 2.0

XML

Derivative Instruments - Schedule of Outstanding Commodity Derivative Instruments (Details) bbl in Thousands, MMBTU in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($) MMBTU $ / bbl $ / MMBTU bbl
Oil [Member]
Derivative [Line Items]
Fair value asset (liability) | $	$ (7,786)
2017 Swaps [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	5,225
Average swap price (in dollars per barrel)	49.60
Fair value asset (liability) | $	$ (9,309)
2017 Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Total notional amount of natural gas (in MMBtu) | MMBTU	4,675
Average swap price (in dollars per barrel) | $ / MMBTU	3.30
Fair value asset (liability) | $	$ (55)
2017 Two Way Collars [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	2,200
Average floor price (in dollars per barrel)	46.25
Average ceiling price (in dollars per barrel)	54.37
Fair value asset (liability) | $	$ (1,707)
2017 Three Way Collars [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	1,650
Average sub-floor price (in dollars per barrel)	31.67
Average floor price (in dollars per barrel)	45.83
Average ceiling price (in dollars per barrel)	59.94
Fair value asset (liability) | $	$ 562
2018 Swaps [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	2,440
Average swap price (in dollars per barrel)	52.93
Fair value asset (liability) | $	$ 2,375
2018 Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Total notional amount of natural gas (in MMBtu) | MMBTU	3,650
Average swap price (in dollars per barrel) | $ / MMBTU	3.00
Fair value asset (liability) | $	$ (121)
2018 Two Way Collars [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	582
Average floor price (in dollars per barrel)	48.40
Average ceiling price (in dollars per barrel)	55.13
Fair value asset (liability) | $	$ 28
2018 Three Way Collars [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	186
Average sub-floor price (in dollars per barrel)	31.67
Average floor price (in dollars per barrel)	45.83
Average ceiling price (in dollars per barrel)	59.94
Fair value asset (liability) | $	$ 58
2019 Swaps [Member]
Derivative [Line Items]
Average swap price (in dollars per barrel)	53.88
2019 Swaps [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	155
Fair value asset (liability) | $	$ 351
2019 Two-way Collars [Member] | Oil [Member]
Derivative [Line Items]
Total ntional amount of oil (in Bbls) | bbl	31
Average floor price (in dollars per barrel)	50.00
Average ceiling price (in dollars per barrel)	55.70
Fair value asset (liability) | $	$ 32

XML

Derivative Instruments - Realized and Unrealized Gains and Losses from Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net gain on derivative instruments	$ 56,075	$ 14,375

XML

Derivative Instruments - Schedule of Location and Fair Value of Outstanding Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative asset, gross amounts recognized	$ 10,326	$ 482
Derivative liability, gross amount recognized	21,480	81,002
Derivative asset, gross amounts offset	(3,485)	(120)
Derivative liability, gross amounts offset	(6,853)	(8,819)
Derivative asset, net asset	6,841	362
Derivative liability, net liability	14,627	72,183
Current Assets [Member] | Commodity derivative instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, gross amounts recognized	5,178	482
Derivative asset, gross amounts offset	(2,152)	(120)
Derivative asset, net asset	3,026	362
Noncurrent Assets [Member] | Commodity derivative instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative asset, gross amounts recognized	5,148
Derivative asset, gross amounts offset	(1,333)
Derivative asset, net asset	3,815
Current Liabilities [Member] | Commodity derivative instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized	21,480	66,838
Derivative liability, gross amounts offset	(6,853)	(6,369)
Derivative liability, net liability	$ 14,627	60,469
Noncurrent Liabilities [Member] | Commodity derivative instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, gross amount recognized		14,164
Derivative liability, gross amounts offset		(2,450)
Derivative liability, net liability		$ 11,714

XML

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	[1]	$ 6,570,588	$ 6,476,833
Less: accumulated depreciation, depletion, amortization and impairment		(2,009,356)	(1,886,732)
Proved oil and gas properties, net		4,561,232	4,590,101
Unproved oil and gas properties		819,711	819,735
Other property and equipment		632,318	618,790
Less: accumulated depreciation		(116,780)	(109,059)
Other property and equipment, net		515,538	509,731
Total property, plant and equipment, net		$ 5,896,481	$ 5,919,567

[1] Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $43.0 million and $42.9 million at March 31, 2017 and December 31, 2016, respectively.

XML

Property, Plant and Equipment Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Asset retirement costs	$ 43.0	$ 42.9

XML

Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016
Debt Instrument [Line Items]
Total long-term debt	$ 2,305,879	$ 2,297,214
Line of Credit [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total principal of senior unsecured notes and revolving line of credit	368,000	363,000
Senior Unsecured Debt [Member]
Debt Instrument [Line Items]
Total principal of senior unsecured notes and revolving line of credit	2,052,950	2,052,950
Less: unamortized deferred financing costs on senior unsecured notes	$ (26,958)	(28,268)
Senior Unsecured Debt [Member] | 7.25% senior unsecured notes due February 1, 2019 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)	7.25%
Total principal of senior unsecured notes and revolving line of credit	$ 54,275	54,275
Senior Unsecured Debt [Member] | 6.5% senior unsecured notes due November 1, 2021 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)	6.50%
Total principal of senior unsecured notes and revolving line of credit	$ 395,501	395,501
Senior Unsecured Debt [Member] | 6.875% senior unsecured notes due March 15, 2022 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)	6.875%
Total principal of senior unsecured notes and revolving line of credit	$ 937,080	937,080
Senior Unsecured Debt [Member] | 6.875% senior unsecured notes due January 15, 2023 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)	6.875%
Total principal of senior unsecured notes and revolving line of credit	$ 366,094	366,094
Senior Unsecured Debt [Member] | 2.625% senior convertible notes due September 15, 2023 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)	2.625%		2.625%
Total principal of senior unsecured notes and revolving line of credit	$ 300,000	300,000
Less: unamortized debt discount on senior unsecured convertible notes	$ (88,113)	$ (90,468)	$ (93,200)

XML

Long-Term Debt - Additional Information (Details)	1 Months Ended	3 Months Ended
	Sep. 30, 2016 USD ($) day $ / shares	Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
Long-term debt		$ 2,305,879,000		$ 2,297,214,000
Total long-term debt		2,305,879,000		2,297,214,000
Repurchase of senior unsecured debt		0	$ 22,308,000
Gain (loss) on extinguishment of debt		$ 0	$ 7,016,000
Ownership percentage, guarantors (as percent)		100.00%
Unsecured Senior Notes [Member]
Debt Instrument [Line Items]
Long-term debt, fair value		$ 2,187,100,000
Line of Credit [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding		10,000,000
Line of Credit [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility amount		2,500,000,000
Line of credit facility, remaining borrowing capacity		$ 772,000,000
Weighted average interest rate (as percent)		2.50%
Commitment fee percentage		0.375%
Long-term debt, gross		$ 368,000,000		363,000,000
Line of Credit [Member] | Revolving Credit Facility [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding		368,000,000
Senior Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term debt, gross		2,052,950,000		2,052,950,000
Debt issuance costs		26,958,000		28,268,000
Senior Unsecured Debt [Member] | Unsecured Senior Notes [Member]
Debt Instrument [Line Items]
Total long-term debt		2,053,000,000
Senior Unsecured Debt [Member] | Notes [Member]
Debt Instrument [Line Items]
Unsecured debt		$ 1,753,000,000
Senior Unsecured Debt [Member] | Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)		6.50%
Senior Unsecured Debt [Member] | Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)		7.25%
Senior Unsecured Debt [Member] | 7.25% senior unsecured notes due February 1, 2019 [Member]
Debt Instrument [Line Items]
Number of days required for unsecured noted to be retired or refinanced prior to maturity		90 days
Stated interest rate (as percent)		7.25%
Long-term debt, gross		$ 54,275,000		54,275,000
Senior Unsecured Debt [Member] | 6.5% senior unsecured notes due November 1, 2021 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)		6.50%
Long-term debt, gross		$ 395,501,000		395,501,000
Senior Unsecured Debt [Member] | 6.875% senior unsecured notes due March 15, 2022 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)		6.875%
Long-term debt, gross		$ 937,080,000		937,080,000
Senior Unsecured Debt [Member] | 2.625% senior convertible notes due September 15, 2023 [Member]
Debt Instrument [Line Items]
Stated interest rate (as percent)	2.625%	2.625%
Long-term debt, gross		$ 300,000,000		300,000,000
Debt issued	$ 300,000,000
Debt conversion rate per $1000 principal (in shares per $1000)	76.3650
Debt conversion price (in dollars per share) | $ / shares	$ 13.10
Debt instrument effective interest rate (percent)	8.97%
Estimated fair value of debt	$ 206,800,000
Debt discount	$ 93,200,000	$ 88,113,000		$ 90,468,000
Debt Conversion Scenario 1 [Member] | Senior Unsecured Debt [Member] | 2.625% senior convertible notes due September 15, 2023 [Member]
Debt Instrument [Line Items]
Number of trading days | day	20
Number of consecutive trading days	30 days
Stock price relative to conversion price (percent)	130.00%
Debt Conversion Scenario 2 [Member] | Senior Unsecured Debt [Member] | 2.625% senior convertible notes due September 15, 2023 [Member]
Debt Instrument [Line Items]
Number of trading days | day	5
Number of consecutive trading days	5 days
Stock price relative to product of sale price and conversion rate (percent)	98.00%

XML

Asset Retirement Obligations - Schedule of Changes in Asset Retirement Obligations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2016	$ 49,687
Liabilities incurred during period	351
Liabilities settled during period	(89)
Accretion expense during period	655	[1]
Revisions to estimates	(215)
Balance at March 31, 2017	$ 50,389

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

XML

Asset Retirement Obligations - Additional Information (Details) $ in Millions	Mar. 31, 2017 USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Total asset retirement obligations, current portion	$ 0.3

XML

Income Taxes - Additional Information (Details)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Effective tax rate (as percent)	40.20%	30.00%

XML

Stock-Based Compensation - Additional Information (Details) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($) day $ / shares shares	Mar. 31, 2016 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expenses | $	$ 6,708	$ 6,730
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Stock granted (in shares) | shares	1,551,560
Granted, weighted average grant date fair value per unit (in usd per share) | $ / shares	$ 15.35
Stock-based compensation expenses | $	$ 5,400	5,800
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock granted (in shares) | shares	509,800
Granted, weighted average grant date fair value per unit (in usd per share) | $ / shares	$ 16.89
Stock-based compensation expenses | $	$ 1,300	$ 900
Right to received shares of common stock (in shares) | shares	1
Number of trading days | day	30
Performance Share Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSU granted percentage of earnings (as a percent)	0.00%
Performance Share Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSU granted percentage of earnings (as a percent)	200.00%

XML

Stock-Based Compensation - Summary of Assumptions (Details) - Performance Share Units [Member]	3 Months Ended
	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility assumption, volume weighted average stock price	30 days
Oasis stock price volatility (as percent)	17.16%
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as percent)	1.18%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate (as percent)	1.66%

XML

Earnings (Loss) Per Share - Schedule of Weighted-Average Number of Shares Outstanding (Details) - shares shares in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Basic weighted average common shares outstanding (in shares)		233,068	162,922
Diluted weighted average common shares outstanding (in shares)		237,900	162,922
Convertible Debt [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Dilution effect of stock awards at end of period (in shares)	[1]	1,594	0
Stock Awards [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Dilution effect of stock awards at end of period (in shares)		3,238	0

[1] The Company issued its Senior Convertible Notes in September 2016 (see Note 7 – Long-Term Debt).

XML

Earnings (Loss) Per Share - Schedule of Common Shares Excluded from Diluted Earnings (Loss) per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Document Fiscal Year Focus	2017
Anti-dilutive stock-based compensation awards (in shares)	2,884
Stock Compensation Plan [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive stock-based compensation awards (in shares)		4,668

XML

Business Segment Information - Additional Information (Details)	3 Months Ended
	Mar. 31, 2017 Segment
Segment Reporting [Abstract]
Number of current operating units	3

XML

Business Segment Information - Summarized Financial Information of Segments (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total revenues		$ 285,116	$ 130,283
Operating income (loss)		20,092	(75,215)
Other income (expense)		19,770	(16,869)
Income (loss) before income taxes		39,862	(92,084)
Property, plant and equipment, net		5,896,481		$ 5,919,567
Total assets	[1]	6,189,628		6,178,632
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total revenues		264,883	117,315
Midstream Services [Member]
Segment Reporting Information [Line Items]
Total revenues		37,641	29,818
Well Services [Member]
Segment Reporting Information [Line Items]
Total revenues		20,979	30,888
Operating Segments [Member] | Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total revenues		264,883	117,315
Operating income (loss)		968	(88,877)
Other income (expense)		19,768	(16,887)
Income (loss) before income taxes		20,736	(105,764)
Property, plant and equipment, net		5,589,014		5,620,558
Total assets	[1]	5,871,573		5,868,747
Operating Segments [Member] | Midstream Services [Member]
Segment Reporting Information [Line Items]
Total revenues		14,606	6,983
Operating income (loss)		20,763	15,144
Other income (expense)		(2)	13
Income (loss) before income taxes		20,761	15,157
Property, plant and equipment, net		433,867		424,197
Total assets	[1]	440,548		431,095
Operating Segments [Member] | Well Services [Member]
Segment Reporting Information [Line Items]
Total revenues		5,627	5,985
Operating income (loss)		(3,592)	4,006
Other income (expense)		4	5
Income (loss) before income taxes		(3,588)	4,011
Property, plant and equipment, net		44,025		47,189
Total assets	[1]	47,932		51,167
Segment Reconciling Items [Member] | Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total revenues		0	0
Segment Reconciling Items [Member] | Midstream Services [Member]
Segment Reporting Information [Line Items]
Total revenues		23,035	22,835
Segment Reconciling Items [Member] | Well Services [Member]
Segment Reporting Information [Line Items]
Total revenues		15,352	24,903
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues		(38,387)	(47,738)
Operating income (loss)		1,953	(5,488)
Other income (expense)		0	0
Income (loss) before income taxes		1,953	$ (5,488)
Property, plant and equipment, net		(170,425)		(172,377)
Total assets	[1]	$ (170,425)		$ (172,377)

[1] Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

XML

Commitments and Contingencies - Additional Information (Details) $ in Millions	Mar. 23, 2017 USD ($)
Mirada Litigation [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Damages sought (in excess of)	$ 100

XML

Condensed Consolidating Financial Information - Additional Information (Details)	3 Months Ended
	Mar. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Ownership percentage, guarantors (as percent)	100.00%

XML

Condensed Consolidating Financial Information - Schedule of Condensed Consolidating Balance Sheet (Details) - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents		$ 13,785	$ 11,226	$ 19,397	$ 9,730
Accounts receivable, net		226,427	204,335
Accounts receivable – affiliates		0	0
Inventory		14,327	10,648
Prepaid expenses		7,176	7,623
Derivative instruments		3,026	362
Other current assets		4,452	4,355
Total current assets		269,193	238,549
Property, plant and equipment
Oil and gas properties (successful efforts method)		7,390,299	7,296,568
Other property and equipment		632,318	618,790
Less: accumulated depreciation, depletion, amortization and impairment		(2,126,136)	(1,995,791)
Total property, plant and equipment, net		5,896,481	5,919,567
Assets held for sale			0
Investments in and advances to subsidiaries		0	0
Derivative instruments		3,815	0
Deferred income taxes		0	0
Other assets		20,139	20,516
Total assets	[1]	6,189,628	6,178,632
Current liabilities
Accounts payable		8,837	4,645
Accounts payable – affiliates		0	0
Revenues and production taxes payable		160,265	139,737
Accrued liabilities		128,241	119,173
Accrued interest payable		20,268	39,004
Derivative instruments		14,627	60,469
Advances from joint interest partners		6,838	7,597
Other current liabilities		13,435	10,490
Total current liabilities		352,511	381,115
Long-term debt		2,305,879	2,297,214
Deferred income taxes		524,842	513,529
Asset retirement obligations		50,088	48,985
Derivative instruments		0	11,714
Other liabilities		2,834	2,918
Total liabilities		3,236,154	3,255,475
Stockholders’ equity
Capital contributions from affiliates		0	0
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding at March 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016		2,344	2,331
Treasury stock, at cost: 1,229,568 and 856,892 shares at March 31, 2017 and December 31, 2016, respectively		(21,369)	(15,950)
Additional paid-in capital		2,354,485	2,345,271
Retained earnings		618,014	591,505
Total stockholders’ equity		2,953,474	2,923,157
Total liabilities and stockholders’ equity		6,189,628	6,178,632
Intercompany Eliminations [Member]
Current assets
Cash and cash equivalents		0	0	0	0
Accounts receivable, net		0	0
Accounts receivable – affiliates		(233,863)	(279,619)
Inventory		0	0
Prepaid expenses		0	0
Derivative instruments		0	0
Other current assets		0	0
Total current assets		(233,863)	(279,619)
Property, plant and equipment
Oil and gas properties (successful efforts method)		0	0
Other property and equipment		0	0
Less: accumulated depreciation, depletion, amortization and impairment		0	0
Total property, plant and equipment, net		0	0
Assets held for sale			0
Investments in and advances to subsidiaries		(4,503,650)	(4,451,192)
Derivative instruments		0
Deferred income taxes		(239,419)	(220,058)
Other assets		0	0
Total assets		(4,976,932)	(4,950,869)
Current liabilities
Accounts payable		0	0
Accounts payable – affiliates		(233,863)	(279,619)
Revenues and production taxes payable		0	0
Accrued liabilities		0	0
Accrued interest payable		0	0
Derivative instruments		0	0
Advances from joint interest partners		0	0
Other current liabilities		0	0
Total current liabilities		(233,863)	(279,619)
Long-term debt		0	0
Deferred income taxes		(239,419)	(220,058)
Asset retirement obligations		0	0
Derivative instruments			0
Other liabilities		0	0
Total liabilities		(473,282)	(499,677)
Stockholders’ equity
Capital contributions from affiliates		(3,392,248)	(3,388,893)
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding at March 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016		0	0
Treasury stock, at cost: 1,229,568 and 856,892 shares at March 31, 2017 and December 31, 2016, respectively		0	0
Additional paid-in capital		(8,743)	(8,743)
Retained earnings		(1,102,659)	(1,053,556)
Total stockholders’ equity		(4,503,650)	(4,451,192)
Total liabilities and stockholders’ equity		(4,976,932)	(4,950,869)
Parent/Issuer [Member]
Current assets
Cash and cash equivalents		177	166	90	777
Accounts receivable, net		0	0
Accounts receivable – affiliates		200,770	252,000
Inventory		0	0
Prepaid expenses		334	275
Derivative instruments		0	0
Other current assets		2	0
Total current assets		201,283	252,441
Property, plant and equipment
Oil and gas properties (successful efforts method)		0	0
Other property and equipment		0	0
Less: accumulated depreciation, depletion, amortization and impairment		0	0
Total property, plant and equipment, net		0	0
Assets held for sale			0
Investments in and advances to subsidiaries		4,503,650	4,451,192
Derivative instruments		0
Deferred income taxes		239,419	220,058
Other assets		0	0
Total assets		4,944,352	4,923,691
Current liabilities
Accounts payable		0	0
Accounts payable – affiliates		33,093	27,619
Revenues and production taxes payable		0	0
Accrued liabilities		34	12
Accrued interest payable		19,872	38,689
Derivative instruments		0	0
Advances from joint interest partners		0	0
Other current liabilities		0	0
Total current liabilities		52,999	66,320
Long-term debt		1,937,879	1,934,214
Deferred income taxes		0	0
Asset retirement obligations		0	0
Derivative instruments			0
Other liabilities		0	0
Total liabilities		1,990,878	2,000,534
Stockholders’ equity
Capital contributions from affiliates		0	0
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding at March 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016		2,344	2,331
Treasury stock, at cost: 1,229,568 and 856,892 shares at March 31, 2017 and December 31, 2016, respectively		(21,369)	(15,950)
Additional paid-in capital		2,354,485	2,345,271
Retained earnings		618,014	591,505
Total stockholders’ equity		2,953,474	2,923,157
Total liabilities and stockholders’ equity		4,944,352	4,923,691
Combined Guarantor Subsidiaries [Member]
Current assets
Cash and cash equivalents		13,608	11,060	$ 19,307	$ 8,953
Accounts receivable, net		226,427	204,335
Accounts receivable – affiliates		33,093	27,619
Inventory		14,327	10,648
Prepaid expenses		6,842	7,348
Derivative instruments		3,026	362
Other current assets		4,450	4,355
Total current assets		301,773	265,727
Property, plant and equipment
Oil and gas properties (successful efforts method)		7,390,299	7,296,568
Other property and equipment		632,318	618,790
Less: accumulated depreciation, depletion, amortization and impairment		(2,126,136)	(1,995,791)
Total property, plant and equipment, net		5,896,481	5,919,567
Assets held for sale			0
Investments in and advances to subsidiaries		0	0
Derivative instruments		3,815
Deferred income taxes		0	0
Other assets		20,139	20,516
Total assets		6,222,208	6,205,810
Current liabilities
Accounts payable		8,837	4,645
Accounts payable – affiliates		200,770	252,000
Revenues and production taxes payable		160,265	139,737
Accrued liabilities		128,207	119,161
Accrued interest payable		396	315
Derivative instruments		14,627	60,469
Advances from joint interest partners		6,838	7,597
Other current liabilities		13,435	10,490
Total current liabilities		533,375	594,414
Long-term debt		368,000	363,000
Deferred income taxes		764,261	733,587
Asset retirement obligations		50,088	48,985
Derivative instruments			11,714
Other liabilities		2,834	2,918
Total liabilities		1,718,558	1,754,618
Stockholders’ equity
Capital contributions from affiliates		3,392,248	3,388,893
Common stock, $0.01 par value: 450,000,000 shares authorized; 238,691,038 shares issued and 237,461,470 shares outstanding at March 31, 2017 and 237,201,064 shares issued and 236,344,172 shares outstanding at December 31, 2016		0	0
Treasury stock, at cost: 1,229,568 and 856,892 shares at March 31, 2017 and December 31, 2016, respectively		0	0
Additional paid-in capital		8,743	8,743
Retained earnings		1,102,659	1,053,556
Total stockholders’ equity		4,503,650	4,451,192
Total liabilities and stockholders’ equity		$ 6,222,208	$ 6,205,810

[1] Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.

XML

Condensed Consolidating Financial Information Condensed Consolidating Financial Information - Schedule of Condensed Consolidating Balance Sheet - Additional Information (Details) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	238,691,038	237,201,064
Common stock, shares outstanding (in shares)	237,461,470	236,344,172
Treasury stock, shares (in shares)	1,229,568	856,892

XML

Condensed Consolidating Financial Information - Schedule of Condensed Consolidating Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues
Oil and gas revenues	$ 237,252	$ 117,315
Bulk oil sales	27,631	0
Midstream revenues	14,606	6,983
Well services revenues	5,627	5,985
Total revenues	285,116	130,283
Operating expenses
Lease operating expenses	43,872	31,064
Midstream operating expenses	3,327	1,738
Well services operating expenses	3,902	2,651
Marketing, transportation and gathering expenses	10,951	8,552
Bulk oil purchases	28,002	0
Production taxes	20,299	10,753
Depreciation, depletion and amortization	126,666	122,449
Exploration expenses	1,489	363
Impairment	2,682	3,562
General and administrative expenses	23,834	24,366
Total operating expenses	265,024	205,498
Operating income (loss)	20,092	(75,215)
Other income (expense)
Equity in earnings of subsidiaries	0	0
Net gain (loss) on derivative instruments	56,075	14,375
Interest expense, net of capitalized interest	(36,321)	(38,739)
Gain on extinguishment of debt	0	7,016
Other income	16	479
Total other income (expense)	19,770	(16,869)
Income (loss) before income taxes	39,862	(92,084)
Income tax benefit	(16,037)	27,629
Net income (loss)	23,825	(64,455)
Intercompany Eliminations [Member]
Revenues
Oil and gas revenues	0	0
Bulk oil sales	0
Midstream revenues	0	0
Well services revenues	0	0
Total revenues	0	0
Operating expenses
Lease operating expenses	0	0
Midstream operating expenses	0	0
Well services operating expenses	0	0
Marketing, transportation and gathering expenses	0	0
Bulk oil purchases	0
Production taxes	0	0
Depreciation, depletion and amortization	0	0
Exploration expenses	0	0
Impairment	0	0
General and administrative expenses	0	0
Total operating expenses	0	0
Operating income (loss)	0	0
Other income (expense)
Equity in earnings of subsidiaries	(49,103)	37,327
Net gain (loss) on derivative instruments	0	0
Interest expense, net of capitalized interest	0	0
Gain on extinguishment of debt		0
Other income	0	0
Total other income (expense)	(49,103)	37,327
Income (loss) before income taxes	(49,103)	37,327
Income tax benefit	0	0
Net income (loss)	(49,103)	37,327
Parent/Issuer [Member]
Revenues
Oil and gas revenues	0	0
Bulk oil sales	0
Midstream revenues	0	0
Well services revenues	0	0
Total revenues	0	0
Operating expenses
Lease operating expenses	0	0
Midstream operating expenses	0	0
Well services operating expenses	0	0
Marketing, transportation and gathering expenses	0	0
Bulk oil purchases	0
Production taxes	0	0
Depreciation, depletion and amortization	0	0
Exploration expenses	0	0
Impairment	0	0
General and administrative expenses	7,065	7,451
Total operating expenses	7,065	7,451
Operating income (loss)	(7,065)	(7,451)
Other income (expense)
Equity in earnings of subsidiaries	49,103	(37,327)
Net gain (loss) on derivative instruments	0	0
Interest expense, net of capitalized interest	(32,851)	(34,832)
Gain on extinguishment of debt		7,016
Other income	0	43
Total other income (expense)	16,252	(65,100)
Income (loss) before income taxes	9,187	(72,551)
Income tax benefit	14,638	8,096
Net income (loss)	23,825	(64,455)
Combined Guarantor Subsidiaries [Member]
Revenues
Oil and gas revenues	237,252	117,315
Bulk oil sales	27,631
Midstream revenues	14,606	6,983
Well services revenues	5,627	5,985
Total revenues	285,116	130,283
Operating expenses
Lease operating expenses	43,872	31,064
Midstream operating expenses	3,327	1,738
Well services operating expenses	3,902	2,651
Marketing, transportation and gathering expenses	10,951	8,552
Bulk oil purchases	28,002
Production taxes	20,299	10,753
Depreciation, depletion and amortization	126,666	122,449
Exploration expenses	1,489	363
Impairment	2,682	3,562
General and administrative expenses	16,769	16,915
Total operating expenses	257,959	198,047
Operating income (loss)	27,157	(67,764)
Other income (expense)
Equity in earnings of subsidiaries	0	0
Net gain (loss) on derivative instruments	56,075	14,375
Interest expense, net of capitalized interest	(3,470)	(3,907)
Gain on extinguishment of debt		0
Other income	16	436
Total other income (expense)	52,621	10,904
Income (loss) before income taxes	79,778	(56,860)
Income tax benefit	(30,675)	19,533
Net income (loss)	$ 49,103	$ (37,327)

XML

Condensed Consolidating Financial Information - Schedule of Condensed Consolidating Statement of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 23,825	$ (64,455)
Adjustments to reconcile net income to cash provided by operating activities:
Equity in loss of subsidiaries	0	0
Depreciation, depletion and amortization	126,666	122,449
Gain on extinguishment of debt	0	(7,016)
Impairment	2,682	3,562
Deferred income taxes	16,037	(27,629)
Derivative instruments	(56,075)	(14,375)
Stock-based compensation expenses	6,708	6,730
Deferred financing costs amortization and other	4,940	5,066
Working capital and other changes:
Change in accounts receivable	(22,478)	(995)
Change in inventory	(3,679)	349
Change in prepaid expenses	282	241
Change in other current assets	(110)	4
Change in other assets	(4)	77
Change in accounts payable, interest payable and accrued liabilities	6,060	(64,056)
Change in other current liabilities	2,945	(6,000)
Change in other liabilities	0	(3)
Net cash provided by (used in) operating activities	107,799	(46,051)
Cash flows from investing activities:
Capital expenditures	(96,047)	(103,411)
Derivative settlements	(7,960)	73,313
Advances from joint interest partners	(759)	(257)
Net cash used in investing activities	(104,766)	(30,355)
Cash flows from financing activities:
Proceeds from revolving credit facility	246,000	214,000
Principal payments on revolving credit facility	(241,000)	(287,000)
Repurchase of senior unsecured notes	0	(22,308)
Deferred financing costs	0	(751)
Proceeds from sale of common stock	0	183,164
Purchases of treasury stock	(5,419)	(1,032)
Investment in / capital contributions from subsidiaries	0	0
Other	(55)	0
Net cash provided by (used in) financing activities	(474)	86,073
Increase in cash and cash equivalents	2,559	9,667
Beginning of period	11,226	9,730
End of period	13,785	19,397
Intercompany Eliminations [Member]
Cash flows from operating activities:
Net income (loss)	(49,103)	37,327
Adjustments to reconcile net income to cash provided by operating activities:
Equity in loss of subsidiaries	49,103	(37,327)
Depreciation, depletion and amortization	0	0
Gain on extinguishment of debt		0
Impairment	0	0
Deferred income taxes	0	0
Derivative instruments	0	0
Stock-based compensation expenses	0	0
Deferred financing costs amortization and other	0	0
Working capital and other changes:
Change in accounts receivable	(45,756)	(97,263)
Change in inventory	0	0
Change in prepaid expenses	0	0
Change in other current assets	0	0
Change in other assets	0	0
Change in accounts payable, interest payable and accrued liabilities	45,756	97,263
Change in other current liabilities	0	0
Change in other liabilities		0
Net cash provided by (used in) operating activities	0	0
Cash flows from investing activities:
Capital expenditures	0	0
Derivative settlements	0	0
Advances from joint interest partners	0	0
Net cash used in investing activities	0	0
Cash flows from financing activities:
Proceeds from revolving credit facility	0	0
Principal payments on revolving credit facility	0	0
Repurchase of senior unsecured notes		0
Deferred financing costs		0
Proceeds from sale of common stock		0
Purchases of treasury stock	0	0
Investment in / capital contributions from subsidiaries	0	0
Other	0
Net cash provided by (used in) financing activities	0	0
Increase in cash and cash equivalents	0	0
Beginning of period	0	0
End of period	0	0
Parent/Issuer [Member]
Cash flows from operating activities:
Net income (loss)	23,825	(64,455)
Adjustments to reconcile net income to cash provided by operating activities:
Equity in loss of subsidiaries	(49,103)	37,327
Depreciation, depletion and amortization	0	0
Gain on extinguishment of debt		(7,016)
Impairment	0	0
Deferred income taxes	(14,638)	(8,096)
Derivative instruments	0	0
Stock-based compensation expenses	6,498	6,547
Deferred financing costs amortization and other	3,665	1,701
Working capital and other changes:
Change in accounts receivable	51,230	(85)
Change in inventory	0	0
Change in prepaid expenses	(59)	139
Change in other current assets	(2)	0
Change in other assets	0	77
Change in accounts payable, interest payable and accrued liabilities	(13,321)	(122,242)
Change in other current liabilities	0	0
Change in other liabilities		0
Net cash provided by (used in) operating activities	8,095	(156,103)
Cash flows from investing activities:
Capital expenditures	0	0
Derivative settlements	0	0
Advances from joint interest partners	0	0
Net cash used in investing activities	0	0
Cash flows from financing activities:
Proceeds from revolving credit facility	0	0
Principal payments on revolving credit facility	0	0
Repurchase of senior unsecured notes		(22,308)
Deferred financing costs		0
Proceeds from sale of common stock		183,164
Purchases of treasury stock	(5,419)	(1,032)
Investment in / capital contributions from subsidiaries	(2,610)	(4,408)
Other	(55)
Net cash provided by (used in) financing activities	(8,084)	155,416
Increase in cash and cash equivalents	11	(687)
Beginning of period	166	777
End of period	177	90
Combined Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net income (loss)	49,103	(37,327)
Adjustments to reconcile net income to cash provided by operating activities:
Equity in loss of subsidiaries	0	0
Depreciation, depletion and amortization	126,666	122,449
Gain on extinguishment of debt		0
Impairment	2,682	3,562
Deferred income taxes	30,675	(19,533)
Derivative instruments	(56,075)	(14,375)
Stock-based compensation expenses	210	183
Deferred financing costs amortization and other	1,275	3,365
Working capital and other changes:
Change in accounts receivable	(27,952)	96,353
Change in inventory	(3,679)	349
Change in prepaid expenses	341	102
Change in other current assets	(108)	4
Change in other assets	(4)	0
Change in accounts payable, interest payable and accrued liabilities	(26,375)	(39,077)
Change in other current liabilities	2,945	(6,000)
Change in other liabilities		(3)
Net cash provided by (used in) operating activities	99,704	110,052
Cash flows from investing activities:
Capital expenditures	(96,047)	(103,411)
Derivative settlements	(7,960)	73,313
Advances from joint interest partners	(759)	(257)
Net cash used in investing activities	(104,766)	(30,355)
Cash flows from financing activities:
Proceeds from revolving credit facility	246,000	214,000
Principal payments on revolving credit facility	(241,000)	(287,000)
Repurchase of senior unsecured notes		0
Deferred financing costs		(751)
Proceeds from sale of common stock		0
Purchases of treasury stock	0	0
Investment in / capital contributions from subsidiaries	2,610	4,408
Other	0
Net cash provided by (used in) financing activities	7,610	(69,343)
Increase in cash and cash equivalents	2,548	10,354
Beginning of period	11,060	8,953
End of period	$ 13,608	$ 19,307

XML

Subsequent Events (Details) bbl in Thousands	1 Months Ended
	Apr. 30, 2017 $ / bbl bbl	Apr. 10, 2017 USD ($)	Mar. 31, 2017 USD ($) $ / bbl $ / MMBTU
Subsequent Event [Line Items]
Maximum borrowing base			$ 1,150,000,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Maximum borrowing base		$ 1,600,000,000
Line of credit facility, current borrowing commitment		$ 1,150,000,000
2019 Swaps [Member]
Subsequent Event [Line Items]
Average swap price (in dollars per barrel) | $ / bbl			53.88
Crude Oil [Member] | Swap [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Average swap price (in dollars per barrel) | $ / bbl	54.12
Crude Oil [Member] | 2018 Swaps [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Total ntional amount of oil (in Bbls) | bbl	668
Crude Oil [Member] | 2019 Swaps [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Total ntional amount of oil (in Bbls) | bbl	62
Natural Gas [Member] | 2018 Swaps [Member]
Subsequent Event [Line Items]
Average swap price (in dollars per barrel) | $ / MMBTU			3.00