Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-Q


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

For the quarterly period ended June 30, 2019


☐			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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock

OAS

New York Stock Exchange

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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ 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	☒	Accelerated filer	☐

Non-accelerated filer	☐	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 ☒

Number of shares of the registrant’s common stock outstanding at July 31, 2019: 321,871,437 shares.

OASIS PETROLEUM INC.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2019

TABLE OF CONTENTS


			Page
PART I — FINANCIAL INFORMATION			1
Item 1. — Financial Statements (Unaudited)			1
Condensed Consolidated Balance Sheets at June 30 , 2019 and December 31, 2018			1
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30 , 2019 and 2018			3
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three and Six Months Ended June 30, 2019 and 2018			4
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30 , 2019 and 2018			5
Notes to Condensed Consolidated Financial Statements			7
1. Organization and Operations of the Company			7
2. Summary of Significant Accounting Policies			7
3. Oasis Midstream Partners			9
4. Revenue Recognition			9
5. Inventory			11
6. Accounts Receivable			12
7. Fair Value Measurements			12
8. Derivative Instruments			14
9. Property, Plant and Equipment			17
10. Divestitures			18
11. Long-Term Debt			18
12. Asset Retirement Obligations			20
13. Income Taxes			20
14. Equity-Based Compensation			20
15. Earnings (Loss) Per Share			21
16. Business Segment Information			22
17. Leases			24
18. Commitments and Contingencies			27
19. Condensed Consolidating Financial Information			29
20. Subsequent Events			38
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations			39
Item 3. — Quantitative and Qualitative Disclosures About Market Risk			57
Item 4. — Controls and Procedures			59
PART II — OTHER INFORMATION			60
Item 1. — Legal Proceedings			60
Item 1A. — Risk Factors			61
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds			61
Item 6. — Exhibits			62
SIGNATURES			63

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Oasis Petroleum Inc.

Condensed Consolidated Balance Sheets

(Unaudited)


	June 30, 2019		December 31, 2018

	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	20,258	$	22,190
Accounts receivable, net	396,104		387,602
Inventory	30,056		33,128
Prepaid expenses	6,018		10,997

Derivative instruments	19,089		99,930
Intangible assets, net	—		125
Other current assets	195		183
Total current assets	471,720		554,155
Property, plant and equipment
Oil and gas properties (successful efforts method)	9,283,462		8,912,189
Other property and equipment	1,301,835		1,151,772
Less: accumulated depreciation, depletion, amortization and impairment	(3,416,183)		(3,036,852)
Total property, plant and equipment, net	7,169,114		7,027,109

Derivative instruments	5,636		6,945
Long-term inventory	13,286		12,260
Operating right-of-use assets	20,054		—
Other assets	30,478		25,673
Total assets	$	7,710,288	$	7,626,142

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	15,155	$	20,166
Revenues and production taxes payable	170,534		216,695
Accrued liabilities	315,450		331,651
Accrued interest payable	37,701		38,040
Derivative instruments	4,445		84

Advances from joint interest partners	4,076		5,140
Current operating lease liabilities	7,837		—
Other current liabilities	3,230		—
Total current liabilities	558,428		611,776
Long-term debt	2,896,524		2,735,276
Deferred income taxes	308,672		300,055
Asset retirement obligations	55,228		52,384

Derivative instruments	—		20
Operating lease liabilities	18,021		—
Other liabilities	6,957		7,751
Total liabilities	3,843,830		3,707,262
Commitments and contingencies (Note 18)

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Stockholders’ equity
Common stock, $0.01 par value: 900,000,000 shares authorized; 324,680,450 shares issued and 321,894,286 shares outstanding at June 30, 2019 and 320,469,049 shares issued and 318,377,161 shares outstanding at December 31, 2018	3,183		3,157
Treasury stock, at cost: 2,786,164 and 2,091,888 shares at June 30, 2019 and December 31, 2018, respectively	(33,330)		(29,025)
Additional paid-in capital	3,096,355		3,077,755
Retained earnings	610,564		682,689
Oasis share of stockholders’ equity	3,676,772		3,734,576
Non-controlling interests	189,686		184,304
Total stockholders’ equity	3,866,458		3,918,880
Total liabilities and stockholders’ equity	$	7,710,288	$	7,626,142

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

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Oasis Petroleum Inc.

Condensed Consolidated Statements of Operations

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands, except per share data)
Revenues
Oil and gas revenues	$	357,004	$	397,849	$	725,786	$	764,444
Purchased oil and gas sales	109,389		128,064		257,860		195,773
Midstream revenues	51,573		29,342		99,594		57,264
Well services revenues	11,439		18,496		21,897		30,082
Total revenues	529,405		573,751		1,105,137		1,047,563
Operating expenses
Lease operating expenses	56,228		44,141		114,672		88,922
Midstream expenses	17,368		7,688		34,097		15,673
Well services expenses	8,474		13,560		15,444		20,947
Marketing, transportation and gathering expenses	28,488		22,833		63,438		43,846
Purchased oil and gas expenses	109,662		129,579		259,566		200,173
Production taxes	28,142		34,026		57,760		65,026
Depreciation, depletion and amortization	177,358		153,570		367,191		302,835
Exploration expenses	887		617		1,717		1,386

Impairment	24		384,135		653		384,228
General and administrative expenses	30,926		28,230		65,385		56,170
Total operating expenses	457,557		818,379		979,923		1,179,206
Gain (loss) on sale of properties	(276)		1,954		(3,198)		1,954
Operating income (loss)	71,572		(242,674)		122,016		(129,689)
Other income (expense)
Net gain (loss) on derivative instruments	34,749		(120,285)		(82,862)		(191,401)
Interest expense, net of capitalized interest	(43,186)		(40,910)		(87,654)		(78,056)
Loss on extinguishment of debt	—		(13,651)		—		(13,651)
Other income	279		218		233		35
Total other expense, net	(8,158)		(174,628)		(170,283)		(283,073)
Income (loss) before income taxes	63,414		(417,302)		(48,267)		(412,762)
Income tax benefit (expense)	(12,240)		101,001		(8,537)		100,173
Net income (loss) including non-controlling interests	51,174		(316,301)		(56,804)		(312,589)
Less: Net income attributable to non-controlling interests	8,417		3,903		15,321		7,025
Net income (loss) attributable to Oasis	$	42,757	$	(320,204)	$	(72,125)	$	(319,614)
Earnings (loss) attributable to Oasis per share:
Basic (Note 15)	$	0.14	$	(1.02)	$	(0.23)	$	(1.06)
Diluted (Note 15)	0.14		(1.02)		(0.23)		(1.06)
Weighted average shares outstanding:
Basic (Note 15)	314,982		313,072		314,724		301,652
Diluted (Note 15)	314,982		313,072		314,724		301,652

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

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Oasis Petroleum Inc.

Condensed Consolidated Statements of Changes in Stockholders’ Equity

(Unaudited)


	Attributable to Oasis
	Common Stock							Treasury Stock							Additional Paid-in Capital		Retained Earnings		Non-controlling Interests	Total Stockholders’ Equity
		Shares			Amount		Shares			Amount

	(In thousands)
Balance as of December 31, 2018	318,377		$	3,157		2,092		$	(29,025)		$	3,077,755	$	682,689	$	184,304	$	3,918,880


Equity-based compensation	4,360		25			—		—			9,462		—		119		9,606

Distributions to non-controlling interest owners	—		—			—		—			—		—		(4,937)		(4,937)

Treasury stock - tax withholdings	(686)		—			686		(4,261)			—		—		—		(4,261)
Other	—		—			—		—			(134)		—		(41)		(175)
Net income (loss)	—		—			—		—			—		(114,882)		6,904		(107,978)
Balance as of March 31, 2019	322,051		3,182			2,778		(33,286)			3,087,083		567,807		186,349		3,811,135




Equity-based compensation	(149)		1			—		—			9,465		—		100		9,566

Distributions to non-controlling interest owners	—		—			—		—			—		—		(5,156)		(5,156)

Treasury stock - tax withholdings	(8)		—			8		(44)			—		—		—		(44)
Other	—		—			—		—			(193)		—		(24)		(217)
Net income	—		—			—		—			—		42,757		8,417		51,174
Balance as of June 30, 2019	321,894		$	3,183		2,786		$	(33,330)		$	3,096,355	$	610,564	$	189,686	$	3,866,458


	Attributable to Oasis
	Common Stock							Treasury Stock							Additional Paid-in Capital		Retained Earnings		Non-controlling Interests	Total Stockholders’ Equity
		Shares			Amount		Shares			Amount

	(In thousands)
Balance as of December 31, 2017	269,295		$	2,668		1,332		$	(22,179)		$	2,677,217	$	717,985	$	137,888	$	3,513,579
Issuance of common stock in connection with acquisition	46,000		460			—		—			370,760		—		—		371,220


Equity-based compensation	2,758		26			—		—			7,116		—		66		7,208

Distributions to non-controlling interest owners	—		—			—		—			—		—		(3,450)		(3,450)

Treasury stock - tax withholdings	(690)		—			690		(6,021)			—		—		—		(6,021)
Other	—		—			—		—			(90)		—		—		(90)
Net income	—		—			—		—			—		590		3,122		3,712
Balance as of March 31, 2018	317,363		3,154			2,022		(28,200)			3,055,003		718,575		137,626		3,886,158

Equity-based compensation	625		—			—		—			7,730		—		100		7,830

Distributions to non-controlling interest owners	—		—			—		—			—		—		(3,396)		(3,396)

Treasury stock - tax withholdings	(3)		—			3		(43)			—		—		—		(43)
Other	—		—			—		—			128		—		(125)		3
Net income (loss)	—		—			—		—			—		(320,204)		3,903		(316,301)
Balance as of June 30, 2018	317,985		$	3,154		2,025		$	(28,243)		$	3,062,861	$	398,371	$	138,108	$	3,574,251

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

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Oasis Petroleum Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2019		2018

	(In thousands)
Cash flows from operating activities:
Net loss including non-controlling interests	$	(56,804)	$	(312,589)
Adjustments to reconcile net loss including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	367,191		302,835
Loss on extinguishment of debt	—		13,651
(Gain) loss on sale of properties	3,198		(1,954)
Impairment	653		384,228
Deferred income taxes	8,617		(100,293)
Derivative instruments	82,862		191,401
Equity-based compensation expenses	17,924		14,130
Deferred financing costs amortization and other	12,245		10,518
Working capital and other changes:
Change in accounts receivable, net	(12,914)		(5,866)
Change in inventory	3,029		(4,721)
Change in prepaid expenses	3,918		573


Change in accounts payable, interest payable and accrued liabilities	(36,514)		40,849


Change in other assets and liabilities, net	(4,473)		(746)
Net cash provided by operating activities	388,932		532,016
Cash flows from investing activities:
Capital expenditures	(525,501)		(536,959)
Acquisitions	(5,781)		(524,255)
Proceeds from sale of properties	—		2,236


Derivative settlements	3,629		(96,823)


Other	—		(933)
Net cash used in investing activities	(527,653)		(1,156,734)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	1,178,000		1,933,000
Principal payments on Revolving Credit Facilities	(1,025,000)		(1,265,000)
Repurchase of senior unsecured notes	—		(423,143)
Proceeds from issuance of senior unsecured notes	—		400,000
Deferred financing costs	(482)		(6,790)


Purchases of treasury stock	(4,305)		(6,064)
Distributions to non-controlling interests	(10,093)		(6,846)
Other	(1,331)		(87)
Net cash provided by financing activities	136,789		625,070
Increase (decrease) in cash and cash equivalents	(1,932)		352
Cash and cash equivalents:
Beginning of period	22,190		16,720
End of period	$	20,258	$	17,072
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	(30,598)	$	90,040
Change in asset retirement obligations	3,840		5,407

Issuance of shares in connection with acquisition	—		371,220

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

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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”) is an independent exploration and production company focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct the Company’s exploration and production activities and own its crude oil and natural gas properties located in the Williston Basin and the Delaware Basin, respectively. In addition to its exploration and production segment, the Company also operates a midstream business segment through Oasis Midstream Partners LP (“OMP”) and Oasis Midstream Services LLC (“OMS”) and a well services business segment through Oasis Well Services LLC (“OWS”). OMP is a growth-oriented, fee-based master limited partnership that develops and operates a diversified portfolio of midstream assets.

2. Summary of Significant Accounting Policies

Basis of Presentation

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, 2018 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 of the Company’s financial position, 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, 2018 (“2018 Annual Report”).

Consolidation. The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis, the accounts of wholly-owned subsidiaries and the accounts of OMP and its general partner, OMP GP LLC (“OMP GP”). The Company has determined that the partners with equity at risk in OMP lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact OMP’s economic performance. Therefore, as the limited partners of OMP do not have substantive kick-out or substantive participating rights over OMP GP, OMP is a variable interest entity. Through the Company’s ownership interest in OMP GP, the Company has the authority to direct the activities that most significantly affect economic performance and the right to receive benefits that could be potentially significant to OMP. Therefore, the Company is considered the primary beneficiary and consolidates OMP and records a non-controlling interest for the interest owned by the public. All intercompany balances and transactions have been eliminated upon consolidation.

Revision of Prior Period Financial Statements. In connection with the preparation of the Company’s 2018 Annual Report, the Company identified errors in its previously issued 2017 annual consolidated financial statements and in each of the interim periods within 2018 and 2017. These prior period errors related to the manner in which it accounted for certain crude oil purchase and sale arrangements. Specifically, although the Company previously reported the transactions on a net basis, the Company was required to account for these purchase and sale arrangements on a gross basis, in accordance with Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”) in 2018, as these transactions were not subject to Accounting Standards Codification 845, Nonmonetary Transactions (“ASC 845”). The correction of these errors had no effect on the reported consolidated net income (loss) attributable to Oasis or earnings (loss) attributable to Oasis per share data.

In accordance with Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, the Company evaluated the errors and, based on an analysis of quantitative and qualitative factors, determined that the related impact was not material to the Company’s consolidated financial statements for any prior period. Therefore, amendments of previously filed reports are not required. In accordance with Accounting Standards Codification 250, Accounting Changes and Error Corrections, the Company has corrected the errors for the three and six months ended June 30, 2018 by revising the unaudited condensed consolidated financial statements appearing herein.

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For the three and six months ended June 30, 2018, the revision did not impact the Company’s financial position or cash flows from operations, and the impacts to the Company’s Condensed Consolidated Statement of Operations were as follows:


	Three Months Ended June 30, 2018										Six Months Ended June 30, 2018
	As Reported		Revision		As Revised		As Reported		Revision		As Revised

	(In thousands, except per share data)
Oil and gas revenues	$	395,921	$	1,928	$	397,849	$	759,592	$	4,852	$	764,444
Purchased oil and gas sales	57,578		70,486		128,064		75,615		120,158		195,773
Total revenues	501,337		72,414		573,751		922,553		125,010		1,047,563
Purchased oil and gas expenses	57,165		72,414		129,579		75,163		125,010		200,173
Total operating expenses	745,965		72,414		818,379		1,054,196		125,010		1,179,206
Net loss attributable to Oasis	(320,204)		—		(320,204)		(319,614)		—		(319,614)
Loss attributable to Oasis per share:
Basic	$	(1.02)	$	—	$	(1.02)	$	(1.06)	$	—	$	(1.06)
Diluted	$	(1.02)	$	—	$	(1.02)	$	(1.06)	$	—	$	(1.06)

The accompanying notes to the condensed consolidated financial statements reflect the impact of this revision.

Dividends

The Company has not paid any cash dividends since its inception. Covenants contained in its revolving credit facilities and the indentures governing the Company’s senior notes restrict the payment of cash dividends on its common stock. The Company currently intends to retain all earnings for the development of its business and for repayment of outstanding debt, and the Company does not anticipate declaring or paying any cash dividends to holders of its common stock.

Risks and Uncertainties

As a crude oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude 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 crude oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude 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 crude 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 2018 Annual Report, other than as noted below.

Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842), which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than twelve months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by various Accounting Standards Updates, which provided additional implementation guidance.

The Company adopted the new standard as of January 1, 2019 using the required modified retrospective approach and elected the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings in the period of adoption. Prior period amounts were not adjusted.

The Company elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight line basis. See Note 17 — Leases for the adoption impact and disclosures required by ASC 842.

Recent Accounting Pronouncements

Financial Instruments. In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the effectiveness of the disclosure requirements for fair value measurements. The changes affect all companies

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that are required to include fair value measurement disclosures. ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those years. An entity is permitted to early adopt the removed or modified disclosures upon the issuance of ASU 2018-13 and may delay adoption of the additional disclosures until their effective date. The Company does not expect the adoption of this guidance to have an impact on its financial position, cash flows or results of operations, but it may result in changes to disclosures.

3. Oasis Midstream Partners

2019 Capital Expenditures Arrangement. On February 22, 2019, the Company entered into a memorandum of understanding (the “MOU”) with OMP regarding the funding of Bobcat DevCo LLC’s (“Bobcat DevCo”) capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC, as amended (the “First A&R Bobcat LLCA”), OMS and OMP are each required to make pro-rata capital contributions to Bobcat DevCo in accordance with their respective percentage ownership interests in Bobcat DevCo.

Pursuant to the MOU, OMP agreed to make up to $80.0 million of capital contributions to Bobcat DevCo that OMS would otherwise be required to contribute under the First A&R Bobcat LLCA. In connection with execution of the MOU, OMS and OMP have amended the First A&R Bobcat LLCA and entered into the Second Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC (the “Second A&R Bobcat LLCA”). The Second A&R Bobcat LLCA includes provisions applicable to the disproportionate capital contributions that OMP will make to Bobcat DevCo in connection with the 2019 Capital Expenditures Arrangement.

Pursuant to the Second A&R Bobcat LLCA, upon the occurrence of a disproportionate capital contribution, the percentage interests of OMS and OMP in Bobcat DevCo will be adjusted to take into account the amount of the disproportionate capital contribution. During the three and six months ended June 30, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $35.8 million and $52.8 million, respectively. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 67.5% as of June 30, 2019.

4. Revenue Recognition

Disaggregation of revenues

Revenues associated with contracts with customers for crude oil, natural gas and natural gas liquids (“NGL”) sales were as follows for the three and six months ended June 30, 2019 and 2018:


Exploration and Production Revenues
	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Crude oil revenues	$	327,977	$	363,182	$	646,098	$	689,492
Purchased crude oil sales	106,441		127,212		253,577		194,872
Natural gas revenues	9,734		23,059		41,330		50,021
Purchased natural gas sales	2,920		496		4,255		545
NGL revenues	19,293		11,608		38,358		24,931
Total exploration and production revenues	$	466,365	$	525,557	$	983,618	$	959,861

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Revenues associated with contracts with customers for midstream services under fee-based arrangements and midstream product sales from purchase arrangements were as follows for the three and six months ended June 30, 2019 and 2018:


Midstream Revenues⁽¹⁾
	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Midstream service revenues
Crude oil and natural gas revenues	$	22,875	$	17,907	$	47,538	$	35,936
Produced and flowback water revenues	9,473		9,058		18,506		17,934
Total midstream service revenues	$	32,348	$	26,965	$	66,044	$	53,870
Midstream product revenues
Purchased crude oil sales	$	28	$	356	$	28	$	356
Natural gas and NGL revenues	17,319		—		30,116		—
Freshwater revenues	1,906		2,377		3,434		3,394
Total midstream product revenues	$	19,253	$	2,733	$	33,578	$	3,750
Total midstream revenues	$	51,601	$	29,698	$	99,622	$	57,620

__________________

(1)Represents midstream revenues, excluding all intercompany revenues for work performed by the midstream services business segment for the Company’s ownership interests that are eliminated in consolidation and are therefore not included in consolidated midstream services revenues.

Revenues associated with contracts with customers for well services were as follows for the three and six months ended June 30, 2019 and 2018:


Well Services Revenues⁽¹⁾
	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Hydraulic fracturing revenues	$	10,628	$	17,390	$	20,403	$	27,816
Equipment rental revenues	811		1,106		1,494		2,266
Total well services revenues	$	11,439	$	18,496	$	21,897	$	30,082

__________________

(1)Represents well services revenues, excluding all intercompany revenues for work performed by the well services business segment for the Company’s ownership interests that are eliminated in consolidation and are therefore not included in consolidated well services revenues.

Prior period performance obligations

For sales of commodities, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. For the three and six months ended June 30, 2019 and 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Contract balances

Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract liabilities are recorded for consideration received from customers primarily related to (i) temporary deficiency quantities under minimum volume commitments, which are recognized as revenue when the customer makes up the volumes or the deficiency makeup period expires and (ii) aid in construction payments received from customers which are recognized as revenue over the expected period of future benefit. The Company does not recognize contract assets or contract liabilities under its customer contracts for which invoicing occurs once the Company’s performance obligations have been satisfied and payment is

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unconditional. No material contract balances were recorded in the condensed consolidated financial statements at June 30, 2019 or December 31, 2018.

Remaining performance obligations

The following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of June 30, 2019:


	(In thousands)
2019 (excluding the six months ended June 30, 2019)	$	11,189
2020	24,183
2021	27,035
2022	19,262
2023	12,642
Thereafter	14,642
Total	$	108,953

The partially and wholly unsatisfied performance obligations presented in the table above are generally limited to customer contracts which have fixed pricing and fixed volume terms and conditions, which generally include customer contracts with minimum volume commitment payment obligations.

The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which the Company recognizes revenue under the right to invoice practical expedient.

5. Inventory

Crude oil inventory includes crude oil in tanks and linefill. Linefill that represents the minimum volume of product in a pipeline system that enables the system to operate is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil linefill in third party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Condensed Consolidated Balance Sheets.

Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations, well fracturing equipment and spare parts and equipment for the Company’s midstream assets.

Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.

Total inventory consists of the following:


	June 30, 2019		December 31, 2018

	(In thousands)
Inventory
Crude oil inventory	$	11,923	$	14,933
Equipment and materials	18,133		18,195
Total inventory	$	30,056	$	33,128

Long-term inventory
Linefill in third party pipelines	$	13,286	$	12,260
Total long-term inventory	$	13,286	$	12,260

Total	$	43,342	$	45,388

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6. Accounts Receivable

The following table sets forth the Company’s accounts receivable, net:


	June 30, 2019		December 31, 2018

	(In thousands)

Trade accounts	$	262,189	$	245,546
Joint interest accounts	124,395		133,375
Other accounts	11,137		10,207
Total	397,721		389,128
Allowance for doubtful accounts	(1,617)		(1,526)
Total accounts receivable, net	$	396,104	$	387,602

7. 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.

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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 June 30, 2019
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Money market funds	$	144	$	—	$	—	$	144
Commodity derivative instruments (see Note 8)	—		24,725		—		24,725
Total assets	$	144	$	24,725	$	—	$	24,869
Liabilities:
Commodity derivative instruments (see Note 8)	$	—	$	4,445	$	—	$	4,445
Total liabilities	$	—	$	4,445	$	—	$	4,445


	Fair value at December 31, 2018
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Money market funds	$	143	$	—	$	—	$	143
Commodity derivative instruments (see Note 8)	—		106,875		—		106,875
Total assets	$	143	$	106,875	$	—	$	107,018
Liabilities:
Commodity derivative instruments (see Note 8)	$	—	$	104	$	—	$	104
Total liabilities	$	—	$	104	$	—	$	104

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 Sheets at June 30, 2019 and December 31, 2018. 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 crude 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. 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 asset by $0.1 million at June 30, 2019 and by $0.2 million at December 31, 2018.

There were no transfers between fair value levels during the six months ended June 30, 2019 and twelve months ended December 31, 2018.

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8. Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. The Company’s crude oil contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”), the average Intercontinental Exchange, Inc. Brent crude oil index price (“ICE Brent”), the average Argus WTI Midland crude oil index price (“Midland”) and the average Argus WTI Houston crude oil index price (“Houston”). The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).

At June 30, 2019, the Company utilized fixed price swaps, basis swaps and two-way and three-way costless collars to reduce the volatility of crude oil and natural gas prices on a significant portion of its future expected crude oil and natural gas production. The Company’s fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor), which the Company will receive for the volumes under contract. A basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relation to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume. 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 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 Sheets as either assets or liabilities measured at its fair value (see Note 7 — 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 Statements 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 Statements of Cash Flows.

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At June 30, 2019, the Company had the following outstanding commodity derivative instruments:


Commodity	Settlement Period	Derivative Instrument	Index	Volumes				Weighted Average Prices														Fair Value Assets (Liabilities)
																Fixed Price Swaps		Basis Swaps	Sub-Floor	Floor	Ceiling
																					(In thousands)
Crude oil	2019	Fixed price swaps	NYMEX WTI	4,000,000	Bbl	$	57.04									$	(3,303)
Crude oil	2019	Basis swaps	ICE Brent-NYMEX WTI	60,000	Bbl			$	9.68							86
Crude oil	2019	Basis swaps	Midland-NYMEX WTI	120,000	Bbl			$	(6.71)							(740)
Crude oil	2019	Basis swaps	Houston-NYMEX WTI	366,000	Bbl			$	4.55							90
Crude oil	2019	Two-way collar	NYMEX WTI	2,592,000	Bbl							$	57.87	$	74.22	7,308
Crude oil	2019	Three-way collar	NYMEX WTI	2,196,000	Bbl					$	40.14	$	51.52	$	65.92	(284)
Crude oil	2020	Fixed price swaps	NYMEX WTI	2,597,000	Bbl	$	59.30									6,728
Crude oil	2020	Two-way collar	NYMEX WTI	434,000	Bbl							$	58.07	$	74.64	1,835
Crude oil	2020	Three-way collar	NYMEX WTI	4,268,000	Bbl					$	40.00	$	53.49	$	64.49	4,790
Crude oil	2021	Fixed price swaps	NYMEX WTI	93,000	Bbl	$	58.85									357
Crude oil	2021	Three-way collar	NYMEX WTI	310,000	Bbl					$	40.00	$	52.97	$	63.76	376
Natural gas	2019	Fixed price swaps	NYMEX HH	5,520,000	MMBtu	$	2.92									3,037
																$	20,280

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Subsequent to June 30, 2019, the Company entered into additional fixed price swaps and two-way and three-way costless collars. As of August 9, 2019, the Company had the following outstanding commodity derivative contracts:


Commodity	Settlement Period	Derivative Instrument	Index	Volumes				Weighted Average Prices
														Fixed Price Swaps			Basis Swaps	Sub-Floor	Floor	Ceiling
Crude oil	2019	Fixed price swaps	NYMEX WTI	4,122,000	Bbl	$	57.13
Crude oil	2019	Basis swaps	ICE Brent-NYMEX WTI	60,000	Bbl			$	9.68
Crude oil	2019	Basis swaps	Midland-NYMEX WTI	120,000	Bbl			$	(6.71)
Crude oil	2019	Basis swaps	Houston-NYMEX WTI	366,000	Bbl			$	4.55
Crude oil	2019	Two-way collar	NYMEX WTI	2,592,000	Bbl							$	57.87		$	74.22
Crude oil	2019	Three-way collar	NYMEX WTI	2,196,000	Bbl					$	40.14	$	51.52		$	65.92
Crude oil	2020	Fixed price swaps	NYMEX WTI	2,992,000	Bbl	$	59.05
Crude oil	2020	Two-way collar	NYMEX WTI	1,650,000	Bbl							$	53.04		$	64.95
Crude oil	2020	Three-way collar	NYMEX WTI	4,574,000	Bbl					$	40.00	$	53.26		$	64.48
Crude oil	2021	Fixed price swaps	NYMEX WTI	93,000	Bbl	$	58.85
Crude oil	2021	Two-way collar	NYMEX WTI	62,000	Bbl							$	50.50		$	60.70
Crude oil	2021	Three-way collar	NYMEX WTI	734,000	Bbl					$	40.00	$	51.26		$	64.05
Natural gas	2019	Fixed price swaps	NYMEX HH	5,520,000	MMBtu	$	2.92

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 Statements of Operations for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
Statements of Operations Location	2019		2018		2019		2018

	(In thousands)
Net gain (loss) on derivative instruments	$	34,749	$	(120,285)	$	(82,862)	$	(191,401)

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 Sheets.

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


		June 30, 2019
Commodity	Balance Sheet Location	Gross Recognized Assets/Liabilities		Gross Amount Offset		Net Recognized Fair Value Assets/ Liabilities

		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	28,196	$	(9,107)	$	19,089
Commodity contracts	Derivative instruments — non-current assets	12,237		(6,601)		5,636
Total derivatives assets				$	40,433	$	(15,708)	$	24,725
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	11,265	$	(6,820)	$	4,445
Commodity contracts	Derivative instruments — non-current liabilities	—		—		—
Total derivatives liabilities				$	11,265	$	(6,820)	$	4,445

		December 31, 2018
Commodity	Balance Sheet Location	Gross Recognized Assets/Liabilities		Gross Amount Offset		Net Recognized Fair Value Assets/Liabilities

		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	110,729	$	(10,799)	$	99,930
Commodity contracts	Derivative instruments — non-current assets	8,251		(1,306)		6,945
Total derivatives assets				$	118,980	$	(12,105)	$	106,875
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	84	$	—	$	84
Commodity contracts	Derivative instruments — non-current liabilities	20		—		20
Total derivatives liabilities				$	104	$	—	$	104

9. Property, Plant and Equipment

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


	June 30, 2019		December 31, 2018

	(In thousands)
Proved oil and gas properties⁽¹⁾	$	8,244,667	$	7,878,104
Less: Accumulated depreciation, depletion, amortization and impairment	(3,205,534)		(2,853,353)
Proved oil and gas properties, net	5,039,133		5,024,751
Unproved oil and gas properties	1,038,795		1,034,085
Other property and equipment⁽²⁾	1,301,835		1,151,772
Less: Accumulated depreciation	(210,649)		(183,499)
Other property and equipment, net	1,091,186		968,273
Total property, plant and equipment, net	$	7,169,114	$	7,027,109

__________________

(1)Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $42.2 million and $40.5 million at June 30, 2019 and December 31, 2018, respectively.

(2)Included in the Company’s other property and equipment are estimates of future asset retirement costs of $1.4 million and $1.3 million at June 30, 2019 and December 31, 2018, respectively.

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10. Divestitures

During the six months ended June 30, 2019, the Company completed the final closing statements for the sale of non-strategic oil and gas properties and certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin. The Company recognized an additional $0.3 million and $3.2 million net loss on sale of properties, which includes customary closing adjustments, in its Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2019, respectively. The additional amounts recognized for the divested properties were in the Company’s exploration and production segment.

11. Long-Term Debt

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


	June 30, 2019		December 31, 2018

	(In thousands)
Oasis Credit Facility	$	531,000	$	468,000
OMP Credit Facility	408,000		318,000
Senior unsecured notes

6.50% senior unsecured notes due November 1, 2021	71,835		71,835
6.875% senior unsecured notes due March 15, 2022	901,480		901,480
6.875% senior unsecured notes due January 15, 2023	366,094		366,094
6.25% senior unsecured notes due May 1, 2026	400,000		400,000
2.625% senior unsecured convertible notes due September 15, 2023	300,000		300,000
Total principal of senior unsecured notes	2,039,409		2,039,409
Less: unamortized deferred financing costs on senior unsecured notes	(18,507)		(20,865)
Less: unamortized debt discount on senior unsecured convertible notes	(63,378)		(69,268)
Total long-term debt	$	2,896,524	$	2,735,276

Senior secured revolving line of credit. The Company has a senior secured revolving line of credit among OPNA, as Borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “Oasis Credit Facility”) with an overall senior secured line of credit of $3,000.0 million as of June 30, 2019, which has a maturity date of the earlier of (i) October 16, 2023, (ii) 90 days prior to the maturity date of the Company’s senior unsecured notes due in 2022 and 2023, of which $1,267.6 million is outstanding, to the extent such senior unsecured notes are not retired or refinanced to have a maturity date at least 90 days after October 16, 2023 and (iii) 90 days prior to the maturity date of the Company’s senior unsecured convertible notes due in 2023, of which $300.0 million is outstanding, to the extent such senior unsecured convertible notes are not retired, converted, redeemed or refinanced to have a maturity date at least 90 days after October 16, 2023.

The Oasis 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. On April 15, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2019, which reaffirmed the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively. In connection with the April 1, 2019 borrowing base redetermination, the Company entered into the First Amendment to the Third Amended and Restated Credit Agreement to the Oasis Credit Facility, dated April 15, 2019, which, among other things, incorporated the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million. All other significant rates, terms and conditions of the Oasis Credit Facility remained the same. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for October 1, 2019.

At June 30, 2019, the Company had $531.0 million of London Interbank Offered Rate (“LIBOR”) loans at a weighted average interest rate of 4.2% and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $805.0 million. On a quarterly basis, the Company also pays a commitment fee that can range from 0.375% to 0.500% 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 Oasis Credit Facility as of June 30, 2019.

OMP Operating LLC revolving line of credit. Through its ownership of OMP, the Company has access to a senior secured revolving credit facility among OMP, as parent, OMP Operating LLC, a subsidiary of OMP, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “OMP Credit Facility,” and, together with the Oasis Credit Facility, the “Revolving Credit Facilities”). The OMP Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. On May 6, 2019, OMP entered into an amendment to the OMP Credit

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Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million; (ii) provide for the ability to further increase commitments to $675.0 million; and (iii) add a new lender to the bank group. As of June 30, 2019, the OMP Credit Facility has an aggregate amount of commitments of $475.0 million and has a maturity date of September 25, 2022.

At June 30, 2019, the Company had $408.0 million of borrowings outstanding under the OMP Credit Facility at a weighted average interest rate of 4.2%, and $8.2 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $58.8 million. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%. The Company was in compliance with the financial covenants under the OMP Credit Facility at June 30, 2019.

The Revolving Credit Facilities are recorded at values that approximate fair value since their variable interest rates are tied to current market rates.

Senior unsecured notes. At June 30, 2019, the Company had $1,739.4 million principal amount of senior unsecured notes outstanding with maturities ranging from November 2021 to May 2026 and coupons ranging from 6.25% to 6.875% (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.

Senior unsecured convertible notes. At June 30, 2019, the Company had $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 commencing after the calendar quarter ending on September 30, 2016 (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 June 30, 2019, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, the Company was in compliance with the terms of the indentures for the Senior Convertible Notes as of June 30, 2019.

Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The fair value of the Notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $1,997.5 million at June 30, 2019. 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.

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12. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2019:


	(In thousands)
Balance at December 31, 2018	$	52,449
Liabilities incurred during period	1,019
Liabilities settled during period	(139)
Accretion expense during period⁽¹⁾	1,928
Revisions to estimates	827

Balance at June 30, 2019	$	56,084

___________________

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

At June 30, 2019, the current portion of the total ARO balance was approximately $0.9 million and was included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheets.

13. Income Taxes

The Company’s effective tax rate for the three and six months ended June 30, 2019 was 19.3% on a pre-tax income of $63.4 million and (17.7)% on a pre-tax loss of $48.3 million, respectively, as compared to an effective tax rate of 24.2% on a pre-tax loss of $417.3 million and 24.3% on a pre-tax loss of $412.8 million for the three and six months ended June 30, 2018, respectively.

The effective tax rate for the three months ended June 30, 2019 was lower than the statutory federal rate of 21% primarily due to the impact of non-controlling interests, partially offset by state income taxes and the impact of other permanent differences, primarily non-deductible executive compensation. The effective tax rate for the six months ended June 30, 2019 was lower than the statutory federal rate of 21% primarily due to the impacts of non-controlling interests and equity-based compensation shortfalls. These decreases were partially offset by state income taxes and other permanent differences, primarily non-deductible executive compensation.

The effective tax rate for the three and six months ended June 30, 2018 was higher than the statutory federal rate of 21% primarily due to state income taxes.

14. Equity-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 awards 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 six months ended June 30, 2019, employees and non-employee directors of the Company were granted restricted stock awards equal to 4,035,175 shares of common stock with a $6.62 weighted average grant date per share value. Equity-based compensation expense recorded for restricted stock awards was $6.3 million and $12.6 million for the three and six months ended June 30, 2019, respectively, and $4.9 million and $9.6 million for the three and six months ended June 30, 2018, respectively. Equity-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statements 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.

The Company accounts for 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, stock

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price on the date of grant, 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 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 equity-based compensation expense of the PSUs granted during the six months ended June 30, 2019:


Risk-free interest rate	2.55% - 2.56%
Oasis volatility	71.17	%
Oasis initial value	$5.85
Oasis stock price on date of grant	$6.63

During the six months ended June 30, 2019, officers of the Company were granted 1,685,090 PSUs with a $6.80 weighted average grant date per unit value. Equity-based compensation expense recorded for PSUs was $2.5 million and $5.0 million for the three and six months ended June 30, 2019, respectively, and $2.3 million and $4.2 million for the three and six months ended June 30, 2018, respectively. Equity-based compensation expense is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.

OMP phantom unit awards. The Company has granted OMP phantom unit awards (collectively, the “OMP Phantom Unit Awards,” and each an “OMP Phantom Unit”) to employees under its Amended and Restated 2010 Long Term Incentive Plan in 2018 and 2019, and in 2017, under OMP GP’s Oasis Midstream Partners LP 2017 Long Term Incentive Plan.

Each OMP Phantom Unit represents the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one OMP common unit on the day prior to the date it vests (the “Vesting Date”). Award recipients are also entitled to Distribution Equivalent Rights (“DER”) with respect to each OMP Phantom Unit received. Each DER represents the right to receive, upon vesting of the award, a cash payment equal to the value of the distributions paid on one OMP common unit between the grant date and the applicable Vesting Date. The OMP Phantom Unit Awards vest in equal amounts each year over a three-year period, and compensation expense will be recognized over the requisite service period and is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.

The OMP Phantom Unit Awards are accounted for as liability-classified awards since the awards will settle in cash, and equity-based compensation expense is accounted for under the fair value method in accordance with GAAP. Under the fair value method for liability-classified awards, compensation expense is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay, or will reimburse OMP, for the cash settlement amount of these awards.

During the six months ended June 30, 2019, the Company granted 341,290 OMP Phantom Unit Awards to certain employees of Oasis with a weighted average grant date fair value of $18.57 per unit. Equity-based compensation expense recorded for the OMP Phantom Unit Awards was $0.8 million and $1.5 million for the three and six months ended June 30, 2019, respectively, and $0.1 million and $0.2 million for the three and six months ended June 30, 2018, respectively, and is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.

OMP restricted unit awards. During the six months ended June 30, 2019, independent directors of OMP were granted 16,170 restricted unit awards, which vest over a one-year period with a weighted average grant date fair value of $18.57 per common unit. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. Equity-based compensation cost is accounted for under the fair value method in accordance with GAAP. Under the fair value method for equity-classified awards, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the vesting period. Equity-based compensation expense recorded for these awards was approximately $0.1 million and $0.2 million for the three and six months ended June 30, 2019, respectively, and $0.1 million and $0.2 million for the three and six months ended June 30, 2018, respectively, and is included in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations.

15. Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis 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 unvested restricted stock awards and contingently issuable shares related to PSUs and the Senior Convertible Notes during the periods presented, unless its effect is anti-dilutive. There are no adjustments made to the income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share.

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The following is a calculation of the basic and diluted weighted average shares outstanding for the three and six months ended June 30, 2019 and 2018:


	Three Months Ended June 30,			Six Months Ended June 30,
	2019	2018	2019	2018

	(In thousands)
Basic and diluted weighted average common shares outstanding	314,982	313,072	314,724	301,652

For the six months ended June 30, 2019 and for the three and six months ended June 30, 2018, the Company incurred a net loss, and therefore the diluted loss per share calculation for the period excludes the anti-dilutive effect of unvested stock awards. In addition, the diluted earnings per share calculation for the three months ended June 30, 2019 excludes the dilutive effect of unvested stock awards that were anti-dilutive under the treasury stock method. 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 June 30,			Six Months Ended June 30,
	2019	2018	2019	2018

	(In thousands)
Restricted stock awards and PSUs	10,406	7,515	10,369	7,440

The Company issued its Senior Convertible Notes in September 2016 (see Note 11 — Long-Term Debt). The Company has the option to settle conversions of its Senior Convertible 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. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of June 30, 2019 and 2018, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for the three and six months ended June 30, 2019 and 2018.

16. 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 crude oil and natural gas production. The Company’s midstream services business segment performs produced and flowback water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for crude oil and natural gas wells operated by the Company as well as third-party operated wells. Revenues for the midstream segment are primarily derived from produced and flowback water pipeline transport, produced and flowback 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 performs completion services for the Company’s crude oil and natural gas wells. 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 OMP, OMS and OWS for the Company's ownership 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 Statements 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 (“DD&A”).

For the three and six months ended June 30, 2018, the Company has revised the condensed consolidated financial statements and business segment financial information to reflect the correction of errors related to the manner in which it accounted for certain crude oil purchase and sale arrangements, which are included in the Company’s exploration and production segment and had no effect on operating income. Please see Note 2 — Summary of Significant Accounting Policies for more information related to the revision.

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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 June 30, 2019:
Revenues from non-affiliates	$	466,365	$	51,601	$	11,439	$	—	$	529,405
Inter-segment revenues	—		67,844		27,842		(95,686)		—
Total revenues	466,365		119,445		39,281		(95,686)		529,405
Operating income	18,895		55,216		1,487		(4,026)		71,572
Other income (expense), net	(3,970)		(4,200)		12		—		(8,158)
Income before income taxes including non-controlling interests	$	14,925	$	51,016	$	1,499	$	(4,026)	$	63,414
General and administrative	$	25,761	$	7,980	$	6,088	$	(8,903)	$	30,926
Equity-based compensation	8,522		515		527		(653)		8,911

Three months ended June 30, 2018:
Revenues from non-affiliates	$	525,557	$	29,698	$	18,496	$	—	$	573,751
Inter-segment revenues	—		39,710		41,418		(81,128)		—
Total revenues	525,557		69,408		59,914		(81,128)		573,751
Operating income (loss)	(280,090)		37,894		8,028		(8,506)		(242,674)
Other income (expense), net	(174,572)		(79)		23		—		(174,628)
Income (loss) before income taxes including non-controlling interests	$	(454,662)	$	37,815	$	8,051	$	(8,506)	$	(417,302)
General and administrative	$	23,492	$	6,079	$	5,756	$	(7,097)	$	28,230
Equity-based compensation	7,012		409		409		(454)		7,376

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Six months ended June 30, 2019:
Revenues from non-affiliates	$	983,618	$	99,622	$	21,897	$	—	$	1,105,137
Inter-segment revenues	—		126,405		50,015		(176,420)		—
Total revenues	983,618		226,027		71,912		(176,420)		1,105,137
Operating income	20,819		105,022		2,302		(6,127)		122,016
Other income (expense), net	(162,352)		(7,948)		17		—		(170,283)
Income (loss) before income taxes including non-controlling interests	$	(141,533)	$	97,074	$	2,319	$	(6,127)	$	(48,267)
General and administrative	$	53,288	$	16,841	$	13,549	$	(18,293)	$	65,385
Equity-based compensation	17,102		980		1,088		(1,246)		17,924

Six months ended June 30, 2018:
Revenues from non-affiliates	$	959,861	$	57,620	$	30,082	$	—	$	1,047,563
Inter-segment revenues	—		76,350		74,721		(151,071)		—
Total revenues	959,861		133,970		104,803		(151,071)		1,047,563
Operating income (loss)	(200,130)		70,132		16,178		(15,869)		(129,689)
Other expense, net	(282,717)		(336)		(20)		—		(283,073)
Income (loss) before income taxes including non-controlling interests	$	(482,847)	$	69,796	$	16,158	$	(15,869)	$	(412,762)
General and administrative	$	46,971	$	12,493	$	11,647	$	(14,941)	$	56,170
Equity-based compensation	13,463		780		795		(908)		14,130

At June 30, 2019:
Property, plant and equipment, net	$	6,336,438	$	1,024,625	$	30,792	$	(222,741)	$	7,169,114
Total assets⁽¹⁾	6,804,705		1,057,033		36,292		(187,742)		7,710,288
At December 31, 2018:
Property, plant and equipment, net	$	6,311,566	$	893,285	$	38,871	$	(216,613)	$	7,027,109
Total assets⁽¹⁾	6,838,987		920,619		48,150		(181,614)		7,626,142

___________________

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

17. Leases

As discussed in Note 2 — Summary of Significant Accounting Policies, the Company adopted ASC 842 as of January 1, 2019 using the modified retrospective method, which resulted in the Company recognizing operating lease ROU assets and lease liabilities of $31.1 million and $37.1 million, respectively. In addition, the Company recognized offsetting finance lease ROU assets and lease liabilities of $6.0 million. There was no impact to the opening equity balance as a result of adoption as the difference between the asset and liability balance is attributable to reclasses of pre-existing balances, such as deferred rent, into the lease asset balance. Prior period amounts are not adjusted and continue to be reported in accordance with the previous guidance, Accounting Standards Codification 840 (“ASC 840”).

In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception. The Company’s operating and finance leases consist primarily of office space, drilling rigs, vehicles and other property and equipment used in its operations. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.

As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company has

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determined their respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.

For the three and six months ended June 30, 2019, the Company incurred lease expenses, which includes short-term leases. The following table sets forth the Company’s components of lease expense:


	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019

	(In thousands)
Operating lease costs	$	6,799	$	18,475
Variable lease costs⁽¹⁾	3,963		5,003
Short-term lease costs	907		1,370
Finance lease costs:
Amortization of ROU assets	650		1,216
Interest on lease liabilities	69		124
Total lease costs	$	12,388	$	26,188

___________________

(1)Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs.

The amounts disclosed herein include costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners.

The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Condensed Consolidated Balance Sheets or are recognized in the Company’s Condensed Consolidated Statements of Operations in lease operating expenses, midstream expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets and the interest on lease liabilities disclosed above are included in depreciation, depletion and amortization and interest expense, net of capitalized interest, respectively, on the Company’s Condensed Consolidated Statements of Operations.

As of June 30, 2019, maturities of the Company’s lease liabilities are as follows:


	Operating Leases		Finance Leases

	(In thousands)
2019 (excluding the six months ended June 30, 2019)	$	6,276	$	1,440
2020	4,594		2,881
2021	1,680		2,068
2022	2,297		1,298
2023	2,345		234
Thereafter	12,802		684
Total future lease payments	$	29,994	$	8,605
Less: Imputed interest	4,137		705
Present value of future lease payments	$	25,857	$	7,900

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As of December 31, 2018, future minimum annual rental commitments under non-cancelable leases under ASC 840 were as follows:


	(In thousands)
2019	$	8,723
2020	7,009
2021	6,005
2022	5,130
2023	4,361
Thereafter	13,134
Total future minimum lease payments	$	44,362

Supplemental balance sheet information related to the Company’s leases are as follows:

Balance Sheet Location

June 30, 2019

(In thousands)

Assets

Operating lease assets

Operating right-of-use assets

20,054

Finance lease assets⁽¹⁾

Other assets

7,900

Total lease assets

27,954

Liabilities

Current

Operating lease liabilities

Current operating lease liabilities

7,837

Finance lease liabilities

Other current liabilities

2,626

Long-term

Operating lease liabilities

18,021

Finance lease liabilities

Other liabilities

5,247

Total lease liabilities

33,731

___________________

(1)Finance lease ROU assets are recorded net of accumulated amortization of $1.2 million as of June 30, 2019.

Supplemental cash flow information and non-cash transactions related to the Company’s leases are as follows:


	June 30, 2019
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	16,696
Operating cash flows from finance leases	124
Financing cash flows from finance leases	941
ROU assets obtained in exchange for lease obligations
Operating leases	$	6,803
Finance leases	3,174

Weighted-average remaining lease term and discount rate for the Company’s leases are as follows:


	As of June 30, 2019
Operating Leases
Weighted average remaining lease term	7.1 years
Weighted average discount rate	4.0	%
Finance Leases
Weighted average remaining lease term	4.1 years
Weighted average discount rate	3.8	%

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18. Commitments and Contingencies

As of June 30, 2019, there have been no material changes to the Company’s future commitments disclosed in Note 20 — Commitments and Contingencies in the Company's 2018 Annual Report, except as noted below. The amounts disclosed represent undiscounted cash flows on a gross basis, and no inflation elements have been applied.

Volume commitment agreements. As of June 30, 2019, the Company had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 48.3 MMBbl of crude oil, 39.5 MMBbl of natural gas liquids, 900.2 Bcf of natural gas and 31.7 MMBbl of water, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less. As of June 30, 2019, the estimable future commitments under these agreements were approximately $643.1 million. The future commitments under certain agreements cannot be estimated as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the Williston Basin for the production month. The commitments under these arrangements are not recorded in the accompanying Condensed Consolidated Balance Sheet as of June 30, 2019.

Lease commitments. The Company has various operating and finance lease commitments that consists primarily of offices, drilling rigs, vehicles and other property and equipment used in its operations. See Note 17 — Leases for additional information.

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 Oasis Midstream Services LLC, 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) 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 natural 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.”

On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.

On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleged new legal theories for being entitled to enforce the underlying contracts and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada.

On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added Oasis Midstream Partners LP as a defendant, asserting that it was created in bad faith in an effort to avoid contractual obligations owed to Mirada.

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 that do not apply to the Company. The Company filed answers denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims.

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On July 2, 2019, Oasis, OPNA, Oasis Midstream Services LLC, Oasis Midstream Partners LP, Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC (collectively “Oasis Entities”) counterclaimed against Mirada for a judgment declaring that Oasis Entities are not obligated to purchase, manage, gather, transport, compress, process, market, sell or otherwise handle Mirada’s proportionate share of oil and gas produced from OPNA-operated wells. The counterclaim also seeks attorney’s fees, costs and expenses.

Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is scheduled for February 2020. 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, financial condition, results of operations or cash flows. 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. In addition, the Company has agreed to indemnify OMP for any losses resulting from this litigation under the omnibus agreement it entered into with OMP at the time of OMP’s initial public offering.

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19. Condensed Consolidating Financial Information

The Notes (see Note 11 — 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 operating units, including OMP, which is accounted for on a consolidated basis, do not guarantee the Notes (“Non-Guarantor Subsidiaries”).

The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), its Guarantors on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity basis of accounting. 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.

During the preparation of the condensed consolidating financial information as of and for the three and six months ended June 30, 2019, the Company identified errors primarily relating to the presentation of non-controlling interests and equity in earnings of subsidiaries in the financial information of the Combined Guarantor Subsidiaries and the related intercompany eliminations.

•Condensed Consolidating Balance Sheet. As of December 31, 2018, it was determined that (1) in the Issuer's financial information, investment in and advances to subsidiaries and Oasis share of stockholders’ equity were both overstated by $9.6 million, (2) in the Combined Guarantor Subsidiaries financial information, investment in and advances to subsidiaries and non-controlling interests were overstated by $11.1 million and $184.3 million, respectively, and Oasis share of stockholders’ equity was understated by $173.2 million and (3) in the intercompany eliminations financial information, investments in and advances to subsidiaries and non-controlling interests were understated by $20.7 million and $184.3 million, respectively, and Oasis share of stockholders’ equity was overstated by $163.6 million.

•Condensed Consolidated Statements of Operations. For the three months ended June 30, 2018, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $6.6 million and $3.9 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $6.6 million and $3.9 million, respectively, in the intercompany eliminations financial information. For the six months ended June 30, 2018, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $11.4 million and $7.0 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $11.4 million and $7.0 million, respectively, in the intercompany eliminations financial information.

•Condensed Consolidated Statement of Cash Flows. For the six months ended June 30, 2018, it was determined that cash paid for distributions to non-controlling interests was understated by $48.9 million in the Combined Guarantor Subsidiaries financial information and overstated by $48.9 million in the intercompany eliminations financial information, with the offsetting impacts in investment in subsidiaries / capital contributions from parent.

These errors in the condensed consolidated financial information, which the Company has determined are not material to this disclosure, were all eliminated in consolidation and therefore have no impact on the Company's consolidated financial position, results of operations or cash flows. The Company has revised the condensed consolidating financial information as of December 31, 2018 and for the three and six months ended June 30, 2018 to reflect the correction of these errors.

In addition, for the three and six months ended June 30, 2018, the Company has revised the condensed consolidating financial information to reflect the correction of errors related to the manner in which it accounted for certain crude oil purchase and sale arrangements, which had no effect on the Company’s or any of its subsidiaries’ net income (loss). All impacts of this revision are included in the Combined Guarantor Subsidiaries financial information. Please see Note 2 — Summary of Significant Accounting Policies for more information related to this revision.

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Condensed Consolidating Balance Sheet


	June 30, 2019
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	144	$	13,868	$	6,246	$	—	$	20,258

Accounts receivable, net	—		390,094		6,010		—		396,104
Accounts receivable - affiliates	585,473		79,516		80,088		(745,077)		—
Inventory	—		30,056		—		—		30,056
Prepaid expenses	273		4,478		1,267		—		6,018

Derivative instruments	—		19,089		—		—		19,089

Other current assets	—		195		—		—		195
Total current assets	585,890		537,296		93,611		(745,077)		471,720
Property, plant and equipment
Oil and gas properties (successful efforts method)	—		9,299,365		—		(15,903)		9,283,462
Other property and equipment	—		241,456		1,060,379		—		1,301,835
Less: accumulated depreciation, depletion, amortization and impairment	—		(3,336,023)		(80,160)		—		(3,416,183)
Total property, plant and equipment, net	—		6,204,798		980,219		(15,903)		7,169,114

Investments in and advances to subsidiaries	4,886,462		367,275		—		(5,253,737)		—
Derivative instruments	—		5,636		—		—		5,636
Deferred income taxes	243,866		—		—		(243,866)		—
Long-term inventory	—		13,286		—		—		13,286
Operating right-of-use assets	—		16,412		3,642		—		20,054
Other assets	—		27,093		3,385		—		30,478
Total assets	$	5,716,218	$	7,171,796	$	1,080,857	$	(6,258,583)	$	7,710,288
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	14,381	$	774	$	—	$	15,155
Accounts payable - affiliates	44,643		665,561		34,873		(745,077)		—
Revenues and production taxes payable	—		169,786		748		—		170,534
Accrued liabilities	183		258,337		56,930		—		315,450
Accrued interest payable	37,096		312		293		—		37,701
Derivative instruments	—		4,445		—		—		4,445

Advances from joint interest partners	—		4,076		—		—		4,076
Current operating lease liabilities	—		5,786		2,051		—		7,837
Other current liabilities	—		2,620		610		—		3,230
Total current liabilities	81,922		1,125,304		96,279		(745,077)		558,428
Long-term debt	1,957,524		531,000		408,000		—		2,896,524
Deferred income taxes	—		552,538		—		(243,866)		308,672
Asset retirement obligations	—		53,664		1,564		—		55,228


Operating lease liabilities	—		16,424		1,597		—		18,021
Other liabilities	—		6,404		553		—		6,957
Total liabilities	2,039,446		2,285,334		507,993		(988,943)		3,843,830
Stockholders’ equity






Oasis share of stockholders’ equity	3,676,772		4,886,462		257,733		(5,144,195)		3,676,772
Non-controlling interests	—		—		315,131		(125,445)		189,686
Total stockholders’ equity	3,676,772		4,886,462		572,864		(5,269,640)		3,866,458
Total liabilities and stockholders’ equity	$	5,716,218	$	7,171,796	$	1,080,857	$	(6,258,583)	$	7,710,288

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Condensed Consolidating Balance Sheet


	December 31, 2018
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	179	$	15,362	$	6,649	$	—	$	22,190

Accounts receivable, net	—		385,121		2,481		—		387,602
Accounts receivable - affiliates	643,382		76,127		80,805		(800,314)		—
Inventory	—		33,106		22		—		33,128
Prepaid expenses	373		9,206		1,418		—		10,997

Derivative instruments	—		99,930		—		—		99,930
Intangible assets, net	—		125		—		—		125
Other current assets	—		183		—		—		183
Total current assets	643,934		619,160		91,375		(800,314)		554,155
Property, plant and equipment
Oil and gas properties (successful efforts method)	—		8,923,291		—		(11,102)		8,912,189
Other property and equipment	—		218,617		933,155		—		1,151,772
Less: accumulated depreciation, depletion, amortization and impairment	—		(2,974,122)		(62,730)		—		(3,036,852)
Total property, plant and equipment, net	—		6,167,786		870,425		(11,102)		7,027,109

Investments in and advances to subsidiaries	4,900,528		356,039		—		(5,256,567)		—
Derivative instruments	—		6,945		—		—		6,945
Deferred income taxes	219,670		—		—		(219,670)		—
Long-term inventory	—		12,260		—		—		12,260
Other assets	—		23,221		2,452		—		25,673
Total assets	$	5,764,132	$	7,185,411	$	964,252	$	(6,287,653)	$	7,626,142
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	18,567	$	1,599	$	—	$	20,166
Accounts payable - affiliates	43,113		724,187		33,014		(800,314)		—
Revenues and production taxes payable	—		216,114		581		—		216,695
Accrued liabilities	71		273,923		57,657		—		331,651
Accrued interest payable	37,096		502		442		—		38,040
Derivative instruments	—		84		—		—		84

Advances from joint interest partners	—		5,140		—		—		5,140

Total current liabilities	80,280		1,238,517		93,293		(800,314)		611,776
Long-term debt	1,949,276		468,000		318,000		—		2,735,276
Deferred income taxes	—		519,725		—		(219,670)		300,055
Asset retirement obligations	—		50,870		1,514		—		52,384

Derivative instruments	—		20		—		—		20
Other liabilities	—		7,751		—		—		7,751
Total liabilities	2,029,556		2,284,883		412,807		(1,019,984)		3,707,262
Stockholders’ equity






Oasis share of stockholders’ equity	3,734,576		4,900,528		238,630		(5,139,158)		3,734,576
Non-controlling interests	—		—		312,815		(128,511)		184,304
Total stockholders’ equity	3,734,576		4,900,528		551,445		(5,267,669)		3,918,880
Total liabilities and stockholders’ equity	$	5,764,132	$	7,185,411	$	964,252	$	(6,287,653)	$	7,626,142

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Condensed Consolidating Statement of Operations


	Three Months Ended June 30, 2019
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	357,004	$	—	$	—	$	357,004
Purchased oil and gas sales	—		109,389		—		—		109,389
Midstream revenues	—		1,082		97,644		(47,153)		51,573
Well services revenues	—		11,439		—		—		11,439
Total revenues	—		478,914		97,644		(47,153)		529,405
Operating expenses
Lease operating expenses	—		69,362		—		(13,134)		56,228
Midstream expenses	—		675		28,025		(11,332)		17,368
Well services expenses	—		8,474		—		—		8,474
Marketing, transportation and gathering expenses	—		38,574		—		(10,086)		28,488
Purchased oil and gas expenses	—		109,662		—		—		109,662
Production taxes	—		28,142		—		—		28,142
Depreciation, depletion and amortization	—		173,754		8,562		(4,958)		177,358
Exploration expenses	—		887		—		—		887

Impairment	—		24		—		—		24
General and administrative expenses	6,308		21,352		7,809		(4,543)		30,926
Total operating expenses	6,308		450,906		44,396		(44,053)		457,557
Loss on sale of properties	—		(276)		—		—		(276)
Operating income (loss)	(6,308)		27,732		53,248		(3,100)		71,572
Other income (expense)
Equity in earnings of subsidiaries	73,855		37,518		—		(111,373)		—
Net gain on derivative instruments	—		34,749		—		—		34,749
Interest expense, net of capitalized interest	(32,415)		(6,562)		(4,209)		—		(43,186)

Other income (expense)	1		282		(4)		—		279
Total other income (expense), net	41,441		65,987		(4,213)		(111,373)		(8,158)
Income before income taxes	35,133		93,719		49,035		(114,473)		63,414
Income tax benefit (expense)	7,624		(19,864)		—		—		(12,240)
Net income including non-controlling interests	42,757		73,855		49,035		(114,473)		51,174
Less: Net income attributable to non-controlling interests	—		—		22,837		(14,420)		8,417
Net income attributable to Oasis	$	42,757	$	73,855	$	26,198	$	(100,053)	$	42,757

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Condensed Consolidating Statement of Operations


	Three Months Ended June 30, 2018
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	397,849	$	—	$	—	$	397,849
Purchased oil and gas sales	—		128,064		—		—		128,064
Midstream revenues	—		917		66,558		(38,133)		29,342
Well services revenues	—		18,496		—		—		18,496
Total revenues	—		545,326		66,558		(38,133)		573,751
Operating expenses
Lease operating expenses	—		57,615		—		(13,474)		44,141
Midstream expenses	—		780		16,334		(9,426)		7,688
Well services expenses	—		13,560		—		—		13,560
Marketing, transportation and gathering expenses	—		28,653		—		(5,820)		22,833
Purchased oil and gas expenses	—		129,579		—		—		129,579
Production taxes	—		34,026		—		—		34,026
Depreciation, depletion and amortization	—		150,554		6,659		(3,643)		153,570
Exploration expenses	—		617		—		—		617

Impairment	—		384,135		—		—		384,135
General and administrative expenses	7,496		17,954		5,897		(3,117)		28,230
Total operating expenses	7,496		817,473		28,890		(35,480)		818,379
Gain on sale of properties	—		1,954		—		—		1,954
Operating income (loss)	(7,496)		(270,193)		37,668		(2,653)		(242,674)
Other income (expense)
Equity in earnings (loss) of subsidiaries	(278,014)		30,929		—		247,085		—
Net loss on derivative instruments	—		(120,285)		—		—		(120,285)
Interest expense, net of capitalized interest	(33,135)		(7,592)		(183)		—		(40,910)
Loss on extinguishment of debt	(13,651)		—		—		—		(13,651)
Other income	—		218		—		—		218
Total other expense, net	(324,800)		(96,730)		(183)		247,085		(174,628)
Income (loss) before income taxes	(332,296)		(366,923)		37,485		244,432		(417,302)
Income tax benefit	12,092		88,909		—		—		101,001
Net income (loss) including non-controlling interests	(320,204)		(278,014)		37,485		244,432		(316,301)
Less: Net income attributable to non-controlling interests	—		—		25,042		(21,139)		3,903
Net income (loss) attributable to Oasis	$	(320,204)	$	(278,014)	$	12,443	$	265,571	$	(320,204)

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Condensed Consolidating Statement of Operations


	Six Months Ended June 30, 2019
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	725,786	$	—	$	—	$	725,786
Purchased oil and gas sales	—		257,860		—		—		257,860
Midstream revenues	—		4,152		189,295		(93,853)		99,594
Well services revenues	—		21,897		—		—		21,897
Total revenues	—		1,009,695		189,295		(93,853)		1,105,137
Operating expenses
Lease operating expenses	—		141,147		—		(26,475)		114,672
Midstream expenses	—		2,523		54,940		(23,366)		34,097
Well services expenses	—		15,444		—		—		15,444
Marketing, transportation and gathering expenses	—		83,811		—		(20,373)		63,438
Purchased oil and gas expenses	—		259,566		—		—		259,566
Production taxes	—		57,760		—		—		57,760
Depreciation, depletion and amortization	—		359,823		17,491		(10,123)		367,191
Exploration expenses	—		1,717		—		—		1,717

Impairment	—		653		—		—		653
General and administrative expenses	15,395		42,177		16,529		(8,716)		65,385
Total operating expenses	15,395		964,621		88,960		(89,053)		979,923
Loss on sale of properties	—		(3,198)		—		—		(3,198)
Operating income (loss)	(15,395)		41,876		100,335		(4,800)		122,016
Other income (expense)
Equity in earnings (loss) of subsidiaries	(15,637)		72,253		—		(56,616)		—
Net loss on derivative instruments	—		(82,862)		—		—		(82,862)
Interest expense, net of capitalized interest	(65,291)		(14,406)		(7,957)		—		(87,654)

Other income (expense)	1		236		(4)		—		233
Total other expense, net	(80,927)		(24,779)		(7,961)		(56,616)		(170,283)
Income (loss) before income taxes	(96,322)		17,097		92,374		(61,416)		(48,267)
Income tax benefit (expense)	24,197		(32,734)		—		—		(8,537)
Net income (loss) including non-controlling interests	(72,125)		(15,637)		92,374		(61,416)		(56,804)
Less: Net income attributable to non-controlling interests	—		—		44,633		(29,312)		15,321
Net income (loss) attributable to Oasis	$	(72,125)	$	(15,637)	$	47,741	$	(32,104)	$	(72,125)

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Condensed Consolidating Statement of Operations


	Six Months Ended June 30, 2018
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	764,444	$	—	$	—	$	764,444
Purchased oil and gas sales	—		195,773		—		—		195,773
Midstream revenues	—		2,067		127,979		(72,782)		57,264
Well services revenues	—		30,082		—		—		30,082
Total revenues	—		992,366		127,979		(72,782)		1,047,563
Operating expenses
Lease operating expenses	—		113,314		—		(24,392)		88,922
Midstream expenses	—		1,526		33,450		(19,303)		15,673
Well services expenses	—		20,947		—		—		20,947
Marketing, transportation and gathering expenses	—		55,325		—		(11,479)		43,846
Purchased oil and gas expenses	—		200,173		—		—		200,173
Production taxes	—		65,026		—		—		65,026
Depreciation, depletion and amortization	—		296,781		13,023		(6,969)		302,835
Exploration expenses	—		1,386		—		—		1,386

Impairment	—		384,228		—		—		384,228
General and administrative expenses	14,728		35,632		12,047		(6,237)		56,170
Total operating expenses	14,728		1,174,338		58,520		(68,380)		1,179,206
Gain on sale of properties	—		1,954		—		—		1,954
Operating income (loss)	(14,728)		(180,018)		69,459		(4,402)		(129,689)
Other income (expense)
Equity in earnings (loss) of subsidiaries	(245,850)		57,587		—		188,263		—
Net loss on derivative instruments	—		(191,401)		—		—		(191,401)
Interest expense, net of capitalized interest	(65,581)		(12,030)		(445)		—		(78,056)
Loss on extinguishment of debt	(13,651)		—		—		—		(13,651)
Other income	—		35		—		—		35
Total other expense, net	(325,082)		(145,809)		(445)		188,263		(283,073)
Income (loss) before income taxes	(339,810)		(325,827)		69,014		183,861		(412,762)
Income tax benefit	20,196		79,977		—		—		100,173
Net income (loss) including non-controlling interests	(319,614)		(245,850)		69,014		183,861		(312,589)
Less: Net income attributable to non-controlling interests	—		—		46,616		(39,591)		7,025
Net income (loss) attributable to Oasis	$	(319,614)	$	(245,850)	$	22,398	$	223,452	$	(319,614)

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Condensed Consolidating Statement of Cash Flows


	Six Months Ended June 30, 2019
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands)
Cash flows from operating activities:
Net income (loss) including non-controlling interests	$	(72,125)	$	(15,637)	$	92,374	$	(61,416)	$	(56,804)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:
Equity in earnings (loss) of subsidiaries	15,637		(72,253)		—		56,616		—
Depreciation, depletion and amortization	—		359,823		17,491		(10,123)		367,191

Loss on sale of properties	—		3,198		—		—		3,198
Impairment	—		653		—		—		653
Deferred income taxes	(24,197)		32,814		—		—		8,617
Derivative instruments	—		82,862		—		—		82,862
Equity-based compensation expenses	13,933		3,772		219		—		17,924
Deferred financing costs amortization and other	8,246		3,582		417		—		12,245
Working capital and other changes:
Change in accounts receivable, net	57,909		(13,500)		(2,086)		(55,237)		(12,914)
Change in inventory	—		3,029		—		—		3,029
Change in prepaid expenses	100		3,668		150		—		3,918


Change in accounts payable, interest payable and accrued liabilities	1,643		(97,321)		3,927		55,237		(36,514)


Change in other assets and liabilities, net	—		(4,074)		(399)		—		(4,473)
Net cash provided by operating activities	1,146		290,616		112,093		(14,923)		388,932
Cash flows from investing activities:
Capital expenditures	—		(394,675)		(130,826)		—		(525,501)
Acquisitions	—		(5,781)		—		—		(5,781)


Derivative settlements	—		3,629		—		—		3,629



Net cash used in investing activities	—		(396,827)		(130,826)		—		(527,653)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	—		1,083,000		95,000		—		1,178,000
Principal payments on Revolving Credit Facilities	—		(1,020,000)		(5,000)		—		(1,025,000)


Deferred financing costs	—		(42)		(440)		—		(482)


Purchases of treasury stock	(4,305)		—		—		—		(4,305)
Distributions to non-controlling interests	—		—		(43,581)		33,488		(10,093)
Investment in subsidiaries / capital contributions from parent	3,124		42,642		(27,201)		(18,565)		—
Other	—		(883)		(448)		—		(1,331)
Net cash provided by (used in) financing activities	(1,181)		104,717		18,330		14,923		136,789
Decrease in cash and cash equivalents	(35)		(1,494)		(403)		—		(1,932)
Cash and cash equivalents at beginning of period	179		15,362		6,649		—		22,190
Cash and cash equivalents at end of period	$	144	$	13,868	$	6,246	$	—	$	20,258

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Condensed Consolidating Statement of Cash Flows


	Six Months Ended June 30, 2018
	Parent/ Issuer		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Intercompany Eliminations		Consolidated

	(In thousands)
Cash flows from operating activities:
Net income (loss) including non-controlling interests	$	(319,614)	$	(245,850)	$	69,014	$	183,861	$	(312,589)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:
Equity in earnings (loss) of subsidiaries	245,850		(57,587)		—		(188,263)		—
Depreciation, depletion and amortization	—		296,781		13,023		(6,969)		302,835
Loss on extinguishment of debt	13,651		—		—		—		13,651
Gain on sale of properties	—		(1,954)		—		—		(1,954)
Impairment	—		384,228		—		—		384,228
Deferred income taxes	(20,196)		(80,097)		—		—		(100,293)
Derivative instruments	—		191,401		—		—		191,401
Equity-based compensation expenses	13,340		624		166		—		14,130
Deferred financing costs amortization and other	7,892		2,522		104		—		10,518
Working capital and other changes:
Change in accounts receivable, net	96,993		(8,178)		29,407		(124,088)		(5,866)
Change in inventory	—		(4,629)		(92)		—		(4,721)
Change in prepaid expenses	58		95		420		—		573


Change in accounts payable, interest payable and accrued liabilities	3,335		(90,679)		4,105		124,088		40,849


Change in other assets and liabilities, net	—		(746)		—		—		(746)
Net cash provided by operating activities	41,309		385,931		116,147		(11,371)		532,016
Cash flows from investing activities:
Capital expenditures	—		(381,971)		(154,988)		—		(536,959)
Acquisitions	—		(524,255)		—		—		(524,255)
Proceeds from sale of properties	—		2,236		—		—		2,236

Derivative settlements	—		(96,823)		—		—		(96,823)


Other	—		(933)		—		—		(933)
Net cash used in investing activities	—		(1,001,746)		(154,988)		—		(1,156,734)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	—		1,820,000		113,000		—		1,933,000
Principal payments on Revolving Credit Facilities	—		(1,239,000)		(26,000)		—		(1,265,000)
Repurchase of senior unsecured notes	(423,143)		—		—		—		(423,143)
Proceeds from issuance of senior unsecured convertible notes	400,000		—		—		—		400,000
Deferred financing costs	(6,524)		(266)		—		—		(6,790)


Purchases of treasury stock	(6,064)		—		—		—		(6,064)
Distributions to non-controlling interests	—		—		(55,757)		48,911		(6,846)
Investment in subsidiaries / capital contributions from parent	(5,619)		33,695		9,464		(37,540)		—
Other	38		(125)		—		—		(87)
Net cash provided by (used in) financing activities	(41,312)		614,304		40,707		11,371		625,070
Increase (decrease) in cash and cash equivalents	(3)		(1,511)		1,866		—		352
Cash and cash equivalents at beginning of period	178		15,659		883		—		16,720
Cash and cash equivalents at end of period	$	175	$	14,148	$	2,749	$	—	$	17,072

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20. 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 previously disclosed.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 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 strategic tactics, 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 2018 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 strategic tactics;

•estimated future net reserves and present value thereof;

•timing and amount of future production of crude 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, including ownership interests in a master limited partnership;

•owning and operating a well services company;

•infrastructure for produced and flowback water gathering and disposal;

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

•property acquisitions;

•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 strategic tactic, budget, projections, execution of business plan and operating results;

•cash flows and liquidity;

•crude oil and natural gas realized prices;

•general economic conditions;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;

•changes in environmental, safety and other laws and regulations;

•effectiveness of risk management activities;

•competition in the crude oil and natural gas industry;

•counterparty credit risk;

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•environmental liabilities;

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

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

•technology;

•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;

•uncertainty regarding future operating results;

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

•our remediation of the previously identified and reported material weakness in our internal control over financial reporting; and

•certain factors discussed elsewhere in this Form 10-Q.

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 crude 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 onshore, unconventional crude oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct our exploration and production activities and own our crude oil and natural gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Delaware Basin, respectively. In February 2018, we acquired acreage in the Delaware Basin from Forge Energy, LLC, representing our initial entry into the Delaware Basin (the “Permian Basin Acquisition”). In addition to our exploration and production segment, we operate a midstream business segment through Oasis Midstream Partners LP (“OMP”) and Oasis Midstream Services LLC (“OMS”) and a well services business segment through Oasis Wells Services LLC (“OWS”). OMP is a growth-oriented, fee-based master limited partnership that develops and operates a diversified portfolio of midstream assets.

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 and Delaware Basin assets through acquisitions and development activities, which were financed with a combination of capital from private investors, borrowings under our revolving credit facilities, cash flows provided by operating activities, proceeds from our senior unsecured notes, proceeds from our public equity offerings, the sale of certain non-core crude oil and natural 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 crude oil and natural gas properties in the Williston Basin and Delaware 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 crude oil and natural gas;

•transportation capacity;

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•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 crude oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for crude oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our crude oil and natural gas activities, commodity prices have experienced significant fluctuations and may fluctuate widely in the future. A substantial or extended decline in prices for crude oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of crude 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 crude oil and natural gas, we manage our commodity marketing activities in-house, which enables us to market and sell our crude 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 crude 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. Currently, 88% of our gross operated crude oil production is connected to these gathering systems, which originate at the wellhead and reduce the need to transport barrels by truck from the wellhead. In the Williston Basin, our crude oil price differentials improved to a less than $2.00 per barrel discount to NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”) throughout 2019 primarily due to the additional takeaway capacity of the Dakota Access Pipeline of over 500,000 barrels per day. In the Delaware Basin, price differentials in the first quarter of 2019 averaged more than $5.00 per barrel below NYMEX WTI due to pipeline constraints. However, expansions of pipelines have started to reduce price differentials and will continue to improve differentials and provide ample takeaway for our Delaware Basin production.

Highlights:

•We produced 84,454 barrel of oil equivalent per day (“Boepd”) in the second quarter of 2019, which represents a 6% increase over second quarter 2018 and was 72% crude oil.

•Lease operating expenses per barrel of oil equivalent (“Boe”) averaged $7.32 per Boe in the second quarter of 2019.

•Our crude oil differentials have improved to $0.96 off of NYMEX WTI in the second quarter of 2019.

•Our total general and administrative (“G&A”) expense and E&P Cash G&A expense decreased 10% from the first quarter of 2019. For a definition of E&P Cash G&A and a reconciliation of E&P Cash G&A to total E&P G&A, see “Non-GAAP Financial Measures” below.

•Net cash provided by operating activities was $214.0 million for the three months ended June 30, 2019. Adjusted EBITDA, a non-GAAP financial measure, was $249.6 million for the three months ended June 30, 2019. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) including non-controlling interests and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.

Results of Operations

Revenues

Our crude oil and natural gas revenues are derived from the sale of crude 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 purchased crude oil and natural gas sales are primarily derived from the sale of crude oil and natural gas purchased through our marketing activities primarily to optimize transportation costs or for blending at our crude oil terminal. Revenues and expenses from crude oil and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

Our midstream revenues are primarily derived from natural gas gathering and processing, produced and flowback water gathering and disposal, crude oil gathering and transportation and fresh water sales. Our well services revenues are derived from well services, product sales and equipment rentals. A majority of our midstream revenues and substantially all of our well services revenues are from services for third party interest owners in our operated wells. Intercompany revenues for work performed by OMS and OWS for our ownership interests are eliminated in consolidation and are therefore not included in midstream and well services revenues.

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


	Three Months Ended June 30,										Six Months Ended June 30,
	2019		2018		Change		2019		2018		Change
Operating results (in thousands)
Revenues
Crude oil revenues⁽¹⁾	$	327,977	$	363,183	$	(35,206)	$	646,098	$	689,493	$	(43,395)
Natural gas revenues	29,027		34,666		(5,639)		79,688		74,951		4,737
Purchased oil and gas sales⁽¹⁾	109,389		128,064		(18,675)		257,860		195,773		62,087
Midstream revenues	51,573		29,342		22,231		99,594		57,264		42,330
Well services revenues	11,439		18,496		(7,057)		21,897		30,082		(8,185)
Total revenues	$	529,405	$	573,751	$	(44,346)	$	1,105,137	$	1,047,563	$	57,574
Production data
Williston Basin
Crude oil (MBbl)	5,116		5,214		(98)		10,623		10,330		293
Natural gas (MMcf)	12,027		9,800		2,227		25,235		19,291		5,944
Oil equivalents (MBoe)	7,121		6,847		274		14,829		13,545		1,284
Average daily production (Boepd)	78,251		75,242		3,009		81,929		74,835		7,094
Delaware Basin
Crude oil (MBbl)	455		303		152		892		472		420
Natural gas (MMcf)	657		468		189		1,309		754		555
Oil equivalents (MBoe)	564		382		182		1,111		597		514
Average daily production (Boepd)	6,203		4,195		2,008		6,135		3,300		2,835
Total average daily production (Boepd)	84,454		79,437		5,017		88,064		78,135		9,929
Average sales prices
Crude oil, without derivative settlements (per Bbl)	$	58.87	$	65.82	$	(6.95)	$	56.11	$	63.83	$	(7.72)
Crude oil, with derivative settlements (per Bbl)⁽²⁾	56.79		54.88		1.91		56.27		54.81		1.46
Natural gas, without derivative settlements (per Mcf)⁽³⁾	2.29		3.38		(1.09)		3.00		3.74		(0.74)
Natural gas, with derivative settlements (per Mcf)⁽²⁾⁽³⁾	2.43		3.43		(1.00)		3.07		3.77		(0.70)

____________________

(1)We have revised the Condensed Consolidated Statements of Operations to correct the presentation of certain purchase and sale arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and gas revenues, by increasing purchased oil and gas sales, purchased oil and gas expenses and oil and gas revenues by $70.5 million, $72.4 million and $1.9 million, respectively, for the three months ended June 30, 2018 and by $120.2 million, $125.0 million and $4.9 million, respectively, for the six months ended June 30, 2018. See Note 2 to our unaudited condensed consolidated financial statements for more information on this revision.

(2)Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for or 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.

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

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Three months ended June 30, 2019 as compared to three months ended June 30, 2018

Crude oil and natural gas revenues. Our crude oil and natural gas revenues decreased $40.8 million to $357.0 million during the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. This decrease was primarily driven by a $49.6 million decrease due to the lower crude oil and natural gas sales prices, offset by an $8.7 million increase driven by higher crude oil and natural gas production amounts sold quarter over quarter. Average crude oil sales prices, without derivative settlements, decreased by $6.95 per barrel to an average of $58.87 per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids and does not include derivative settlements, decreased by $1.09 per Mcf to an average of $2.29 per Mcf for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. Average daily production sold increased by 5,017 Boepd to 84,454 Boepd quarter over quarter. The increase in average daily production sold was primarily a result of our 17.6 net well completions in the Williston Basin and 3.0 net well completions in the Delaware Basin during the three months ended June 30, 2019.

Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize transportation costs or for blending at our crude oil terminal, decreased $18.7 million to $109.4 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018, primarily due to lower crude oil volumes purchased and sold in the Williston Basin.

Midstream revenues. Midstream revenues increased $22.2 million to $51.6 million during the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. This increase was primarily driven by a $21.8 million increase related to higher natural gas sales resulting from the commencement of third party natural gas purchase arrangements in the fourth quarter of 2018. Despite downtime at our natural gas processing plants during the second quarter of 2019, midstream revenues also increased due to higher natural gas volumes gathered, compressed and processed as a result of the start-up of our second natural gas processing plant in Wild Basin during the fourth quarter of 2018, offset by a $2.9 million decrease related to lower crude oil volumes gathered, stabilized and transported.

Well services revenues. Our well services revenues decreased by $7.1 million to $11.4 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018, primarily due to a $3.7 million decrease in product sales to third parties, coupled with a decrease of $3.1 million in well completion revenue.

Six months ended June 30, 2019 as compared to six months ended June 30, 2018

Crude oil and natural gas revenues. Our crude oil and natural gas revenues decreased $38.6 million, or 5%, to $725.8 million during the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. The lower crude oil and natural gas sales prices decreased revenues by $98.2 million, offset by a $59.5 million increase due to the higher crude oil and natural gas production amounts sold period over period. Average crude oil sales prices, without derivative settlements, decreased by $7.72 per barrel to an average of $56.11 per barrel, and average natural gas sales prices, which include the value for natural gas and natural gas liquids and does not include derivative settlements, decreased by $0.74 per Mcf to an average of $3.00 per Mcf for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. Average daily production sold increased by 9,929 Boe per day to 88,064 Boe per day period over period. The increase in average daily production sold was primarily a result of our 51.2 total net well completions in the Williston Basin and 8.3 total net well completions in the Delaware Basin during the twelve months ended June 30, 2019.

Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize transportation costs or for blending at our crude oil terminal, increased $62.1 million to $257.9 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018 due to higher volumes purchased and sold driven by increased market opportunities in the Williston Basin and in the Delaware Basin.

Midstream revenues. Midstream revenues were $99.6 million for the six months ended June 30, 2019, which was a $42.3 million increase period over period. This increase was driven by a $41.0 million increase related to higher natural gas sales resulting from the commencement of third party natural gas purchase arrangements in the fourth quarter of 2018. Despite downtime at our natural gas processing plants during 2019, midstream revenues also increased due to higher natural gas volumes gathered, compressed and processed, coupled with a $0.6 million increase related to higher water service volumes driven by an increase in producing wells. These increases were offset by a $2.7 million decrease in revenues related to lower crude oil volumes gathered, stabilized and transported.

Well services revenues. Our well services revenues decreased by $8.2 million to $21.9 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. This decrease was primarily driven by a $4.7 million decrease in product sales to third parties, a $2.7 million decrease in well completion revenue due to decreased activity and a $0.7 million decrease in equipment rentals period over period.

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Expenses and other income

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


	Three Months Ended June 30,										Six Months Ended June 30,
	2019		2018		Change		2019		2018		Change

	(In thousands, except per Boe of production)
Operating expenses
Lease operating expenses	$	56,228	$	44,141	$	12,087	$	114,672	$	88,922	$	25,750
Midstream expenses	17,368		7,688		9,680		34,097		15,673		18,424
Well services expenses	8,474		13,560		(5,086)		15,444		20,947		(5,503)
Marketing, transportation and gathering expenses	28,488		22,833		5,655		63,438		43,846		19,592
Purchased oil and gas expenses⁽¹⁾	109,662		129,579		(19,917)		259,566		200,173		59,393
Production taxes	28,142		34,026		(5,884)		57,760		65,026		(7,266)
Depreciation, depletion and amortization	177,358		153,570		23,788		367,191		302,835		64,356
Exploration expenses	887		617		270		1,717		1,386		331

Impairment	24		384,135		(384,111)		653		384,228		(383,575)
General and administrative expenses	30,926		28,230		2,696		65,385		56,170		9,215
Total operating expenses	457,557		818,379		(360,822)		979,923		1,179,206		(199,283)
Gain (loss) on sale of properties	(276)		1,954		(2,230)		(3,198)		1,954		(5,152)
Operating income (loss)	71,572		(242,674)		314,246		122,016		(129,689)		251,705
Other income (expense)
Net gain (loss) on derivative instruments	34,749		(120,285)		155,034		(82,862)		(191,401)		108,539
Interest expense, net of capitalized interest	(43,186)		(40,910)		(2,276)		(87,654)		(78,056)		(9,598)
Loss on extinguishment of debt	—		(13,651)		13,651		—		(13,651)		13,651
Other income	279		218		61		233		35		198
Total other expense, net	(8,158)		(174,628)		166,470		(170,283)		(283,073)		112,790
Income (loss) before income taxes	63,414		(417,302)		480,716		(48,267)		(412,762)		364,495
Income tax benefit (expense)	(12,240)		101,001		(113,241)		(8,537)		100,173		(108,710)
Net income (loss) including non-controlling interests	51,174		(316,301)		367,475		(56,804)		(312,589)		255,785
Less: Net income attributable to non-controlling interests	8,417		3,903		4,514		15,321		7,025		8,296
Net income (loss) attributable to Oasis	$	42,757	$	(320,204)	$	362,961	$	(72,125)	$	(319,614)	$	247,489
Costs and expenses (per Boe of production)
Lease operating expenses	$	7.32	$	6.11	$	1.21	$	7.19	$	6.29	$	0.90
Marketing, transportation and gathering expenses	3.71		3.16		0.55		3.98		3.10		0.88
Production taxes	3.66		4.71		(1.05)		3.62		4.60		(0.98)

____________________

(1)We have revised the Condensed Consolidated Statement of Operations to correct the presentation of certain purchase and sale arrangements that should have been presented on a gross basis, which were previously recognized on a net basis in oil and gas revenues, by increasing purchased oil and gas sales, purchased oil and gas expenses and oil and gas revenues by $70.5 million, $72.4 million and $1.9 million, respectively, for the three months ended June 30, 2018 and by $120.2 million, $125.0 million and $4.9 million, respectively, for the six months ended June 30, 2018. See Note 2 to our unaudited condensed consolidated financial statements for more information on this revision.

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Three months ended June 30, 2019 as compared to three months ended June 30, 2018

Lease operating expenses. Lease operating expenses increased $12.1 million to $56.2 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. The increase was primarily due to higher costs associated with operating an increased number of producing wells as a result of our well completions, coupled with an increase in workover costs quarter over quarter. In addition, lease operating expenses increased due to an increase in produced and flowback water disposal volumes being transported and injected into produced and flowback water disposal wells. Lease operating expenses per Boe increased quarter over quarter from $6.11 per Boe to $7.32 per Boe primarily due to the higher aforementioned costs.

Midstream expenses. Midstream expenses represent third party working interest owners’ share of operating expenses incurred by OMS, as well as operating expenses related to midstream services provided to third parties. The $9.7 million increase quarter over quarter was primarily related to a $9.4 million increase in natural gas gathering, compression and processing expenses as a result of the start-up of our second natural gas processing plant in Wild Basin during the fourth quarter of 2018, coupled with increased costs related to downtime at our natural gas processing plants during the second quarter of 2019.

Well services expenses. Well services expenses represent third party working interest owners’ share of completion service costs, cost of goods sold and operating expenses incurred by OWS. The $5.1 million decrease quarter over quarter was primarily attributable to a $2.5 million decrease in product sales to third parties, coupled with a $1.2 million decrease in well completion expenses.

Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $5.7 million, or $0.55 per Boe, for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018, which was primarily attributable to higher crude oil gathering and transportation expenses related to an increase in volumes being transported on the Dakota Access Pipeline to market our equity barrels. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $3.69 during the three months ended June 30, 2019 as compared to $3.19 during the three months ended June 30, 2018 primarily due to the higher aforementioned costs.

Purchased oil and gas expenses. Purchased oil and gas expenses, which represent the crude oil purchased primarily to optimize transportation costs or for blending at our crude oil terminal, decreased $19.9 million to $109.7 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018 primarily due to lower crude oil volumes purchased and sold in the Williston Basin.

Production taxes. Our production taxes as a percentage of crude oil and natural gas sales were 7.9% and 8.6% for the three months ended June 30, 2019 and 2018, respectively. The production tax rate decreased quarter over quarter primarily due to a lower crude oil production mix, coupled with the addition of Delaware Basin assets following the Permian Basin Acquisition in February 2018, which bear a lower average production tax rate than Williston Basin assets. North Dakota’s natural gas production tax is $0.0705 per Mcf, while its crude oil tax structure is based on a 5% production tax and a 5% crude oil extraction tax, resulting in a combined tax rate of 10% of crude oil revenues.

Depreciation, depletion and amortization (“DD&A”). DD&A expenses increased $23.8 million to $177.4 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. This increase was a result of increased production from our wells completed during the three months ended June 30, 2019, coupled with an increase in the DD&A rate to $23.08 per Boe for the three months ended June 30, 2019 as compared to $21.24 per Boe for the three months ended June 30, 2018. The increase in the DD&A rate was primarily due to higher well costs in the Williston Basin and Delaware Basin, coupled with lower recoverable reserves in the Williston Basin.

Impairment. During the three months ended June 30, 2018, we recorded an impairment loss of $383.4 million to adjust the carrying value of our properties held for sale located in the Foreman Butte area of the Williston Basin 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 June 30, 2019.

G&A. G&A increased $2.7 million to $30.9 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018. E&P G&A increased $2.3 million quarter over quarter primarily due to costs related to increased employee compensation expenses as a result of organizational growth, offset by the decrease in costs related to the Permian Basin Acquisition, which were incurred during the three months ended June 30, 2018. OMS G&A increased $0.5 million quarter over quarter primarily due to increased shared services expenses as a result of organizational growth. OWS G&A remained flat at $1.8 million for both the three months ended June 30, 2019 and 2018.

Gain (loss) on sale of properties. For the three months ended June 30, 2019, we recognized a $0.3 million net loss primarily related to the sale of non-strategic oil and gas properties and certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin (see Note 10 — Divestitures). For the three months ended June 30, 2018, we recognized a $2.0 million gain related to the sale of certain unproved properties in the Williston Basin.

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Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip crude oil and natural gas price changes, we incurred a $34.7 million net gain on derivative instruments, including net cash settlement payments of $9.8 million, for the three months ended June 30, 2019, and a $120.3 million net loss on derivative instruments, including net cash settlement payments of $59.8 million, for the three months ended June 30, 2018. 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.

Interest expense. Interest expense increased $2.3 million to $43.2 million for the three months ended June 30, 2019 as compared to the three months ended June 30, 2018 primarily due to a $2.7 million increase in interest expense related to our borrowings under the OMP Credit Facility, coupled with a decrease in capitalized interest of $0.6 million due to lower costs for work in progress assets, partially offset by a $1.0 million decrease in interest expense related to our borrowings under the Oasis Credit Facility. For the three months ended June 30, 2019, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $544.3 million and $190.5 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 4.2% and 4.2%, respectively. For the three months ended June 30, 2018, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $698.6 million and $148.3 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 3.9% and 3.7%, respectively. Interest capitalized during the three months ended June 30, 2019 and 2018 was $3.6 million and $4.2 million, respectively, which will be amortized over the life of the related assets.

Loss on extinguishment of debt. During the three months ended June 30, 2019, we did not repurchase any portion of our outstanding senior unsecured notes. During the three months ended June 30, 2018, we repurchased an aggregate principal amount of $413.5 million of our outstanding senior unsecured notes for an aggregate cost of $423.1 million, including fees. For the three months ended June 30, 2018, we recognized a pre-tax loss related to the repurchase of $13.7 million, which included unamortized deferred financing costs write-offs of $4.0 million.

Income tax benefit (expense). Our income tax expense for the three months ended June 30, 2019 was recorded at 19.3% of pre-tax income and the income tax benefit for the three months ended June 30, 2018 was recorded at 24.2% of pre-tax loss. Our effective tax rate for the three months ended June 30, 2019 was lower than the effective tax rate for the three months ended June 30, 2018 primarily due to the impact of non-controlling interests, partially offset by the impact of other permanent differences, primarily non-deductible executive compensation.

Six months ended June 30, 2019 as compared to six months ended June 30, 2018

Lease operating expenses. Lease operating expenses increased $25.8 million to $114.7 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. The increase was primarily due to higher costs associated with operating an increased number of producing wells as a result of our well completions, coupled with higher workover costs and increased costs related to produced and flowback water disposal volumes being transported and injected during the six months ended June 30, 2019. Lease operating expenses per Boe increased from $6.29 per Boe to $7.19 per Boe primarily due to the higher aforementioned costs.

Midstream expenses. Midstream expenses represent third party working interest owners’ share of operating expenses incurred by OMS, as well as operating expenses related to midstream services provided to third parties. The $18.4 million increase for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018 was primarily related to the $19.3 million increase in natural gas purchases from third parties and natural gas gathering, compression and processing expenses driven by increased production as a result of the start-up of our second natural gas processing plant in Wild Basin during the fourth quarter of 2018, coupled with increased costs related to downtime at our natural gas processing plants during 2019. These increases were partially offset by a $1.4 million decrease related to lower produced and flowback water operating expenses.

Well services expenses. Well services expenses represent third party working interest owners’ share of completion service costs, cost of goods sold and operating expenses incurred by OWS. The $5.5 million decrease for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018 was primarily attributable to a $3.1 million decrease in product sales to third parties, coupled with a $1.1 million decrease in well completion expenses.

Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $19.6 million period over period, or a $0.88 increase per Boe, which was primarily attributable to higher oil gathering and transportation expenses related to increased throughput on the Dakota Access Pipeline to market our equity barrels. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $3.83 for the six months ended June 30, 2019 as compared to $3.10 for the six months ended June 30, 2018 primarily due to the higher aforementioned costs.

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June 30, 2019 as compared to the six months ended June 30, 2018 primarily due to higher volumes purchased and sold driven by increased market opportunities in the Williston Basin and in the Delaware Basin.

Production taxes. Our production taxes as a percentage of crude oil and natural gas sales were 8.0% and 8.6% for the six months ended June 30, 2019 and 2018, respectively. The production tax rate decreased period over period primarily due to a lower crude oil production mix, coupled with the addition of Delaware Basin assets following the Permian Basin Acquisition in February 2018, which bear a lower average production tax rate than Williston Basin assets. North Dakota’s natural gas production tax is $0.0705 per Mcf, while its crude oil tax structure is based on a 5% production tax and a 5% crude oil extraction tax, resulting in a combined tax rate of 10% of crude oil revenues.

DD&A. DD&A expenses increased $64.4 million to $367.2 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. This increase was a result of increased production from our wells completed during the six months ended June 30, 2019, coupled with an increase in the DD&A rate to $23.04 per Boe for the six months ended June 30, 2019 as compared to $21.41 per Boe for the six months ended June 30, 2018. The increase in the DD&A rate was primarily due to higher well costs in the Williston Basin and Delaware Basin, coupled with lower recoverable reserves in the Williston Basin.

Impairment. During the six months ended June 30, 2018, we recorded an impairment loss of $383.4 million to adjust the carrying value of our properties held for sale located in the Foreman Butte area of the Williston Basin 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 six months ended June 30, 2019.

G&A. G&A increased $9.2 million to $65.4 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. E&P G&A increased $6.3 million period over period primarily due to costs related to increased employee compensation expenses as a result of organizational growth, offset by the decrease in costs related to the Permian Basin Acquisition, which were incurred during the six months ended June 30, 2018. OMS and OWS G&A increased $2.0 million and $0.9 million, respectively, period over period primarily due to increased employee compensation expenses as a result of organizational growth.

Gain (loss) on sale of properties. For the six months ended June 30, 2019, we recognized a $3.2 million net loss related to the sale of non-strategic oil and gas properties and certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin (see Note 10 — Divestitures). For the six months ended June 30, 2018, we recognized a $2.0 million gain related to the sale of certain unproved properties in the Williston Basin.

Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip crude oil and natural gas price changes, we incurred an $82.9 million net loss on derivative instruments, including net cash settlement receipts of $3.6 million, for the six months ended June 30, 2019, and a $191.4 million net loss on derivative instruments, including net cash settlement payments of $96.8 million, for the six months ended June 30, 2018. 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.

Interest expense. Interest expense increased $9.6 million to $87.7 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018 primarily due to a $6.5 million increase in interest expense related to our borrowings under our Revolving Credit Facilities, coupled with a decrease in capitalized interest of $2.2 million due to lower costs for work in progress assets. For the six months ended June 30, 2019, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $540.0 million and $355.5 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 4.2% and 4.2%, respectively. For the six months ended June 30, 2018, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $895.6 million and $201.2 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 3.8% and 3.6%, respectively. Interest capitalized during the six months ended June 30, 2019 and 2018 was $6.5 million and $8.7 million, respectively, which will be amortized over the life of the related assets.

Loss on extinguishment of debt. During the six months ended June 30, 2019, we did not repurchase any portion of our outstanding senior unsecured notes. During the six months ended June 30, 2018, we repurchased an aggregate principal amount of $413.5 million of our outstanding senior unsecured notes for an aggregate cost of $423.1 million, including fees. For the six months ended June 30, 2018, we recognized a pre-tax loss related to the repurchase of $13.7 million, which included unamortized deferred financing costs write-offs of $4.0 million.

Income tax benefit (expense). Our income tax expense for the six months ended June 30, 2019 was recorded at (17.7)% of pre-tax loss and the income tax benefit for the six months ended June 30, 2018 was recorded at 24.3% of pre-tax loss. Our effective tax rate for the six months ended June 30, 2019 was lower than the effective tax rate for the six months ended June 30, 2018 primarily due to the impacts of non-controlling interests and equity-based compensation shortfalls. These decreases were partially offset by the impacts of other permanent differences, primarily non-deductible executive compensation.

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Liquidity and Capital Resources

Our primary sources of liquidity as of the date of this report have been cash flows from operations, borrowings under our Revolving Credit Facilities and cash settlements of derivative contracts. Our primary uses of cash have been for the acquisition and development of oil and gas properties and midstream infrastructure, distributions to non-controlling interests, interest payments on outstanding debt and payment of operating and general and administrative costs. We continually monitor potential capital sources, including equity and debt financings and potential asset monetization opportunities, 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 six months ended June 30, 2019 and 2018 are presented below:


	Six Months Ended June 30,
	2019		2018

	(In thousands)
Net cash provided by operating activities	$	388,932	$	532,016
Net cash used in investing activities	(527,653)		(1,156,734)
Net cash provided by financing activities	136,789		625,070
Increase (decrease) in cash and cash equivalents	$	(1,932)	$	352

Our cash flows depend on many factors, including the price of crude 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 crude oil and natural gas prices on a portion of our production, thereby mitigating our exposure to crude oil and natural gas price declines, but these transactions may also limit our cash flow in periods of rising crude 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 $388.9 million and $532.0 million for the six months ended June 30, 2019 and 2018, respectively. The change in cash flows from operating activities for the period ended June 30, 2019 as compared to 2018 was primarily the result of changes in working capital and other assets and liabilities, coupled with a 20% decrease in realized prices for natural gas and a 12% decrease in realized prices for crude oil. These decreases were offset by a 13% increase in crude oil and natural gas production and non-cash adjustments to the net loss including non-controlling interests.

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 the impact of our outstanding derivative instruments. We had a working capital deficit of $86.7 million at June 30, 2019 due to decreases in our derivative assets, offset by the decreases in our revenues and production taxes payable and accrued liabilities for drilling and development costs. As of June 30, 2019, we had $884.1 million of liquidity available, including $20.3 million in cash and cash equivalents and $863.8 million of aggregate unused borrowing capacity available under our Revolving Credit Facilities. At June 30, 2018, we had a working capital deficit of $407.6 million.

Cash flows used in investing activities

Net cash used in investing activities was $527.7 million and $1,156.7 million during the six months ended June 30, 2019 and 2018, respectively. Net cash used in investing activities during the six months ended June 30, 2019 was primarily attributable to $525.5 million in capital expenditures primarily for drilling and development costs. Net cash used in investing activities during the six months ended June 30, 2018 was primarily attributable to $524.3 million in acquisitions primarily for the Permian Basin Acquisition, coupled with $537.0 million in capital expenditures primarily for drilling and development costs.

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Our capital expenditures are summarized in the following table:


	Three Months Ended						Six Months Ended June 30, 2019
	March 31, 2019		June 30, 2019

	(In thousands)
Capital expenditures:
E&P	$	165,702	$	202,129	$	367,831
Well services	104		—		104
Other capital expenditures⁽¹⁾	3,880		4,330		8,210
Total capital expenditures before midstream	169,686		206,459		376,145
Midstream⁽²⁾	57,108		82,634		139,742
Total capital expenditures before acquisitions	226,794		289,093		515,887
Acquisitions	—		5,781		5,781
Total capital expenditures⁽³⁾	$	226,794	$	294,874	$	521,668

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

(2)Midstream capital expenditures attributable to OMP were $45.2 million and $70.9 million for the three months ended March 31, 2019 and June 30, 2019, respectively.

(3)Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.

Our current total 2019 capital expenditure plan is approximately $839 million to $870 million, which includes approximately $620 million to $640 million for E&P and other capital expenditures. Other capital expenditures includes OWS and administrative capital and excludes capitalized interest of approximately $15 million. As a result of increased OMP capital expenditures expected in the Delaware Basin, our planned 2019 midstream capital expenditures are now approximately $219 million to $230 million, which includes approximately $15 million to $16 million for midstream capital expenditures attributable to Oasis.

On February 22, 2019, the Company entered into a memorandum of understanding (the “MOU”) with OMP regarding the funding of Bobcat DevCo’s expansion capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the MOU, in exchange for increasing its percentage ownership interest in Bobcat DevCo, OMP agreed to make up to $80.0 million of the capital contributions to Bobcat DevCo that OMS would otherwise be required to contribute. During the three and six months ended June 30, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $35.8 million and $52.8 million, respectively. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 67.5% as of June 30, 2019.

While we have planned approximately $839 million to $870 million for total capital expenditures in 2019, 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 planned. 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 Facilities, should be sufficient to fund our 2019 capital expenditure plan and to meet our future obligations. However, because the operated wells funded by our 2019 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 plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If crude oil prices decline substantially or for an extended period of time, we could defer a significant portion of our planned 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.

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Cash flows provided by financing activities

Net cash provided by financing activities was $136.8 million and $625.1 million for the six months ended June 30, 2019 and 2018, respectively. For the six months ended June 30, 2019 and 2018, cash provided by financing activities was primarily due to proceeds from the borrowings under our Revolving Credit Facilities, partially offset by principal payments on our Revolving Credit Facilities, distributions to non-controlling interests and purchases of treasury stock for shares that employees surrendered back to us to pay tax withholdings upon the vesting of restricted stock awards.

Senior secured revolving line of credit. We have the Oasis Credit Facility with an overall senior secured line of credit of $3,000.0 million as of June 30, 2019. The Oasis 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. The maturity date of the Oasis Credit Facility is the earlier of (i) October 16, 2023, (ii) 90 days prior to the maturity date of our 2022 and 2023 Senior Notes, of which $1,267.6 million is outstanding, to the extent such 2022 and 2023 Senior Notes are not retired or refinanced to have a maturity date at least 90 days after October 16, 2023 and (iii) 90 days prior to the maturity date of our 2023 Senior Convertible Notes (as defined below), of which $300.0 million is outstanding, to the extent such 2023 Senior Convertible Notes are not retired, converted, redeemed or refinanced to have a maturity date at least 90 days after October 16, 2023. In addition, OP Permian is a guarantor under the Oasis Credit Facility.

On April 15, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2019, which reaffirmed the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively. In connection with the April 1, 2019 borrowing base redetermination, we entered into the First Amendment to the Third Amended and Restated Credit Agreement to the Oasis Credit Facility, dated April 15, 2019, which, among other things, incorporated the ability for us to request swingline loans subject to a swingline loans sublimit of $50.0 million. All other significant rates, terms and conditions of the Third Amended Credit Facility remained the same. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for October 1, 2019.

The Oasis 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 crude oil and natural gas derivative financial instruments;

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

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

•if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility) exceed 85% of the effective borrowing base (“Trigger”), we are required to maintain a ratio of total debt (as defined in the Oasis Credit Facility) to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage Ratio will be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be tested as long as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and shall not exceed 4.25 to 1.00 for the first two quarters and 4.00 to 1.00 for each fiscal quarter thereafter.

The Oasis 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 Oasis Credit Facility to be immediately due and payable.

As of June 30, 2019, we had $531.0 million of borrowings at a weighted average interest rate of 4.2% and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $805.0 million. We were in compliance with the financial covenants of the Oasis Credit Facility as of June 30, 2019. 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.

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OMP Operating LLC revolving line of credit. Through our majority ownership of OMP, we have access to the OMP Credit Facility, which is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. On May 6, 2019, OMP entered into an amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million; (ii) provide for the ability to further increase commitments to $675.0 million; and (iii) add a new lender to the bank group. As of June 30, 2019, the OMP Credit Facility has an aggregate amount of commitments of $475.0 million and has a maturity date of September 25, 2022.

At June 30, 2019, we had $408.0 million of borrowings at a weighted average interest rate of 4.2% and $8.2 million of outstanding letters of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $58.8 million.

The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (i) consolidated total leverage ratio, (ii) consolidated senior secured leverage ratio and (iii) consolidated interest coverage ratio (each covenant as described in the OMP Credit Facility). All obligations of OMP Operating LLC, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and several basis by OMP, OMP Operating LLC and Bighorn DevCo LLC. OMP Operating LLC was in compliance with the financial covenants of the OMP Credit Facility at June 30, 2019.

Senior unsecured notes. As of June 30, 2019, our long-term debt includes outstanding senior unsecured note obligations of $1,739.4 million for senior unsecured notes with maturities ranging from November 2021 to May 2026 and coupons ranging from 6.25% to 6.875% (the “Senior 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 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. We were in compliance with the terms of the indentures for the Senior Notes as of June 30, 2019.

Senior unsecured convertible notes. At June 30, 2019, we had $300.0 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). The Senior Convertible Notes will mature on September 15, 2023 unless earlier converted in accordance with their terms.

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 commencing after the calendar quarter ending on September 30, 2016 (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 “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 June 30, 2019, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, we were in compliance with the terms of the indentures for the Senior Convertible Notes as of June 30, 2019.

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

E&P Cash G&A, Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share are supplemental non-GAAP financial measures that are used

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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 general and administrative expense, 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 E&P Cash G&A, Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis 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.

E&P Cash G&A

We define E&P Cash G&A as the total general and administrative expenses included in our exploration and production segment less non-cash equity-based compensation expenses included in our exploration and production segment. E&P Cash G&A is not a measure of general and administrative expenses as determined by GAAP. Management believes that the presentation of E&P Cash G&A provides useful additional information to investors and analysts to assess our operating costs in comparison to peers without regard to equity-based compensation programs, which can vary substantially from company to company.

The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses included in our exploration and production segment to the non-GAAP financial measure of E&P Cash G&A for the periods presented:


Exploration and Production
	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
E&P general and administrative expenses	$	25,761	$	23,492	$	53,288	$	46,971
Equity-based compensation expenses	(8,522)		(7,012)		(17,102)		(13,463)
E&P Cash G&A	$	17,239	$	16,480	$	36,186	$	33,508

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 June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Interest expense	$	43,186	$	40,910	$	87,654	$	78,056
Capitalized interest	3,645		4,227		6,463		8,678
Amortization of deferred financing costs	(1,823)		(1,937)		(3,593)		(3,698)
Amortization of debt discount	(3,006)		(2,731)		(5,890)		(5,349)
Cash Interest	$	42,002	$	40,469	$	84,634	$	77,687

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 non-recurring 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 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 attributable to Oasis 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

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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.

The following table presents reconciliations of the GAAP financial measures of net income (loss) including non-controlling interests 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 June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Net income (loss) including non-controlling interests	$	51,174	$	(316,301)	$	(56,804)	$	(312,589)
(Gain) loss on sale of properties	276		(1,954)		3,198		(1,954)
Loss on extinguishment of debt	—		13,651		—		13,651
Net (gain) loss on derivative instruments	(34,749)		120,285		82,862		191,401
Derivative settlements⁽¹⁾	(9,817)		(59,849)		3,629		(96,823)
Interest expense, net of capitalized interest	43,186		40,910		87,654		78,056
Depreciation, depletion and amortization	177,358		153,570		367,191		302,835
Impairment	24		384,135		653		384,228

Exploration expenses	887		617		1,717		1,386
Equity-based compensation expenses	8,911		7,376		17,924		14,130
Income tax (benefit) expense	12,240		(101,001)		8,537		(100,173)
Other non-cash adjustments	120		(226)		2,395		(17)
Adjusted EBITDA	249,610		241,213		518,956		474,131
Adjusted EBITDA attributable to non-controlling interests	11,693		5,148		21,896		9,452
Adjusted EBITDA attributable to Oasis	237,917		236,065		497,060		464,679
Cash Interest	(42,002)		(40,469)		(84,634)		(77,687)
Capital expenditures⁽²⁾	(294,875)		(358,534)		(521,668)		(1,525,762)
Capitalized interest	3,645		4,227		6,463		8,678
Free Cash Flow	$	(95,315)	$	(158,711)	$	(102,779)	$	(1,130,092)

Net cash provided by operating activities	$	214,006	$	303,657	$	388,932	$	532,016
Derivative settlements⁽¹⁾	(9,817)		(59,849)		3,629		(96,823)
Interest expense, net of capitalized interest	43,186		40,910		87,654		78,056

Exploration expenses	887		617		1,717		1,386
Deferred financing costs amortization and other	(5,315)		(5,043)		(12,245)		(10,518)
Current tax (benefit) expense	76		120		(80)		120
Changes in working capital	6,467		(38,973)		46,954		(30,089)
Other non-cash adjustments	120		(226)		2,395		(17)
Adjusted EBITDA	249,610		241,213		518,956		474,131
Adjusted EBITDA attributable to non-controlling interests	11,693		5,148		21,896		9,452
Adjusted EBITDA attributable to Oasis	237,917		236,065		497,060		464,679
Cash Interest	(42,002)		(40,469)		(84,634)		(77,687)
Capital expenditures⁽²⁾	(294,875)		(358,534)		(521,668)		(1,525,762)
Capitalized interest	3,645		4,227		6,463		8,678
Free Cash Flow	$	(95,315)	$	(158,711)	$	(102,779)	$	(1,130,092)

___________________

(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.

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(2)Capital expenditures (including acquisitions) reflected in the table above differ from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in this table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. Acquisitions totaled $5.8 million for the three and six months ended June 30, 2019, and $3.5 million and $894.5 million for the three and six months ended June 30, 2018, respectively.

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


Exploration and Production
	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Income (loss) before income taxes including non-controlling interests	$	14,925	$	(454,662)	$	(141,533)	$	(482,847)
(Gain) loss on sale of properties	276		(1,954)		3,198		(1,954)
Loss on extinguishment of debt	—		13,651		—		13,651
Net (gain) loss on derivative instruments	(34,749)		120,285		82,862		191,401
Derivative settlements⁽¹⁾	(9,817)		(59,849)		3,629		(96,823)
Interest expense, net of capitalized interest	38,977		40,727		79,697		77,611
Depreciation, depletion and amortization	172,687		149,250		357,506		294,454
Impairment	24		384,135		653		384,228
Exploration expenses	887		617		1,717		1,386

Equity-based compensation expenses	8,522		7,012		17,102		13,463
Other non-cash adjustments	120		(226)		2,395		(17)
Adjusted EBITDA	$	191,852	$	198,986	$	407,226	$	394,553

___________________


Midstream Services
	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Income before income taxes including non-controlling interests	$	51,016	$	37,815	$	97,074	$	69,796

Interest expense, net of capitalized interest	4,209		183		7,957		445
Depreciation, depletion and amortization	8,893		6,900		18,080		13,529

Equity-based compensation expenses	515		409		980		780

Adjusted EBITDA	$	64,633	$	45,307	$	124,091	$	84,550


Well Services
	Three Months Ended June 30,						Six Months Ended June 30,
	2019		2018		2019		2018

	(In thousands)
Income before income taxes including non-controlling interests	$	1,499	$	8,051	$	2,319	$	16,158
Depreciation, depletion and amortization	3,358		3,930		7,287		7,619

Equity-based compensation expenses	527		409		1,088		795

Adjusted EBITDA	$	5,384	$	12,390	$	10,694	$	24,572

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Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share

We define Adjusted Net Income (Loss) Attributable to Oasis as net income (loss) after adjusting 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, (2) the impact of net income attributable to non-controlling interests and (3) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items, excluding net income attributable to non-controlling interests, in the same period. Adjusted Net Income (Loss) Attributable to Oasis is not a measure of net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share as Adjusted Net Income (Loss) Attributable to Oasis divided by diluted weighted average shares outstanding. Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share is not a measure of diluted earnings (loss) as determined by GAAP. Management believes that the presentation of Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis 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 are excluded from guidance provided by the Company.

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


	Three Months Ended June 30,									Six Months Ended June 30,
	2019			2018			2019			2018

	(In thousands, except per share data)
Net income (loss) attributable to Oasis	$	42,757		$	(320,204)		$	(72,125)		$	(319,614)

(Gain) loss on sale of properties	276			(1,954)			3,198			(1,954)
Loss on extinguishment of debt	—			13,651			—			13,651
Net (gain) loss on derivative instruments	(34,749)			120,285			82,862			191,401
Derivative settlements⁽¹⁾	(9,817)			(59,849)			3,629			(96,823)
Impairment	24			384,135			653			384,228

Amortization of deferred financing costs	1,823			1,937			3,593			3,698
Amortization of debt discount	3,006			2,731			5,890			5,349
Other non-cash adjustments	120			(226)			2,395			(17)
Tax impact⁽²⁾	7,565			(111,592)			14,273			(121,102)
Adjusted Net Income Attributable to Oasis	$	11,005		$	28,914		$	44,368		$	58,817

Diluted earnings (loss) attributable to Oasis per share	$	0.14		$	(1.02)		$	(0.23)		$	(1.06)

(Gain) loss on sale of properties	—			(0.01)			0.01			(0.01)
Loss on extinguishment of debt	—			0.04			—			0.04
Net (gain) loss on derivative instruments	(0.11)			0.38			0.26			0.63
Derivative settlements⁽¹⁾	(0.03)			(0.19)			0.01			(0.32)
Impairment	—			1.23			—			1.26

Amortization of deferred financing costs	0.01			0.01			0.01			0.01
Amortization of debt discount	0.01			0.01			0.02			0.02
Other non-cash adjustments	—			—			0.01			—
Tax impact⁽²⁾	0.01			(0.36)			0.05			(0.38)
Adjusted Diluted Earnings Attributable to Oasis Per Share	$	0.03		$	0.09		$	0.14		$	0.19

Diluted weighted average shares outstanding⁽³⁾	314,982			315,664			316,081			304,859

Effective tax rate applicable to adjustment items	19.2		%	24.2		%	(14.0)		%	24.2		%

___________________

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

(3)No unvested stock awards were included in computing Adjusted Diluted Earnings Attributable to Oasis Per Share for the three months ended June 30, 2019 because the effect was anti-dilutive under the treasury stock method. For the six months ended June 30, 2019 and the three and six months ended June 30, 2018, we included 1,357,000, 2,592,000 and 3,207,000, respectively, of unvested stock awards in computing Adjusted Diluted Earnings Attributable to Oasis Per Share due to the dilutive effect under the treasury stock method.

Fair Value of Financial Instruments

See Note 7 — Fair Value Measurements 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.

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Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2018 Annual Report, other than as disclosed in Note 2 — Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements..

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 prices for crude oil, natural gas and natural gas liquids, 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 2018 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 crude 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 crude oil and natural gas prices. Our crude oil contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”), the average Intercontinental Exchange, Inc. Brent crude oil index price (“ICE Brent”), the average Argus WTI Midland crude oil index price (“Midland”) and the average Argus WTI Houston crude oil index price (“Houston”). Our natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).

As of June 30, 2019, we utilized fixed price swaps, basis swaps and two-way and three-way costless collars to reduce the volatility of crude oil and natural gas prices on a significant portion of its future expected crude oil and natural gas production. Our fixed price swaps are comprised of 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 basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relation to the fixed basis differential, we either receive an amount from its counterparty, or pay an amount to its counterparty, equal to the difference multiplied by the hedged contract volume. 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 June 30, 2019:


Commodity	Settlement Period	Derivative Instrument	Index	Volumes				Weighted Average Prices														Fair Value Assets (Liabilities)
																Fixed Price Swaps		Basis Swaps	Sub-Floor	Floor	Ceiling
																					(In thousands)
Crude oil	2019	Fixed price swaps	NYMEX WTI	4,000,000	Bbl	$	57.04									$	(3,303)
Crude oil	2019	Basis swaps	ICE Brent-NYMEX WTI	60,000	Bbl			$	9.68							86
Crude oil	2019	Basis swaps	Midland-NYMEX WTI	120,000	Bbl			$	(6.71)							(740)
Crude oil	2019	Basis swaps	Houston-NYMEX WTI	366,000	Bbl			$	4.55							90
Crude oil	2019	Two-way collar	NYMEX WTI	2,592,000	Bbl							$	57.87	$	74.22	7,308
Crude oil	2019	Three-way collar	NYMEX WTI	2,196,000	Bbl					$	40.14	$	51.52	$	65.92	(284)
Crude oil	2020	Fixed price swaps	NYMEX WTI	2,597,000	Bbl	$	59.30									6,728
Crude oil	2020	Two-way collar	NYMEX WTI	434,000	Bbl							$	58.07	$	74.64	1,835
Crude oil	2020	Three-way collar	NYMEX WTI	4,268,000	Bbl					$	40.00	$	53.49	$	64.49	4,790
Crude oil	2021	Fixed price swaps	NYMEX WTI	93,000	Bbl	$	58.85									357
Crude oil	2021	Three-way collar	NYMEX WTI	310,000	Bbl					$	40.00	$	52.97	$	63.76	376
Natural gas	2019	Fixed price swaps	NYMEX HH	5,520,000	MMBtu	$	2.92									3,037
																$	20,280

A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $64.9 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $64.1 million.

Interest rate risk. At June 30, 2019, we had (i) $71.8 million of senior unsecured notes at a fixed cash interest rate of 6.50% per annum, (ii) $1,267.6 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum, (iii) $300.0 million of senior unsecured convertible notes at a fixed cash interest rate of 2.625% per annum and (iv) $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.25% per annum outstanding.

At June 30, 2019, we had $531.0 million of borrowings and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, which were subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a LIBOR loan or a domestic bank prime interest rate loan (defined in each of the Revolving Credit Facilities as an Alternate Based Rate or “ABR” loan). At June 30, 2019, the outstanding borrowings under the Oasis Credit Facility bore interest at LIBOR plus a 1.75% margin. On a quarterly basis, we also pay a commitment fee that can range from 0.375% to 0.500% 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.

At June 30, 2019, we had $408.0 million of borrowings and $8.2 million of outstanding letters of credit issued under the OMP Credit Facility, which were subject to a per annum interest rate equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the OMP Credit Facility) or (ii) with respect to ABR Loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Facility). The applicable margin for borrowings under the OMP Credit Facility based on OMP’s most recently tested consolidated total leverage ratio and varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75%, and (b) in the case of ABR Loans or swingline loans, 0.75% to 1.75%. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%. At June 30, 2019, the outstanding borrowings under the OMP Credit Facility bore interest at LIBOR plus a 1.75% 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 the Oasis Credit Facility or the OMP 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. For the three and six months ended June 30, 2019, we recorded $0.1 million of bad debt expense as a result of our assessment that it is probable certain receivables may not be collected. We are also subject to credit risk due to concentration of our crude 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.

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.

In addition, our crude 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 the counterparties on our derivative instruments currently in place are Lenders under the Oasis Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other Lenders under the Oasis Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. 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 $20.3 million at June 30, 2019.

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 June 30, 2019. 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, and as a result of the remediation of the material weakness described in “Management’s report on internal control over financial reporting” in our 2018 Annual Report under Part II, Item 9A. “Controls and Procedures,” our CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2019.

Remediation of Previously Identified Material Weakness

Our remediation plan, which was developed and executed in response to the identified material weakness, implements certain changes to our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act), including, but not limited to, the following efforts:

•Enhancement of the controls over all purchase and sale arrangements;

•Revision and communication of the accounting controls, policies and procedures relating to the application of Accounting Standards Codification 845, Nonmonetary Transactions (“ASC 845”); and

•Enhancement of integration and documentation of standards within and between accounting, marketing and other key departments to timely identify transactions that are subject to ASC 845.

During the quarter ended June 30, 2019, management completed the testing and evaluation of the operating effectiveness of the enhanced controls, and based on the results of the testing, the controls were determined to be designed and operating effectively as of June 30, 2019. Accordingly, management concluded the previously identified and reported material weakness was remediated as of June 30, 2019.

Changes in internal control over financial reporting

Except for the remediation of the previously reported material weakness, as noted above, there were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

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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 2018 Annual Report. There have been no material changes in our risk factors from those described in our 2018 Annual Report and subsequent SEC filings.

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

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

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended June 30, 2019:


Period	Total Number of Shares Exchanged⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
April 1 – April 30, 2019	1,313	$	6.03	—	—
May 1 – May 31, 2019	2,401	5.73		—	—
June 1 – June 30, 2019	4,460	5.20		—	—
Total	8,174	$	5.49	—	—

___________________

(1)Represents 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.

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Item 6. — Exhibits


Exhibit No.						Description of Exhibit

10.1						First Amendment to the Third Amended and Restated Credit Agreement, dated as of April 15, 2019, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (filed as Exhibit 10.1 to the Company's Quarterly Report Form 10-Q on May 8, 2019, and incorporated herein by reference).

10.2						First Amendment to Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on May 3, 2019, and incorporated herein by reference).

10.3						Second Amendment to the Third Amended and Restated Credit Agreement, dated as of July 2, 2019, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto.

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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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 Label Linkbase Document.

101.PRE(a)						XBRL Presentation Linkbase Document.

___________________

(a)Filed herewith.

(b)Furnished herewith.

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SIGNATURES

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

OASIS PETROLEUM INC.

Date:

August 9, 2019

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)