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 September 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 October 31, 2019: 321,311,099 shares.

Table of Contents

OASIS PETROLEUM INC.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2019

TABLE OF CONTENTS


			Page
PART I — FINANCIAL INFORMATION			1
Item 1. — Financial Statements (Unaudited)			1
Condensed Consolidated Balance Sheets at September 30, 2019 and December 31, 2018			1
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018			3
Condensed Consolidated Statements of Changes in Stockholders’ Equity			4
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2019 and 2018			6
Notes to Condensed Consolidated Financial Statements			8
1. Organization and Operations of the Company			8
2. Summary of Significant Accounting Policies			8
3. Oasis Midstream Partners			10
4. Revenue Recognition			11
5. Inventory			12
6. Accounts Receivable			13
7. Fair Value Measurements			13
8. Derivative Instruments			15
9. Property, Plant and Equipment			17
10. Divestitures and Assets Held for Sale			17
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			26
19. Condensed Consolidating Financial Information			28
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			59
Item 4. — Controls and Procedures			61
PART II — OTHER INFORMATION			62
Item 1. — Legal Proceedings			62
Item 1A. — Risk Factors			63
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds			63
Item 5.— Other Information			64
Item 6. — Exhibits			64
SIGNATURES			65

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Oasis Petroleum Inc.

Condensed Consolidated Balance Sheets

(Unaudited)


	September 30, 2019		December 31, 2018

	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	19,425	$	22,190
Accounts receivable, net	381,617		387,602
Inventory	36,758		33,128
Prepaid expenses	5,302		10,997

Derivative instruments	52,180		99,930
Intangible assets, net	—		125
Other current assets	332		183
Total current assets	495,614		554,155
Property, plant and equipment
Oil and gas properties (successful efforts method)	9,374,506		8,912,189
Other property and equipment	1,339,268		1,151,772
Less: accumulated depreciation, depletion, amortization and impairment	(3,624,164)		(3,036,852)
Total property, plant and equipment, net	7,089,610		7,027,109
Assets held for sale, net	6,700		—
Derivative instruments	9,729		6,945
Long-term inventory	14,395		12,260
Operating right-of-use assets	21,255		—
Other assets	29,674		25,673
Total assets	$	7,666,977	$	7,626,142

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	18,003	$	20,166
Revenues and production taxes payable	213,773		216,695
Accrued liabilities	325,445		331,651
Accrued interest payable	21,329		38,040
Derivative instruments	830		84

Advances from joint interest partners	3,649		5,140
Current operating lease liabilities	8,050		—
Other current liabilities	2,782		—
Total current liabilities	593,861		611,776
Long-term debt	2,798,859		2,735,276
Deferred income taxes	291,215		300,055
Asset retirement obligations	55,502		52,384
Liabilities held for sale	6,700		—
Derivative instruments	—		20
Operating lease liabilities	19,095		—
Other liabilities	2,084		7,751

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Total liabilities	3,767,316		3,707,262
Commitments and contingencies (Note 18)
Stockholders’ equity
Common stock, $0.01 par value: 900,000,000 shares authorized; 324,235,047 shares issued and 321,343,995 shares outstanding at September 30, 2019 and 320,469,049 shares issued and 318,377,161 shares outstanding at December 31, 2018	3,186		3,157
Treasury stock, at cost: 2,891,052 and 2,091,888 shares at September 30, 2019 and December 31, 2018, respectively	(33,650)		(29,025)
Additional paid-in capital	3,104,938		3,077,755
Retained earnings	630,852		682,689
Oasis share of stockholders’ equity	3,705,326		3,734,576
Non-controlling interests	194,335		184,304
Total stockholders’ equity	3,899,661		3,918,880
Total liabilities and stockholders’ equity	$	7,666,977	$	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 September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands, except per share data)
Revenues
Oil and gas revenues	$	344,470	$	454,195	$	1,070,256	$	1,218,639
Purchased oil and gas sales	79,352		172,985		337,212		368,758
Midstream revenues	50,023		31,187		149,617		88,451
Well services revenues	8,898		16,262		30,795		46,344
Total revenues	482,743		674,629		1,587,880		1,722,192
Operating expenses
Lease operating expenses	50,313		48,534		164,985		137,456
Midstream expenses	12,967		8,652		47,064		24,325
Well services expenses	6,151		11,405		21,595		32,352
Marketing, transportation and gathering expenses	32,659		30,713		96,097		74,559
Purchased oil and gas expenses	78,655		174,269		338,221		374,442
Production taxes	28,461		38,722		86,221		103,748
Depreciation, depletion and amortization	210,832		162,984		578,023		465,819
Exploration expenses	652		22,315		2,369		23,701

Impairment	—		—		653		384,228
General and administrative expenses	52,860		34,859		118,245		91,029
Total operating expenses	473,550		532,453		1,453,473		1,711,659
Gain (loss) on sale of properties	(752)		36,869		(3,950)		38,823
Operating income	8,441		179,045		130,457		49,356
Other income (expense)
Net gain (loss) on derivative instruments	47,922		(48,544)		(34,940)		(239,945)
Interest expense, net of capitalized interest	(43,897)		(39,560)		(131,551)		(117,616)
Loss on extinguishment of debt	—		(47)		—		(13,698)
Other income	473		111		706		146
Total other income (expense), net	4,498		(88,040)		(165,785)		(371,113)
Income (loss) before income taxes	12,939		91,005		(35,328)		(321,757)
Income tax benefit (expense)	17,372		(24,782)		8,835		75,391
Net income (loss) including non-controlling interests	30,311		66,223		(26,493)		(246,366)
Less: Net income attributable to non-controlling interests	10,023		3,882		25,344		10,907
Net income (loss) attributable to Oasis	$	20,288	$	62,341	$	(51,837)	$	(257,273)
Earnings (loss) attributable to Oasis per share:
Basic (Note 15)	$	0.06	$	0.20	$	(0.16)	$	(0.84)
Diluted (Note 15)	0.06		0.20		(0.16)		(0.84)
Weighted average shares outstanding:
Basic (Note 15)	315,135		313,167		314,863		305,533
Diluted (Note 15)	315,135		316,387		314,863		305,533

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


Equity-based compensation	(445)		3			—		—			8,583		—		84		8,670

Distributions to non-controlling interest owners	—		—			—		—			—		—		(5,458)		(5,458)

Treasury stock - tax withholdings	(105)		—			105		(320)			—		—		—		(320)

Net income	—		—			—		—			—		20,288		10,023		30,311
Balance as of September 30, 2019	321,344		$	3,186		2,891		$	(33,650)		$	3,104,938	$	630,852	$	194,335	$	3,899,661

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 (Continued)

(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, 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

Equity-based compensation	498		3			—		—			7,781		—		114		7,898

Distributions to non-controlling interest owners	—		—			—		—			—		—		(3,547)		(3,547)

Treasury stock - tax withholdings	(64)		—			64		(742)			—		—		—		(742)

Net income	—		—			—		—			—		62,341		3,882		66,223
Balance as of September 30, 2018	318,419		$	3,157		2,089		$	(28,985)		$	3,070,642	$	460,712	$	138,557	$	3,644,083

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)


	Nine Months Ended September 30,
	2019		2018

	(In thousands)
Cash flows from operating activities:
Net loss including non-controlling interests	$	(26,493)	$	(246,366)
Adjustments to reconcile net loss including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	578,023		465,819
Loss on extinguishment of debt	—		13,698
(Gain) loss on sale of properties	3,950		(38,823)
Impairment	653		384,228
Deferred income taxes	(8,840)		(75,418)
Derivative instruments	34,940		239,945
Equity-based compensation expenses	26,370		21,586
Deferred financing costs amortization and other	18,190		20,074
Working capital and other changes:
Change in accounts receivable, net	1,555		(61,275)
Change in inventory	(3,676)		(12,076)
Change in prepaid expenses	4,153		1,196


Change in accounts payable, interest payable and accrued liabilities	22,280		50,308


Change in other assets and liabilities, net	(11,211)		(895)
Net cash provided by operating activities	639,894		762,001
Cash flows from investing activities:
Capital expenditures	(714,270)		(841,088)
Acquisitions	(8,337)		(579,886)
Proceeds from sale of properties	41,039		333,029
Costs related to sale of properties	—		(2,707)

Derivative settlements	10,752		(162,013)


Other	—		(1,038)
Net cash used in investing activities	(670,816)		(1,253,703)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	1,651,000		2,499,000
Principal payments on Revolving Credit Facilities	(1,600,000)		(1,959,000)
Repurchase of senior unsecured notes	—		(423,190)
Proceeds from issuance of senior unsecured notes	—		400,000
Deferred financing costs	(852)		(7,650)


Purchases of treasury stock	(4,625)		(6,806)
Distributions to non-controlling interests	(15,551)		(10,393)
Payments on finance lease liabilities	(1,423)		—
Other	(392)		(87)
Net cash provided by financing activities	28,157		491,874
Increase (decrease) in cash and cash equivalents	(2,765)		172
Cash and cash equivalents:
Beginning of period	22,190		16,720
End of period	$	19,425	$	16,892

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Supplemental non-cash transactions:
Change in accrued capital expenditures	$	(42,751)	$	79,011
Change in asset retirement obligations	4,114		2,854

Issuance of shares in connection with acquisition	—		371,220

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 nine months ended September 30, 2018 by revising the unaudited condensed consolidated financial statements appearing herein.

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For the three and nine months ended September 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 September 30, 2018										Nine Months Ended September 30, 2018
	As Reported		Revision		As Revised		As Reported		Revision		As Revised

	(In thousands, except per share data)
Oil and gas revenues	$	452,643	$	1,552	$	454,195	$	1,212,235	$	6,404	$	1,218,639
Purchased oil and gas sales	46,356		126,629		172,985		121,971		246,787		368,758
Total revenues	546,448		128,181		674,629		1,469,001		253,191		1,722,192
Purchased oil and gas expenses	46,088		128,181		174,269		121,251		253,191		374,442
Total operating expenses	404,272		128,181		532,453		1,458,468		253,191		1,711,659
Net income (loss) attributable to Oasis	62,341		—		62,341		(257,273)		—		(257,273)
Income (loss) attributable to Oasis per share:
Basic	$	0.20	$	—	$	0.20	$	(0.84)	$	—	$	(0.84)
Diluted	$	0.20	$	—	$	0.20	$	(0.84)	$	—	$	(0.84)

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 Financial Accounting Standards Board (“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.

Contingencies. Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the

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perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 18 — Commitments and Contingencies for additional information regarding the Company’s contingencies.

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 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 nine months ended September 30, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $13.4 million and $66.2 million, respectively. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 65.6% as of September 30, 2019.

Assignment of midstream assets in Delaware Basin

Effective November 1, 2019, the Company agreed to assign to Panther DevCo LLC (“Panther DevCo”), an indirect, wholly-owned subsidiary of OMP, certain crude oil gathering and produced water gathering and disposal assets (the “Delaware Midstream Assets”) under development to support the Company’s production in the Delaware Basin. OMP has agreed to reimburse the Company for all capital expenditures previously made with respect to the Delaware Midstream Assets, which is estimated to be approximately $25.0 million. OMP expects to fund this amount with borrowings under its revolving credit facility. Also, effective November 1, 2019, Panther DevCo entered into long-term commercial agreements with the Company, including a Crude Oil Gathering Agreement and a Produced Water Gathering and Disposal Agreement (collectively, the “Delaware Basin Commercial Agreements”), for crude oil and produced water midstream services in the Delaware Basin, which generally contain terms similar to those contained in the existing commercial agreements between OMP and the Company for midstream services in the Williston Basin. The Delaware Basin Commercial Agreements additionally provide the Company with certain purchase rights with respect to the Delaware Midstream Assets, and provide Panther DevCo with certain sale rights with respect to the Delaware Midstream Assets, in the event of a change of control of OMP or Panther DevCo, which purchase and sale rights will expire after two years.

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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 nine months ended September 30, 2019 and 2018:


Exploration and Production Revenues
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Crude oil revenues	$	318,564	$	414,082	$	964,662	$	1,103,575
Purchased crude oil sales	77,018		169,531		330,594		364,404
Natural gas and NGL revenues	25,906		40,113		105,594		115,064
Purchased natural gas sales	2,334		1,616		6,590		2,161

Total exploration and production revenues	$	423,822	$	625,342	$	1,407,440	$	1,585,204

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 nine months ended September 30, 2019 and 2018:


Midstream Revenues⁽¹⁾
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Midstream service revenues
Crude oil and natural gas revenues	$	21,653	$	18,188	$	69,189	$	54,124
Produced and flowback water revenues	10,803		9,985		29,309		27,919
Total midstream service revenues	$	32,456	$	28,173	$	98,498	$	82,043
Midstream product revenues
Purchased crude oil sales	$	—	$	1,838	$	28	$	2,193
Natural gas and NGL revenues	16,424		—		46,541		—
Freshwater revenues	1,143		3,014		4,578		6,408
Total midstream product revenues	$	17,567	$	4,852	$	51,147	$	8,601
Total midstream revenues	$	50,023	$	33,025	$	149,645	$	90,644

__________________

(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 nine months ended September 30, 2019 and 2018:


Well Services Revenues⁽¹⁾
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Hydraulic fracturing revenues	$	8,228	$	14,985	$	28,631	$	42,801
Equipment rental revenues	670		1,277		2,164		3,543
Total well services revenues	$	8,898	$	16,262	$	30,795	$	46,344

__________________

(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.

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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 20 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 nine months ended September 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 unconditional. No material contract balances were recorded in the condensed consolidated financial statements at September 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 September 30, 2019:


	(In thousands)
2019 (excluding the nine months ended September 30, 2019)	$	3,003
2020	20,501
2021	25,082
2022	19,259
2023	12,642
Thereafter	14,642
Total	$	95,129

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.

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Total inventory consists of the following:


	September 30, 2019		December 31, 2018

	(In thousands)
Inventory
Crude oil inventory	$	14,823	$	14,933
Equipment and materials	21,935		18,195
Total inventory	$	36,758	$	33,128

Long-term inventory
Linefill in third party pipelines	$	14,395	$	12,260
Total long-term inventory	$	14,395	$	12,260

Total	$	51,153	$	45,388

6. Accounts Receivable

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


	September 30, 2019		December 31, 2018

	(In thousands)

Trade accounts	$	262,966	$	245,546
Joint interest accounts	107,254		133,375
Other accounts	13,014		10,207
Total	383,234		389,128
Allowance for doubtful accounts	(1,617)		(1,526)
Total accounts receivable, net	$	381,617	$	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

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underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

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

Financial Assets and Liabilities

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


	Fair value at September 30, 2019
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Money market funds	$	145	$	—	$	—	$	145
Commodity derivative instruments (see Note 8)	—		61,909		—		61,909
Total assets	$	145	$	61,909	$	—	$	62,054
Liabilities:
Commodity derivative instruments (see Note 8)	$	—	$	830	$	—	$	830
Total liabilities	$	—	$	830	$	—	$	830


	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 September 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 September 30, 2019 and by $0.2 million at December 31, 2018.

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

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”) 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 September 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.

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


Commodity	Settlement Period	Derivative Instrument	Index	Volumes				Weighted Average Prices														Fair Value Assets
																Fixed Price Swaps		Basis Swaps	Sub-Floor	Floor	Ceiling
																					(In thousands)
Crude oil	2019	Fixed price swaps	NYMEX WTI	2,275,000	Bbl	$	57.49									$	5,744
Crude oil	2019	Basis swaps	Houston-NYMEX WTI	90,000	Bbl			$	4.55							142
Crude oil	2019	Two-way collar	NYMEX WTI	1,274,000	Bbl							$	58.07	$	74.64	5,002
Crude oil	2019	Three-way collar	NYMEX WTI	1,092,000	Bbl					$	40.00	$	51.57	$	65.40	768
Crude oil	2020	Fixed price swaps	NYMEX WTI	3,418,000	Bbl	$	58.69									21,461
Crude oil	2020	Two-way collar	NYMEX WTI	2,378,000	Bbl							$	52.11	$	62.98	7,609
Crude oil	2020	Three-way collar	NYMEX WTI	4,574,000	Bbl					$	40.00	$	53.26	$	64.48	15,871
Crude oil	2021	Fixed price swaps	NYMEX WTI	93,000	Bbl	$	58.85									770
Crude oil	2021	Two-way collar	NYMEX WTI	62,000	Bbl							$	50.50	$	60.70	245
Crude oil	2021	Three-way collar	NYMEX WTI	734,000	Bbl					$	40.00	$	51.26	$	64.05	2,101
Natural gas	2019	Fixed price swaps	NYMEX HH	2,760,000	MMBtu	$	2.92									1,366
																$	61,079

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Subsequent to September 30, 2019, the Company entered into additional fixed price swaps and two-way collar options for crude oil with a weighted average floor price of $54.25 per Bbl. The commodity contracts included total notional amounts of 2,005,200 Bbls and 74,400 Bbls, which settle in 2020 and 2021, respectively, based on NYMEX WTI. These derivative instruments do not qualify for or were not designated as hedging instruments for accounting purposes.

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 September 30,						Nine Months Ended September 30,
Statements of Operations Location	2019		2018		2019		2018

	(In thousands)
Net gain (loss) on derivative instruments	$	47,922	$	(48,544)	$	(34,940)	$	(239,945)

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.

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


		September 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	$	63,743	$	(11,563)	$	52,180
Commodity contracts	Derivative instruments — non-current assets	16,263		(6,534)		9,729
Total derivatives assets				$	80,006	$	(18,097)	$	61,909
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	1,428	$	(598)	$	830
Commodity contracts	Derivative instruments — non-current liabilities	—		—		—
Total derivatives liabilities				$	1,428	$	(598)	$	830

		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

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9. Property, Plant and Equipment

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


	September 30, 2019		December 31, 2018

	(In thousands)
Proved oil and gas properties⁽¹⁾	$	8,550,060	$	7,878,104
Less: Accumulated depreciation, depletion, amortization and impairment	(3,400,802)		(2,853,353)
Proved oil and gas properties, net	5,149,258		5,024,751
Unproved oil and gas properties	824,446		1,034,085
Other property and equipment⁽²⁾	1,339,268		1,151,772
Less: Accumulated depreciation	(223,362)		(183,499)
Other property and equipment, net	1,115,906		968,273
Total property, plant and equipment, net	$	7,089,610	$	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 September 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 September 30, 2019 and December 31, 2018, respectively.

10. Divestitures and Assets Held for Sale

Divestitures

The Company reviews portfolio opportunities on an ongoing basis and has engaged in various divestiture transactions over recent years. During the nine months ended September 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 $3.2 million net loss on sale of properties, which includes customary closing adjustments, in its Condensed Consolidated Statements of Operations for the nine months ended September 30, 2019. In addition, the Company also sold partial interests in certain oil and gas properties in the Company’s exploration and production segment. During the three and nine months ended September 30, 2019, the Company recognized a $0.7 million net loss on sale of properties, which includes customary closing adjustments, in its Condensed Consolidated Statements of Operations.

Assets Held for Sale

Assets and liabilities held for sale represent the assets that are expected to be sold and the liabilities that are expected to be assumed by the purchaser, respectively. In October 2019, the Company completed the closings for two separate purchase and sale agreements to sell partial interests in certain non-operated oil and gas properties in the Williston Basin (the “2019 Divestitures”), which includes reimbursements for exploration and production capital expenditures of $6.7 million for the three and nine months ended September 30, 2019 and total cash proceeds of $0.5 million. The assets and liabilities held for sale are in the Company’s exploration and production segment. The transactions had effective dates of January 1, 2019 and June 1, 2019, and the final closing statements for the transactions were completed in October 2019. Upon closing these transactions, the Company recognized a $0.5 million net gain on sale of properties, which includes customary closing adjustments, subsequent to the quarter ended September 30, 2019.

The assets and liabilities sold in the 2019 Divestitures were classified as held for sale as of September 30, 2019. The Company did not have any assets or liabilities classified as held for sale as of December 31, 2018. The following table presents balance sheet data related to the assets and liabilities held for sale related to the 2019 Divestitures as of September 30, 2019:


	September 30, 2019
	(In thousands)
Assets:
Oil and gas properties (successful efforts method)	$	6,700
Less: accumulated depreciation, depletion, amortization and impairment	—
Total assets held for sale, net	$	6,700
Liabilities:
Accrued liabilities	$	6,700
Total liabilities held for sale	$	6,700

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11. Long-Term Debt

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


	September 30, 2019		December 31, 2018

	(In thousands)
Oasis Credit Facility	$	406,000	$	468,000
OMP Credit Facility	431,000		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	(17,309)		(20,865)
Less: unamortized debt discount on senior unsecured convertible notes	(60,241)		(69,268)
Total long-term debt	$	2,798,859	$	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 September 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.

On November 4, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of its borrowing base scheduled for October 1, 2019. As a result, the Company’s borrowing base decreased from $1,600.0 million to $1,300.0 million. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2020. Additionally, the Company entered into the third amendment to the Oasis Credit Facility, which decreased the Company’s aggregate elected commitment from $1,350.0 million to $1,100.0 million.

At September 30, 2019, the Company had $406.0 million of London Interbank Offered Rate (“LIBOR”) loans at a weighted average interest rate of 3.8% and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $930.0 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 September 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.

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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. On August 16, 2019, OMP entered into the third amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $475.0 million to $575.0 million and (ii) provide for the ability to further increase commitments to $775.0 million. As of September 30, 2019, the OMP Credit Facility has an aggregate amount of commitments of $575.0 million and has a maturity date of September 25, 2022.

At September 30, 2019, the Company had $431.0 million of borrowings outstanding under the OMP Credit Facility at a weighted average interest rate of 4.1%, and $8.2 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $135.8 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 September 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 September 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 September 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 September 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 September 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 $1,792.4 million at September 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 nine months ended September 30, 2019:


	(In thousands)
Balance at December 31, 2018	$	52,449
Liabilities incurred during period	1,436
Liabilities settled during period	(644)
Accretion expense during period⁽¹⁾	2,187
Revisions to estimates	647

Balance at September 30, 2019	$	56,075

___________________

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

At September 30, 2019, the current portion of the total ARO balance was approximately $0.6 million and was included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

13. Income Taxes

The Company’s effective tax rate for the three and nine months ended September 30, 2019 was (134.3)% on a pre-tax income of $12.9 million and 25.0% on a pre-tax loss of $35.3 million, respectively, as compared to an effective tax rate of 27.2% on a pre-tax income of $91.0 million and 23.4% on a pre-tax loss of $321.8 million for the three and nine months ended September 30, 2018, respectively.

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

The effective tax rate for the three months ended September 30, 2018 was higher than the statutory federal rate of 21% primarily due to state income taxes and the impact of non-deductible executive compensation. The effective tax rate for the nine months ended September 30, 2018 was higher than the statutory rate primarily due to state income taxes and the impact of a decrease in the Company’s deferred state tax rate, partially offset by the impact of non-deductible executive compensation.

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 or date of modification. Compensation expense is recognized ratably over the requisite service period.

During the nine months ended September 30, 2019, employees and non-employee directors of the Company were granted restricted stock awards equal to 4,051,325 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 $5.8 million and $18.4 million for the three and nine months ended September 30, 2019, respectively, and $5.1 million and $14.7 million for the three and nine months ended September 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

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a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, initial value, stock 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 nine months ended September 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 nine months ended September 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 $7.5 million for the three and nine months ended September 30, 2019, respectively, and $2.2 million and $6.3 million for the three and nine months ended September 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 nine months ended September 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 $0.1 million and $1.8 million for the three and nine months ended September 30, 2019, respectively, and $0.2 million and $0.4 million for the three and nine months ended September 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 nine months ended September 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 $0.3 million for the three and nine months ended September 30, 2019, respectively, and $0.1 million and $0.3 million for the three and nine months ended September 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 nine months ended September 30, 2019 and 2018:


	Three Months Ended September 30,			Nine Months Ended September 30,
	2019	2018	2019	2018

	(In thousands)
Basic and diluted weighted average common shares outstanding	315,135	313,167	314,863	305,533
Dilutive effect of restricted stock awards and PSUs⁽¹⁾	—	3,220	—	—

Diluted weighted average common shares outstanding	315,135	316,387	314,863	305,533

___________________

(1)No unvested stock awards were included in computing earnings (loss) per share for the three and nine months ended September 30, 2019 and for the nine months ended September 30, 2018 because the effects were anti-dilutive.

For the nine months ended September 30, 2019 and 2018, respectively, 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 September 30, 2019 and 2018, respectively, exclude 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 September 30,			Nine Months Ended September 30,
	2019	2018	2019	2018

	(In thousands)
Restricted stock awards and PSUs	9,825	4,180	10,106	7,284

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 September 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 nine months ended September 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 nine months ended September 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 September 30, 2019:
Revenues from non-affiliates	$	423,822	$	50,023	$	8,898	$	—	$	482,743
Inter-segment revenues	—		73,388		21,511		(94,899)		—
Total revenues	423,822		123,411		30,409		(94,899)		482,743
Operating income (loss)	(51,476)		64,299		236		(4,618)		8,441
Other income (expense), net	8,871		(4,512)		139		—		4,498
Income (loss) before income taxes including non-controlling interests	$	(42,605)	$	59,787	$	375	$	(4,618)	$	12,939
General and administrative	$	46,377	$	7,842	$	6,489	$	(7,848)	$	52,860
Equity-based compensation	8,246		383		42		(225)		8,446

Three months ended September 30, 2018:
Revenues from non-affiliates	$	625,342	$	33,025	$	16,262	$	—	$	674,629
Inter-segment revenues	—		42,745		40,177		(82,922)		—
Total revenues	625,342		75,770		56,439		(82,922)		674,629
Operating income	146,969		31,326		9,237		(8,487)		179,045
Other expense, net	(87,594)		(367)		(79)		—		(88,040)
Income before income taxes including non-controlling interests	$	59,375	$	30,959	$	9,158	$	(8,487)	$	91,005
General and administrative	$	30,454	$	5,614	$	5,437	$	(6,646)	$	34,859
Equity-based compensation	7,102		442		354		(442)		7,456

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Nine months ended September 30, 2019:
Revenues from non-affiliates	$	1,407,440	$	149,645	$	30,795	$	—	$	1,587,880
Inter-segment revenues	—		199,793		71,526		(271,319)		—
Total revenues	1,407,440		349,438		102,321		(271,319)		1,587,880
Operating income (loss)	(30,657)		169,321		2,538		(10,745)		130,457
Other income (expense), net	(153,481)		(12,460)		156		—		(165,785)
Income (loss) before income taxes including non-controlling interests	$	(184,138)	$	156,861	$	2,694	$	(10,745)	$	(35,328)
General and administrative	$	99,665	$	24,683	$	20,038	$	(26,141)	$	118,245
Equity-based compensation	25,348		1,363		1,130		(1,471)		26,370

Nine months ended September 30, 2018:
Revenues from non-affiliates	$	1,585,204	$	90,644	$	46,344	$	—	$	1,722,192
Inter-segment revenues	—		119,095		114,898		(233,993)		—
Total revenues	1,585,204		209,739		161,242		(233,993)		1,722,192
Operating income (loss)	(53,159)		101,457		25,415		(24,357)		49,356
Other expense, net	(370,311)		(703)		(99)		—		(371,113)
Income (loss) before income taxes including non-controlling interests	$	(423,470)	$	100,754	$	25,316	$	(24,357)	$	(321,757)
General and administrative	$	77,425	$	18,107	$	17,084	$	(21,587)	$	91,029
Equity-based compensation	20,565		1,222		1,149		(1,350)		21,586

At September 30, 2019:
Property, plant and equipment, net	$	6,236,331	$	1,052,558	$	27,712	$	(226,991)	$	7,089,610
Total assets⁽¹⁾	6,736,948		1,088,728		33,292		(191,991)		7,666,977
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 reclassifications 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.

The following table sets forth the Company’s components of lease costs for the periods presented:


	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019

	(In thousands)
Operating lease costs	$	4,986	$	23,461
Variable lease costs⁽¹⁾	1,730		6,733
Short-term lease costs	1,048		2,418
Finance lease costs:
Amortization of ROU assets	694		1,910
Interest on lease liabilities	72		196
Total lease costs	$	8,530	$	34,718

___________________

(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 September 30, 2019, maturities of the Company’s lease liabilities are as follows:


	Operating Leases		Finance Leases

	(In thousands)
2019 (excluding the nine months ended September 30, 2019)	$	3,232	$	729
2020	7,080		2,909
2021	2,704		2,136
2022	3,073		1,367
2023	2,365		274
Thereafter	12,802		684
Total future lease payments	$	31,256	$	8,099
Less: Imputed interest	4,111		652
Present value of future lease payments	$	27,145	$	7,447

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

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

Balance Sheet Location

September 30, 2019

(In thousands)

Assets

Operating lease assets

Operating right-of-use assets

21,255

Finance lease assets⁽¹⁾

Other assets

7,406

Total lease assets

28,661

Liabilities

Current

Operating lease liabilities

Current operating lease liabilities

8,050

Finance lease liabilities

Other current liabilities

2,698

Long-term

Operating lease liabilities

19,095

Finance lease liabilities

Other liabilities

4,748

Total lease liabilities

34,591

___________________

(1)Finance lease ROU assets are recorded net of accumulated amortization of $1.9 million as of September 30, 2019.

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


	September 30, 2019
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	24,985
Operating cash flows from finance leases	196
Financing cash flows from finance leases	1,423
ROU assets obtained in exchange for lease obligations
Operating leases	$	12,746
Finance leases	3,427

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


	As of September 30, 2019
Operating Leases
Weighted average remaining lease term	6.7 years
Weighted average discount rate	3.6	%
Finance Leases
Weighted average remaining lease term	4.1 years
Weighted average discount rate	3.8	%

18. Commitments and Contingencies

As of September 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.

Volume commitment agreements. As of September 30, 2019, the Company had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 47.6 MMBbls of crude oil, 37.3 MMBbls of natural gas liquids, 869.5 Bcf of natural gas and 18.1 MMBbls of water, prior to any applicable volume credits, within specified timeframes, all of which are 25 years or less. As of September 30, 2019, the estimable future commitments under these agreements were approximately $612.1 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 September 30, 2019.

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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.

During the quarter ended September 30, 2019, a loss accrual was recorded in the amount of $20 million, which the Company believes is the estimable amount of loss that could potentially be incurred from its pending legal proceedings based upon currently available information. This amount was recognized in accrued liabilities in the Company’s Condensed Consolidated Balance Sheet and general and administrative expenses in the Company’s Condensed Consolidated Statements of Operations.

Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) 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 OMP 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.

On July 2, 2019, Oasis, OPNA, OMS, OMP, 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.

On November 1, 2019, Mirada filed a sixth amended petition that stated that Mirada seeks in excess of $200 million in damages and asserted that OMS is an agent of OPNA and OPNA, OMS, OMP, Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC are agents of Oasis. Mirada also changed its allegation that it may elect a new operator to allege that Mirada may remove Oasis as operator.

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On November 1, 2019, the Oasis Entities amended their counterclaim against Mirada for a judgment declaring that a provision in one of the agreements does not incorporate by reference any provisions in a certain participation agreement and joint operating agreement. The additional counterclaim also seeks attorney’s fees, costs and expenses. On the same day, the Oasis Entities filed an amended answer asserting additional defenses against Mirada’s claims.

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.

Solomon litigation. On or about August 28, 2019, Oasis Petroleum LLC, a wholly-owned subsidiary of the Company (“OP LLC”), was named as a defendant in the lawsuit styled Andrew Solomon, on behalf of himself and those similarly situated vs. Oasis Petroleum, LLC, pending in the United States District Court for the Western District of North Dakota. The lawsuit alleged violations of the federal Fair Labor Standards Act (the “FLSA”) and Title 29 of the North Dakota Century Code (“Title 29”) as the result of OP LLC’s alleged practice of paying the plaintiff and similarly situated current and former employees overtime at rates less than required by applicable law, or failing to pay for certain overtime hours worked. The lawsuit requested that: (i) its federal claims be advanced as a collective action, with a class of all Operators, Technicians, and all other employees in substantially similar positions employed by OP LLC who were paid hourly for at least one week during the three year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or eight or more hours on at least one workday; and (ii) its state claims be advanced as a class action, with a class of all Operators, Technicians, and all other employees in substantially similar positions employed by OP LLC in North Dakota during the two year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or worked eight or more hours in a day on at least one workday. No motion has been filed for class certification, and the Company cannot predict whether such a motion will be filed or a class certified.

The Company believes that Mr. Solomon’s claims are without merit and that OP LLC has complied with its obligations under the FLSA and Title 29. OP LLC has filed an answer denying all of Mr. Solomon’s claims and intends to vigorously defend against the claims. The Company cannot predict or guarantee the ultimate outcome or resolutions 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.

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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 (the “Combined Guarantor Subsidiaries”) 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 September 30, 2018, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $5.7 million and $3.9 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $5.7 million and $3.9 million, respectively, in the intercompany eliminations financial information. For the nine months ended September 30, 2018, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $17.2 million and $10.9 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $17.2 million and $10.9 million, respectively, in the intercompany eliminations financial information.

•Condensed Consolidated Statement of Cash Flows. For the nine months ended September 30, 2018, it was determined that cash paid for distributions to non-controlling interests was understated by $92.7 million in the Combined Guarantor Subsidiaries financial information and overstated by $92.7 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 nine months ended September 30, 2018 to reflect the correction of these errors.

In addition, for the three and nine months ended September 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


	September 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	$	145	$	14,608	$	4,672	$	—	$	19,425

Accounts receivable, net	—		373,824		7,793		—		381,617
Accounts receivable - affiliates	549,167		72,492		77,393		(699,052)		—
Inventory	—		35,085		1,673		—		36,758
Prepaid expenses	90		4,248		964		—		5,302

Derivative instruments	—		52,180		—		—		52,180

Other current assets	—		195		137		—		332
Total current assets	549,402		552,632		92,632		(699,052)		495,614
Property, plant and equipment
Oil and gas properties (successful efforts method)	—		9,393,370		—		(18,864)		9,374,506
Other property and equipment	—		249,572		1,089,696		—		1,339,268
Less: accumulated depreciation, depletion, amortization and impairment	—		(3,535,035)		(89,129)		—		(3,624,164)
Total property, plant and equipment, net	—		6,107,907		1,000,567		(18,864)		7,089,610
Assets held for sale, net	—		6,700		—		—		6,700
Investments in and advances to subsidiaries	4,941,278		372,784		—		(5,314,062)		—
Derivative instruments	—		9,729		—		—		9,729
Deferred income taxes	243,100		—		—		(243,100)		—
Long-term inventory	—		14,395		—		—		14,395
Operating right-of-use assets	—		15,310		5,945		—		21,255
Other assets	—		26,291		3,383		—		29,674
Total assets	$	5,733,780	$	7,105,748	$	1,102,527	$	(6,275,078)	$	7,666,977
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	—	$	16,319	$	1,684	$	—	$	18,003
Accounts payable - affiliates	45,723		626,561		26,769		(699,053)		—
Revenues and production taxes payable	—		212,602		1,171		—		213,773
Accrued liabilities	115		277,797		47,533		—		325,445
Accrued interest payable	20,758		298		273		—		21,329
Derivative instruments	—		830		—		—		830

Advances from joint interest partners	—		3,649		—		—		3,649
Current operating lease liabilities	—		5,077		2,973		—		8,050
Other current liabilities	—		2,773		9		—		2,782
Total current liabilities	66,596		1,145,906		80,412		(699,053)		593,861
Long-term debt	1,961,859		406,000		431,000		—		2,798,859
Deferred income taxes	—		534,315		—		(243,100)		291,215
Asset retirement obligations	—		53,906		1,596		—		55,502
Liabilities held for sale	—		6,700		—		—		6,700

Operating lease liabilities	—		16,116		2,979		—		19,095
Other liabilities	—		1,527		557		—		2,084
Total liabilities	2,028,455		2,164,470		516,544		(942,153)		3,767,316
Stockholders’ equity






Oasis share of stockholders’ equity	3,705,325		4,941,278		272,202		(5,213,479)		3,705,326
Non-controlling interests	—		—		313,781		(119,446)		194,335
Total stockholders’ equity	3,705,325		4,941,278		585,983		(5,332,925)		3,899,661
Total liabilities and stockholders’ equity	$	5,733,780	$	7,105,748	$	1,102,527	$	(6,275,078)	$	7,666,977

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

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	344,102	$	—	$	368	$	344,470
Purchased oil and gas sales	—		79,352		—		—		79,352
Midstream revenues	—		2,190		100,693		(52,860)		50,023
Well services revenues	—		8,898		—		—		8,898
Total revenues	—		434,542		100,693		(52,492)		482,743
Operating expenses
Lease operating expenses	—		67,367		—		(17,054)		50,313
Midstream expenses	—		4		24,317		(11,354)		12,967
Well services expenses	—		6,151		—		—		6,151
Marketing, transportation and gathering expenses	—		44,409		—		(11,750)		32,659
Purchased oil and gas expenses	—		78,655		—		—		78,655
Production taxes	—		28,461		—		—		28,461
Depreciation, depletion and amortization	—		206,989		8,983		(5,140)		210,832
Exploration expenses	—		652		—		—		652


General and administrative expenses	569		48,944		7,579		(4,232)		52,860
Total operating expenses	569		481,632		40,879		(49,530)		473,550
Loss on sale of properties	—		(752)		—		—		(752)
Operating income (loss)	(569)		(47,842)		59,814		(2,962)		8,441
Other income (expense)
Equity in earnings of subsidiaries	54,755		42,317		—		(97,072)		—
Net gain on derivative instruments	—		47,922		—		—		47,922
Interest expense, net of capitalized interest	(33,133)		(6,252)		(4,512)		—		(43,897)

Other income	1		472		—		—		473
Total other income (expense), net	21,623		84,459		(4,512)		(97,072)		4,498
Income before income taxes	21,054		36,617		55,302		(100,034)		12,939
Income tax benefit (expense)	(766)		18,138		—		—		17,372
Net income including non-controlling interests	20,288		54,755		55,302		(100,034)		30,311
Less: Net income attributable to non-controlling interests	—		—		23,866		(13,843)		10,023
Net income attributable to Oasis	$	20,288	$	54,755	$	31,436	$	(86,191)	$	20,288

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Condensed Consolidating Statement of Operations


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

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	454,195	$	—	$	—	$	454,195
Purchased oil and gas sales	—		172,985		—		—		172,985
Midstream revenues	—		765		71,467		(41,045)		31,187
Well services revenues	—		16,262		—		—		16,262
Total revenues	—		644,207		71,467		(41,045)		674,629
Operating expenses
Lease operating expenses	—		63,099		—		(14,565)		48,534
Midstream expenses	—		528		19,816		(11,692)		8,652
Well services expenses	—		11,405		—		—		11,405
Marketing, transportation and gathering expenses	—		36,839		—		(6,126)		30,713
Purchased oil and gas expenses	—		174,329		—		(60)		174,269
Production taxes	—		38,722		—		—		38,722
Depreciation, depletion and amortization	—		159,843		7,189		(4,048)		162,984
Exploration expenses	—		22,315		—		—		22,315


General and administrative expenses	7,486		24,627		5,449		(2,703)		34,859
Total operating expenses	7,486		531,707		32,454		(39,194)		532,453
Gain on sale of properties	—		36,869		—		—		36,869
Operating income (loss)	(7,486)		149,369		39,013		(1,851)		179,045
Other income (expense)
Equity in earnings of subsidiaries	96,555		33,102		—		(129,657)		—
Net loss on derivative instruments	—		(48,544)		—		—		(48,544)
Interest expense, net of capitalized interest	(32,836)		(6,561)		(163)		—		(39,560)
Loss on extinguishment of debt	(47)		—		—		—		(47)
Other income (expense)	—		126		(15)		—		111
Total other income (expense), net	63,672		(21,877)		(178)		(129,657)		(88,040)
Income before income taxes	56,186		127,492		38,835		(131,508)		91,005
Income tax benefit (expense)	6,155		(30,937)		—		—		(24,782)
Net income including non-controlling interests	62,341		96,555		38,835		(131,508)		66,223
Less: Net income attributable to non-controlling interests	—		—		26,459		(22,577)		3,882
Net income attributable to Oasis	$	62,341	$	96,555	$	12,376	$	(108,931)	$	62,341

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Condensed Consolidating Statement of Operations


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

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	1,069,888	$	—	$	368	$	1,070,256
Purchased oil and gas sales	—		337,212		—		—		337,212
Midstream revenues	—		6,342		289,988		(146,713)		149,617
Well services revenues	—		30,795		—		—		30,795
Total revenues	—		1,444,237		289,988		(146,345)		1,587,880
Operating expenses
Lease operating expenses	—		208,514		—		(43,529)		164,985
Midstream expenses	—		2,527		79,257		(34,720)		47,064
Well services expenses	—		21,595		—		—		21,595
Marketing, transportation and gathering expenses	—		128,220		—		(32,123)		96,097
Purchased oil and gas expenses	—		338,221		—		—		338,221
Production taxes	—		86,221		—		—		86,221
Depreciation, depletion and amortization	—		566,812		26,474		(15,263)		578,023
Exploration expenses	—		2,369		—		—		2,369

Impairment	—		653		—		—		653
General and administrative expenses	15,964		91,121		24,108		(12,948)		118,245
Total operating expenses	15,964		1,446,253		129,839		(138,583)		1,453,473
Loss on sale of properties	—		(3,950)		—		—		(3,950)
Operating income (loss)	(15,964)		(5,966)		160,149		(7,762)		130,457
Other income (expense)
Equity in earnings of subsidiaries	39,118		114,570		—		(153,688)		—
Net loss on derivative instruments	—		(34,940)		—		—		(34,940)
Interest expense, net of capitalized interest	(98,424)		(20,658)		(12,469)		—		(131,551)

Other income (expense)	2		708		(4)		—		706
Total other income (expense), net	(59,304)		59,680		(12,473)		(153,688)		(165,785)
Income (loss) before income taxes	(75,268)		53,714		147,676		(161,450)		(35,328)
Income tax benefit (expense)	23,431		(14,596)		—		—		8,835
Net income (loss) including non-controlling interests	(51,837)		39,118		147,676		(161,450)		(26,493)
Less: Net income attributable to non-controlling interests	—		—		68,499		(43,155)		25,344
Net income (loss) attributable to Oasis	$	(51,837)	$	39,118	$	79,177	$	(118,295)	$	(51,837)

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Condensed Consolidating Statement of Operations


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

	(In thousands)
Revenues
Oil and gas revenues	$	—	$	1,218,639	$	—	$	—	$	1,218,639
Purchased oil and gas sales	—		368,758		—		—		368,758
Midstream revenues	—		2,832		199,446		(113,827)		88,451
Well services revenues	—		46,344		—		—		46,344
Total revenues	—		1,636,573		199,446		(113,827)		1,722,192
Operating expenses
Lease operating expenses	—		176,413		—		(38,957)		137,456
Midstream expenses	—		2,054		53,266		(30,995)		24,325
Well services expenses	—		32,352		—		—		32,352
Marketing, transportation and gathering expenses	—		92,164		—		(17,605)		74,559
Purchased oil and gas expenses	—		374,502		—		(60)		374,442
Production taxes	—		103,748		—		—		103,748
Depreciation, depletion and amortization	—		456,624		20,212		(11,017)		465,819
Exploration expenses	—		23,701		—		—		23,701

Impairment	—		384,228		—		—		384,228
General and administrative expenses	22,214		60,259		17,496		(8,940)		91,029
Total operating expenses	22,214		1,706,045		90,974		(107,574)		1,711,659
Gain on sale of properties	—		38,823		—		—		38,823
Operating income (loss)	(22,214)		(30,649)		108,472		(6,253)		49,356
Other income (expense)
Equity in earnings (loss) of subsidiaries	(149,295)		90,689		—		58,606		—
Net loss on derivative instruments	—		(239,945)		—		—		(239,945)
Interest expense, net of capitalized interest	(98,417)		(18,591)		(608)		—		(117,616)
Loss on extinguishment of debt	(13,698)		—		—		—		(13,698)
Other income (expense)	—		161		(15)		—		146
Total other expense, net	(261,410)		(167,686)		(623)		58,606		(371,113)
Income (loss) before income taxes	(283,624)		(198,335)		107,849		52,353		(321,757)
Income tax benefit	26,351		49,040		—		—		75,391
Net income (loss) including non-controlling interests	(257,273)		(149,295)		107,849		52,353		(246,366)
Less: Net income attributable to non-controlling interests	—		—		73,075		(62,168)		10,907
Net income (loss) attributable to Oasis	$	(257,273)	$	(149,295)	$	34,774	$	114,521	$	(257,273)

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Condensed Consolidating Statement of Cash Flows


	Nine Months Ended September 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	$	(51,837)	$	39,118	$	147,676	$	(161,450)	$	(26,493)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by (used in) operating activities:
Equity in earnings of subsidiaries	(39,118)		(114,570)		—		153,688		—
Depreciation, depletion and amortization	—		566,812		26,474		(15,263)		578,023

Loss on sale of properties	—		3,950		—		—		3,950
Impairment	—		653		—		—		653
Deferred income taxes	(23,431)		14,591		—		—		(8,840)
Derivative instruments	—		34,940		—		—		34,940
Equity-based compensation expenses	13,933		12,134		303		—		26,370
Deferred financing costs amortization and other	12,582		4,948		660		—		18,190
Working capital and other changes:
Change in accounts receivable, net	94,214		9,858		(1,255)		(101,262)		1,555
Change in inventory	—		(3,676)		—		—		(3,676)
Change in prepaid expenses	283		3,416		454		—		4,153


Change in accounts payable, interest payable and accrued liabilities	(13,684)		(63,125)		(2,173)		101,262		22,280


Change in other assets and liabilities, net	—		(9,258)		(1,953)		—		(11,211)
Net cash provided by (used in) operating activities	(7,058)		499,791		170,186		(23,025)		639,894
Cash flows from investing activities:
Capital expenditures	—		(543,420)		(170,850)		—		(714,270)
Acquisitions	—		(8,337)		—		—		(8,337)
Proceeds from sale of properties	—		41,039		—		—		41,039

Derivative settlements	—		10,752		—		—		10,752



Net cash used in investing activities	—		(499,966)		(170,850)		—		(670,816)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	—		1,533,000		118,000		—		1,651,000
Principal payments on Revolving Credit Facilities	—		(1,595,000)		(5,000)		—		(1,600,000)


Deferred financing costs	—		(41)		(811)		—		(852)


Purchases of treasury stock	(4,625)		—		—		—		(4,625)
Distributions to non-controlling interests	—		—		(69,667)		54,116		(15,551)
Investment in subsidiaries / capital contributions from parent	11,649		62,824		(43,382)		(31,091)		—
Payments on finance lease liabilities	—		(1,364)		(59)		—		(1,423)
Other	—		2		(394)		—		(392)
Net cash provided by (used in) financing activities	7,024		(579)		(1,313)		23,025		28,157
Decrease in cash and cash equivalents	(34)		(754)		(1,977)		—		(2,765)
Cash and cash equivalents at beginning of period	179		15,362		6,649		—		22,190
Cash and cash equivalents at end of period	$	145	$	14,608	$	4,672	$	—	$	19,425

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Condensed Consolidating Statement of Cash Flows


	Nine Months Ended September 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	$	(257,273)	$	(149,295)	$	107,849	$	52,353	$	(246,366)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by (used in) operating activities:
Equity in earnings (loss) of subsidiaries	149,295		(90,689)		—		(58,606)		—
Depreciation, depletion and amortization	—		456,624		20,212		(11,017)		465,819
Loss on extinguishment of debt	13,698		—		—		—		13,698
Gain on sale of properties	—		(38,823)		—		—		(38,823)
Impairment	—		384,228		—		—		384,228
Deferred income taxes	(26,351)		(49,067)		—		—		(75,418)
Derivative instruments	—		239,945		—		—		239,945
Equity-based compensation expenses	20,292		1,014		280		—		21,586
Deferred financing costs amortization and other	11,955		7,884		235		—		20,074
Working capital and other changes:
Change in accounts receivable, net	(227,589)		(77,231)		8,747		234,798		(61,275)
Change in inventory	—		(12,076)		—		—		(12,076)
Change in prepaid expenses	(350)		864		682		—		1,196


Change in accounts payable, interest payable and accrued liabilities	(12,270)		278,481		18,895		(234,798)		50,308


Change in other assets and liabilities, net	—		(895)		—		—		(895)
Net cash provided by (used in) operating activities	(328,593)		950,964		156,900		(17,270)		762,001
Cash flows from investing activities:
Capital expenditures	—		(621,269)		(219,819)		—		(841,088)
Acquisitions	—		(579,886)		—		—		(579,886)
Proceeds from sale of properties	—		333,029		—		—		333,029
Costs related to sale of properties	—		(2,707)		—		—		(2,707)
Derivative settlements	—		(162,013)		—		—		(162,013)


Other	—		(1,038)		—		—		(1,038)
Net cash used in investing activities	—		(1,033,884)		(219,819)		—		(1,253,703)
Cash flows from financing activities:
Proceeds from Revolving Credit Facilities	—		2,376,000		123,000		—		2,499,000
Principal payments on Revolving Credit Facilities	—		(1,924,000)		(35,000)		—		(1,959,000)
Repurchase of senior unsecured notes	(423,190)		—		—		—		(423,190)
Proceeds from issuance of senior unsecured convertible notes	400,000		—		—		—		400,000
Deferred financing costs	(7,058)		(261)		(331)		—		(7,650)


Purchases of treasury stock	(6,806)		—		—		—		(6,806)
Distributions to non-controlling interests	—		—		(103,065)		92,672		(10,393)
Investment in subsidiaries / capital contributions from parent	365,601		(372,621)		82,422		(75,402)		—
Other	38		(125)		—		—		(87)
Net cash provided by financing activities	328,585		78,993		67,026		17,270		491,874

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Increase (decrease) in cash and cash equivalents	(8)		(3,927)		4,107		—		172
Cash and cash equivalents at beginning of period	178		15,659		883		—		16,720
Cash and cash equivalents at end of period	$	170	$	11,732	$	4,990	$	—	$	16,892

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, 90% 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 averaged approximately $1.00 per barrel discount to NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”) during the first nine months of 2019. In the Delaware Basin, price differentials have improved throughout the year due to new pipelines coming online, averaging close to $1.00 below NYMEX WTI during the third quarter of 2019 as compared to more than $5.00 per barrel below NYMEX WTI in the first quarter of 2019. Expansions of pipelines will continue to improve differentials and provide ample takeaway for our Delaware Basin production.

Expected future commodity prices and estimates of future production play a significant role in determining impairment of proved oil and natural gas properties. As a result of lower commodity prices and lower recoverable reserves in the Williston Basin and Delaware Basin and their impact on our estimated future cash flows, we reviewed our proved oil and natural gas properties for impairment. As of September 30, 2019, the excess of our estimated undiscounted future cash flows over the carrying value of our proved oil and natural gas properties was $313.6 million in the Williston Basin and $252.9 million in the Delaware Basin. Our estimated undiscounted future cash flows include the cost benefits from consolidating our midstream and well services business segments. If we discontinue the operations of one or both of these business segments, our expected future costs would increase, which may cause the estimated undiscounted future cash flows to decline below the carrying value of our proved oil and natural gas properties. The underlying commodity prices included in our estimated undiscounted cash flows were determined using NYMEX forward strip prices for five years, escalating 3% per year thereafter. Our estimated undiscounted future cash flows also included a 3% inflation factor applied to the future operating and development costs after five years and every year thereafter. If expected future commodity prices decline by approximately 3% as compared to September 30, 2019, holding all other factors constant, the estimated undiscounted future cash flows may not exceed the carrying value of our proved oil and natural gas properties in the Williston Basin, and if expected future commodity prices decline by approximately 16% as compared to September 30, 2019, holding all other factors constant, the estimated undiscounted future cash flows may not exceed the carrying value of our proved oil and natural gas properties in the Delaware Basin. As a result, we may recognize proved property impairment charges in the future for the Williston Basin and Delaware Basin, and such impairment charges could exceed $2 billion and $350 million, respectively, assuming a discount rate of 10%. This sensitivity analysis decreased the expected future prices of both crude oil and natural gas, but a decline in the realized price of either commodity or an increase to costs greater than those described above may independently impact our estimated future cash flows.

Highlights:

•We produced 88,715 barrel of oil equivalent per day (“Boepd”) in the third quarter of 2019, which represents a 4% increase over third quarter 2018 and was 71% crude oil.

•We divested upstream assets in various packages located in the Williston Basin, resulting in approximately $41.0 million in cash proceeds.

•We reduced the debt under the Oasis Credit Facility by $125.0 million during the quarter to $406.0 million as of September 30, 2019.

•Lease operating expenses per barrel of oil equivalent (“Boe”) averaged $6.16 per Boe in the third quarter of 2019.

•Our crude oil differentials remained strong at $1.30 off of NYMEX WTI in the third quarter of 2019.

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•Net cash provided by operating activities was $251.0 million for the three months ended September 30, 2019. Adjusted EBITDA, a non-GAAP financial measure, was $256.6 million for the three months ended September 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 September 30,										Nine Months Ended September 30,
	2019		2018		Change		2019		2018		Change
Operating results (in thousands)
Revenues
Crude oil revenues⁽¹⁾	$	318,564	$	414,082	$	(95,518)	$	964,662	$	1,103,575	$	(138,913)
Natural gas revenues	25,906		40,113		(14,207)		105,594		115,064		(9,470)
Purchased oil and gas sales⁽¹⁾	79,352		172,985		(93,633)		337,212		368,758		(31,546)
Midstream revenues	50,023		31,187		18,836		149,617		88,451		61,166
Well services revenues	8,898		16,262		(7,364)		30,795		46,344		(15,549)
Total revenues	$	482,743	$	674,629	$	(191,886)	$	1,587,880	$	1,722,192	$	(134,312)
Production data
Williston Basin
Crude oil (MBbls)	5,147		5,716		(569)		15,770		16,046		(276)
Natural gas (MMcf)	13,387		10,268		3,119		38,623		29,559		9,064
Oil equivalents (MBoe)	7,378		7,427		(49)		22,207		20,972		1,235
Average daily production (Boepd)	80,194		80,731		(537)		81,344		76,822		4,522
Delaware Basin
Crude oil (MBbls)	632		344		288		1,524		816		708
Natural gas (MMcf)	909		513		396		2,217		1,266		951
Oil equivalents (MBoe)	784		430		354		1,894		1,027		867
Average daily production (Boepd)	8,521		4,669		3,852		6,939		3,761		3,178
Total average daily production (Boepd)	88,715		85,400		3,315		88,283		80,583		7,700
Average sales prices
Crude oil, without derivative settlements (per Bbl)	$	55.12	$	68.33	$	(13.21)	$	55.78	$	65.45	$	(9.67)
Crude oil, with derivative settlements (per Bbl)⁽²⁾	56.03		57.50		(1.47)		56.19		55.78		0.41
Natural gas, without derivative settlements (per Mcf)⁽³⁾	1.81		3.72		(1.91)		2.59		3.73		(1.14)
Natural gas, with derivative settlements (per Mcf)⁽²⁾⁽³⁾	1.95		3.76		(1.81)		2.67		3.77		(1.10)

____________________

(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 $126.6 million, $128.2 million and $1.6 million, respectively, for the three months ended September 30, 2018 and by $246.8 million, $253.2 million and $6.4 million, respectively, for the nine months ended September 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 September 30, 2019 as compared to three months ended September 30, 2018

Crude oil and natural gas revenues. Our crude oil and natural gas revenues decreased $109.7 million to $344.5 million during the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. This decrease was primarily driven by a $100.6 million decrease due to the lower crude oil and natural gas sales prices, coupled with a $15.5 million decrease driven by lower crude oil production amounts sold quarter over quarter. These decreases were partially offset by a $6.4 million increase driven by higher natural gas production amounts sold quarter over quarter. Average crude oil sales prices, without derivative settlements, decreased by $13.21 per barrel to an average of $55.12 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 $1.91 per Mcf to an average of $1.81 per Mcf for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. Average daily production sold increased by 3,315 Boepd to 88,715 Boepd quarter over quarter primarily due to an increase in natural gas production, offset by a decrease in crude oil production. The increase in average daily production sold was primarily a result of our 11.9 net well completions in the Williston Basin and 4.9 net well completions in the Delaware Basin during the three months ended September 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 $93.6 million to $79.4 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018 primarily due to lower crude oil volumes purchased and sold in the Williston Basin.

Midstream revenues. Midstream revenues increased $18.8 million to $50.0 million during the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. This increase was primarily driven by a $19.4 million increase related 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, coupled with higher natural gas sales resulting from the commencement of third party natural gas purchase arrangements in the fourth quarter of 2018. These increases were offset by a decrease of $1.1 million related to lower freshwater sales.

Well services revenues. Our well services revenues decreased by $7.4 million to $8.9 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018, primarily due to a $4.9 million decrease in well completion revenue due to decreased activity as a result of reducing to one fracturing crew in the third quarter of 2019, a $1.9 million decrease in product sales to third parties and a $0.6 million decrease in equipment rentals quarter over quarter.

Nine months ended September 30, 2019 as compared to nine months ended September 30, 2018

Crude oil and natural gas revenues. Our crude oil and natural gas revenues decreased $148.3 million, or 12%, to $1,070.3 million during the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. The lower crude oil and natural gas sales prices decreased revenues by $198.4 million, offset by a $50.0 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 $9.67 per barrel to an average of $55.78 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 $1.14 per Mcf to an average of $2.59 per Mcf for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. Average daily production sold increased by 7,700 Boe per day to 88,283 Boe per day period over period. The increase in average daily production sold was primarily a result of our 54.0 total net well completions in the Williston Basin and 11.2 total net well completions in the Delaware Basin during the twelve months ended September 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 $31.5 million to $337.2 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 primarily due to lower crude oil volumes purchased and sold in the Williston Basin.

Midstream revenues. Midstream revenues were $149.6 million for the nine months ended September 30, 2019, which was a $61.2 million increase period over period. This increase was driven by a $60.4 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. These increases were offset by a $2.2 million decrease in revenues related to lower crude oil volumes gathered, stabilized and transported.

Well services revenues. Our well services revenues decreased by $15.5 million to $30.8 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. This decrease was primarily driven by a $7.6 million decrease in well completion revenue due to decreased activity as a result of reducing to one fracturing crew in the third quarter of 2019, a $6.5 million decrease in product sales to third parties and a $1.3 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 September 30,										Nine Months Ended September 30,
	2019		2018		Change		2019		2018		Change

	(In thousands, except per Boe of production)
Operating expenses
Lease operating expenses	$	50,313	$	48,534	$	1,779	$	164,985	$	137,456	$	27,529
Midstream expenses	12,967		8,652		4,315		47,064		24,325		22,739
Well services expenses	6,151		11,405		(5,254)		21,595		32,352		(10,757)
Marketing, transportation and gathering expenses	32,659		30,713		1,946		96,097		74,559		21,538
Purchased oil and gas expenses⁽¹⁾	78,655		174,269		(95,614)		338,221		374,442		(36,221)
Production taxes	28,461		38,722		(10,261)		86,221		103,748		(17,527)
Depreciation, depletion and amortization	210,832		162,984		47,848		578,023		465,819		112,204
Exploration expenses	652		22,315		(21,663)		2,369		23,701		(21,332)

Impairment	—		—		—		653		384,228		(383,575)
General and administrative expenses	52,860		34,859		18,001		118,245		91,029		27,216
Total operating expenses	473,550		532,453		(58,903)		1,453,473		1,711,659		(258,186)
Gain (loss) on sale of properties	(752)		36,869		(37,621)		(3,950)		38,823		(42,773)
Operating income	8,441		179,045		(170,604)		130,457		49,356		81,101
Other income (expense)
Net gain (loss) on derivative instruments	47,922		(48,544)		96,466		(34,940)		(239,945)		205,005
Interest expense, net of capitalized interest	(43,897)		(39,560)		(4,337)		(131,551)		(117,616)		(13,935)
Loss on extinguishment of debt	—		(47)		47		—		(13,698)		13,698
Other income	473		111		362		706		146		560
Total other income (expense), net	4,498		(88,040)		92,538		(165,785)		(371,113)		205,328
Income (loss) before income taxes	12,939		91,005		(78,066)		(35,328)		(321,757)		286,429
Income tax benefit (expense)	17,372		(24,782)		42,154		8,835		75,391		(66,556)
Net income (loss) including non-controlling interests	30,311		66,223		(35,912)		(26,493)		(246,366)		219,873
Less: Net income attributable to non-controlling interests	10,023		3,882		6,141		25,344		10,907		14,437
Net income (loss) attributable to Oasis	$	20,288	$	62,341	$	(42,053)	$	(51,837)	$	(257,273)	$	205,436
Costs and expenses (per Boe of production)
Lease operating expenses	$	6.16	$	6.18	$	(0.02)	$	6.85	$	6.25	$	0.60
Marketing, transportation and gathering expenses	4.00		3.91		0.09		3.99		3.39		0.60
Production taxes	3.49		4.93		(1.44)		3.58		4.72		(1.14)

____________________

(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 $126.6 million, $128.2 million and $1.6 million, respectively, for the three months ended September 30, 2018 and by $246.8 million, $253.2 million and $6.4 million, respectively, for the nine months ended September 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 September 30, 2019 as compared to three months ended September 30, 2018

Lease operating expenses. Lease operating expenses increased $1.8 million to $50.3 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. This 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 fixed and workover costs quarter over quarter. Lease operating expenses per Boe decreased quarter over quarter from $6.18 per Boe to $6.16 per Boe primarily due to higher production volumes, offset by 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 $4.3 million increase quarter over quarter was primarily related to a $4.8 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, offset by a $0.5 million decrease in 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 $5.3 million decrease quarter over quarter was primarily attributable to a $3.8 million decrease in well completion expenses due to decreased activity as a result of reducing to one fracturing crew in the third quarter of 2019, coupled with a $1.5 million decrease in product sales to third parties.

Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $1.9 million, or $0.09 per Boe, for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018, which was primarily attributable to higher natural gas gathering and processing expenses due to additional well connections on our midstream infrastructure and our second natural gas processing plant. Excluding non-cash valuation adjustments, our marketing, transportation and gathering expenses on a per Boe basis increased to $4.01 during the three months ended September 30, 2019 as compared to $3.84 during the three months ended September 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 $95.6 million to $78.7 million for the three months ended September 30, 2019 as compared to the three months ended September 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 8.3% and 8.6% for the three months ended September 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 $0.0712 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 $47.8 million to $210.8 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. This increase was a result of increased production from our wells completed during the three months ended September 30, 2019, coupled with an increase in the DD&A rate to $25.83 per Boe for the three months ended September 30, 2019 as compared to $20.74 per Boe for the three months ended September 30, 2018. The increase in the DD&A rate was primarily due to lower recoverable reserves in the Williston Basin and Delaware Basin, coupled with higher well costs in the Delaware Basin.

Exploration expenses. Exploration expenses decreased $21.6 million to $0.7 million for the three months ended September 30, 2019, as compared to the three months ended September 30, 2018, primarily due to lower write-off of costs of $19.7 million related to exploratory well locations that are no longer in our current development plan.

General and administrative expenses (“G&A”). G&A increased $18.0 million to $52.9 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. E&P G&A increased $15.9 million quarter over quarter primarily due to a $20 million loss accrual, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information (see Note 18 — Commitments and Contingencies). This increase was coupled with an increase in severance expenses related to a reduction in force during the third quarter of 2019, partially offset by decreases in acquisition costs and accrued bonuses. OWS G&A increased $1.5 million quarter over quarter primarily due to severance expenses resulting from a reduction in force to one fracturing crew during the third quarter of 2019. OMS G&A increased $0.6 million quarter over quarter primarily due to increased shared services expenses.

Gain (loss) on sale of properties. For the three months ended September 30, 2019, we recognized a $0.8 million net loss primarily related to the sale of partial interests in certain oil and gas properties (see Note 10 — Divestitures and Assets Held for Sale). For the three months ended September 30, 2018, we recognized a $36.9 million net gain primarily related to three separate divestitures to sell certain non-strategic oil and gas 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 $47.9 million net gain on derivative instruments, including net cash settlement receipts of $7.1 million, for the three months ended September 30, 2019, and a $48.5 million net loss on derivative instruments, including net cash settlement payments of $65.2 million, for the three months ended September 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, net of capitalized interest. Interest expense increased $4.3 million to $43.9 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018 primarily due to a $2.8 million increase in interest expense related to our borrowings under the OMP Credit Facility, coupled with a decrease in capitalized interest of $1.5 million due to lower costs for work in progress assets. For the three months ended September 30, 2019, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $514.9 million and $418.5 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 4.0% and 4.1%, respectively. For the three months ended September 30, 2018, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $561.3 million and $172.9 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 3.9% and 3.8%, respectively. Interest capitalized during the three months ended September 30, 2019 and 2018 was $3.0 million and $4.5 million, respectively, which will be amortized over the life of the related assets.

Income tax benefit (expense). Our income tax benefit for the three months ended September 30, 2019 was recorded at (134.3)% of pre-tax income and the income tax expense for the three months ended September 30, 2018 was recorded at 27.2% of pre-tax income. Our effective tax rate for the three months ended September 30, 2019 was lower than the effective tax rate for the three months ended September 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.

Nine months ended September 30, 2019 as compared to nine months ended September 30, 2018

Lease operating expenses. Lease operating expenses increased $27.5 million to $165.0 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. This increase was primarily due to higher fixed costs and workover costs, coupled with higher costs associated with operating an increased number of producing wells as a result of our well completions during the nine months ended September 30, 2019. Lease operating expenses per Boe increased from $6.25 per Boe to $6.85 per Boe primarily due to the higher aforementioned costs, offset by higher production volumes period over period.

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 $22.7 million increase for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was primarily related to the $24.1 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 $2.1 million decrease related to lower produced and flowback water operating expenses period over period.

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 $10.8 million decrease for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was primarily attributable to a $6.1 million decrease in well completion expenses due to decreased activity, coupled with a $4.6 million decrease in product sales to third parties.

Marketing, transportation and gathering expenses. Marketing, transportation and gathering expenses increased $21.5 million period over period, or a $0.60 increase per Boe, which was primarily attributable to higher natural gas gathering and processing expenses due to additional well connections on our midstream infrastructure and our second natural gas processing plant, coupled with 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 $3.89 for the nine months ended September 30, 2019 as compared to $3.36 for the nine months ended September 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 $36.2 million to $338.2 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 primarily due to lower crude oil volumes purchased and sold in the Williston Basin.

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Production taxes. Our production taxes as a percentage of crude oil and natural gas sales were 8.1% and 8.6% for the nine months ended September 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 $0.0712 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 $112.2 million to $578.0 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. This increase was a result of increased production from our wells completed during the nine months ended September 30, 2019, coupled with an increase in the DD&A rate to $23.98 per Boe for the nine months ended September 30, 2019 as compared to $21.17 per Boe for the nine months ended September 30, 2018. The increase in the DD&A rate was primarily due to lower recoverable reserves in the Williston Basin and Delaware Basin, coupled with higher well costs in the Delaware Basin.

Exploration expenses. Exploration expenses decreased $21.3 million to $2.4 million for the nine months ended September 30, 2019, as compared to the nine months ended September 30, 2018, primarily due to lower write-off of costs of $20.0 million related to exploratory well locations that are no longer in our current development plan.

Impairment. During the nine months ended September 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 nine months ended September 30, 2019.

G&A. G&A increased $27.2 million to $118.2 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. E&P G&A increased $22.2 million period over period primarily due to a $20 million loss accrual, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information (see Note 18 — Commitments and Contingencies). This increase was coupled with increased costs related to employee compensation expenses as a result of organizational growth during the first half of 2019 coupled with severance expenses related to a reduction in force during the third quarter of 2019, and partially offset by the decrease in costs related to the Permian Basin Acquisition, which were incurred during the nine months ended September 30, 2018. OMS G&A increased $2.6 million period over period primarily due to increased shared services expenses as a result of the growth of our midstream business. OWS G&A increased $2.4 million due to severance expenses resulting from a reduction in force to one fracturing crew during the third quarter of 2019.

Gain (loss) on sale of properties. For the nine months ended September 30, 2019, we recognized a $4.0 million net loss primarily due to 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, coupled with a $0.7 million net loss on the sale of partial interests in certain oil and gas properties (see Note 10 — Divestitures and Assets Held for Sale). For the nine months ended September 30, 2018, we recognized a $38.8 million net gain primarily related to three separate divestitures to sell certain non-strategic oil and gas 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 $34.9 million net loss on derivative instruments, including net cash settlement receipts of $10.8 million, for the nine months ended September 30, 2019, and a $239.9 million net loss on derivative instruments, including net cash settlement payments of $162.0 million, for the nine months ended September 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, net of capitalized interest. Interest expense increased $13.9 million to $131.6 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 primarily due to a $8.9 million increase in interest expense related to our borrowings under our Revolving Credit Facilities, coupled with a decrease in capitalized interest of $3.7 million due to lower costs for work in progress assets. For the nine months ended September 30, 2019, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $531.5 million and $376.7 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 4.2% and 4.2%, respectively. For the nine months ended September 30, 2018, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $552.7 million and $142.8 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 3.8% and 3.7%, respectively. Interest capitalized during the nine months ended September 30, 2019 and 2018 was $9.5 million and $13.2 million, respectively, which will be amortized over the life of the related assets.

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Loss on extinguishment of debt. During the nine months ended September 30, 2019, we did not repurchase any portion of our outstanding senior unsecured notes. During the nine months ended September 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 nine months ended September 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. Our income tax benefit for the nine months ended September 30, 2019 and 2018 was recorded at 25.0% and 23.4%, respectively, of pre-tax loss. Our effective tax rate for the nine months ended September 30, 2019 was higher than the effective tax rate for the nine months ended September 30, 2018 primarily due to the impacts of non-controlling interests, offset by the impacts of other permanent differences, primarily non-deductible executive compensation and equity-based compensation shortfalls.

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, proceeds from sale of properties and cash settlements of derivative contracts. Our primary uses of cash have been for the 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 nine months ended September 30, 2019 and 2018 are presented below:


	Nine Months Ended September 30,
	2019		2018

	(In thousands)
Net cash provided by operating activities	$	639,894	$	762,001
Net cash used in investing activities	(670,816)		(1,253,703)
Net cash provided by financing activities	28,157		491,874
Increase (decrease) in cash and cash equivalents	$	(2,765)	$	172

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 $639.9 million and $762.0 million for the nine months ended September 30, 2019 and 2018, respectively. The change in cash flows from operating activities for the period ended September 30, 2019 as compared to 2018 was primarily the result of a 15% decrease in realized prices for crude oil and a 31% decrease in realized prices for natural gas, coupled with changes in working capital and other assets and liabilities. These decreases were offset by a 10% increase in crude oil and natural gas production.

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 $98.2 million at September 30, 2019 due to the impact of decreases in the forward commodity price curve on our short-term derivative instruments and decreases in accounts receivable, partially offset by decreases in our revenue and production taxes payables and accrued liabilities for drilling and development costs. As of September 30, 2019, we had $1,085.2 million of liquidity available, including $19.4 million in cash and cash equivalents and $1,065.8 million of aggregate unused borrowing capacity available under our Revolving Credit Facilities. At September 30, 2018, we had a working capital deficit of $333.2 million.

Cash flows used in investing activities

Net cash used in investing activities was $670.8 million and $1,253.7 million during the nine months ended September 30, 2019 and 2018, respectively. Net cash used in investing activities during the nine months ended September 30, 2019 was primarily attributable to $714.3 million in capital expenditures primarily for drilling and development costs. Net cash used in investing activities during the nine months ended September 30, 2018 was primarily attributable to $841.1 million in capital expenditures

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primarily for drilling and development costs, coupled with $579.9 million in acquisitions primarily for the Permian Basin Acquisition and to acquire certain exploration and production assets adjacent to such acreage.

Our capital expenditures are summarized in the following table:


	Three Months Ended								Nine Months Ended September 30, 2019
	March 31, 2019		June 30, 2019		September 30, 2019

	(In thousands)
Capital expenditures:
E&P	$	165,702	$	202,129	$	143,436	$	511,267
Well services	104		—		178		282
Other capital expenditures⁽¹⁾	3,880		4,330		4,161		12,371
Total E&P and other capital expenditures	169,686		206,459		147,775		523,920
Midstream⁽²⁾	57,108		82,634		36,884		176,626
Total capital expenditures before acquisitions	226,794		289,093		184,659		700,546
Acquisitions	—		5,781		2,557		8,338
Total capital expenditures⁽³⁾	$	226,794	$	294,874	$	187,216	$	708,884

___________________

(1)Other capital expenditures include such items as administrative capital and capitalized interest. Capitalized interest totaled $3.0 million and $9.5 million for the three and nine months ended September 30, 2019, respectively.

(2)Midstream capital expenditures attributable to OMP were $45.2 million, $70.9 million and $27.6 million for the three months ended March 31, 2019, June 30, 2019 and September 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 $832 million to $862 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 $12 million. As a result of increased OMP capital expenditures expected in the Delaware Basin, our planned 2019 midstream capital expenditures are now approximately $212 million to $222 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 nine months ended September 30, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $13.4 million and $66.2 million, respectively. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 65.6% as of September 30, 2019.

While we have planned approximately $832 million to $862 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

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review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Cash flows provided by financing activities

Net cash provided by financing activities was $28.2 million and $491.9 million for the nine months ended September 30, 2019 and 2018, respectively. For the nine months ended September 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 September 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.

On November 4, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for October 1, 2019. As a result, the borrowing base decreased from $1,600.0 million to $1,300.0 million. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2020. Additionally, we entered into the third amendment to the Oasis Credit Facility, which decreased the aggregate elected commitment from $1,350.0 million to $1,100.0 million.

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.

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As of September 30, 2019, we had $406.0 million of borrowings at a weighted average interest rate of 3.8% and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing base committed capacity of $930.0 million. We were in compliance with the financial covenants of the Oasis Credit Facility as of September 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.

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. On August 16, 2019, OMP entered into the third amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $475.0 million to $575.0 million and (ii) provide for the ability to further increase commitments to $775.0 million. As of September 30, 2019, the OMP Credit Facility has an aggregate amount of commitments of $575.0 million and has a maturity date of September 25, 2022.

At September 30, 2019, we had $431.0 million of borrowings at a weighted average interest rate of 4.1% and $8.2 million of outstanding letters of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $135.8 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 September 30, 2019.

Senior unsecured notes. As of September 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 September 30, 2019.

Senior unsecured convertible notes. At September 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 September 30, 2019, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes

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had been met. In addition, we were in compliance with the terms of the indentures for the Senior Convertible Notes as of September 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 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 expenses, 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 and other non-cash charges 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 September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
E&P general and administrative expenses	$	46,377	$	30,454	$	99,665	$	77,425
Equity-based compensation expenses	(8,246)		(7,102)		(25,348)		(20,565)
Litigation contingency expenses⁽¹⁾	(20,000)		—		(20,000)		—
E&P Cash G&A	$	18,131	$	23,352	$	54,317	$	56,860

___________________

(1)In the third quarter of 2019, we incurred a charge to establish a loss accrual of $20 million, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information.

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:

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Interest expense	$	43,897	$	39,560	$	131,551	$	117,616
Capitalized interest	3,001		4,531		9,464		13,209
Amortization of deferred financing costs	(1,861)		(1,813)		(5,454)		(5,511)
Amortization of debt discount	(3,137)		(2,852)		(9,027)		(8,201)
Cash Interest	$	41,900	$	39,426	$	126,534	$	117,113

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 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:

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Net income (loss) including non-controlling interests	$	30,311	$	66,223	$	(26,493)	$	(246,366)
(Gain) loss on sale of properties	752		(36,869)		3,950		(38,823)
Loss on extinguishment of debt	—		47		—		13,698
Net (gain) loss on derivative instruments	(47,922)		48,544		34,940		239,945
Derivative settlements⁽¹⁾	7,123		(65,190)		10,752		(162,013)
Interest expense, net of capitalized interest	43,897		39,560		131,551		117,616
Depreciation, depletion and amortization	210,832		162,984		578,023		465,819
Impairment	—		—		653		384,228

Exploration expenses	652		22,315		2,369		23,701
Equity-based compensation expenses	8,446		7,456		26,370		21,586
Litigation contingency expenses⁽²⁾	20,000		—		20,000		—
Income tax (benefit) expense	(17,372)		24,782		(8,835)		(75,391)
Other non-cash adjustments	(79)		574		2,316		557
Adjusted EBITDA	256,640		270,426		775,596		744,557
Adjusted EBITDA attributable to non-controlling interests	13,606		5,194		35,501		14,647
Adjusted EBITDA attributable to Oasis	243,034		265,232		740,095		729,910
Cash Interest	(41,900)		(39,426)		(126,534)		(117,113)
Capital expenditures⁽³⁾	(187,216)		(372,343)		(708,884)		(1,898,105)
Capitalized interest	3,001		4,531		9,464		13,209
Free Cash Flow	$	16,919	$	(142,006)	$	(85,859)	$	(1,272,099)

Net cash provided by operating activities	$	250,962	$	229,985	$	639,894	$	762,001
Derivative settlements⁽¹⁾	7,123		(65,190)		10,752		(162,013)
Interest expense, net of capitalized interest	43,897		39,560		131,551		117,616

Exploration expenses	652		22,315		2,369		23,701
Deferred financing costs amortization and other	(5,945)		(9,556)		(18,190)		(20,074)
Current tax (benefit) expense	84		(93)		5		27
Changes in working capital	(60,054)		52,831		(13,101)		22,742
Litigation contingency expenses⁽²⁾	20,000		—		20,000		—
Other non-cash adjustments	(79)		574		2,316		557
Adjusted EBITDA	256,640		270,426		775,596		744,557
Adjusted EBITDA attributable to non-controlling interests	13,606		5,194		35,501		14,647
Adjusted EBITDA attributable to Oasis	243,034		265,232		740,095		729,910
Cash Interest	(41,900)		(39,426)		(126,534)		(117,113)
Capital expenditures⁽³⁾	(187,216)		(372,343)		(708,884)		(1,898,105)
Capitalized interest	3,001		4,531		9,464		13,209
Free Cash Flow	$	16,919	$	(142,006)	$	(85,859)	$	(1,272,099)

___________________

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

(2)In the third quarter of 2019, we incurred a charge to establish a loss accrual of $20 million, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information.

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(3)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 $2.5 million and $8.3 million for the three and nine months ended September 30, 2019, respectively, and $55.6 million and $950.1 million for the three and nine months ended September 30, 2018, respectively. In addition, capital expenditures (including acquisitions) reflected in the table above includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition for the nine months ended September 30, 2018.

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 September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Income (loss) before income taxes including non-controlling interests	$	(42,605)	$	59,375	$	(184,138)	$	(423,470)
(Gain) loss on sale of properties	752		(46,459)		3,950		(48,413)
Loss on extinguishment of debt	—		47		—		13,698
Net (gain) loss on derivative instruments	(47,922)		48,544		34,940		239,945
Derivative settlements⁽¹⁾	7,123		(65,190)		10,752		(162,013)
Interest expense, net of capitalized interest	39,385		39,398		119,082		117,009
Depreciation, depletion and amortization	205,902		158,630		563,408		453,083
Impairment	—		—		653		384,228
Exploration expenses	652		22,315		2,369		23,701

Equity-based compensation expenses	8,246		7,102		25,348		20,565
Litigation contingency expenses⁽²⁾	20,000		—		20,000		—
Other non-cash adjustments	(79)		574		2,316		557
Adjusted EBITDA	$	191,454	$	224,336	$	598,680	$	618,890

___________________


Midstream Services
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Income before income taxes including non-controlling interests	$	59,787	$	30,959	$	156,861	$	100,754
Loss on sale of properties	—		9,590		—		9,590
Interest expense, net of capitalized interest	4,512		162		12,469		607
Depreciation, depletion and amortization	9,340		7,373		27,420		20,902

Equity-based compensation expenses	383		442		1,363		1,222

Adjusted EBITDA	$	74,022	$	48,526	$	198,113	$	133,075

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Well Services
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019		2018		2019		2018

	(In thousands)
Income before income taxes including non-controlling interests	$	375	$	9,158	$	2,694	$	25,316
Depreciation, depletion and amortization	3,206		3,940		10,493		11,560

Equity-based compensation expenses	42		354		1,130		1,149

Adjusted EBITDA	$	3,623	$	13,452	$	14,317	$	38,025

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 September 30,									Nine Months Ended September 30,
	2019			2018			2019			2018

	(In thousands, except per share data)
Net income (loss) attributable to Oasis	$	20,288		$	62,341		$	(51,837)		$	(257,273)

(Gain) loss on sale of properties	752			(36,869)			3,950			(38,823)
Loss on extinguishment of debt	—			47			—			13,698
Net (gain) loss on derivative instruments	(47,922)			48,544			34,940			239,945
Derivative settlements⁽¹⁾	7,123			(65,190)			10,752			(162,013)
Impairment	—			—			653			384,228

Amortization of deferred financing costs	1,861			1,814			5,454			5,512
Amortization of debt discount	3,137			2,852			9,027			8,201
Litigation contingency expenses⁽²⁾	20,000			—			20,000			—
Other non-cash adjustments	(79)			574			2,316			557
Tax impact⁽³⁾	(21,173)			12,214			(28,026)			(108,028)
Adjusted Net Income (Loss) Attributable to Oasis	$	(16,013)		$	26,327		$	7,229		$	86,004

Diluted earnings (loss) attributable to Oasis per share	$	0.06		$	0.20		$	(0.16)		$	(0.84)

(Gain) loss on sale of properties	—			(0.12)			0.01			(0.13)
Loss on extinguishment of debt	—			—			—			0.04
Net (gain) loss on derivative instruments	(0.15)			0.15			0.11			0.78
Derivative settlements⁽¹⁾	0.02			(0.21)			0.03			(0.52)
Impairment	—			—			—			1.24

Amortization of deferred financing costs	0.01			0.01			0.02			0.02
Amortization of debt discount	0.01			0.01			0.03			0.03
Litigation contingency expenses⁽²⁾	0.06			—			0.06			—
Other non-cash adjustments	—			—			0.01			—
Tax impact⁽³⁾	(0.06)			0.04			(0.09)			(0.34)
Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share	$	(0.05)		$	0.08		$	0.02		$	0.28

Diluted weighted average shares outstanding⁽⁴⁾	315,135			316,387			315,944			308,985

Effective tax rate applicable to adjustment items	(140.0)		%	25.3		%	32.2		%	23.9		%

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

(4)No unvested stock awards were included in computing Adjusted Diluted Loss Attributable to Oasis Per Share for the three months ended September 30, 2019 because the effect was anti-dilutive due to the Adjusted Net Loss Attributable to Oasis. For the nine months ended September 30, 2019 and three and nine months ended September 30, 2018, we included 1,081,000, 3,220,000 and 3,452,000, 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.

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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.

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”) 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 September 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 our 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 our counterparty, or pay an amount to our 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 September 30, 2019:


Commodity	Settlement Period	Derivative Instrument	Index	Volumes				Weighted Average Prices														Fair Value Assets
																Fixed Price Swaps		Basis Swaps	Sub-Floor	Floor	Ceiling
																					(In thousands)
Crude oil	2019	Fixed price swaps	NYMEX WTI	2,275,000	Bbl	$	57.49									$	5,744
Crude oil	2019	Basis swaps	Houston-NYMEX WTI	90,000	Bbl			$	4.55							142
Crude oil	2019	Two-way collar	NYMEX WTI	1,274,000	Bbl							$	58.07	$	74.64	5,002
Crude oil	2019	Three-way collar	NYMEX WTI	1,092,000	Bbl					$	40.00	$	51.57	$	65.40	768
Crude oil	2020	Fixed price swaps	NYMEX WTI	3,418,000	Bbl	$	58.69									21,461
Crude oil	2020	Two-way collar	NYMEX WTI	2,378,000	Bbl							$	52.11	$	62.98	7,609
Crude oil	2020	Three-way collar	NYMEX WTI	4,574,000	Bbl					$	40.00	$	53.26	$	64.48	15,871
Crude oil	2021	Fixed price swaps	NYMEX WTI	93,000	Bbl	$	58.85									770
Crude oil	2021	Two-way collar	NYMEX WTI	62,000	Bbl							$	50.50	$	60.70	245
Crude oil	2021	Three-way collar	NYMEX WTI	734,000	Bbl					$	40.00	$	51.26	$	64.05	2,101
Natural gas	2019	Fixed price swaps	NYMEX HH	2,760,000	MMBtu	$	2.92									1,366
																$	61,079

A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $55.2 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $55.1 million.

Interest rate risk. At September 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 September 30, 2019, we had $406.0 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 September 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 September 30, 2019, we had $431.0 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 September 30, 2019, the outstanding borrowings under the OMP Credit Facility bore interest at LIBOR plus a 2.00% margin.

We do not currently, but may in the future, utilize interest rate derivatives to mitigate 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 nine months ended September 30, 2019, we

recorded $0.4 million and $0.5 million, respectively, 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 $61.1 million at September 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 September 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, our CEO and CFO concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2019.

Changes in internal control over financial reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 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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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.

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 September 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
July 1 – July 31, 2019	4,456	$	5.16	—	—
August 1 – August 31, 2019	95,177	3.06		—	—
September 1 – September 30, 2019	5,255	3.79		—	—
Total	104,888	$	3.19	—	—

___________________

(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 5. — Other Information

On November 4, 2019, the Company entered into the third amendment to the Oasis Credit Facility, which decreased the aggregate elected commitment from $1,350.0 million to $1,100.0 million.

Item 6. — Exhibits


Exhibit No.						Description of Exhibit

10.1						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 (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q on August 9, 2019, and incorporated herein by reference).

10.2						Third Amendment to the Third Amended and Restated Credit Agreement, dated as of November 4, 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.

104(a)						Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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:

November 6, 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)