oas-20210630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-Q


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

For the quarterly period ended June 30, 2021


☐			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

The Nasdaq Stock Market LLC

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 ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨

Number of shares of the registrant’s common stock outstanding at July 30, 2021: 19,905,111 shares.

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OASIS PETROLEUM INC.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2021

TABLE OF CONTENTS


			Page
PART I — FINANCIAL INFORMATION			1
Item 1. — Financial Statements (Unaudited)			1
Condensed Consolidated Balance Sheets at June 30, 2021 and December 31, 2020			1
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2021 (Successor) and 2020 (Predecessor)			3
Condensed Consolidated Statements of Changes in Stockholders’ Equity (Deficit)			4
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2021 (Successor) and 2020 (Predecessor)			6
Notes to Condensed Consolidated Financial Statements			8
1. Organization and Operations of the Company			8


2. Summary of Significant Accounting Policies			8

3. Revenue Recognition			10
4. Inventory			11
5. Additional Balance Sheet Information			12
6. Fair Value Measurements			12
7. Derivative Instruments			14
8. Property, Plant and Equipment			16
9. Acquisitions			17
10. Divestitures			17
11. Long-Term Debt			18
12. Asset Retirement Obligations			21
13. Income Taxes			21
14. Equity-Based Compensation			21
15. Stockholders’ Equity			23
16. Earnings (Loss) Per Share			24
17. Business Segment Information			24

18. Commitments and Contingencies			26


Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 3. — Quantitative and Qualitative Disclosures About Market Risk			45
Item 4. — Controls and Procedures			47
PART II — OTHER INFORMATION			48
Item 1. — Legal Proceedings			48
Item 1A. — Risk Factors			48
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds			49


Item 6. — Exhibits			49
SIGNATURES			51

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PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Oasis Petroleum Inc.

Condensed Consolidated Balance Sheets (Unaudited)


	Successor
	June 30, 2021		December 31, 2020

	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	388,915	$	15,856
Restricted cash	—		4,370
Accounts receivable, net	302,506		206,539
Inventory	32,833		33,929
Prepaid expenses	5,186		9,729
Derivative instruments	—		467
Other current assets	2,892		727
Total current assets	732,332		271,617
Property, plant and equipment
Oil and gas properties (successful efforts method)	689,958		810,328
Other property and equipment	946,054		935,950
Less: accumulated depreciation, depletion and amortization	(81,327)		(17,491)
Total property, plant and equipment, net	1,554,685		1,728,787
Restricted cash – non–current	400,000		—
Assets held for sale, net	—		5,500
Derivative instruments	32,860		—
Long-term inventory	8,683		14,522
Operating right-of-use assets	4,951		6,083
Intangible assets	42,305		43,667
Goodwill	70,534		70,534

Other assets	90,366		18,327
Total assets	$	2,936,716	$	2,159,037

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	4,867	$	3,242
Revenues and production taxes payable	189,963		146,497
Accrued liabilities	223,119		126,284
Accrued interest payable	11,082		980
Derivative instruments	256,055		56,944
Advances from joint interest partners	2,334		2,723
Current operating lease liabilities	2,193		2,607
Other current liabilities	1,812		1,954
Total current liabilities	691,425		341,231
Long-term debt	1,044,474		710,000
Deferred income taxes	984		984
Asset retirement obligations	44,993		46,363
Derivative instruments	125,594		37,614

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Operating lease liabilities	1,552		2,362
Other liabilities	5,921		7,744
Total liabilities	1,914,943		1,146,298
Commitments and contingencies (Note 18)
Stockholders’ equity
Common stock, $0.01 par value: 60,000,000 shares authorized; 20,095,116 shares issued and 19,904,333 shares outstanding at June 30, 2021 and 20,093,017 shares issued and 20,093,017 shares outstanding at December 31, 2020	200		200
Treasury stock, at cost: 190,783 shares at June 30, 2021 and no shares at December 31, 2020	(14,560)		—
Additional paid-in capital	870,567		965,654
Accumulated deficit	(20,140)		(49,912)
Oasis share of stockholders’ equity	836,067		915,942
Non-controlling interests	185,706		96,797
Total stockholders’ equity	1,021,773		1,012,739
Total liabilities and stockholders’ equity	$	2,936,716	$	2,159,037

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)

(In thousands, except per share data)


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



Revenues
Oil and gas revenues	$	255,227	$	93,830	$	500,688	$	332,958
Purchased oil and gas sales	81,855		37,352		130,315		123,630
Midstream revenues	55,783		34,774		117,095		91,185
Other services revenues	195		396		421		6,377
Total revenues	393,060		166,352		748,519		554,150
Operating expenses
Lease operating expenses	34,321		29,608		69,581		79,377
Midstream expenses	23,547		8,161		51,445		21,245
Other services expenses	21		729		21		5,660
Gathering, processing and transportation expenses	20,485		23,765		36,196		53,229
Purchased oil and gas expenses	85,455		33,180		133,865		118,383
Production taxes	16,208		6,764		32,488		26,090
Depreciation, depletion and amortization	38,968		33,130		78,958		236,885
Exploration expenses	1,250		1,430		1,673		2,598

Impairment	2		2,319		5		4,825,997
General and administrative expenses	20,210		37,443		40,947		68,617

Total operating expenses	240,467		176,529		445,179		5,438,081
Gain (loss) on sale of properties	222,980		(1,047)		223,068		10,179
Operating income (loss)	375,573		(11,224)		526,408		(4,873,752)
Other income (expense)
Net gain (loss) on derivative instruments	(267,037)		(37,187)		(448,552)		248,135
Interest expense, net of capitalized interest	(22,571)		(44,388)		(31,268)		(140,145)
Gain on extinguishment of debt	—		—		—		83,887

Other income (expense)	(1,002)		837		(544)		900
Total other income (expense), net	(290,610)		(80,738)		(480,364)		192,777
Income (loss) before income taxes	84,963		(91,962)		46,044		(4,680,975)
Income tax benefit (expense)	(3,654)		2,613		—		257,351
Net income (loss) including non-controlling interests	81,309		(89,349)		46,044		(4,423,624)
Less: Net income (loss) attributable to non-controlling interests	7,945		3,594		16,272		(19,820)
Net income (loss) attributable to Oasis	$	73,364	$	(92,943)	$	29,772	$	(4,403,804)
Earnings (loss) attributable to Oasis per share:
Basic (Note 16)	$	3.69	$	(0.29)	$	1.49	$	(13.90)
Diluted (Note 16)	3.52		(0.29)		1.46		(13.90)
Weighted average shares outstanding:
Basic (Note 16)	19,904		317,629		19,952		316,899
Diluted (Note 16)	20,822		317,629		20,419		316,899

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 (Deficit)

(Unaudited)


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

	(In thousands)
Balance as of December 31, 2020 (Successor)	20,093	$	200	—	$	—	$	965,654	$	(49,912)	$	96,797	$	1,012,739
Equity-based compensation	—	—		—	—		1,709		—		489		2,198
Dividends to shareholders ($0.375 per share)	—	—		—	—		(7,535)		—		—		(7,535)
Distributions to non-controlling interest owners	—	—		—	—		—		—		(6,029)		(6,029)
Midstream Simplification (Note 2)	—	—		—	—		2,358		—		(2,358)		—

Common control transaction costs	—	—		—	—		(4,111)		—		—		(4,111)
Warrants exercised	—	—		—	—		6		—		—		6
Net income (loss)	—	—		—	—		—		(43,592)		8,327		(35,265)
Balance as of March 31, 2021 (Successor)	20,093	200		—	—		958,081		(93,504)		97,226		962,003





Equity-based compensation	—	—		—	—		4,688		—		14		4,702
Dividends to shareholders ($0.375 per share)	—	—		—	—		(8,090)		—		—		(8,090)
Special dividend declared ($4.00 per share, Note 15)	—	—		—	—		(82,958)		—		—		(82,958)
Distributions to non-controlling interest owners	—	—		—	—		—		—		(6,136)		(6,136)
Repurchase of common stock	(191)	—		191	(14,560)		—		—		—		(14,560)
Issuance of OMP common units, net of offering costs	—	—		—	—		—		—		86,657		86,657
Warrants exercised	2	—		—	—		167		—		—		167
Common control transaction costs	—	—		—	—		(1,321)		—		—		(1,321)

Net income	—	—		—	—		—		73,364		7,945		81,309
Balance as of June 30, 2021 (Successor)	19,904	$	200	191	$	(14,560)	$	870,567	$	(20,140)	$	185,706	$	1,021,773

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 (Deficit) (Continued)

(Unaudited)


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

	(In thousands)
Balance as of December 31, 2019 (Predecessor)	321,231	$	3,189	2,967	$	(33,881)	$	3,112,384	$	554,446	$	200,943	$	3,837,081
Cumulative-effect adjustment for adoption of ASU 2016-13	—	—		—	—		—		(410)		—		(410)
Equity-based compensation	3,836	32		—	—		7,007		—		66		7,105
Distributions to non-controlling interest owners	—	—		—	—		—		—		(6,028)		(6,028)
Equity component of senior unsecured convertible notes, net	—	—		—	—		(337)		—		—		(337)
Treasury stock - tax withholdings	(942)	—		942	(2,308)		—		—		—		(2,308)

Net loss	—	—		—	—		—		(4,310,861)		(23,414)		(4,334,275)
Balance as of March 31, 2020 (Predecessor)	324,125	3,221		3,909	(36,189)		3,119,054		(3,756,825)		171,567		(499,172)
Equity-based compensation	(2,889)	1,018		—	—		3,858		—		66		4,942
Distributions to non-controlling interest owners	—	—		—	—		—		—		(6,014)		(6,014)
Treasury stock - tax withholdings	(252)	—		252	(318)		—		—		—		(318)

Net income (loss)	—	—		—	—		—		(92,943)		3,594		(89,349)
Balance as of June 30, 2020 (Predecessor)	320,984	$	4,239	4,161	$	(36,507)	$	3,122,912	$	(3,849,768)	$	169,213	$	(589,911)

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)

(In thousands)


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



Cash flows from operating activities:
Net income (loss) including non-controlling interests	$	46,044	$	(4,423,624)
Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	78,958		236,885
Gain on extinguishment of debt	—		(83,887)
Gain on sale of properties	(223,068)		(10,179)
Impairment	5		4,825,997
Deferred income taxes	—		(257,315)
Derivative instruments	448,552		(248,135)
Equity-based compensation expenses	6,900		11,697

Deferred financing costs amortization and other	16,289		16,755
Working capital and other changes:
Change in accounts receivable, net	(96,704)		167,871
Change in inventory	(2,880)		(8,739)
Change in prepaid expenses	3,773		(7,465)
Change in accounts payable, interest payable and accrued liabilities	80,969		(156,668)
Change in other assets and liabilities, net	(8,475)		(3,298)
Net cash provided by operating activities	350,363		59,895
Cash flows from investing activities:
Capital expenditures	(85,217)		(270,283)
Acquisition deposit	(74,500)		—
Proceeds from sale of properties	369,819		13,780
Costs related to sale of properties	(2,358)		—
Derivative settlements	(78,575)		144,069
Derivative modification	(82,419)		—
Net cash provided by (used in) investing activities	46,750		(112,434)
Cash flows from financing activities:
Proceeds from revolving credit facilities	369,500		577,000
Principal payments on revolving credit facilities	(866,500)		(383,000)
Proceeds from issuance of senior unsecured notes	850,000		—
Repurchase of senior unsecured notes	—		(68,040)
Deferred financing costs	(20,332)		(102)
Proceeds from issuance of OMP common units, net of offering costs	86,657		—
Common control transaction costs	(5,432)		—
Purchases of treasury stock	(14,560)		(2,626)
Dividends paid	(15,039)		—
Distributions to non-controlling interests	(12,165)		(12,042)
Payments on finance lease liabilities	(726)		(1,262)
Proceeds from warrants exercised	173		—
Net cash provided by financing activities	371,576		109,928
Increase in cash, cash equivalents and restricted cash	768,689		57,389
Cash, cash equivalents and restricted cash:
Beginning of period	20,226		20,019

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End of period	$	788,915	$	77,408
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	11,515	$	(60,655)
Change in asset retirement obligations	(1,370)		2,039
Note receivable from divestiture	2,900		—
Contingent consideration from Permian Basin Sale	32,860		—
Dividends payable	83,543		—

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 (“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”) conducts the Company’s E&P activities and owns its oil and gas properties located in the North Dakota and Montana regions of the Williston Basin. During the second quarter of 2021, the Company sold its E&P assets in the Texas region of the Permian Basin (see Note 10 — Divestitures). In addition to its E&P segment, the Company operates a midstream business segment through Oasis Midstream Partners LP (“OMP”), a gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets in North America.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited 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, 2020 is derived from audited financial statements. 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 unaudited 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 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, 2020 (“2020 Annual Report”).

Consolidation. The accompanying unaudited condensed consolidated financial statements of the Company include the accounts of Oasis, its wholly-owned subsidiaries and OMP. 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 its general partner, OMP GP LLC (“OMP GP”), OMP is a variable interest entity. Through the Company’s ownership of 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 the primary beneficiary and consolidates OMP. The Company records a non-controlling interest for the ownership interest held by public unitholders in OMP. As of June 30, 2021, Oasis owns approximately 70% of OMP. All intercompany balances and transactions have been eliminated upon consolidation.

Midstream Simplification. On March 30, 2021, the Company completed the transactions contemplated by a contribution and simplification agreement (the “Contribution and Simplification Agreement”), dated as of March 22, 2021.

Pursuant to the Contribution and Simplification Agreement, among other things, (a) the Company contributed to OMP its remaining limited liability company interests in Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”) of 64.7% and 30.0%, respectively, in exchange for total consideration of approximately $512.5 million composed of (x) a cash distribution of $231.5 million and (y) 12,949,644 common units representing limited partner interests in OMP, (b) OMP’s incentive distribution rights were cancelled and converted into 1,850,356 OMP common units (the “IDR Conversion Common Units”), and (c) OMP GP distributed the IDR Conversion Common Units on a pro rata basis to holders of its Class A Units and Class B Units, such that following such distribution, Oasis, through its wholly-owned subsidiary OMS Holdings LLC (“OMS Holdings”), is the sole member of OMP GP (the foregoing clauses (a), (b) and (c), the “Midstream Simplification”). The effective date of the Midstream Simplification was January 1, 2021.

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Fresh start accounting. On November 19, 2020 (the “Emergence Date”), the Company emerged from bankruptcy and adopted fresh start accounting in accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification 852, Reorganizations, which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. As a result of the adoption of fresh start accounting, the condensed consolidated financial statements after the Emergence Date are not comparable to the condensed consolidated financial statements prior to that date. References to “Successor” relate to the reorganized Company’s financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to the Company’s financial position prior to, and results of operations through and including, the Emergence Date.

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 and natural gas liquids (“NGLs”), could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil and natural gas reserves that may be economically produced and the Company’s access to capital.

Cash Equivalents and Restricted Cash

The Company may invest in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents.

As of June 30, 2021, restricted cash consists of funds from the Oasis Senior Notes (defined in Note 11 – Long-Term Debt) held in a standalone account to fund a portion of the Williston Basin Acquisition (defined in Note 9 – Acquisitions). As of December 31, 2020, restricted cash consists of funds that were held in an escrow account for the payment of professional fees associated with the Company’s emergence from bankruptcy.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows:


	Successor
	June 30, 2021		December 31, 2020

	(In thousands)
Cash and cash equivalents	$	388,915	$	15,856
Restricted cash	—		4,370
Restricted cash – non–current	400,000		—
Total cash, cash equivalents and restricted cash	$	788,915	$	20,226

Significant Accounting Policies

There have been no material changes to the Company’s critical accounting policies and estimates from those disclosed in the 2020 Annual Report.

Recent Accounting Pronouncements

Reference rate reform. In March 2020, the FASB issued Accounting Standards Update 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance for a limited time to ease the potential burden in accounting for reference rate reform, including optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. ASU 2020-04 applies only to contracts and hedging relationships that reference the London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued due to reference rate reform. ASU 2020-04 is effective immediately and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The Company is currently evaluating its contracts and the optional expedients provided by ASU 2020-04 and the impact the new standard will have on its financial statements and related disclosures.

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3. Revenue Recognition

Exploration and Production Revenues

E&P revenues from contracts with customers for crude oil, natural gas and NGL sales and other services were as follows for the periods presented (in thousands):


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



Crude oil revenues	$	206,729	$	81,059	$	392,547	$	293,852
Purchased crude oil sales	73,505		23,519		110,222		109,276
Natural gas and NGL revenues	48,498		12,771		108,141		39,106
Purchased natural gas sales	60		4,081		354		4,602
Other services revenues	195		396		421		6,377
Total E&P revenues	$	328,987	$	121,826	$	611,685	$	453,213

Midstream Revenues

Midstream revenues are derived from contracts with customers for midstream services under fee-based arrangements and midstream product sales from purchase arrangements. The Company’s midstream revenues exclude intercompany revenues for goods and services provided by the midstream business segment for the Company’s ownership interests, which are eliminated in consolidation.

Revenues derived from contracts with customers for midstream revenues were as follows for the periods presented (in thousands):


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



Midstream service revenues
Crude oil, natural gas and NGL revenues	$	20,794	$	22,898	$	43,019	$	49,584
Produced and flowback water revenues	7,466		7,247		14,874		18,499
Total midstream service revenues	28,260		30,145		57,893		68,083
Midstream product revenues
Purchased crude oil sales(1)	8,290		9,752		$	19,739	$	9,752
Crude oil, natural gas and NGL revenues	26,782		4,335		57,965		20,608
Freshwater revenues	741		294		1,237		2,494
Total midstream product revenues	35,813		14,381		78,941		32,854
Total midstream revenues	$	64,073	$	44,526	$	136,834	$	100,937

___________________

(1) Reported under purchased oil and gas sales on the Condensed Consolidated Statements of Operations.

Contract Balances

Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract assets relate to revenue recognized for accrued deficiency fees associated with minimum volume commitments where the Company believes it is probable there will be a shortfall payment and that a significant reversal of revenue recognized will not occur once the related performance period is completed and the customer is billed. Contract liabilities relate to 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. Contract balances are classified as current or long-term based on when the Company expects to receive cash for contract assets or recognize revenue for contract liabilities. Contract liabilities are included in other current liabilities and other liabilities on the Company’s Condensed Consolidated Balance Sheets. There were no material contract asset balances at June 30, 2021 or December 31, 2020.

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The following table summarizes the changes in the Company’s contract liabilities for the six months ended June 30, 2021:


	(In thousands)
Balance as of December 31, 2020 (Successor)	$	3,966

Revenues recognized	(164)
Balance as of June 30, 2021 (Successor)	$	3,802

Performance Obligations

The Company records revenue when the performance obligations under the terms of its customer contracts are satisfied. For sales of commodities, the Company records revenue in the month the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 60 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 uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. For midstream services, the Company measures the satisfaction of its performance obligations using the output method based upon the volume of crude oil, natural gas or water that flows through its systems. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. For the three and six months ended June 30, 2021 and 2020, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Remaining Performance Obligations

The following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of June 30, 2021:


	(In thousands)
2021 (excluding the six months ended June 30, 2021)	$	8,376
2022	17,175
2023	10,896
2024	11,089
2025	2,768

Total	$	50,304

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 Accounting Standards Codification 606, Revenue from Contracts with Customers, 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 and (ii) contracts with an original expected duration of one year or less.

4. Inventory

The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s E&P activities and spare parts and equipment for the Company’s midstream assets. Crude oil inventory includes crude oil in tanks and linefill that is expected to be withdrawn within one year. Linefill represents the minimum volume of product in a pipeline system that enables the system to operate and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil and NGL 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.

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 as well as the liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net

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realizable value. No material write-downs of inventory or long-term inventory were recorded during the three or six months ended June 30, 2021.

The Company’s total inventory consists of the following:


	Successor
	June 30, 2021		December 31, 2020

	(In thousands)
Inventory
Equipment and materials	$	21,827	$	25,103
Crude oil inventory	11,006		8,826
Total inventory	32,833		33,929
Long-term inventory
Linefill in third party pipelines	8,683		14,522
Total long-term inventory	8,683		14,522
Total	$	41,516	$	48,451

5. Additional Balance Sheet Information

The following table sets forth certain balance sheet amounts comprised of the following:


	Successor
	June 30, 2021		December 31, 2020

	(In thousands)
Accounts receivable, net
Trade accounts	$	228,518	$	161,519
Joint interest accounts	41,422		31,920

Other accounts	32,953		13,206
Total accounts receivable	302,893		206,645
Less: allowance for credit losses	(387)		(106)
Total accounts receivable, net	$	302,506	$	206,539

Accrued liabilities
Accrued capital costs	$	49,914	$	39,380
Accrued lease operating expenses	18,296		18,635
Accrued oil and gas purchases	33,111		8,967
Accrued general and administrative expenses	12,231		35,249
Accrued dividends payable	83,543		—
Accrued midstream operating expenses	17,338		15,051
Other accrued liabilities	8,686		9,002
Total accrued liabilities	$	223,119	$	126,284

6. 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 properties acquired in a business combination or 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,

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market corroborated or generally unobservable.

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

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

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

Level 3 — Pricing inputs are generally unobservable 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:


	Successor
	Fair value at June 30, 2021
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:


Permian Basin Sale Contingent Consideration	$	—	$	32,860	$	—	$	32,860
Total assets	$	—	$	32,860	$	—	$	32,860
Liabilities:
Commodity derivative instruments	$	—	$	381,649	$	—	$	381,649
Total liabilities	$	—	$	381,649	$	—	$	381,649


	Successor
	Fair value at December 31, 2020
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:

Commodity derivative instruments	$	—	$	467	$	—	$	467
Total assets	$	—	$	467	$	—	$	467
Liabilities:
Commodity derivative instruments	$	—	$	94,558	$	—	$	94,558
Total liabilities	$	—	$	94,558	$	—	$	94,558

Commodity derivative instruments. The fair value of the Company’s commodity derivative instruments is 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 commodity prices, volatility, skew, discount rate and the contract terms of the derivative

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instruments. The Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or the third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in forward commodity 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 market credit spread of the Company or similarly rated public issuers. The Company recorded an adjustment to reduce the fair value of its net derivative liability by $15.7 million and $4.3 million at June 30, 2021 and December 31, 2020, respectively. See Note 7 – Derivative Instruments for more information.

Permian Basin Sale Contingent Consideration. The fair value of the Permian Basin Sale Contingent Consideration (defined in Note 7 – Derivative Instruments) was determined by a third-party valuation specialist as of the close date using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs used are NYMEX West Texas Intermediate crude oil price index (“NYMEX WTI”) forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. See Note 7 – Derivative Instruments and Note 10 – Divestitures for more information.

Non-Financial Assets and Liabilities

The fair value of the Company’s non-financial assets measured at fair value on a non-recurring basis is determined using valuation techniques that include Level 3 inputs.

Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.

7. 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 settle monthly based on the average NYMEX WTI, and its natural gas contracts settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).

The Company primarily utilizes fixed price swaps and collars to reduce the volatility of crude oil and natural gas prices on future expected production. Swaps are designed to establish a fixed price for the volumes under contract, while collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.

All derivative instruments are recorded on the Company’s Condensed Consolidated Balance Sheets as either assets or liabilities measured at their fair value (see Note 6 – 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. Derivative settlements, which are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows, represent net cash payments to or receipts from counterparties upon the maturity or liquidation of a derivative contract.

On March 22, 2021, the Company entered into the Second Amendment to the Oasis Credit Facility (as defined in Note 11 –Long-Term Debt) to, among other things, reduce the rolling hedging requirement and add incremental flexibility to allow for restructuring of existing hedge positions (see Note 11 – Long-Term Debt).

On May 17, 2021, the Company entered into a series of transactions with derivative counterparties to modify the swap price of certain commodity hedge contracts to $50.00 per Bbl based on NYMEX WTI from weighted average prices of $40.72 per Bbl, $43.57 per Bbl and $43.68 per Bbl for 2022, 2023 and 2024, respectively. The commodity contracts modified included total notional volumes of 6,346,000 Bbls, 5,265,000 Bbls and 434,000 Bbls which settle in 2022, 2023 and 2024, respectively. The Company paid $82.4 million for the modification of these commodity derivative contracts, which is reflected as a cash outflow from investing activities in the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2021.

At June 30, 2021 (Successor), the Company had the following outstanding commodity derivative instruments:


Commodity	Settlement Period	Derivative Instrument	Volumes			Weighted Average Prices						Fair Value Assets (Liabilities)
					Fixed Price Swaps			Floor			Ceiling
												(In thousands)
Crude oil	2021	Fixed price swaps	5,307,000	Bbl		$	42.09							$	(154,623)
Crude oil	2021	Two-way collar	1,224,000	Bbl					$	51.25		$	68.24	(6,846)
Crude oil	2022	Fixed price swaps	7,245,000	Bbl		$	49.02							(120,533)
Crude oil	2022	Two-way collar	4,799,000	Bbl					$	49.50		$	66.62	(21,819)
Crude oil	2023	Fixed price swaps	5,265,000	Bbl		$	50.00							(53,619)
Crude oil	2023	Two-way collar	4,380,000	Bbl					$	45.42		$	65.05	(11,769)
Crude oil	2024	Fixed price swaps	434,000	Bbl		$	50.00							(3,434)
Crude oil	2024	Two-way collar	372,000	Bbl					$	45.00		$	64.88	(521)
Natural gas	2021	Fixed price swaps	7,360,000	MMBtu		$	2.84							(5,889)
Natural gas	2022	Fixed price swaps	5,430,000	MMBtu		$	2.82							(2,596)
														$	(381,649)

Permian Basin Sale Contingent Consideration. Pursuant to the Primary Permian Basin Sale PSA (defined in Note 10 – Divestitures), the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”). If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter the buyer’s obligation to make any remaining earn-out payments is terminated. The Company determined that the Permian Basin Sale Contingent Consideration was an embedded derivative in accordance with the FASB Accounting Standards Codification 815, Derivatives and Hedging. The Company bifurcated the Permian Basin Sale Contingent Consideration from the host contract and accounted for it separately at fair value. The fair value of the Permian Basin Sale Contingent Consideration was estimated to be $32.9 million as of the close date on June 29, 2021. The Permian Basin Sale Contingent Consideration is classified as a noncurrent derivative asset on the Condensed Consolidated Balance Sheet, with an offsetting amount recorded to gain on sale of properties on the Condensed Consolidated Statements of Operations. The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recognized as a net gain or loss on derivative instruments in other income (expense) on the Condensed Consolidated Statements of Operations. See Note 6 – Fair Value Measurements and Note 10 – Divestitures for additional information.

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


		Successor		Predecessor		Successor		Predecessor
		Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Derivative Instrument	Statements of Operations Location


Commodity derivative instruments	Net gain (loss) on derivative instruments	$	(267,037)	$	(37,187)	$	(448,552)	$	248,135
Contingent consideration	Gain (loss) on sale of properties	32,860		—		32,860		—

The change in fair value was not material from the close date of the Primary Permian Basin Sale on June 29, 2021 to June 30, 2021.

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

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


		Successor
		June 30, 2021
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount

		(In thousands)
Derivatives assets:


Contingent consideration	Derivative instruments — non-current assets	$	32,860	$	—	$	32,860


Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	260,314	$	(4,259)	$	256,055
Commodity contracts	Derivative instruments — non-current liabilities	149,289		(23,695)		125,594
Total derivatives liabilities		$	409,603	$	(27,954)	$	381,649

		Successor
		December 31, 2020
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount

		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	467	$	—	$	467



Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	59,262	$	(2,318)	$	56,944
Commodity contracts	Derivative instruments — non-current liabilities	38,426		(812)		37,614
Total derivatives liabilities		$	97,688	$	(3,130)	$	94,558

8. Property, Plant and Equipment

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


	Successor
	June 30, 2021		December 31, 2020

	(In thousands)
Proved oil and gas properties	$	661,349	$	770,117
Less: Accumulated depreciation, depletion and amortization	(51,175)		(12,403)
Proved oil and gas properties, net	610,174		757,714
Unproved oil and gas properties	28,609		40,211
Other property and equipment	946,054		935,950
Less: Accumulated depreciation	(30,152)		(5,088)
Other property and equipment, net	915,902		930,862
Total property, plant and equipment, net	$	1,554,685	$	1,728,787

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9. Acquisitions

Williston Basin Acquisition. On May 3, 2021, OPNA entered into a purchase and sale agreement (the “Williston Basin Acquisition PSA”) with QEP Energy Company, a wholly-owned subsidiary of Diamondback Energy, Inc., to acquire approximately 95,000 net acres in the Williston Basin (the “Williston Basin Acquisition”) in a cash transaction for aggregate consideration of $745.0 million, subject to customary purchase price adjustments. Upon execution of the purchase and sale agreement, the Company paid a deposit of $74.5 million, which is included in other assets in the Condensed Consolidated Balance Sheet at June 30, 2021. The Williston Basin Acquisition is expected to close late in the third quarter of 2021 with an effective date of April 1, 2021.

10. Divestitures

Permian Basin Divestiture. On May 20, 2021, Oasis Petroleum Permian LLC (“OPP”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement (the “Primary Permian Basin Sale PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”), effective March 1, 2021. Pursuant to the Primary Permian Basin Sale PSA, OPP agreed to sell to Percussion its remaining upstream assets in the Texas region of the Permian Basin (the “Primary Permian Basin Sale”) for aggregate consideration of up to $450.0 million, consisting of $375.0 million cash and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60.00 per barrel for such year. On June 29, 2021, the Company completed the closing of the Primary Permian Basin Sale and received cash proceeds (after purchase price adjustments) of $347.3 million, subject to subsequent earn-out payments and post-closing adjustments.

In addition to the Primary Permian Basin Sale, the Company divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 and received cash proceeds (after purchase price adjustments) of $19.4 million, subject to post-closing adjustments (the “Additional Permian Basin Sale” and together with the Primary Permian Basin Sale, the “Permian Basin Sale”). The assets divested in the Permian Basin Sale were in the Company’s E&P segment. During the three and six months ended June 30, 2021, the Company recognized a gain from the Permian Basin Sale of $222.5 million, comprised of $208.8 million from the Primary Permian Basin Sale and $13.7 million from the Additional Permian Basin Sale.

The Company accounted for revenues and expenses related to assets divested in the Permian Basin Sale as income from continuing operations in the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2021 because the Permian Basin Sale did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under FASB Accounting Standards Codification 205-20, Presentation of financial statements – Discontinued Operations.

For the three and six months ended June 30, 2021, the Company recorded income before income taxes related to the assets divested in the Permian Basin Sale of $238.9 million and $262.2 million, respectively, which includes the gain on sale of $222.5 million. For the three and six months ended June 30, 2020 (Predecessor), the Company recorded income before income taxes related to the assets divested in the Permian Basin Sale of $2.3 million and loss before income taxes related to the assets divested in the Permian Basin Sale of $895.1 million, respectively.

Other. On March 22, 2021, the Company completed the sale of certain well services equipment and inventory in connection with its 2020 exit from the well services business for total consideration of $5.5 million, comprised of cash proceeds of $2.6 million and a $2.9 million 6.6% promissory note due within one year, which is included in other current assets in the Condensed Consolidated Balance Sheet. The divested well services equipment and inventory were in the Company’s E&P segment.

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11. Long-Term Debt

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


	Successor
	June 30, 2021		December 31, 2020

	(In thousands)
Oasis Credit Facility	$	—	$	260,000
Oasis Senior Notes	400,000		—
Less: unamortized deferred financing costs on Oasis Senior Notes	(8,913)		—
Total Oasis Guarantors	391,087		260,000

OMP Credit Facility	213,000		450,000
OMP Senior Notes	450,000		—
Less: unamortized deferred financing costs on OMP Senior Notes	(9,613)		—
Total unrestricted subsidiaries	653,387		450,000
Total long-term debt, net	$	1,044,474	$	710,000

Oasis Debt

Oasis Credit Facility

The Company has a senior secured revolving credit facility (the “Oasis Credit Facility”) among Oasis Petroleum Inc., as parent, OPNA, as borrower, and Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent and the lenders party thereto, which has a maturity date of May 19, 2024.

On March 22, 2021, the Company entered into the Second Amendment to the Oasis Credit Facility to, among other things, (i) provide for the occurrence of the transactions pursuant to the Midstream Simplification, (ii) decrease the borrowing base from $575.0 million to $500.0 million, (iii) decrease the aggregate lender commitments from $575.0 million to $450.0 million, (iv) provide the ability to initiate certain share-repurchases, (v) reduce the rolling hedging requirement and add incremental flexibility to allow for restructuring of existing hedge positions and (vi) decrease the LIBOR floor from 1.00% to 0.25%.

On May 3, 2021, the Company entered into the Third Amendment to the Oasis Credit Facility to, among other things, (i) provide the ability to incur loans pursuant to a customary bridge loan facility, (ii) add customary terms allowing for the incurrence of second liens, (iii) eliminate restrictions on the ability to make deposits of cash and/or cash equivalents in connection with any letter of intent or purchase agreement for certain acquisitions or investments, (iv) remove limitations on the making of capital expenditures and (v) provide for improvements and conforming changes to terms to facilitate acquisitions and investments.

On May 21, 2021, the Company entered into the Fourth Amendment to the Oasis Credit Facility (the “Fourth Amendment”) to, among other things, (i) provide that no borrowing base reduction shall occur in connection with any issuance of senior notes in an aggregate principal amount not in excess of $550.0 million issued after the effective date of the Fourth Amendment and prior to the effectiveness of the scheduled redetermination to occur on or about October 1, 2021, (ii) reduce the borrowing base by $100.0 million upon consummation of the Primary Permian Basin Sale and (iii) increase the borrowing base by $250.0 million upon consummation of the Williston Basin Acquisition. The Fourth Amendment also amends the exceptions from the restricted payments negative covenant to provide increased restricted payment flexibility, permitting unlimited restricted payments subject to (x) no event of default under the Oasis Credit Facility, (y) at least 25% availability under the Oasis Credit Facility and (z) the pro forma leverage ratio being not more than 1.5 to 1.0; provided that if the conditions described in clauses (x) and (y) are satisfied and the pro forma leverage ratio is less than 2.0 to 1.0, but more than 1.5 to 1.0, restricted payments are permitted in an amount such that all restricted payments made in reliance on such exception since the closing date of the Oasis Credit Facility will not exceed the positive amount of free cash flow.

At June 30, 2021, the borrowing base under the Oasis Credit Facility was $400.0 million and the aggregate amount of elected commitments was $450.0 million. At June 30, 2021, the Company had no borrowings outstanding and $1.3 million of outstanding letters of credit under the Oasis Credit Facility, resulting in an unused borrowing capacity of $398.7 million. For the three and six months ended June 30, 2021, the weighted average interest rate incurred on borrowings under the Oasis Credit Facility was 3.4% and 4.2%, respectively. The fair value of the Oasis Credit Facility approximates its carrying value since borrowings under the Oasis Credit Facility bear interest at variable rates, which are tied to current market rates.

The Oasis Credit Facility contains customary events of default, as well as cross-default provisions with other indebtedness of

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OPNA and the restricted subsidiaries under the Oasis Credit Facility. 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. There are no cross-default provisions between the Oasis Credit Facility and the indebtedness of OMP and its restricted subsidiaries, other than to the extent that any “DevCo” (as defined in the Oasis Credit Facility) then exists that is owned in part by OMP and in part by the Company, in which case the Oasis Credit Facility contains a cross-default in the event that any material debt of such DevCo is accelerated prior to its scheduled maturity. The Company was in compliance with the financial covenants under the Oasis Credit Facility at June 30, 2021.

Oasis Bridge Facility

On May 3, 2021, the Company entered into a commitment letter with J.P. Morgan Chase Bank, N.A., Wells Fargo and Wells Fargo Securities, LLC (the “Arrangers”) pursuant to which the Arrangers committed to provide the Company a $500.0 million senior secured second lien facility (the “Oasis Bridge Facility”) to partially finance the transactions contemplated by the Williston Basin Acquisition. Prior to being drawn, the Oasis Bridge Facility was replaced with the Oasis Senior Notes (defined below), which terminated all obligations under the Oasis Bridge Facility. In connection with the Oasis Bridge Facility, the Company incurred aggregate fees of $7.8 million during the three and six months ended June 30, 2021, which were recorded to interest expense on the Company’s Condensed Consolidated Statements of Operations.

Oasis Senior Notes

On June 9, 2021, the Company issued in a private placement $400.0 million of 6.375% senior unsecured notes due June 1, 2026 (the “Oasis Senior Notes”). The Oasis Senior Notes were issued at par and resulted in net proceeds of $393.0 million, after deducting the underwriters’ discounts and commissions. The Company intends to use the net proceeds to fund a portion of the Williston Basin Acquisition. Pursuant to the indenture governing the Oasis Senior Notes, the proceeds from the Oasis Senior Notes are being held in a standalone account until the completion of the Williston Basin Acquisition (see Note 2 – Summary of Significant Accounting Policies – Cash Equivalents and Restricted Cash). In addition, the indenture governing the Oasis Senior Notes includes certain redemption provisions, including a special mandatory redemption that would require the Company to redeem the Oasis Senior Notes at a price equal to 100% of the issue price plus accrued and unpaid interest in the event either: (a) the Company does not complete the Williston Basin Acquisition on or prior to September 27, 2021 (or such later date that is the “Outside Date” as defined in the Williston Basin Acquisition PSA) or (b) the Williston Basin Acquisition is terminated prior to September 27, 2021 (or such later date that is the “Outside Date” as defined in the Williston Basin Acquisition PSA). The Company expects to complete the Williston Basin Acquisition late in the third quarter of 2021.

In connection with the issuance of the Oasis Senior Notes, the Company recorded deferred financing costs of $9.0 million, which are being amortized over the term of the notes. The fair value of the Oasis Senior Notes, which are publicly traded among qualified institutional investors and represent a Level 1 fair value measurement, was $417.1 million at June 30, 2021.

Interest on the Oasis Senior Notes is payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2021. The Oasis Senior Notes are guaranteed on a senior unsecured basis by the Company, along with its wholly-owned subsidiaries (the “Oasis Guarantors”). These guarantees are full and unconditional and joint and several among the Oasis Guarantors, subject to certain customary release provisions. The indentures governing the Oasis Senior Notes contain customary events of default. In addition, the indenture governing the Oasis Senior Notes contains cross-default provisions with other indebtedness of Oasis and its restricted subsidiaries; however, there are no cross-default provisions with the indebtedness of OMP and its restricted subsidiaries.

The indentures governing the Oasis Senior Notes restrict the Company’s ability and the ability of certain of its subsidiaries to, among other things: (i) make investments; (ii) incur additional indebtedness or issue preferred stock; (iii) create liens; (iv) sell assets; (v) enter into agreements that restrict dividends or other payments by restricted subsidiaries; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets with another company; (vii) enter into transactions with affiliates; (viii) pay dividends or make other distributions on capital stock or prepay subordinated indebtedness; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Oasis Senior Notes are rated investment grade by two out of the three rating agencies and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with the terms of the indentures for the Oasis Senior Notes as of June 30, 2021.

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OMP Debt

OMP Credit Facility

OMP has a senior secured revolving credit facility (the “OMP Credit Facility”) among OMP, as parent, OMP Operating LLC, as borrower, Wells Fargo, as administrative agent and the lenders party thereto. On March 22, 2021, OMP entered into the Fourth Amendment to the OMP Credit Facility (the “OMP Credit Facility Fourth Amendment”) to, among other things, (i) provide for the occurrence of the transactions pursuant to the Midstream Simplification, (ii) amend the consolidated total leverage ratio financial covenant to no greater than 5.00 to 1.00, (iii) amend the consolidated senior secured leverage ratio to no greater than 3.00 to 1.00, (iv) amend the consolidated interest coverage ratio to no less than 2.50 to 1.00, (v) provide for the issuance of the OMP Senior Notes (defined below), (vi) decrease the aggregate lender commitments from $575.0 million to $450.0 million, (vii) increase pricing for credit under the OMP Credit Facility and (viii) extend the maturity date from September 25, 2022 until at least September 30, 2024.

Following the OMP Credit Facility Fourth Amendment, the applicable margin for borrowings under the OMP Credit Facility varies from (a) in the case of LIBOR loans (defined in the OMP Credit Facility as Eurodollar Loans), 2.25% to 3.25%, and (b) in the case of domestic bank prime rate interest loans (defined in the OMP Credit Facility as ABR Loans) or swingline loans, 1.25% to 2.25%. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%.

At June 30, 2021, the aggregate amount of elected commitments under the OMP Credit Facility was $450.0 million, and there were $213.0 million of borrowings outstanding and $5.5 million of outstanding letters of credit, resulting in an unused borrowing capacity of $231.5 million. For the three and six months ended June 30, 2021, the weighted average interest rate incurred on borrowings under the OMP Credit Facility was 2.6% and 2.3%, respectively. The fair value of the OMP Credit Facility approximates its carrying value since borrowings under the OMP Credit Facility bear interest at variable rates, which are tied to current market rates.

The OMP Credit Facility contains customary events of default, as well as cross-default provisions with other indebtedness of OMP and the restricted subsidiaries under the OMP Credit Facility. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the OMP Credit Facility to be immediately due and payable. There are no cross-default provisions between the OMP Credit Facility and the indebtedness of Oasis and its restricted subsidiaries. OMP was in compliance with the financial covenants under the OMP Credit Facility at June 30, 2021.

OMP Senior Notes

On March 30, 2021, OMP and OMP Finance Corp. (“OMP Finance” and together with OMP, the “OMP Issuers”) issued in a private placement $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”). The OMP Senior Notes were issued at par and resulted in net proceeds, after deducting the underwriters’ gross spread, of $442.1 million. OMP used the net proceeds from the OMP Senior Notes to: (i) make a distribution to OMS Holdings of $231.5 million in connection with the Midstream Simplification, (ii) repay $204.0 million of outstanding principal borrowings and $0.5 million of accrued interest under the OMP Credit Facility and (iii) pay approximately $6.1 million in fees and other expenses. In connection with the issuance of the OMP Senior Notes, OMP recorded deferred financing costs of $9.9 million, which are being amortized over the term of the notes. The fair value of the OMP Senior Notes, which are publicly traded among qualified institutional investors and represent a Level 1 fair value measurement, was $478.4 million at June 30, 2021.

Interest on the OMP Senior Notes is payable semi-annually on April 1 and October 1 of each year, commencing on October 1, 2021. The OMP Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the OMP Issuers, along with OMP’s wholly-owned subsidiaries (the “OMP Guarantors”). The OMP Senior Notes guarantees are joint and several obligations of the OMP Guarantors. The OMP Issuers and the OMP Guarantors do not have any significant restrictions on the ability to obtain funds from its subsidiaries by dividend or loan. In addition, there are no restrictions on the subsidiaries to transfer funds, and as such, there are no restricted net assets to disclose.

The indenture governing the OMP Senior Notes contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit OMP’s ability and the ability of its restricted subsidiaries to, among other things: (i) incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, (ii) make certain investments, (iii) declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, (iv) transfer or sell assets including equity of restricted subsidiaries, (v) agree to payment restrictions affecting OMP’s restricted subsidiaries, (vi) consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, (vii) enter into transactions with affiliates, (viii) incur liens and (ix) designate certain of OMP’s subsidiaries as unrestricted subsidiaries. The indenture governing the OMP Senior Notes contains cross-default provisions with other indebtedness of OMP and its restricted subsidiaries; however, there are no cross-default provisions with the indebtedness of Oasis and its restricted subsidiaries.

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12. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2021:


	(In thousands)
Balance at December 31, 2020 (Successor)	$	48,594
Liabilities incurred during period	401
Liabilities settled during period	(322)
Accretion expense during period	2,043
Revisions to estimates	193
Liabilities settled through divestitures	(4,845)

Balance at June 30, 2021 (Successor)	$	46,064

Accretion expense is included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations. At June 30, 2021 (Successor) and December 31, 2020 (Successor), the current portion of the total ARO balance was $1.1 million and $2.2 million, respectively, and is included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheets.

13. Income Taxes

The Company’s effective tax rates for the three and six months ended June 30, 2021 (Successor) were 4.3% and (0.2)%, respectively, as compared to the effective tax rates for the three and six months ended June 30, 2020 (Predecessor) of 2.7% and 5.5%, respectively.

The effective tax rates for the three and six months ended June 30, 2021 and 2020 were lower than the statutory federal rate of 21% primarily as a result of the Company’s valuation allowance, which was initially recorded against substantially all of the Company’s net deferred tax assets as of March 31, 2020 and was maintained as of June 30, 2021.

The Company’s estimated valuation allowance as of June 30, 2021 was $559.5 million, which decreased $5.9 million from $565.4 million as of December 31, 2020. The Company concluded it is more likely than not that some or all of the benefits from its deferred tax assets will not be realized, and as such, recorded a valuation allowance on these assets. Management assesses the available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. If the Company concludes it is more likely than not that a portion, or all, of its deferred tax assets will not be realized, the deferred tax asset is reduced by a valuation allowance. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years, excluding the impact of the voluntary restructuring under Chapter 11 of the Bankruptcy Code in 2020. Such objective negative evidence limits the ability to consider other subjective positive evidence. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income change or if objective negative evidence, in the form of cumulative losses, is no longer present and additional weight is given to subjective evidence such as future growth. The Company evaluates the appropriateness of its valuation allowance on a quarterly basis.

Upon emergence from bankruptcy, the Company experienced an “ownership change” as defined by Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). Under Section 382 of the Code, the Company’s net operating loss carryforwards (“NOLs”) and other tax attributes (collectively, the “Tax Benefits”) are potentially subject to various limitations going forward. The Company previously had not determined whether it would be eligible for, and would utilize the exception under Section 382(l)(5) of the Code, which allows for no limitations going forward; accordingly, the limitation was previously determined under Section 382(l)(6) of the Code. After additional consideration and review, the Company believes it qualifies for treatment under Section 382(l)(5) of the Code and intends to utilize this exception with the filing of its 2020 tax return. As a result, the Company expects to pay no cash taxes for the 2021 tax year. Prior to determining it could utilize the exception under Section 382(l)(5) of the Code, the Company made an estimated income tax payment of $20.0 million during the second quarter of 2021, which the Company expects to be refunded in the first quarter of 2022. This amount is recorded under accounts receivable, net on the Condensed Consolidated Balance Sheet at June 30, 2021.

14. Equity-Based Compensation

Successor equity-based compensation

The Compensation Committee has approved the grant of certain awards under the Company’s 2020 Long Term Incentive Plan (“2020 LTIP”), which consists of restricted stock units (“RSUs”), performance share units (“PSUs”) and leveraged stock units (“LSUs”). The Company accounts for RSUs, PSUs and LSUs as equity classified awards in accordance with the FASB’s authoritative guidance for share-based payments.

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Restricted stock units. RSUs are contingent shares that are scheduled to vest 25% each year over a four-year period to promote retention of key employees. The fair value is based on the closing price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period. During the six months ended June 30, 2021, the Company granted 443,836 RSUs with a weighted average grant date per share value of $51.64. During the three and six months ended June 30, 2021, the Company recorded equity-based compensation expense related to RSUs of $1.4 million and $2.0 million, respectively, in general and administrative expenses on its Condensed Consolidated Statements of Operations.

Performance share units. PSUs are contingent shares that may be earned over three-year and four-year performance periods. 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 applicable performance periods, with 50% of the PSU awards eligible to be earned based on performance relative to a certain group of the Company’s oil and gas peers and 50% of the PSU awards eligible to be earned based on performance relative to the broad-based Russell 2000 index. Depending on the Company’s TSR performance relative to the defined peer group, award recipients may earn between 0% and 150% of target.

During the six months ended June 30, 2021, the Company granted 183,915 PSUs with a weighted average grant date per share value of $63.95. During the three and six months ended June 30, 2021, the Company recorded equity-based compensation expense related to PSUs of $1.0 million and $1.3 million, respectively, in general and administrative expenses on its Condensed Consolidated Statements of Operations.

Leveraged stock units. LSUs are contingent shares that may be earned over a three-year or four-year performance period. The number of LSUs to be earned is subject to a market condition, which is based on the TSR performance of the Company’s common stock measured against specific premium return objectives. Depending on the Company’s TSR performance, award recipients may earn between 0% and 300% of target; however, the number of shares delivered in respect to these awards during the grant cycle may not exceed ten times the fair value of the award on the grant date.

During the six months ended June 30, 2021, the Company granted 262,406 LSUs with a weighted average grant date per share value of $78.79. During the three and six months ended June 30, 2021, the Company recorded equity-based compensation expense related to LSUs of $2.0 million and $2.5 million, respectively, in general and administrative expenses on its Condensed Consolidated Statements of Operations.

Fair value assumptions. The aggregate grant date fair value of PSUs and LSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) implied equity volatility, (iv) stock price on the date of grant and, for PSUs, (v) correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data.

The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date:


Grant date	January 18, 2021	February 11, 2021	April 13, 2021
Forecast period (years)	3 - 4	3 - 4	3 - 4
Risk-free interest rates	0.2% - 0.3%	0.2% - 0.3%	0.3% - 0.6%
Implied equity volatility	55% - 60%	55% - 60%	45% - 50%

Stock price on date of grant	$44.41	$49.66	$68.07

Restricted stock awards. The Company has granted restricted stock awards to its directors under the 2020 LTIP, which vest one-third annually over a three-year period subject to a service condition. The fair value of restricted stock awards is based on the closing price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period. During the three and six months ended June 30, 2021, the Company recorded equity-based compensation expense for restricted stock awards of $0.3 million and $0.6 million, respectively, in general and administrative expenses on its Condensed Consolidated Statements of Operations.

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Class B Units in OMP GP

OMP GP previously granted restricted Class B Units to certain employees, including OMP’s named executive officers, as consideration for services to the Company. On March 30, 2021, in connection with the Midstream Simplification, certain Class B Units representing membership interests in OMP GP that were previously issued to certain of OMP’s named executive officers were converted into and exchanged for the right to receive restricted common units in OMP, subject to the following vesting schedule: (i) 34% vested on March 30, 2021, (ii) 33% will vest on March 30, 2022 and (iii) 33% will vest on March 30, 2023. As of June 30, 2021, the unamortized grant date fair value related to the unvested OMP restricted common units was $0.5 million and will be recognized over a remaining life of approximately two years.

Predecessor equity-based compensation

The Predecessor previously granted equity-classified restricted stock awards and PSUs under its Amended and Restated 2010 Long Term Incentive Plan (the “Predecessor 2010 LTIP”). For the three and six months ended June 30, 2020, the Predecessor recorded equity-based compensation expense of $3.0 million and $7.4 million, respectively, related to restricted stock awards and $1.9 million and $4.1 million, respectively, related to PSUs in general and administrative expenses on its Condensed Consolidated Statements of Operations. On the Emergence Date and pursuant to the Company’s restructuring plan, all outstanding unvested restricted stock awards and PSUs granted under the Predecessor 2010 LTIP vested, and there were no outstanding Predecessor restricted stock awards and PSUs at June 30, 2021 or December 31, 2020.

2020 Incentive Compensation Program. In the second quarter of 2020, the board of directors of the Predecessor implemented a revised 2020 incentive compensation program pursuant to which all 2020 equity-based awards previously granted were forfeited and concurrently replaced with cash retention incentives. In connection with the 2020 cash incentive compensation program, the Predecessor recorded $6.5 million in general and administrative expenses on its Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2020.

15. Stockholders’ Equity

Dividends. On February 24, 2021, the Company declared a dividend of $0.375 per share of common stock. The dividend of $7.5 million was paid on March 22, 2021 to shareholders of record as of March 8, 2021.

On May 3, 2021, the Company declared a dividend of $0.375 per share of common stock. The dividend of $7.5 million was paid on May 31, 2021 to shareholders of record as of May 17, 2021.

On June 29, 2021, the Company declared a special dividend of $4.00 per share of common stock (the “Special Dividend”). The Special Dividend was paid on July 21, 2021 to shareholders of record as of July 9, 2021. As of June 30, 2021, the Company recorded a dividend payable of $83.0 million in accrued liabilities on its Condensed Consolidated Balance Sheet.

On August 3, 2021, the Company declared a dividend of $0.375 per share of common stock payable on August 27, 2021 to shareholders of record as of August 16, 2021.

Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share repurchase program. In March 2021, the Board of Directors authorized a share-repurchase program covering up to $100.0 million of the Company’s common stock which expires on December 31, 2022. During the three and six months ended June 30, 2021, the Company repurchased an aggregate amount of 190,783 shares of common stock at a weighted average price of $76.30 per common share for a total cost of $14.6 million.

Warrants. As of June 30, 2021, there were 1,618,346 warrants outstanding. During the three and six months ended June 30, 2021, there were 3,192 and 3,259 warrants exercised, respectively. The warrants, which are classified as equity, are exercisable to purchase one share of common stock per warrant at an initial exercise price of $94.57 per warrant. In connection with the Special Dividend, the exercise price decreased from $94.57 per warrant to $90.57 per warrant on July 12, 2021.

The warrants are exercisable from the date of issuance until November 19, 2024, at which time all unexercised warrants will expire and the rights of the holders of such warrants to purchase common stock will terminate. The number of shares of common stock for which a warrant is exercisable, and the exercise price, are subject to adjustment from time to time upon the occurrence of certain events, including: (1) stock splits, reverse stock splits or stock dividends to holders of common stock or (2) a reclassification in respect of common stock.

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OMP Equity Offering. On June 29, 2021, OMP completed an underwritten public offering of 3,623,188 common units representing limited partnership interests at a price to the public of $24.00 per common unit (the “OMP Equity Offering”) and received net proceeds of $86.7 million, after deducting underwriting discounts, commissions and offering expenses. OMP used the proceeds from the OMP Equity Offering to redeem 3,623,188 common units held by Oasis for $87.0 million (the “OMP Unit Redemption”). Following the OMP Unit Redemption, the Company owns approximately 70% of OMP’s outstanding common units. There was no consolidated reporting impact from the OMP Unit Redemption.

Tax Benefits Preservation Plan. Subsequent to June 30, 2021, the Board of Directors adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s Tax Benefits, which may be utilized in certain circumstances to reduce the Company’s future income tax obligations.

In adopting the Tax Plan, the Board of Directors declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of the Company’s common stock. The Rights will trade with the Company’s common stock and will expire at the close of business on the earlier of August 3, 2024 (three years from adoption) and the date upon which the Board of Directors determines that no Tax Benefits remain available or earlier, as described in more detail in the Tax Plan. The Rights will be exercisable if, among other things, a person or group of persons acquires 4.95% or more of the Company’s outstanding common stock.

16. 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 effect of potentially dilutive shares outstanding for the period using the treasury stock method, unless its effect is anti-dilutive. For the Successor period, potentially dilutive shares outstanding include unvested restricted stock awards, warrants and contingently issuable shares related to RSUs, PSUs and LSUs. For the Predecessor period, potentially dilutive shares outstanding included Predecessor unvested restricted stock awards, Predecessor contingently issuable shares related to PSUs and Predecessor senior convertible notes. There were no adjustments made to the income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share during either the Successor period or Predecessor period.

The following table summarizes the basic and diluted weighted average common shares outstanding and the weighted average common shares excluded from the calculation of diluted weighted average common shares outstanding due to the anti-dilutive effect for the periods presented (in thousands):


	Successor	Predecessor	Successor	Predecessor
	Three Months Ended June 30, 2021	Three Months Ended June 30, 2020	Six Months Ended June 30, 2021	Six Months Ended June 30, 2020



Weighted average common shares outstanding:
Basic	19,904	317,629	19,952	316,899
Dilutive effect of equity-classified awards	918	—	467	—
Diluted	20,822	317,629	20,419	316,899

Anti-dilutive weighted average common shares:
Potential common shares	2,168	8,676	2,309	9,152

For the three and six months ended June 30, 2021 (Successor), the diluted earnings per share calculation excludes the impact of unvested share based awards and outstanding warrants that were anti-dilutive under the treasury stock method. In addition, for the three and six months ended June 30, 2020 (Predecessor), the Company incurred a net loss, and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of all potentially dilutive shares.

For the Predecessor period, the conversion value of the Predecessor senior convertible notes did not exceed the principal amount; accordingly, there was no impact to diluted earnings per share.

17. Business Segment Information

The Company has two reportable segments: E&P and midstream. The Company’s E&P business segment is engaged in the acquisition and development of oil and gas properties. Revenues for the E&P business segment are primarily derived from the sale of crude oil and natural gas production.

The Company’s midstream business segment performs midstream services including: (i) natural gas gathering, compression, processing, gas lift supply; (ii) crude oil gathering, terminaling and transportation; (iii) produced and flowback water gathering and disposal; and (iv) freshwater supply and distribution. Revenues for the midstream segment are derived from performing

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these services for the Company’s E&P segment, as well as third-party producers. The revenues and expenses related to services provided by the midstream segment for the Company’s ownership interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated interest owners and third-party customers are included in the Company’s Condensed Consolidated Statements of Operations.

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 (loss), which is defined as segment operating revenues less operating expenses, including depreciation, depletion and amortization.

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


	E&P		Midstream		Eliminations		Consolidated


	(In thousands)
Successor
Three months ended June 30, 2021:
Revenues from non-affiliates	$	328,987	$	64,073	$	—	$	393,060
Inter-segment revenues	—		42,090		(42,090)		—
Total revenues	328,987		106,163		(42,090)		393,060
Operating income (loss)	337,188		39,990		(1,605)		375,573
Total other income (expense), net	(279,602)		(11,008)		—		(290,610)
Income (loss) before income taxes including non-controlling interests	$	57,586	$	28,982	$	(1,605)	$	84,963
Lease operating expenses	$	50,436	$	—	$	(16,115)	$	34,321
Gathering, processing and transportation expenses	32,787		—		(12,302)		20,485
General and administrative expenses(1)	15,707		8,175		(3,672)		20,210
Equity-based compensation expenses	4,686		16		—		4,702

Predecessor
Three months ended June 30, 2020:
Revenues from non-affiliates	$	121,826	$	44,526	$	—	$	166,352
Inter-segment revenues	—		37,195		(37,195)		—
Total revenues	121,826		81,721		(37,195)		166,352
Operating income (loss)	(40,901)		30,620		(943)		(11,224)
Total other income (expense), net	(75,465)		(5,273)		—		(80,738)
Income (loss) before income taxes including non-controlling interests	$	(116,366)	$	25,347	$	(943)	$	(91,962)
Lease operating expenses	$	37,864	$	—	$	(8,256)	$	29,608
Gathering, processing and transportation expenses	31,180		—		(7,415)		23,765
General and administrative expenses(1)	32,290		9,304		(4,151)		37,443
Equity-based compensation expenses	4,811		203		(124)		4,890

Successor
Six months ended June 30, 2021:
Revenues from non-affiliates	$	611,685	$	136,834	$	—	$	748,519
Inter-segment revenues	—		83,446		(83,446)		—
Total revenues	611,685		220,280		(83,446)		748,519
Operating income (loss)	440,368		88,657		(2,617)		526,408
Total other income (expense), net	(465,498)		(14,866)		—		(480,364)
Income (loss) before income taxes including non-controlling interests	$	(25,130)	$	73,791	$	(2,617)	$	46,044
Lease operating expenses	$	101,500	$	—	$	(31,919)	$	69,581
Gathering, processing and transportation expenses	60,892		—		(24,696)		36,196
General and administrative expenses(1)	31,382		16,735		(7,170)		40,947
Equity-based compensation expenses	6,374		526		—		6,900

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Predecessor
Six months ended June 30, 2020:
Revenues from non-affiliates	$	453,213	$	100,937	$	—	$	554,150
Inter-segment revenues	—		105,739		(105,739)		—
Total revenues	453,213		206,676		(105,739)		554,150
Operating loss	(4,858,156)		(11,606)		(3,990)		(4,873,752)
Total other income (expense), net	228,533		(35,756)		—		192,777
Loss before income taxes including non-controlling interests	$	(4,629,623)	$	(47,362)	$	(3,990)	$	(4,680,975)
Lease operating expenses	$	103,677	$	—	$	(24,300)	$	79,377
Gathering, processing and transportation expenses	73,894		—		(20,665)		53,229
General and administrative expenses(1)	58,963		17,906		(8,252)		68,617
Equity-based compensation expenses	11,407		631		(341)		11,697

Successor
At June 30, 2021:
Property, plant and equipment, net	$	670,699	$	886,116	$	(2,130)	$	1,554,685
Total assets	1,894,614		1,044,232		(2,130)		2,936,716
At December 31, 2020:
Property, plant and equipment, net	$	837,020	$	892,043	$	(276)	$	1,728,787
Total assets	1,093,253		1,066,060		(276)		2,159,037

___________________

(1)Includes equity-based compensation expenses.

18. Commitments and Contingencies

As of June 30, 2021, the Company’s material off-balance sheet arrangements and transactions include $6.8 million in outstanding letters of credit under the revolving credit facilities and $7.5 million in net surety bond exposure issued as financial assurance on certain agreements.

As of June 30, 2021, there have been no material changes to the Company’s commitments and contingencies disclosed in Note 24 — Commitments and Contingencies in the Company’s 2020 Annual Report other than the items discussed below.

Volume commitment agreements. There were $32.6 million of estimable future commitments under volume commitment agreements included in the Company’s 2020 Annual Report that related to the properties divested in the Permian Basin Sale. Such volume commitment agreements were assigned to Percussion at closing, and the Company no longer has any remaining volume commitments associated with these agreements. In addition, the Company previously disclosed in its 2020 Annual Report potential future obligations associated with a continuous development agreement (the “CDA”) concerning certain drilling and development obligations in the Permian Basin. The CDA was assigned to Percussion at closing, and the Company does not have any future obligations associated with this agreement.

During the three and six months ended June 30, 2021, the Company recorded a deficiency fee of $2.4 million under gathering, processing and transportation expenses in the Condensed Consolidated Statements of Operations in connection with a volume shortfall payment the Company expects to make pursuant to certain volume commitment agreements. The expected shortfall payment of $2.4 million was recorded under accrued liabilities in the Condensed Consolidated Balance Sheet at June 30, 2021.

Subsequent to June 30, 2021, certain escalations to transport a minimum quantity of crude oil volumes became effective. The estimable future commitment pursuant to such escalation was $149.6 million and has a remaining term of approximately 7 years.

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

Mirada litigation. As previously disclosed in the Company’s 2020 Annual Report, the Company entered into a Settlement and Mutual Release Agreement (the “Mirada Settlement Agreement”) with Mirada Energy, LLC and certain related parties

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(“Mirada”) on September 28, 2020. The Mirada Settlement Agreement provides for, among other things, payment by OPNA to Mirada of $42.8 million. The Company paid Mirada $20.0 million on the Emergence Date and $22.8 million in May 2021. These amounts were previously accrued for in the Company’s condensed consolidated financial statements, and there are no remaining settlement payments outstanding as of June 30, 2021.

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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, 2020 (“2020 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 (the “Securities Act”), 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. Our forward-looking statements address the various risks and uncertainties associated with the extraordinary market environment and impacts resulting from the novel coronavirus 2019 (“COVID-19”) pandemic and the related impacts to energy demand, our businesses, operations, earnings and results. In particular, the factors discussed below and detailed under Part II, Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q 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:

•crude oil, natural gas and natural gas liquids (“NGL”) realized prices;

•developments in the global economy as well as the public health crisis related to the COVID-19 pandemic and resulting demand and supply for crude oil and natural gas;

•uncertainty regarding the worldwide response to COVID-19, including the impact of new virus strains and the risk of renewed restrictions on various commercial and economic activities; such restrictions are designed to protect public health but also have the effect of significantly reducing demand for crude oil and natural gas;

•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil and natural gas;

•uncertainty regarding the timing, pace and extent of an economic recovery in the U.S. and elsewhere, which in turn will likely affect demand for crude oil and natural gas;

•the effect of a surplus of crude oil and natural gas inventory stored in the U.S. and elsewhere, and the impact that such inventory surplus ultimately has on the timing of a return to market conditions that support increased drilling and production activities in the U.S.;

•general economic conditions;

•our business strategy;

•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;

•infrastructure for produced and flowback water gathering and disposal;

•gathering, transportation and marketing of crude oil and natural gas in the Williston Basin and other regions in the U.S.;

•property acquisitions and divestitures;

•completion of the Williston Basin Acquisition (defined below) late in the third quarter of 2021;

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

•cash flows and liquidity;

•our ability to return capital to shareholders;

•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;

•our ability to comply with the covenants under our credit agreements and other indebtedness;

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

•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;

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

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

•execution of our environmental, social and governance (“ESG”) initiatives;

•effectiveness of risk management activities;

•competition in the oil and gas industry;

•counterparty credit risk;

•environmental liabilities;

•governmental regulation and the taxation of the oil and 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;

•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;

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

•certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2020 Annual Report and in our other SEC filings.

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, the ability to realize the anticipated benefits from the Williston Basin Acquisition and the Permian Basin Sale (each as defined herein), 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.

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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”) conducts our E&P activities and owns our oil and gas properties located in the North Dakota and Montana regions of the Williston Basin. During the second quarter of 2021, we sold our E&P assets in the Texas region of the Permian Basin. In addition to our E&P segment, we operate a midstream business through Oasis Midstream Partners LP (“OMP”), a leading gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets in North America. We own OMP’s general partner and approximately 70% of OMP. We derive significant cash flows from the midstream segment through distributions from our ownership of OMP limited partner units.

Recent Developments

Williston Basin Acquisition

On May 3, 2021, we entered into a purchase and sale agreement with QEP Energy Company, a wholly-owned subsidiary of Diamondback Energy, Inc. (“Diamondback”), to acquire approximately 95,000 net acres in the Williston Basin (the “Williston Basin Acquisition”) in a cash transaction for aggregate consideration of $745.0 million, subject to customary purchase price adjustments. Upon execution of the purchase and sale agreement, we paid a deposit of $74.5 million to Diamondback. The Williston Basin Acquisition is expected to close late in the third quarter of 2021 with an effective date of April 1, 2021. We expect to fund the Williston Basin Acquisition with cash on hand, which includes proceeds from the Permian Basin Sale (defined below) and proceeds from our issuance of $400.0 million in aggregate principal amount of 6.375% senior unsecured notes due 2026 (the “Oasis Senior Notes”).

Permian Basin Sale

On May 20, 2021, we entered into a purchase and sale agreement with Percussion Petroleum Operating II, LLC (“Percussion”), pursuant to which we agreed to sell to Percussion our remaining upstream assets in the Texas region of the Permian Basin (the “Primary Permian Basin Sale”) for aggregate consideration of up to $450.0 million, consisting of $375.0 million cash at closing, as adjusted pursuant to the terms of the purchase and sale agreement and inclusive of a $31.9 million deposit made by Percussion at signing, and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX West Texas Intermediate (“NYMEX WTI”) crude oil exceeds $60 per barrel for such year. On June 29, 2021, we closed on the Primary Permian Basin Sale and received cash proceeds (after purchase price adjustments) of $347.3 million, which remains subject to potential earn-out payments and post-closing adjustments.

In addition to the Primary Permian Basin Sale, we also divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 (the “Additional Permian Basin Sale” and together with the Primary Permian Basin Sale, the “Permian Basin Sale”). We received cash proceeds from the Additional Permian Basin Sale of $19.4 million at closing, and we expect to receive total aggregate cash proceeds of $32.4 million after post-closing adjustments.

Change in Chief Executive Officer

On April 13, 2021, Daniel E. Brown was appointed Chief Executive Officer of the Company. At the same time, Mr. Brown was also appointed to the Company’s Board of Directors. Mr. Brown replaces Douglas E. Brooks, who was previously appointed to serve as Chief Executive Officer on an interim basis. Mr. Brooks will continue to serve in his role as Board Chair.

Dakota Access Pipeline

The U.S. Army Corps of Engineers (the “Corps”) is currently conducting a court-ordered environmental review to determine whether the Dakota Access Pipeline (“DAPL”) poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. Once this review is finished, which completion is estimated by the Corps to occur by no later than March 2022, the Corps will determine whether DAPL is safe to operate or must be permanently shut down. On April 9, 2021, the Biden Administration announced that the Corps will not take immediate action to shut down DAPL while it conducts the environmental review, and on May 3, 2021, the Corps filed a Status Report with the federal district court, confirming that it currently is not seeking a shutdown of DAPL while the agency conducts the environmental review. In a related legal proceeding involving the Standing Rock Sioux Tribe’s request for an injunction to shut down DAPL while the environmental review is being conducted, U.S. District Judge James Boasberg ruled on May 21, 2021 that DAPL will not be forced to shut down while the Corps conducts the environmental review, indicating that the tribe had failed to make a successful showing of irreparable harm based on the threat of an oil spill. The pipeline currently remains in operation while the Corps conducts its review.

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Midstream Simplification

On March 30, 2021, we closed on the transactions contemplated by a contribution and simplification agreement pursuant to which we contributed our remaining 64.7% interest in Bobcat DevCo LLC (“Bobcat DevCo”) and remaining 30.0% interest in Beartooth DevCo LLC (“Beartooth DevCo”) to OMP as well as eliminated OMP’s incentive distribution rights for total consideration of approximately $512.5 million, including cash consideration of $231.5 million and 14.8 million OMP common units (the “Midstream Simplification”). The effective date for the Midstream Simplification was January 1, 2021. See “Item 1. — Financial Statements (Unaudited)—Note 2—Summary of Significant Accounting Policies—Basis of Presentation” for more information.

OMP Unit Redemption

On June 29, 2021, OMP completed an underwritten public offering of 3,623,188 common units representing limited partnership interests at a price to the public of $24.00 per common unit (the “OMP Equity Offering”) and received net proceeds of $86.7 million, after deducting underwriting discounts, commissions and offering expenses. OMP used the proceeds from the OMP Equity Offering to redeem an equal number of common units held by Oasis (the “OMP Unit Redemption”) for $87.0 million. Following the OMP Unit Redemption, we own approximately 70% of OMP’s outstanding common units.

Market Conditions and COVID-19

Market conditions have improved but remain uncertain as the worldwide response to COVID-19 continues to evolve. Federal, state and local public health and governmental authorities have commenced programs to administer vaccines, and certain regions across the United States have lifted restrictions that were imposed to contain the spread of COVID-19, resulting in improved global economic activity levels and higher energy demand. Despite improvements in market conditions, uncertainties related to COVID-19 remain, including the impact of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. In response to the impacts of COVID-19 and economic environment, we reduced our workforce during the first quarter of 2021 to adjust our business to expected lower levels of activity and operate in a sustainable and cost-efficient manner.

In response to the outbreak of the COVID-19 pandemic in 2020, we adopted a work-from-home system for all office-based employees and deployed additional safety protocols at our operating sites in order to keep the field-based employees and contractors supporting our operations safe while continuing operations running without material disruption. Our Crisis Management Team continues to monitor public health data and guidance, engages with peer companies, and participates with industry associations to ensure alignment with guidance for employee health and safety. In 2021, we completed a phased return-to-office program while continuing to follow enhanced safety standards, including enhanced daily cleaning in common spaces of office locations, restricting use of conference rooms and group gatherings, adherence to social distancing requirements and establishing training requirements and procedures.

Our revenue, profitability and ability to return cash to shareholders 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, natural gas and NGLs can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for crude oil, natural gas and NGLs, as well as market uncertainty, economic conditions and a variety of additional factors. Commodity prices have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future. Commodity prices have increased in recent months due to improving economic activity and increased energy demand. Following historic production cuts in 2020 to balance oil markets, OPEC and other non-OPEC oil-producing countries, including Russia have announced plans to increase production in response to improved economic activity and reductions in the surplus of inventory. Despite commodity price increases in recent months, uncertainties related to COVID-19 and the balance between the supply of and demand for crude oil and natural gas remain.

In an effort to improve price realizations from the sale of our crude oil, natural gas and NGLs, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, natural gas and NGLs to a broader array of potential purchasers. We enter into crude oil, natural gas and NGL 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. During the second quarter of 2021, our crude oil price differentials averaged $0.61 per barrel discount to NYMEX WTI. 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. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of June 30, 2021, 92% of our gross operated crude oil production and substantially all of our gross operated natural gas production were connected to gathering systems.

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Recent Highlights:

•Declared a special dividend of $4.00 per share that was paid on July 21, 2021.

•Declared a dividend for second quarter of 2021 of $0.375 per share of common stock. The dividend will be payable on August 27, 2021 to shareholders of record as of August 16, 2021.

•Repurchased $14.6 million of common stock in the second quarter of 2021.

•Production volumes averaged 54,271 barrels of oil equivalent per day (“Boepd”) (64% oil) in the second quarter of 2021.

•E&P capital expenditures were $52.4 million in the second quarter of 2021.

•E&P lease operating expense (“LOE”) was $10.21 per barrel of oil equivalent (“Boe”) in the second quarter of 2021.

•Crude oil differentials averaged $0.61 to NYMEX WTI in the second quarter of 2021.

•Net cash provided by operating activities was $160.0 million for the three months ended June 30, 2021. Adjusted EBITDA attributable to Oasis, a non-GAAP financial measure, was $107.0 million for the three months ended June 30, 2021. See “Non-GAAP Financial Measures” below.

Results of Operations

Comparability

Upon our emergence from bankruptcy on November 19, 2020 (the “Emergence Date”), we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the condensed consolidated financial statements on or after the Emergence Date are not comparable to the condensed consolidated financial statements prior to the Emergence Date. References to “Successor” relate to our financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to our financial position prior to, and our results of operations through and including, the Emergence Date. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their estimated fair values as of the Emergence Date. As a result, the impact to the comparability of the Predecessor and Successor results is generally limited to those areas associated with the basis in and accounting for our oil and gas and other properties.

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 oil and gas sales are primarily derived from the sale of crude oil and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending at our crude oil terminal or to cover production shortfalls. 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, compression, processing and gas lift supply, sales of residue gas and NGLs related to third-party natural gas purchase arrangements, produced and flowback water gathering and disposal, crude oil gathering, terminaling and transportation and fresh water distribution. Our other services revenues are derived from equipment rentals, and also include revenues from well completion services prior to our exit from the well services business in the first quarter of 2020 (the “Well Services Exit”). A significant portion of our midstream revenues and all of our other services revenues are from services performed for our operated wells. Intercompany revenues for work performed for our ownership interests are eliminated in consolidation, and only the revenues related to non-affiliated interest owners and other third-party customers are included in midstream and other services revenues.

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


	Successor						Predecessor
	Three Months Ended June 30, 2021		Three Months Ended March 31, 2021		Six Months Ended June 30, 2021			Six Months Ended June 30, 2020

Revenues (in thousands)
Crude oil revenues	$	206,729	$	185,818	$	392,547		$	293,852
Natural gas revenues	48,498		59,643		108,141			39,106
Purchased oil and gas sales	81,855		48,460		130,315			123,630
Midstream revenues	55,783		61,312		117,095			91,185
Other services revenues	195		226		421			6,377
Total revenues	$	393,060	$	355,459	$	748,519		$	554,150
Production data
Williston Basin
Crude oil (MBbls)	2,648		2,787		5,435			6,913
Natural gas (MMcf)	9,946		10,291		20,237			21,920
Oil equivalents (MBoe)	4,306		4,502		8,808			10,567
Average daily production (Boepd)	47,316		50,019		48,660			58,059
Permian Basin
Crude oil (MBbls)	507		526		1,033			1,325
Natural gas (MMcf)	757		724		1,481			1,911
Oil equivalents (MBoe)	633		647		1,280			1,643
Average daily production (Boepd)	6,955		7,186		7,070			9,029
Total average daily production (Boepd)	54,271		57,205		55,730			67,088
Average sales prices
Crude oil (per Bbl)
Average sales price	$	65.52	$	56.09	$	60.69		$	35.67
Effect of derivative settlements(1)	(17.75)		(6.98)		(12.23)			14.42
Average realized price after the effect of derivative settlements(1)	$	47.77	$	49.11	$	48.46		$	50.09
Natural gas (per Mcf)(2)
Average sales price	$	4.53	$	5.41	$	4.98		$	1.64
Effect of derivative settlements(1)	—		0.05		0.03			—
Average realized price after the effect of derivative settlements(1)	$	4.53	$	5.46	$	5.01		$	1.64

____________________

(1)The effect of derivative settlements includes the cash received or paid for the gains or losses on commodity derivatives settled in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

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

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Three months ended June 30, 2021 as compared to three months ended March 31, 2021

Crude oil and natural gas revenues. Our crude oil and natural gas revenues increased $9.8 million to $255.2 million during the three months ended June 30, 2021. This increase was primarily driven by a $31.2 million increase due to higher crude oil sales prices, offset by a $11.7 million decrease driven by lower crude oil and natural gas production amounts sold quarter over quarter and a $9.7 million decrease due to lower natural gas sales prices. Average crude oil sales prices, without derivative settlements, increased by $9.43 per barrel quarter over quarter to an average of $65.52 per barrel for the three months ended June 30, 2021. Average natural gas sales prices, which include the value for residue gas and NGLs and do not include derivative settlements, decreased by $0.88 per Mcf quarter over quarter to an average of $4.53 per Mcf for the three months ended June 30, 2021. Average daily production sold decreased by 2,934 Boepd to 54,271 Boepd quarter over quarter primarily driven by a decrease in crude oil production as a result of the natural decline in production from wells that were producing as of March 31, 2021.

Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize transportation costs, for blending at our crude oil terminal or to cover production shortfalls, increased $33.4 million to $81.9 million for the three months ended June 30, 2021. This increase was primarily due to an increase in crude oil volumes purchased and then subsequently sold in the Williston Basin, coupled with higher crude oil sales prices quarter over quarter.

Midstream revenues. Midstream revenues decreased $5.5 million to $55.8 million during the three months ended June 30, 2021. This decrease was primarily driven by a $4.4 million decrease related to lower natural gas revenues from third party producers, coupled with a $1.2 million decrease related to lower natural gas revenues from our operated wells.

Six months ended June 30, 2021 as compared to six months ended June 30, 2020

Crude oil and natural gas revenues. Our crude oil and natural gas revenues increased $167.7 million to $500.7 million during the six months ended June 30, 2021. This increase was primarily driven by a $285.7 million increase due to higher crude oil and natural gas sales prices, offset by a $117.9 million decrease due to the lower crude oil and natural gas production amounts sold period over period. Average crude oil sales prices, without derivative settlements, increased by $25.02 per barrel to an average of $60.69 per barrel, and average natural gas sales prices, which include the value for residue gas and NGLs and do not include derivative settlements, increased by $3.34 per Mcf to an average of $4.98 per Mcf for the six months ended June 30, 2021. Average daily production sold decreased by 11,358 Boepd to 55,730 Boepd period over period. The decrease in average daily production sold period over period was driven by a reduction in new wells coming online due to a decrease in well completion activity.

Purchased oil and gas sales. Purchased oil and gas sales increased $6.7 million to $130.3 million for the six months ended June 30, 2021. This increase was primarily due to higher crude oil sales prices period over period, partially offset by lower crude oil volumes purchased and then subsequently sold in the Williston Basin and Permian Basin.

Midstream revenues. Midstream revenues were $117.1 million for the six months ended June 30, 2021, which was a $25.9 million increase period over period. This increase was driven by a $37.5 million increase related to higher natural gas revenues from third party producers, offset by a $6.1 million decrease related to lower natural gas revenues from our operated wells, a $3.6 million decrease in produced water revenues and a $1.3 million decrease in freshwater revenues.

Other services revenues. Other services revenues decreased by $6.0 million to $0.4 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020, primarily driven by a decrease in well completion revenues due to the Well Services Exit.

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Expenses and other income (expenses)

The following table summarizes our operating expenses and other income (expenses) for the periods presented (in thousands, except per Boe of production):


	Successor						Predecessor
	Three Months Ended June 30, 2021		Three Months Ended March 31, 2021		Six Months Ended June 30, 2021			Six Months Ended June 30, 2020



Operating expenses
Lease operating expenses	$	34,321	$	35,260	$	69,581		$	79,377
Midstream expenses	23,547		27,898		51,445			21,245
Other services expenses	21		—		21			5,660
Gathering, processing and transportation expenses	20,485		15,711		36,196			53,229
Purchased oil and gas expenses	85,455		48,410		133,865			118,383
Production taxes	16,208		16,280		32,488			26,090
Depreciation, depletion and amortization	38,968		39,990		78,958			236,885
Exploration expenses	1,250		423		1,673			2,598

Impairment	2		3		5			4,825,997
General and administrative expenses	20,210		20,737		40,947			68,617

Total operating expenses	240,467		204,712		445,179			5,438,081
Gain on sale of properties	222,980		88		223,068			10,179
Operating income (loss)	375,573		150,835		526,408			(4,873,752)
Other income (expense)
Net gain (loss) on derivative instruments	(267,037)		(181,515)		(448,552)			248,135
Interest expense, net of capitalized interest	(22,571)		(8,697)		(31,268)			(140,145)
Gain on extinguishment of debt	—		—		—			83,887

Other income (expense)	(1,002)		458		(544)			900
Total other income (expense), net	(290,610)		(189,754)		(480,364)			192,777
Income (loss) before income taxes	84,963		(38,919)		46,044			(4,680,975)
Income tax benefit (expense)	(3,654)		3,654		—			257,351
Net income (loss) including non-controlling interests	81,309		(35,265)		46,044			(4,423,624)
Less: Net income (loss) attributable to non-controlling interests	7,945		8,327		16,272			(19,820)
Net income (loss) attributable to Oasis	$	73,364	$	(43,592)	$	29,772		$	(4,403,804)
Costs and expenses (per Boe of production)
Lease operating expenses	$	6.95	$	6.85	$	6.90		$	6.50
Gathering, processing and transportation expenses	4.15		3.05		3.59			4.36
Production taxes	3.28		3.16		3.22			2.14

Three months ended June 30, 2021 as compared to three months ended March 31, 2021

Lease operating expenses. LOE decreased $0.9 million to $34.3 million for the three months ended June 30, 2021. This decrease was primarily due to lower costs related to a decrease in produced and flowback water disposal volumes transported and injected quarter over quarter, coupled with lower workover costs. LOE per Boe increased slightly quarter over quarter from $6.85 per Boe to $6.95 per Boe primarily due to lower production volumes. E&P LOE, which excludes impacts from our midstream segment, increased $0.29 to $10.21 per BOE for the second quarter of 2021.

Midstream expenses. Midstream expenses represent operating expenses related to midstream services provided to third parties as well as non-affiliated interest owners’ share of operating expenses incurred by our midstream business segment. Midstream expenses decreased $4.4 million during the three months ended June 30, 2021, primarily due to a $3.6 million decrease in natural gas purchases from third party producers, coupled with a $0.7 million decrease in natural gas gathering, compression and processing expenses.

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Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $4.8 million during the three months ended June 30, 2021, primarily attributable to $2.4 million in minimum volume commitment deficiency fees incurred during the three months ended June 30, 2021, coupled with a $2.6 million increase in pipeline imbalances. GPT per Boe increased $1.10 to $4.15 for the three months ended June 30, 2021 due to the higher aforementioned costs, coupled with lower production volumes. E&P GPT per Boe, which excludes certain impacts from our midstream segment, increased to $4.36 for the three months ended June 30, 2021. Cash GPT per Boe, which excludes non-cash valuation adjustments, increased to $4.00 for the three months ended June 30, 2021. E&P GPT and Cash GPT are non-GAAP financial measures. See “Non-GAAP Financial Measures” below.

Purchased oil and gas expenses. Purchased oil and gas expenses, which represent crude oil purchased to optimize transportation costs, for blending at our crude oil terminal or to cover production shortfalls, increased $37.0 million to $85.5 million for the three months ended June 30, 2021. This increase was primarily due to an increase in crude oil volumes purchased and then subsequently sold in the Williston Basin, coupled with higher crude oil prices quarter over quarter.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expenses decreased $1.0 million to $39.0 million for the three months ended June 30, 2021 due to a decrease in DD&A expenses related to our Permian E&P assets, which were classified as held for sale during the second quarter of 2021.

Exploration expenses. Exploration expenses increased $0.8 million to $1.3 million for the three months ended June 30, 2021, as compared to the three months ended March 31, 2021, primarily due to cost write-offs related to exploratory well locations that are no longer in our current development plan.

Gain on sale of properties. For the three months ended June 30, 2021, we recognized a $223.0 million net gain from sale of properties primarily related to the Permian Basin Sale (see Item 1. “Financial Statements (Unaudited) — Note 10 — Divestitures”). For the three months ended March 31, 2021, we recognized a $0.1 million net gain from the sale of certain non-operated oil and gas properties and well services equipment and inventory.

Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip commodity price changes, we recorded a $267.0 million net loss on derivative instruments, which included a realized loss of $56.0 million from net cash settlement payments, for the three months ended June 30, 2021, and a $181.5 million net loss on derivative instruments, including net cash settlement payments of $22.6 million, for the three months ended March 31, 2021.

Interest expense, net of capitalized interest. Interest expense increased $13.9 million to $22.6 million for the three months ended June 30, 2021 primarily due to a $8.9 million increase in interest expense related to the OMP Senior Notes, coupled with fees related to the Oasis Bridge Facility of $7.8 million and $1.6 million in interest expense related to the Oasis Senior Notes. These increases were partially offset by a $3.0 million decrease in interest expense related to the Oasis Credit Facility and OMP Credit Facility (both as defined below under “Liquidity and Capital Resources”) due to fewer outstanding borrowings during the period.

Income tax benefit (expense). Our income tax expense was recorded at 4.3% of pre-tax income for the three months ended June 30, 2021. Our income tax benefit for the three months ended March 31, 2021 was recorded at 9.4% of pre-tax loss. Our effective tax rate for the three months ended June 30, 2021 was lower than the effective tax rate for the three months ended March 31, 2021, primarily due to the impact of the change in the valuation allowance, offset by the impact of non-controlling interests.

Six months ended June 30, 2021 as compared to six months ended June 30, 2020

Lease operating expenses. LOE decreased $9.8 million to $69.6 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. This decrease was primarily due to lower fixed costs, coupled with lower costs related to a reduction in produced and flowback water volumes transported and injected period over period. These decreases were offset by higher workover costs period over period. LOE per Boe increased $0.40 per Boe to $6.90 per Boe for the six months ended June 30, 2021 primarily due to lower production volumes. E&P LOE, which excludes impacts from our midstream segment, increased $2.88 to $10.06 per Boe for the six months ended June 30, 2021.

Midstream expenses. The $30.2 million increase in midstream expenses for the six months ended June 30, 2021 compared to the six months ended June 30, 2020 was primarily related to a $32.6 million increase in natural gas purchases from third party producers, driven by higher NGL and residue gas prices, offset by a $1.8 million decrease in water operating expenses as a result of lower activity.

Other services expenses. Other services expenses represent third party working interest owners’ share of expenses incurred related to equipment rental services provided to our operated wells, and prior to the Well Services Exit, also included the non-affiliated share of well completion service costs and costs of goods sold. The $5.6 million decrease for the six months ended June 30, 2021 was primarily attributable to a decrease in well completion expenses due to the Well Services Exit.

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Gathering, processing and transportation expenses. GPT expenses decreased $17.0 million period over period, which was primarily attributable to a $10.5 million decrease in crude oil gathering and transportation expenses, a $6.3 million decrease in natural gas gathering and transportation expenses due to a decrease in production volumes, and a $2.5 million decrease in pipeline imbalances. These decreases were offset by $2.4 million in minimum volume commitment deficiency fees incurred during the six months ended June 30, 2021. GPT per Boe decreased $0.77 to $3.59 for the six months ended June 30, 2021 due to the lower aforementioned expenses, offset by lower production volumes. E&P GPT per Boe was $4.06 for the six months ended June 30, 2021 as compared to $4.55 for the six months ended June 30, 2020. Cash GPT per Boe decreased to $3.70 for the six months ended June 30, 2021 as compared to $4.24 for the six months ended June 30, 2020. E&P GPT and Cash GPT are non-GAAP financial measures. See “Non-GAAP Financial Measures” below.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $15.5 million to $133.9 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020 primarily due to higher crude oil prices period over period, coupled with higher transportation expenses. These increases were partially offset by lower crude oil volumes purchased in the Williston Basin and Permian Basin.

Production taxes. Our production taxes as a percentage of crude oil and natural gas sales were 6.5% and 7.8% for the six months ended June 30, 2021 and 2020, respectively. Production taxes as a percentage of crude oil and natural gas sales decreased period over period primarily due to a lower crude oil production mix in the Williston Basin.

Depreciation, depletion and amortization. DD&A expenses decreased $157.9 million to $79.0 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. This decrease was a result of a decrease in the DD&A rate to $7.83 per Boe for the six months ended June 30, 2021 as compared to $19.40 per Boe for the six months ended June 30, 2020, coupled with decreased production during the six months ended June 30, 2021. The decrease in the DD&A rate was primarily due to a lower basis in our proved oil and gas properties as a result of write-downs during 2020.

Exploration expenses. Exploration expenses decreased $0.9 million to $1.7 million for the six months ended June 30, 2021 as compared to $2.6 million for the six months ended June 30, 2020, primarily due to lower cost write-offs related to exploratory well locations.

Impairment. Impairment expense decreased $4.8 billion for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. There were no material asset impairment charges taken during the six months ended June 30, 2021. Impairment expense of $4.8 billion for the six months ended June 30, 2020 was primarily due to the following:

•Proved oil and gas properties. We recorded an impairment charge of $4.4 billion on our proved oil and gas properties, including $3.8 billion in the Williston Basin and $637.3 million in the Permian Basin, for the six months ended June 30, 2020 primarily due to a significant decline in commodity prices.

•Unproved oil and gas properties. We recorded impairment losses on our unproved oil and gas properties of $292.1 million as a result of leases expiring or expected to expire as well as drilling plan uncertainty on certain acreage of unproved properties.

•Other property and equipment. We recorded impairment charges of $108.3 million to reduce the carrying values of our midstream assets to their estimated fair values as a result of lower forecasted throughput volumes.

•Assets held for sale. We recorded an impairment loss of $14.5 million to write-off the net book value of certain well services equipment held for sale as of December 31, 2019 for which a sale was no longer probable to be completed within one year. In addition, we recorded an impairment loss of $1.4 million to adjust the carrying value of the remaining equipment held for sale related to the Well Services Exit to its estimated fair value less costs to sell.

•Inventory. We recorded impairment losses of $7.2 million, $1.3 million and $1.0 million to adjust the carrying values of our crude oil inventory, long-term linefill inventory and equipment and materials inventory, respectively, to their net realizable values.

General and administrative (“G&A”) expenses. G&A expenses decreased $27.7 million to $40.9 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020 primarily due to lower employee compensation expenses due to a 23% decrease in employee headcount period over period, coupled with restructuring related expenses which were incurred during the six months ended June 30, 2020.

Gain on sale of properties. For the six months ended June 30, 2021, we recognized a $223.1 million net gain primarily related to the Permian Basin Sale (see Item 1. “Financial Statements (Unaudited) — Note 10 — Divestitures”). For the six months ended June 30, 2020, we recognized a $10.2 million net gain primarily related to the sale of certain 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 commodity price changes, we recorded a $448.6 million net loss on derivative instruments, including net cash settlement payments of $78.6 million, for the six months ended June 30, 2021, and a $248.1 million net gain on derivative instruments, including net cash settlement receipts of $144.1 million, for the six months ended June 30, 2020.

Interest expense, net of capitalized interest. Interest expense decreased $108.9 million to $31.3 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. During the six months ended June 30, 2020, we recorded specified default interest charges of $30.3 million and $28.0 million related to the Predecessor Credit Facility and OMP Credit Facility, respectively. These specified default interest charges were subsequently waived upon our emergence from bankruptcy in November 2020. In addition, interest expense decreased $56.3 million period over period as a result of the cancellation of the Predecessor senior unsecured notes upon emergence from bankruptcy in 2020. These decreases were offset by a $9.1 million increase in interest expense related to the OMP Senior Notes. For the six months ended June 30, 2021, the weighted average debts outstanding under the Oasis Credit Facility and the OMP Credit Facility were $132.2 million and $331.5 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings were 4.2% and 2.3%, respectively. For the six months ended June 30, 2020, the weighted average debts outstanding under the Predecessor Credit Facility and the OMP Credit Facility were $457.6 million and $480.3 million, respectively, and the weighted average interest rates incurred on the outstanding borrowings, excluding additional interest charges, were 3.3% and 2.9%, respectively. Interest capitalized during the six months ended June 30, 2021 and 2020 was $1.0 million and $4.1 million, respectively.

Gain on extinguishment of debt. There was no extinguishment of debt during the six months ended June 30, 2021. During the six months ended June 30, 2020, we repurchased an aggregate principal amount of $156.8 million of Predecessor senior unsecured notes for an aggregate cost of $68.0 million and recognized a pre-tax gain of $83.9 million, which included the write-off of unamortized debt discount, unamortized deferred financing costs and the equity component of the Predecessor senior unsecured convertible notes.

Income tax benefit. Our income tax benefit was recorded at (0.2)% of pre-tax income and 5.5% of pre-tax loss for the six months ended June 30, 2021 and 2020, respectively. Our effective tax rate for the six months ended June 30, 2021 was lower than the effective tax rate for the six months ended June 30, 2020 primarily due to the impacts of the change in the valuation allowance, which was initially recorded in the first quarter of 2020 and the impacts of non-controlling interests.

Liquidity and Capital Resources

Our primary sources of liquidity during the period covered by this report have been from cash flows from operations, proceeds from the Permian Basin Sale, the issuance of the Oasis Senior Notes and OMP Senior Notes and proceeds from the OMP Equity Offering. Our primary uses of cash have been for net principal payments under our revolving credit facilities, derivative settlements and modifications, the acquisition and development of oil and gas properties and midstream infrastructure, deferred financing costs, interest payments on our long-term debt, dividends paid to our shareholders, share repurchases and distributions to non-controlling interests.

We are committed to a disciplined capital strategy of investing within our cash flows from operations and cash settlements of derivative contracts. Our capital allocation committee provides for a rigorous, systematic framework for evaluating and approving capital projects, and we believe our asset base and strong balance sheet will allow us to generate significant free cash flow and corporate-level returns.

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and obligations associated with our operating and finance leases. In addition, we have contracts which include provisions for the delivery, transport, or purchase of a minimum volume of crude oil, natural gas, NGLs and water within specified time frames, all of which are ten years or less, except for one agreement with a remaining term of approximately 24 years. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. However, we believe that our production and reserves are sufficient to fulfill the volume commitments, and therefore, we expect to avoid any material deficiency payments under these contracts. In connection with the Permian Basin Sale, certain of our agreements that contained volume commitments were assigned to Percussion. See “Item 1. — Financial Statements (Unaudited)—Note 18—Commitments and Contingencies” for more information.

As of June 30, 2021, we had $1,419.1 million of liquidity available, including $388.9 million in cash and cash equivalents and $630.2 million of aggregate unused borrowing capacity available under the Oasis Credit Facility and the OMP Credit Facility. We have $400.0 million of restricted cash at June 30, 2021 that is held in a standalone account to fund a portion of the Williston Basin Acquisition upon closing.

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Oasis Credit Facility. We have a reserves-based credit agreement (the “Oasis Credit Facility”), which has an overall senior secured line of credit of $1,500.0 million, an aggregate amount of elected commitments of $450.0 million and a borrowing base of $400.0 million at June 30, 2021. Pursuant to the Fourth Amendment to the Oasis Credit Facility, upon closing of the Williston Basin Acquisition, the borrowing base will increase by $250.0 million to $650.0 million. The Oasis Credit Facility has a maturity date of May 19, 2024. See “Item 1. — Financial Statements (Unaudited)—Note 11—Long-Term Debt” for more information.

As of June 30, 2021, we had no borrowings outstanding and $1.3 million of outstanding letters of credit under the Oasis Credit Facility, resulting in an unused borrowing capacity of $398.7 million. For the three and six months ended June 30, 2021, the weighted average interest rate incurred on borrowings under the Oasis Credit Facility was 3.4% and 4.2%, respectively. The Company was in compliance with the financial covenants of the Oasis Credit Facility at June 30, 2021.

Oasis Senior Notes. On June 9, 2021, we issued in a private placement $400.0 million of 6.375% senior unsecured notes due June 1, 2026. The Oasis Senior Notes were issued at par and resulted in net proceeds of $393.0 million. We intend to use the proceeds from the Oasis Senior Notes offering to fund a portion of the Williston Basin Acquisition. Interest on the Oasis Senior Notes is payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2021. See “Item 1. — Financial Statements (Unaudited)—Note 11—Long-Term Debt” for more information.

OMP Credit Facility. We consolidate OMP and include OMP’s revolving credit facility (the “OMP Credit Facility”) in our condensed consolidated financial statements. OMP uses this credit facility to fund working capital and to finance acquisitions and other capital expenditures. The OMP Credit Facility does not mature until at least September 30, 2024. On March 22, 2021, OMP entered into the Fourth Amendment to the OMP Credit Facility. See “Item 1. — Financial Statements (Unaudited)—Note 11—Long-Term Debt” for more information.

As of June 30, 2021, the OMP Credit Facility had an aggregate amount of commitments of $450.0 million with $213.0 million of outstanding borrowings and $5.5 million of outstanding letters of credit, resulting in an unused borrowing capacity of $231.5 million. For the three and six months ended June 30, 2021, the weighted average interest rate incurred on borrowings under the OMP Credit Facility was 2.6% and 2.3%, respectively. OMP was in compliance with the financial covenants of the OMP Credit Facility at June 30, 2021.

OMP Senior Notes. On March 30, 2021, OMP issued in a private placement $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”). The OMP Senior Notes were issued at par and resulted in net proceeds of $442.1 million, which OMP used to (i) make a distribution of $231.5 million to Oasis in connection with the Midstream Simplification, (ii) repay approximately $204.0 million of outstanding principal borrowings under the OMP Credit Facility and $0.5 million of accrued interest under the OMP Credit Facility and (iii) pay approximately $6.1 million in fees and other expenses. Interest on the OMP Senior Notes is payable semi-annually on April 1 and October 1 of each year, commencing on October 1, 2021. See “Item 1. — Financial Statements (Unaudited)—Note 11—Long-Term Debt” for more information.

OMP Equity Offering. On June 29, 2021, OMP completed an underwritten public offering of 3,623,188 common units representing limited partnership interests at a price to the public of $24.00 per common unit and received net proceeds of $86.7 million, after deducting underwriting discounts and commissions. OMP used the proceeds from the OMP Equity Offering to redeem 3,623,188 common units held by Oasis for $87.0 million. Following the OMP Unit Redemption, the Company owns approximately 70% of OMP’s outstanding common units.

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Cash flows

Our cash flows for the six months ended June 30, 2021 and 2020 are presented below (in thousands):


	Successor		Predecessor
	Six months ended June 30, 2021		Six Months Ended June 30, 2020



Net cash provided by operating activities	$	350,363	$	59,895
Net cash provided by (used in) investing activities	46,750		(112,434)
Net cash provided by financing activities	371,576		109,928
Increase in cash, cash equivalents and restricted cash	$	768,689	$	57,389

Cash flows provided by operating activities

Net cash provided by operating activities was $350.4 million for the six months ended June 30, 2021. The increase in net cash provided by operating activities from the six months ended June 30, 2020 was due primarily to higher crude oil and natural gas revenues, coupled with lower interest expense related to the cancellation of the Predecessor senior unsecured notes. In addition, G&A, GPT and LOE expenses decreased period over period. Refer to “Results of Operations” above for more information on the impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods.

Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes, capital spending to fund development of our oil and gas properties and the impact of our outstanding derivative instruments. We had a working capital surplus of $40.9 million and a working capital deficit of $69.6 million at June 30, 2021 and December 31, 2020, respectively. We believe we have adequate liquidity to meet our working capital requirements. Our working capital increased due to higher cash and cash equivalents and accounts receivable, partially offset by increases in the net liability related to our short-term derivative instruments, accrued liabilities and revenues and production taxes payable.

Cash flows provided by (used in) investing activities

Net cash provided by investing activities increased from the six months ended June 30, 2020 due to proceeds from the Permian Basin Sale, coupled with a decrease in cash capital expenditures primarily for drilling and development costs. These increases in net cash provided by investing activities were partially offset by increases in derivative settlement payments as a result of higher commodity prices, derivative modification payments and the Williston Basin Acquisition deposit.

Cash flows provided by financing activities

Net cash provided by financing activities was $371.6 million for the six months ended June 30, 2021, which increased from net cash provided by financing activities for the six months ended June 30, 2020 due to the issuance of $450.0 million in aggregate principal amount of OMP Senior Notes, coupled with the issuance of $400.0 million in aggregate principal amount of Oasis Senior Notes, partially offset by the net principal repayments of outstanding borrowings under the Oasis Credit Facility and OMP Credit Facility.

Capital expenditures

Our capital expenditures are summarized in the following table:



	Three Months Ended				Six Months Ended
	March 31, 2021		June 30, 2021		June 30, 2021

	(In thousands)
Capital expenditures:
E&P	$	28,595	$	52,355	$	80,950

Other capital expenditures(1)	414		660		1,074
Total E&P and other capital expenditures	29,009		53,015		82,024
Midstream(2)	259		13,392		13,651


Total capital expenditures(3)	$	29,268	$	66,407	$	95,675

___________________

(1)Other capital expenditures include such items as administrative capital and capitalized interest. Capitalized interest totaled $0.5 million and $1.0 million for the three and six months ended June 30, 2021.

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(2)Midstream capital expenditures attributable to OMP were $0.2 million and $13.2 million for the three months ended March 31, 2021 and June 30, 2021, respectively.

(3)Total capital expenditures 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.

Dividends

On March 22, 2021, we paid a dividend of $0.375 per share of common stock, or $7.5 million, to shareholders of record as of March 8, 2021.

On May 31, 2021, we paid a dividend of $0.375 per share of common stock, or $7.5 million, to shareholders of record as of May 17, 2021.

On June 29, 2021, we declared a special dividend of $4.00 per share of common stock payable on July 21, 2021 to shareholders of record as of July 9, 2021. We recorded a dividend payable of $83.0 million in accrued liabilities on our Condensed Consolidated Balance Sheet at June 30, 2021.

On August 3, 2021, we declared a dividend of $0.375 per share of common stock payable on August 27, 2021 to shareholders of record as of August 16, 2021.

Share Repurchase Program

In March 2021, the Board of Directors authorized a share-repurchase program covering up to $100.0 million of the Company's common stock which expires on December 31, 2022. As of June 30, 2021, the Company repurchased an aggregate amount of 190,783 shares of common stock at a weighted average price of $76.30 per common share for a total cost of $14.6 million.

Tax Benefits Preservation Plan

The Company has determined that it qualifies for an exception to the limitation on its net operating loss carryforwards (“NOLs”) and other tax attributes (collectively, the “Tax Benefits”) under Section 382(l)(5) of the Internal Revenue Code (the “Code”), as of its emergence from Chapter 11 restructuring. This qualification results in reducing cash taxes to zero in the second quarter of 2021 and for the fiscal year ending December 31, 2021. As of December 31, 2021, the Company estimates its federal NOL will be between $400 million and $500 million, subject to the closing of the Williston Basin Acquisition, fluctuations in commodity prices and other revisions.

Under Section 382(l)(5) of the Code, if the Company were to experience an “ownership change” as defined by Section 382 of the Code within the two-year period immediately following its date of emergence, the Company would be precluded from utilizing the Tax Benefits following such ownership change. If Oasis is unable to use its Tax Benefits in years in which the Company has taxable income, the Company will pay significantly more in cash tax than if it were able to utilize the Tax Benefits, and those tax costs would negatively impact the Company’s financial position, results of operations and cash flows. As a result, the Board of Directors has adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s Tax Benefits, which may be utilized in certain circumstances to reduce the Company’s future income tax obligations. The Tax Plan reduces the likelihood that any changes in the Company’s investor base, including an ownership change, would limit the Company’s future use of its Tax Benefits.

In adopting the Tax Plan, the Board of Directors declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of the Company’s common stock. The Rights will trade with the Company’s common stock and will expire at the close of business on the earlier of August 3, 2024 (three years from adoption) and the date upon which the Board of Directors determines that no Tax Benefits remain available or earlier as described in more detail in the Tax Plan. The Rights will be exercisable if, among other things, a person or group of persons acquires 4.95% or more of the Company’s outstanding common stock.

The Tax Plan adopted by the Board of Directors is similar to plans adopted by other publicly-held companies with significant NOLs or other substantial tax benefits and is not designed to prevent any action that the Board of Directors determines to be in the best interest of the Company and its shareholders. The Company expects to submit the Tax Plan for ratification by the Company’s shareholders at the Company’s 2022 Annual Meeting. For more information regarding the Company’s Tax Benefits, please refer to the 2020 Annual Report.

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Non-GAAP Financial Measures

The following measures described below 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 financial measures should not be considered in isolation or as a substitute for gas revenues, GPT expenses, G&A expenses, interest expense, net income (loss), operating income (loss) and net cash provided by (used in) operating activities or any other measures prepared under GAAP. Because these non-GAAP financial measures 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 Adjusted Gas Revenue

We define E&P Adjusted Gas Revenue as total natural gas revenues less benefits from our midstream business segment related to natural gas gathering and processing services recorded to consolidated GPT expenses. E&P Adjusted Gas Revenue is not a measure of natural gas revenues as determined by GAAP. Management believes that the presentation of E&P Adjusted Gas Revenue provides useful additional information to investors and analysts to evaluate the natural gas revenues derived from our E&P business. This non-GAAP measure is intended to provide investors and analysts an indication of the natural gas revenues we would receive if our natural gas volumes were serviced by a third-party midstream operator.

The following table presents a reconciliation of the GAAP financial measure of natural gas revenues to the non-GAAP financial measure of E&P Adjusted Gas Revenue for the periods presented (in thousands):


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



Natural gas and NGL revenues	$	48,498	$	12,771	$	108,141	$	39,106
Intercompany impacts from midstream segment	(10,511)		(5,630)		(21,096)		(16,869)
E&P Adjusted Gas Revenue	$	37,987	$	7,141	$	87,045	$	22,237

Cash GPT and E&P GPT

We define Cash GPT as total GPT expenses less non-cash valuation charges on pipeline imbalances. We define E&P GPT as Cash GPT less the benefits from our midstream business segment related to crude oil gathering and transportation services. Cash GPT and E&P GPT are not measures of GPT expenses as determined by GAAP. Management believes that the presentation of Cash GPT and E&P GPT provide useful additional information to investors and analysts to assess the cash costs incurred to market and transport our commodities from the wellhead to delivery points for sale without regard for certain benefits of our midstream business segment, as well as the change in value of our pipeline imbalances, which vary monthly based on commodity prices.

The following table presents a reconciliation of the GAAP financial measure of GPT expenses to the non-GAAP financial measures of Cash GPT and E&P GPT for the periods presented (in thousands):


	Successor		Predecessor	Successor				Predecessor
	Three Months Ended June 30, 2021			Three Months Ended June 30, 2020		Six Months Ended June 30, 2021			Six Months Ended June 30, 2020



GPT	$	20,485		$	23,765	$	36,196		$	53,229
Pipeline imbalances	(738)			(1,222)		1,109			(1,467)
Cash GPT	19,747			22,543		37,305			51,762
Intercompany impacts from midstream segment	1,790			1,784		3,600			3,796
E&P GPT	$	21,537		$	24,327	$	40,905		$	55,558

E&P Cash G&A

We define E&P Cash G&A as total G&A expenses less non-cash equity-based compensation expenses, other non-cash charges and G&A expenses attributable to midstream and others services. E&P Cash G&A is not a measure of G&A 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.

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The following table presents a reconciliation of the GAAP financial measure of G&A expenses to the non-GAAP financial measure of E&P Cash G&A for the periods presented (in thousands):


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



General and administrative expenses	$	20,210	$	37,443	$	40,947	$	68,617
Equity-based compensation expenses	(4,702)		(4,738)		(6,900)		(11,359)
G&A expenses attributable to midstream and other services	(4,487)		(3,923)		(9,039)		(11,811)

E&P Cash G&A	$	11,021	$	28,782	$	25,008	$	45,447

Cash Interest and E&P 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, and E&P Cash Interest is defined as total Cash Interest less Cash Interest attributable to OMP. Cash Interest and E&P Cash Interest are not measures of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest and E&P Cash Interest provide useful additional information to investors and analysts for assessing the interest charges incurred on our debt to finance our E&P activities, 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 measures of Cash Interest and E&P Cash Interest for the periods presented (in thousands):


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020(1)		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020(1)



Interest expense	$	22,571	$	44,388	$	31,268	$	140,145
Capitalized interest	543		1,776		961		4,063
Amortization of deferred financing costs(2)	(9,990)		(4,448)		(13,461)		(6,147)
Amortization of debt discount	—		(2,696)		—		(5,535)
Cash Interest	13,124		39,020		18,768		132,526
Cash Interest attributable to OMP	(10,758)		(4,980)		(13,486)		(35,212)
E&P Cash Interest	$	2,366	$	34,040	$	5,282	$	97,314

___________________

(1)For the three and six months ended June 30, 2020, interest expense, Cash Interest and E&P Cash Interest include specified default interest charges of $1.0 million and $30.3 million, respectively, related to the Predecessor Credit Facility. For the three and six months ended June 30, 2020, interest expense, Cash Interest and Cash Interest attributable to OMP include specified default interest charges of $2.1 million and $28.0 million, respectively, related to the OMP Credit Facility. These specified default interest charges were waived upon our emergence from bankruptcy.

(2)The three and six months ended June 30, 2021 includes bridge facility fees of $7.8 million which were expensed as incurred. See “Item 1. — Financial Statements (Unaudited)—Note 11—Long-Term Debt” for more information.

Adjusted EBITDA and Adjusted EBITDA attributable to Oasis

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. We define Adjusted EBITDA attributable to Oasis as Adjusted EBITDA less Adjusted EBITDA attributable to OMP, plus distributions from OMP for our ownership of OMP limited partner units and, prior to the Midstream Simplification, Adjusted EBITDA attributable to our retained interests in Bobcat DevCo and Beartooth DevCo (the “DevCo Interests”) and distributions from OMP GP related to OMP’s incentive distribution rights.

Adjusted EBITDA and Adjusted EBITDA attributable to Oasis are not measures of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA and Adjusted EBITDA to Oasis provides useful additional information to investors and analysts for assessing our results of operations, financial performance, ability to generate cash from our business operations without regard to our financing methods or capital structure and, with respect to Adjusted EBITDA attributable to Oasis, our ability to maintain compliance with our debt covenants under the Oasis Credit Facility.

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The following table presents reconciliations of the GAAP financial measures of net loss including non-controlling interests and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA attributable to Oasis for the periods presented (in thousands):


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



Net income (loss) including non-controlling interests	$	81,309	$	(89,349)	$	46,044	$	(4,423,624)
(Gain) loss on sale of properties	(222,980)		1,047		(223,068)		(10,179)
Gain on extinguishment of debt	—		—		—		(83,887)
Net (gain) loss on derivative instruments	267,037		37,187		448,552		(248,135)
Derivative settlements	(55,979)		139,049		(78,575)		144,069
Interest expense, net of capitalized interest(1)	22,571		44,388		31,268		140,145
Depreciation, depletion and amortization	38,968		33,130		78,958		236,885
Impairment	2		2,319		5		4,825,997

Exploration expenses	1,250		1,430		1,673		2,598
Equity-based compensation expenses	4,702		4,890		6,900		11,697


Income tax (benefit) expense	3,654		(2,613)		—		(257,351)
Other non-cash adjustments	1,720		2,765		(303)		3,010
Adjusted EBITDA	142,254		174,243		311,454		341,225
Adjusted EBITDA attributable to OMP	(55,818)		(40,020)		(112,277)		(112,948)
Adjusted EBITDA attributable to DevCo Interests	—		14,208		—		40,746
Cash distributions from OMP to Oasis(2)	20,608		13,272		33,874		26,509
Adjusted EBITDA attributable to Oasis	$	107,044	$	161,703	$	233,051	$	295,532





Net cash provided by (used in) operating activities	$	159,950	$	(47,880)	$	350,363	$	59,895
Derivative settlements	(55,979)		139,049		(78,575)		144,069
Interest expense, net of capitalized interest(1)	22,571		44,388		31,268		140,145

Exploration expenses	1,250		1,430		1,673		2,598
Deferred financing costs amortization and other	(13,969)		(10,567)		(16,289)		(16,755)
Current tax (benefit) expense	—		25		—		(36)
Changes in working capital	26,711		45,033		23,317		8,299

Other non-cash adjustments	1,720		2,765		(303)		3,010
Adjusted EBITDA	142,254		174,243		311,454		341,225
Adjusted EBITDA attributable to OMP	(55,818)		(40,020)		(112,277)		(112,948)
Adjusted EBITDA attributable to DevCo interests	—		14,208		—		40,746
Cash distributions from OMP to Oasis	20,608		13,272		33,874		26,509
Adjusted EBITDA attributable to Oasis	$	107,044	$	161,703	$	233,051	$	295,532

___________________

(1)For the three and six months ended June 30, 2020, interest expense includes specified default interest charges of $1.0 million and $30.3 million, respectively, related to the Predecessor Credit Facility and $2.1 million and $28.0 million, respectively, related to the OMP Credit Facility. These specified default interest charges were waived upon our emergence from bankruptcy.

E&P Adjusted EBITDA and E&P Free Cash Flow

We define E&P Free Cash Flow as Adjusted EBITDA from our E&P segment plus distributions to Oasis for (i) our ownership of OMP limited partner units and, prior to the Midstream Simplification, (ii) distributions from OMP GP related to OMP’s incentive distribution rights and (iii) the DevCo Interests; less E&P Cash Interest, capital expenditures for E&P and other, excluding capitalized interest, and midstream capital expenditures attributable to the DevCo Interests. E&P Free Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of E&P Free Cash Flow provides useful additional information to investors and analysts for assessing the financial performance of our

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E&P business as compared to our peers and our ability to generate cash from our E&P operations and midstream ownership interests after interest and capital spending. In addition, E&P 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 a reconciliation of the GAAP financial measure of loss before income taxes including non-controlling interests from our E&P segment to the non-GAAP financial measure of Adjusted EBITDA from our E&P segment and E&P Free Cash Flow for the periods presented (in thousands):



	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020



Income (loss) before income taxes including non-controlling interests	$	57,586	$	(116,366)	$	(25,130)	$	(4,629,623)
(Gain) loss on sale of properties	(228,015)		1,047		(228,103)		(10,179)
Gain on extinguishment of debt	—		—		—		(83,887)
Net (gain) loss on derivative instruments	267,037		37,187		448,552		(248,135)
Derivative settlements	(55,979)		139,049		(78,575)		144,069
Interest expense, net of capitalized interest(1)	11,424		39,202		16,289		104,702
Depreciation, depletion and amortization	29,232		25,676		60,002		224,330
Impairment	—		920		3		4,716,314
Exploration expenses	1,250		1,430		1,673		2,598
Equity-based compensation	4,686		4,811		6,374		11,407
Other non-cash adjustments	1,792		2,765		(282)		3,010
E&P Adjusted EBITDA	89,013		135,721		200,803		234,606
Distributions to Oasis from OMP and DevCo Interests(2)	20,608		28,177		33,874		67,949
E&P Cash Interest(1)	(2,366)		(34,040)		(5,282)		(97,314)
E&P and other capital expenditures	(53,015)		(38,655)		(82,024)		(192,284)


Midstream capital expenditures attributable to DevCo Interests	—		(272)		—		(7,713)
Capitalized interest	543		1,776		961		4,063
E&P Free Cash Flow(1)	$	54,783	$	92,707	$	148,332	$	9,307

___________________

(1)For the three and six months ended June 30, 2020, interest expense, E&P Cash Interest and E&P Free Cash Flow include the impact of specified default interest charges related to the Predecessor Credit Facility of $1.0 million and $30.3 million, respectively. The specified default interest was waived upon our emergence from bankruptcy.

(2)There were no distributions to Oasis from DevCo Interests subsequent to the Midstream Simplification. See “Recent Developments – Midstream Simplification” above for more information.

Fair Value of Financial Instruments

See “Item 1. Financial Statements (Unaudited)—Note 6—Fair Value Measurements” for a discussion of our 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 2020 Annual Report.

Item 3. — Quantitative and Qualitative Disclosures about Market Risk

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.

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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 crude oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2020 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, natural gas and NGLs fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, natural gas and NGLs have been volatile, especially over the last several months and years. These prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into commodity derivative contracts in the past and expect to enter into derivative instruments in the future. Additionally, we may choose to liquidate existing derivative positions before the contract ends in order to realize the current value of our existing positions, in accordance with terms under our credit agreements.

In addition, pursuant to the purchase and sale agreement associated with the Primary Permian Basin Sale, the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year. If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter Percussion’s obligation to make any remaining earn-out payments is terminated.

See “Item 1. Financial Statements (Unaudited)—Note 7—Derivative Instruments” to our unaudited condensed consolidated financial statements for additional information regarding our derivative instruments.

We had a net derivative liability position of $381.6 million at June 30, 2021. A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $169.4 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $163.5 million. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions and COVID-19,” for further discussion on the commodity price environment.

Interest rate risk. At June 30, 2021, we had $400.0 million of Oasis Senior Notes outstanding at a fixed cash interest rate of 6.375% per annum and $450.0 million of OMP Senior Notes outstanding at a fixed cash interest rate of 8.00% per annum.

At June 30, 2021, we had no borrowings and $1.3 million of outstanding letters of credit under the Oasis Credit Facility. Borrowings under the Oasis Credit Facility are 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 London interbank offered rate (“LIBOR”) loan (“Eurodollar Loan”) or a domestic bank prime interest rate loan (“ABR Loan”). The unused borrowing base capacity is subject to a commitment fee of 0.500%.

At June 30, 2021, OMP had $213.0 million of borrowings and $5.5 million of outstanding letters of credit under the OMP Credit Facility, which were subject to varying rates of interest based on (i) OMP’s most recently tested consolidated total leverage ratio and (ii) whether the loan is a Eurodollar Loan or an ABR Loan. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%. At June 30, 2021, the outstanding borrowings under the OMP Credit Facility bore interest at LIBOR plus a 2.50% 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 six months ended June 30, 2021, our credit losses on joint interest receivables were immaterial. 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.

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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. All 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.

Item 4. — Controls and Procedures

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2021. 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 June 30, 2021.

Changes in internal control over financial reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2021 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

See “Part I, Item 1. — Financial Statements (Unaudited) — Note 18 — Commitments and Contingencies” which is incorporated herein by reference, for a discussion of material legal proceedings.

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 “Part I. Item 1A. Risk Factors” in our 2020 Annual Report. There have been no material changes in our risk factors from those described in our 2020 Annual Report, except as described below.

We may not be able to utilize a portion of our net operating losses (“NOLs”) and other tax attributes (collectively, the “Tax Benefits”) to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our financial position, results of operations and cash flows. We have adopted a Tax Benefits Preservation Plan that is designed to protect our Tax Benefits.

Upon emergence from bankruptcy, we had significant Tax Benefits, most notably net unrealized built-in losses. While the analysis is complex and subject to subjective determinations and uncertainties, we believe that we should qualify for, and intend to utilize the exception under Section 382(l)(5) of the Code, which allows for no limitations of these Tax Benefits going forward. Utilization of these Tax Benefits depends on many factors, including our future taxable income, which cannot be assured.

If a corporation experiences an “ownership change” as defined by Section 382 of the Code, any Tax Benefits could be substantially limited, and timing of the usage of such Tax Benefits could be substantially delayed. Further, if a subsequent ownership change occurs within two years of an ownership change for which Section 382(l)(5) of the Code was applied, the Company would be precluded from utilizing the Tax Benefits following such ownership change. A corporation generally will experience an ownership change if one or more stockholders (or group of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period (or, if a shorter period, since the corporation’s last ownership change). We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in limitations being placed on our ability to utilize our Tax Benefits.

The Board of Directors has adopted the Tax Plan designed to protect the availability of the Company’s Tax Benefits, which may be utilized in certain circumstances to reduce the Company’s future income tax obligations. Notwithstanding the adoption of the Tax Plan, there is no assurance that the Company will not experience an ownership change under Section 382 of the Code. If the Company is unable to use the Tax Benefits in years in which it has taxable income, the Company will pay significantly more in cash tax than if it were able to utilize the Tax Benefits, and those tax costs would negatively impact the Company’s financial position, results of operations and cash flows.

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

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

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended June 30, 2021:


Period	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
April 1 – April 30, 2021	—	$	100,000,000
May 1 – May 31, 2021	190,783	85,443,582
June 1 – June 30, 2021	—	85,443,582
Total	190,783	$	85,443,582

___________________

(1)In March 2021, the Board of Directors authorized a share-repurchase program covering up to $100.0 million of the Company's common stock. This share-repurchase program expires on December 31, 2022.

During the three months ended June 30, 2021, no shares of common stock were surrendered by the Company’s employees to satisfy tax withholding obligations arising from vesting of restricted stock awards.

Item 6. — Exhibits


Exhibit No.						Description of Exhibit

2.1*						Purchase and Sale Agreement, dated as of May 3, 2021, among Oasis Petroleum North America LLC and QEP Energy Company (filed as Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q on May 6, 2021, and incorporated herein by reference).

2.2						Purchase and Sale Agreement dated May 20, 2021, between Oasis Petroleum Permian LLC and Percussion Petroleum Operating II, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on May 21, 2021, and incorporated herein by reference).

10.1						Third Amendment to Credit Agreement, dated May 3, 2021, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum LLC, a Delaware limited liability company, Oasis Petroleum North America LLC, a Delaware limited liability company, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank and swingline lender, and the lenders party thereto (filed as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q on May 6, 2021, and incorporated herein by reference).

10.2						Fourth Amendment to Credit Agreement, dated May 21, 2021, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum LLC, a Delaware limited liability company, Oasis Petroleum North America LLC, a Delaware limited liability company, as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank, swingline lender, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 21, 2021, and incorporated herein by reference).

10.3						Commitment Letter, dated as of May 3, 2021, by and among the Company and JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q on May 6, 2021, and incorporated herein by reference).

10.4						Purchase Agreement, dated as of May 25, 2021 among Oasis Petroleum Inc., the Guarantors and J.P. Morgan Securities LLC as representative of the several initial purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 26, 2021, and incorporated herein by reference).

10.5**						Employment Agreement, dated April 13, 2021, by and between Oasis Petroleum Inc. and Daniel E. Brown (filed as Exhibit 99.2 to the Company’s Current Report on Form 8-K on April 19, 2021, and incorporated herein by reference).

10.6**						Form of Notice of Grant for Restricted Stock Units for Daniel E. Brown dated April 13, 2021 (with form of associated Restricted Stock Unit Agreement attached thereto) (filed as Exhibit 99.3 to the Company’s Current Report on Form 8-K on April 19, 2021, and incorporated herein by reference).

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10.7**						Form of Notice of Grant for Relative Total Shareholder Return Performance Share Units for Daniel E. Brown dated April 13, 2021 (with form of associated Performance Share Unit Agreement attached thereto) (filed as Exhibit 99.4 to the Company’s Current Report on Form 8-K on April 19, 2021, and incorporated herein by reference).

10.8**						Form of Notice of Grant for Absolute Total Shareholder Return Performance Share Units for Daniel E. Brown dated April 13, 2021 (with form of associated Performance Share Unit Agreement attached thereto) (filed as Exhibit 99.5 to the Company’s Current Report on Form 8-K on April 19, 2021, and incorporated herein by reference).

10.9**						Indemnification Agreement, dated April 13, 2021, by and between Oasis Petroleum Inc. and Daniel E. Brown (filed as Exhibit 99.6 to the Company’s Current Report on Form 8-K on April 19, 2021, and incorporated herein by reference).

31.1(a)						Sarbanes-Oxley Section 302 certification of Principal Executive Officer.

31.2(a)						Sarbanes-Oxley Section 302 certification of Principal Financial Officer.

32.1(b)						Sarbanes-Oxley Section 906 certification of Principal Executive Officer.

32.2(b)						Sarbanes-Oxley Section 906 certification of Principal Financial Officer.

101.INS(a)						XBRL Instance Document - 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.

* Exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company undertakes to furnish supplemental copies of any of the omitted exhibits or schedules upon request by the U.S. Securities and Exchange Commission.

** Management contract or compensatory plan or arrangement.

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SIGNATURES

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

OASIS PETROLEUM INC.

Date:

August 5, 2021

By:

/s/ Daniel E. Brown

Daniel E. Brown

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)