oas-20201231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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

For the fiscal year ended December 31, 2020


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

Commission file number: 1-34776

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Oasis Petroleum Inc.

(Exact name of registrant as specified in its charter)

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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, par value $0.01 per share

OAS

The Nasdaq Stock Market LLC

Securities Registered Pursuant to Section 12(g) of the Act:

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No ¨

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý

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

Indicate by check mark whether the registrant has submitted electronically 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 ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

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

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 ¨

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $236,577,404

Number of shares of registrant’s common stock outstanding as of February 28, 2021: 20,093,083

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Documents Incorporated By Reference:

Portions of the registrant’s definitive proxy statement for its 2021 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2020, are incorporated by reference into Part III of this report for the year ended December 31, 2020.

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OASIS PETROLEUM INC.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2020

TABLE OF CONTENTS


Cautionary Note Regarding Forward-Looking Statements		2
Risk Factors Summary		4

	PART I
Item 1.	Business	6
Item 1A.	Risk Factors	32
Item 1B.	Unresolved Staff Comments	52
Item 2.	Properties	52
Item 3.	Legal Proceedings	52
Item 4.	Mine Safety Disclosures	52

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	53
Item 6.	Selected Financial Data	54
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	79
Item 8.	Financial Statements and Supplementary Data	81
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	153
Item 9A.	Controls and Procedures	153
Item 9B.	Other Information	153

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	154
Item 11.	Executive Compensation	154
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	154
Item 13.	Certain Relationships and Related Transactions, and Director Independence	154
Item 14.	Principal Accountant Fees and Services	154

	PART IV
Item 15.	Exhibits, Financial Statement Schedules	155
Item 16.	Form 10-K Summary	158

Signatures		159
Glossary of Terms		160

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K 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 Annual Report on Form 10-K, 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 Annual Report on Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In addition, 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 actions of foreign oil producers and related impacts on the global balance of supply and demand, and the expected impact on our businesses, operations, earnings and results. In addition, our forward-looking statements include our ability to successfully capitalize on our reorganization under chapter 11 of title 11 (“Chapter 11”) of the United States Code (the “Bankruptcy Code”), execute our new strategy and operate on a long-term basis. In particular, the factors discussed below and detailed under “Item 1A. Risk Factors” 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 length of time it will take for the U.S. and the rest of the world to slow the spread of COVID-19 to the point where applicable authorities are comfortable easing current 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 risk that they take actions that will prolong or exacerbate the current oversupply of crude oil;

•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 an overhang of significant amounts of crude oil and natural gas inventory stored in the U.S. and elsewhere, and the impact that such inventory overhang 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 strategic tactics;

•estimated future net reserves and present value thereof;

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

•drilling and completion of wells;

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

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

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

•availability of qualified personnel;

•owning and operating a midstream company, including ownership interests in a master limited partnership;

•infrastructure for produced and flowback water gathering and disposal;

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

•property acquisitions and divestitures;

•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;

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•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 comply with the covenants under our credit agreements;

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

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

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

•effectiveness of risk management activities;

•competition in the 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 Form 10-K.

All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. 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 Annual Report on Form 10-K 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 our ability to manage our business through the impacts of the COVID-19 pandemic, a weakening of global economic and financial conditions, changes in governmental regulations and other legal or regulatory developments affecting our business and related compliance and litigation costs, changes in crude oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and the proximity to and capacity of transportation facilities, as well as those factors discussed under “Part I, Item 1A. Risk Factors” and “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K, 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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Risk Factors Summary

The following is a summary of some of the principal risks that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed description of each risk factor contained in “Part I, Item 1A. Risk Factors.”

Risks related to our emergence from bankruptcy

•We recently emerged from bankruptcy, which may adversely affect our business and relationships.

•Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.

•Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

•The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

Risks related to the oil and gas industry and our business

•Events outside of our control, including a pandemic, epidemic or outbreak of an infectious disease, such as the COVID-19 pandemic, have materially adversely affected, and may further materially adversely affect, our business.

•A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, natural gas and NGLs, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

•Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.

•Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

•If crude oil, natural gas and NGL prices decline or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties.

•The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

•We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

•All of our producing properties and operations are located in the Williston Basin and the Permian Basin regions, making us vulnerable to risks associated with operating in a limited number of geographic areas.

•The marketability of our production is dependent upon crude oil, natural gas and NGL gathering, processing and transportation facilities, some of which are owned by third parties. Market conditions or operational impediments could hinder our access to crude oil, natural gas or NGL markets, delay our production or reduce the realized prices we receive.

•The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

•Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

•Our business is subject to operating risks that could result in substantial losses or liability claims, and we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

•Drilling locations that we decide to drill may not yield crude oil or natural gas in commercially viable quantities.

•Our potential drilling location inventories are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

•Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

•Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.

•Failure to comply with federal, state and local laws and regulations could adversely affect our ability to produce, gather and transport our crude oil and natural gas and may result in substantial penalties.

•Climate change and climate change legislation and regulatory initiatives could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.

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•Increasing attention and federal actions in regards to ESG matters may impact our business.

•Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect our production.

•Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

•Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls, substantial changes to existing integrity management programs or more stringent enforcement of applicable legal requirements could subject us to increased capital and operating costs and operational delays.

•We do not own all of the land on which our pipelines and associated facilities are located, which could result in disruptions to our operations.

•Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.

•The loss of senior management or technical personnel could adversely affect our operations.

•Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.

•We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting crude oil and natural gas prices and future development, production and marketing costs, and the integration of significant acquisitions may be difficult.

•We may incur losses as a result of title defects in the properties in which we invest.

•Disputes or uncertainties may arise in relation to our royalty obligations.

Risks related to our financial position

•Increased costs of capital could adversely affect our business.

•Our revolving credit facilities contain operating and financial restrictions that may restrict our business and financing activities.

•Our level of indebtedness may increase and reduce our financial flexibility.

•We may not be able to generate enough cash flows to meet our debt obligations.

•Our derivative activities could result in financial losses or could reduce our income.

•Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil and natural gas reserves.

•The inability of one or more of our customers or affiliates to meet their obligations to us may adversely affect our financial results.

•We may not be able to utilize a portion of our net operating losses 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.

•The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business.

Risks related to our common stock

•Our ability to declare and pay dividends is subject to certain considerations and limitations.

•Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

•The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.

•There is a limited trading market for our common stock and the market price of our common stock is subject to volatility.

General risk factors

•We are from time to time involved in legal, governmental and regulatory proceedings that could result in substantial liabilities.

•Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.

•A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

•Ineffective internal controls could impact our business and financial results.

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PART I

Item 1. Business

Overview

Oasis Petroleum Inc. (together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”), a Delaware corporation, is an independent exploration and production (“E&P”) company formed in 2007 focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct our E&P activities and own our oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Permian Basin, respectively. In addition to our E&P segment, we also operate a midstream business segment primarily through Oasis Midstream Partners LP (“OMP”). OMP is a premier gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets in North America. We own a substantial majority of the general partner and a majority of the outstanding units of OMP. We derive significant cash flows from the midstream segment through distributions from our ownership of OMP limited partner units, distributions from the general partner and our retained ownership of equity interests in certain OMP subsidiaries.

As of December 31, 2020, we have 401,766 net leasehold acres in the Williston Basin, of which approximately 98% is held by production, and 24,396 net leasehold acres in the Permian Basin, of which approximately 74% is held by production. In the Williston Basin, we are currently exploiting significant resource potential from the Middle Bakken and Three Forks formations, which are present across a substantial portion of our acreage. In the Permian Basin, our development activities are focused on the Bone Spring and Wolfcamp formations, and our advanced geologic position supports strong inventory across multiple pay zones. We believe the locations, size and concentration of our acreage in the Williston and Permian Basins create an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory. Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs and has substantial Williston Basin and Permian Basin experience.

As of December 31, 2020, we had 1,127 gross (827.9 net) operated producing horizontal wells in the Williston Basin and 57 gross (53.4 net) operated producing horizontal wells in the Permian Basin, and our total average daily production in 2020 was 64,717 barrels of oil equivalent per day (“Boepd”). As of December 31, 2020, DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 152.2 million barrels of oil equivalent (“MMBoe”) in the Williston Basin, of which 74% were classified as proved developed and 63% were crude oil, and net proved reserves to be 30.3 MMBoe in the Permian Basin, of which 55% were classified as proved developed and 80% were crude oil.

Voluntary Reorganization under Chapter 11 and Emergence from Bankruptcy

On September 30, 2020 (the “Petition Date”), Oasis Petroleum Inc. and certain of our direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On November 10, 2020, the Bankruptcy Court confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the “Plan”), and the Debtors emerged from bankruptcy on November 19, 2020 (the “Emergence Date”). OMP and its subsidiaries were not included in the Chapter 11 Cases.

As a result of the restructuring, we strengthened our balance sheet, reducing our total indebtedness by $1.8 billion by issuing equity in a reorganized entity to the holders of our senior unsecured notes. For more information on our emergence from the Chapter 11 Cases and related matters, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” and “Part II, Item 8. Financial Statements and Supplementary Data—Note 2—Emergence from Voluntary Reorganization under Chapter 11.”

Fresh start accounting

Upon emergence from bankruptcy, we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the consolidated financial statements on or after November 19, 2020 are not comparable to the consolidated financial statements prior to that 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. For more information related to fresh start accounting, see “Part II. Item 8. Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting.”

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Business Strategy

Our new operational and financial strategy is focused on rigorous capital discipline and generating free cash flow by executing on the following strategic priorities:

•Returns-focused business model. We intend to generate significant free cash flow and sustainable full cycle returns by efficiently developing our acreage positions in the Williston and Permian Basins while maintaining rigorous capital discipline. Our Board of Directors established a capital allocation committee that developed a framework focused on systematic evaluation and screening of capital investments to ensure strong returns, which forms the foundation of the Company’s budgeting process. We intend to reinvest capital well within cash flow and return capital to shareholders. We declared a dividend of $0.375 per share of common stock payable on March 22, 2021 to shareholders of record as of March 8, 2021. Additionally, our management team is focused on maintaining our strong balance sheet and financial flexibility. As of December 31, 2020, we had $449.0 million of liquidity available, including $15.9 million of cash and cash equivalents and $433.2 million in the aggregate of unused borrowing capacity available under the Oasis Credit Facility and the OMP Credit Facility (both as defined in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments”). Our liquidity position, along with expected cash flows from operations, will provide continued financial flexibility as we actively manage the pace of development on our acreage positions.

•Operational excellence. Our management team is focused on continuous improvement of our operations and overall cost structure and has significant experience in successfully operating cost-efficient development programs. We have initiated an extensive third-party review of our cost structure and organizational efficiency and are targeting new material cost and capital efficiencies. The magnitude and concentration of our acreage within the Williston and Permian Basins, particularly in the core of the plays, allows us to capture economies of scale, including the ability to drill multiple wells from a single drilling pad into multiple formations, utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.

Our team is focused on employing leading drilling and completion techniques to optimize overall project economics. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. We continue to optimize our completion designs based on geology and well spacing.

•Environmental, social and governance leadership. We are committed to environmental, social and governance (“ESG”) initiatives and continue to implement new ESG best practices. We work to provide safe, reliable energy in a responsible manner while meeting the expectations of a carbon-constrained world. We are focused on identifying opportunities to minimize our environmental impact, improve safety, invest in our employees and support the communities in which we live and work.

We are a recognized industry leader in the capture of the natural gas that we produce due to the proactive and significant investments we have made in our midstream business. As of December 31, 2020, we were capturing approximately 96% of our natural gas production in North Dakota, and our flared gas percentage is two-thirds less than the average for North Dakota operators. In addition, we capture gas for other operators, reducing industry-wide emissions.

We provide leadership training and educational and professional development programs for employees at every level of the organization. We have also made meaningful investments in safety training programs that benefit our employees as well as employees of other operators and contractors. We are deeply involved in the areas in which we work and deploy our financial resources, time and talent to support a number of charitable organizations and our local communities.

Our refreshed Board of Directors is comprised of experienced energy industry professionals and 83% independent. The Board of Directors established the Nominating, Environmental, Social and Governance Committee to oversee our ESG policies. We have implemented compensation practices focused on value creation and aligned with shareholder interests. For more information about our ESG and corporate responsibility efforts, please see the “Sustainability” page of our website and the Proxy Statement that we will file for our 2021 Annual Meeting of Shareholders.

•Portfolio review. We are reviewing our E&P portfolio of quality assets in the Williston and Permian Basins for fit with our new business model focused on generating free cash flow and sustainable returns. In addition, we are evaluating our midstream position for optimal structure and value creation options.

•Consolidation. We will evaluate and pursue strategic acquisition opportunities that enhance shareholder value and build scale. As opportunities arise, we intend to identify and acquire additional acreage and producing assets to

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supplement our existing operations. We may acquire additional acreage in the Williston Basin and the Permian Basin or may selectively target additional basins that would allow us to execute large, repeatable development drilling programs.

Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

•Best-in-class balance sheet. We believe our strong balance sheet will allow us to generate significant free cash flow and corporate-level returns. We have no near-term debt maturities. We are focused on rigorous capital discipline and have a robust hedging program to minimize downside risk.

•Incentivized management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry with an average of more than 25 years of industry experience. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of large, repeatable development drilling programs. In addition, a substantial majority of our executive officers’ overall compensation has been in long-term equity-based incentive awards, and we have implemented best-in-class management compensation practices aligned with shareholders, which we believe provides them with significant incentives to grow the value of our business and return capital to shareholders.

•Substantial leasehold position in two of North America’s leading unconventional crude oil resource plays. We believe our Williston Basin acreage is one of the largest concentrated leasehold positions that is prospective in the Bakken and Three Forks formations and will continue to provide significant free cash flow generation. As of December 31, 2020, we had 401,766 net leasehold acres in the Williston Basin, of which 393,719 net acres were held by production, and 63% of our 152.2 MMBoe estimated net proved reserves in this area were comprised of crude oil. We believe our Permian Basin leasehold position provides attractive rates of return in the deepest part of one of the most prolific crude oil plays in North America across the highly contiguous blocks of acreage. As of December 31, 2020, we had 24,396 net leasehold acres in the Permian Basin, of which 17,933 net acres were held by production, and 80% of our 30.3 MMBoe estimated net proved reserves in this area were comprised of crude oil. We believe we have a large project inventory of potential drilling locations that we have not yet drilled, a majority of which are operated by us. In 2021, we will continue our drilling and completion activities in both the Williston and Permian Basins.

•Operating control over the majority of our portfolio. In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. As of December 31, 2020, 97% of our estimated net proved reserves were attributable to properties that we expect to operate. In 2021, we plan to complete approximately 23 to 25 gross operated wells with an average working interest of approximately 86% in the Williston Basin and approximately 6 to 8 gross operated wells with an average working interest of approximately 100% in the Permian Basin. In addition to our E&P position, we have a robust midstream infrastructure platform that we control that provides attractive cost and certainty of service. Controlling operations enables us to optimize capital allocation and control the pace of development of our assets to manage our reinvestment rates in line with our broader strategic objectives. Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio, including both our E&P and midstream segments. We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational and cost efficiencies and capital efficiency. We are also better able to manage infrastructure investment to drive down operating costs and optimize crude oil, natural gas and NGL price realizations.

•Vertical integration. Our investment in and operational control of our midstream business provides us with additional operational efficiencies and cost savings compared to our peers. This vertical integration helps us control capital dollars being spent in advance of production to ensure volumes flow, improve uptime performance of our producing wells, protect against rising service costs and increase transparency in the planning process. In addition, our midstream business generates free cash flow, provides optionality and further diversifies our customer base through midstream services we provide to other companies.

Exploration and Production Operations

Proved reserves

Our estimated net proved reserves and related PV-10 at December 31, 2020, 2019 and 2018 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated 100% of the reserves and discounted values at December 31, 2020, 2019 and 2018 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in crude oil and natural gas

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producing activities. Our estimated net proved reserves and related future net revenues, PV-10 and standardized measure of discounted future net cash flows (“Standardized Measure”) do not include probable or possible reserves and were determined using the preceding 12 months’ unweighted arithmetic average of the first-day-of-the-month index prices for crude oil and natural gas, which were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas, $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas and $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas for the years ended December 31, 2020, 2019 and 2018, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The information in the following table does not give any effect to or reflect our commodity derivatives. Future operating costs, production taxes and capital costs were based on current costs as of each year-end. For a definition of proved reserves under the SEC rules, please see the “Glossary of Terms” included at the end of this report. For more information regarding our independent reserve engineers, please see “Independent petroleum engineers” below. Future net revenues represent projected revenues from the sale of our estimated net proved reserves (excluding derivative contracts) net of production and development costs (including operating expenses and production taxes). PV-10 and Standardized Measure represent the present value of the future net revenues discounted at 10%, before and after income taxes, respectively.

There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties. There can be no assurance that our estimated net proved reserves will be produced within the periods indicated or that prices and costs will remain constant. A substantial or extended decline in crude oil prices could result in a significant decrease in our estimated net proved reserves and related future net revenues, Standardized Measure and PV-10 in the future.

The following table summarizes our estimated net proved reserves and related future net revenues, Standardized Measure and PV-10:


	At December 31,
	2020			2019			2018
Estimated proved reserves:
Crude oil (MMBbls)	119.8			200.8			228.4
Natural gas (Bcf)	376.2			513.5			552.7
Total estimated proved reserves (MMBoe)	182.5			286.4			320.5
Percent crude oil	66		%	70		%	71		%
Estimated proved developed reserves:
Crude oil (MMBbls)	85.4			113.4			144.5
Natural gas (Bcf)	262.7			314.0			339.4
Total estimated proved developed reserves (MMBoe)	129.2			165.8			201.1
Percent proved developed	71		%	58		%	63		%
Estimated proved undeveloped reserves:
Crude oil (MMBbls)	34.3			87.4			83.9
Natural gas (Bcf)	113.5			199.5			213.3
Total estimated proved undeveloped reserves (MMBoe)	53.3			120.6			119.4
Future net revenues (in millions)	$	1,793.6		$	5,385.4		$	8,341.6
Standardized Measure (in millions)(1)	$	948.9		$	2,844.4		$	4,050.3
PV-10 (in millions)(2)	$	1,115.0		$	2,934.4		$	4,674.3

__________________

(1)Standardized Measure represents the present value of estimated future net cash flows from proved crude oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.

(2)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under accounting principles generally accepted in the United States of America (“GAAP”), because it does not include the effect of income taxes on discounted future net cash flows. See “Reconciliation of Standardized Measure to PV-10” below.

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The following table provides additional information regarding our estimated net proved developed and undeveloped crude oil and natural gas reserves by basin as of December 31, 2020:


	Proved Developed			Proved Undeveloped
	Crude oil (MMBbls)	Natural gas (Bcf)	Total (MMBoe)	Crude oil (MMBbls)	Natural gas (Bcf)	Total (MMBoe)
Williston Basin	72.3	241.9	112.6	23.3	97.2	39.6
Permian Basin	13.2	20.8	16.6	11.0	16.3	13.7
Total	85.5	262.7	129.2	34.3	113.5	53.3

Estimated net proved reserves at December 31, 2020 were 182.5 MMBoe, a 36% decrease from estimated net proved reserves of 286.4 MMBoe at December 31, 2019, primarily due to decreases of 86.3 MMBoe for net negative revisions and 23.7 MMBoe for production, partially offset by an increase of 6.0 MMBoe for additions. The net negative revisions were attributable to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 31.9 MMBoe due to lower realized prices, offset by positive revisions of 1.1 MMBoe due to lower operating expenses.

Our proved developed reserves decreased 36.6 MMBoe, or 22%, to 129.2 MMBoe for the year ended December 31, 2020 from 165.8 MMBoe for the year ended December 31, 2019, primarily due to decreases of 27.8 MMBoe for net negative revisions and 23.7 MMBoe for production, partially offset by increases from our 2020 development program, which included 69 gross (34.6 net) wells that were completed and brought on production during 2020 and resulted in conversions of proved undeveloped reserves of 11.7 MMBoe and additions of 3.2 MMBoe. Proved developed revisions were primarily due to negative revisions of 29.3 MMBoe due to lower realized prices, partially offset by positive revisions of 1.5 MMBoe due to lower operating expenses.

Our proved undeveloped reserves decreased 67.4 MMBoe, or 56%, to 53.3 MMBoe for the year ended December 31, 2020 from 120.6 MMBoe for the year ended December 31, 2019 primarily due to net negative revisions of 58.4 MMBoe and the conversion of wells to proved developed of 11.7 MMBoe, offset by additions of 2.8 MMBoe. The proved undeveloped revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the anticipated five-year development plan and 2.6 MMBoe due to lower realized prices.

See Note 27 to our consolidated financial statements for more information on our proved reserves for the years ended December 31, 2019 and 2018. For the comparison of the years ended December 31, 2019 and 2018, refer to “Item 1. Business—Our operations - exploration and production activities” in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020.

Reconciliation of Standardized Measure to PV-10

PV-10 is derived from Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of Standardized Measure on a pre-tax basis. PV-10 is equal to Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and gas properties. PV-10, however, is not a substitute for Standardized Measure. Our PV-10 measure and Standardized Measure do not purport to represent the fair value of our crude oil and natural gas reserves.

The following table provides a reconciliation of Standardized Measure to PV-10:


	At December 31,
	2020		2019		2018

			(In millions)
Standardized Measure of discounted future net cash flows	$	948.9	$	2,844.4	$	4,050.3
Add: present value of future income taxes discounted at 10%	166.1		90.0		624.0
PV-10	$	1,115.0	$	2,934.4	$	4,674.3

The PV-10 of our estimated net proved reserves at December 31, 2020 was $1,115.0 million, a 62% decrease from PV-10 of $2,934.4 million at December 31, 2019. This decrease was primarily due to lower commodity price assumptions and a decrease in reserves year over year.

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Proved undeveloped reserves

At December 31, 2020, we had approximately 53.3 MMBoe of proved undeveloped reserves as compared to 120.6 MMBoe at December 31, 2019. The following table summarizes the changes in our proved undeveloped reserves during 2020:


			Year Ended December 31, 2020

			(MBoe)
Proved undeveloped reserves, beginning of period			120,625
Extensions, discoveries and other additions			2,780


Revisions of previous estimates			(58,426)
Conversion to proved developed reserves			(11,726)
Proved undeveloped reserves, end of period			53,253

During 2020, we spent a total of $115.5 million related to the development of proved undeveloped reserves, $31.6 million of which was spent on proved undeveloped reserves that represent wells in progress at year-end. The remaining $83.9 million resulted in the conversion of 11.7 MMBoe of proved undeveloped reserves, or 10% of our proved undeveloped reserves balance at the beginning of 2020, to proved developed reserves. We added 2.8 MMBoe of proved undeveloped reserves as a result of our five-year development plan. The 2020 proved undeveloped revisions of 58.4 MMBoe were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the anticipated five-year development plan and 2.6 MMBoe due to lower realized prices.

We expect to develop all of our proved undeveloped reserves, including all wells drilled but not yet completed, as of December 31, 2020 within five years. The future development of such proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, the Oasis Credit Facility and our derivative contracts. All proved undeveloped locations are located on properties where the leases are held by existing production or continuous drilling operations. Approximately 21% of our proved undeveloped reserves at December 31, 2020 are attributable to wells that have been drilled but not yet completed, and 100% of our undrilled reserves are within our core acreage in the Williston and Permian Basins.

Independent petroleum engineers

Our estimated net proved reserves and related future net revenues and PV-10 at December 31, 2020, 2019 and 2018 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revised June 2019) and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Moscow, Astana, Buenos Aires, Baku and Algiers. The firm’s more than 180 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton has provided such services for 85 years. The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Professional Engineer in the State of Texas, is a member of the Society of Petroleum Engineers and has over 10 years of experience in crude oil and natural gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Istanbul Technical University in 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any crude oil, natural gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.

Technology used to establish proved reserves

In accordance with rules and regulations of the SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in

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the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007). The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by us to DeGolyer and MacNaughton and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (i) production diagnostics, (ii) decline-curve analysis and (iii) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history and appropriate reserves definitions.

Internal controls over reserves estimation process

We employ DeGolyer and MacNaughton as the independent reserves evaluator for 100% of our reserves base. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Brett Newton, Senior Vice President and Chief Engineer, is the technical person primarily responsible for overseeing our reserves evaluation process. He has over 30 years of industry experience with positions of increasing responsibility in engineering and management. He holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering. Mr. Newton reports directly to our President and Chief Operating Officer.

Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:

•Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;

•Review of working interests and net revenue interests in our reserves database against our well ownership system;

•Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;

•Review of updated capital costs prepared by our operations team;

•Review of internal reserve estimates by well and by area by our internal reservoir engineers;

•Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President and Chief Engineer;

•Review of a preliminary copy of the reserve report by our President and Chief Operating Officer with our internal technical staff; and

•Review of our reserves estimation process by our Audit Committee on an annual basis.

Production, price and cost history

We produce and market crude oil, natural gas and NGLs, which are commodities. The price that we receive for the crude oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, access to markets, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under

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supply of crude oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, natural gas and NGLs, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

The following table sets forth information regarding our crude oil and natural gas production by basin, realized prices and production costs for the periods presented. For additional information on price calculations, please see information set forth in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018
Net production volumes:
Williston Basin
Crude oil (MBbls)	1,336		11,858		20,722		21,786
Natural gas (MMcf)	4,644		38,844		52,813		40,550
Oil equivalents (MBoe)	2,111		18,331		29,524		28,544
Average daily production (Boepd)	50,256		56,579		80,889		78,203
Permian Basin
Crude oil (MBbls)	257		2,368		2,102		1,264
Natural gas (MMcf)	364		3,355		3,093		1,880
Oil equivalents (MBoe)	317		2,927		2,618		1,578
Average daily production (Boepd)	7,553		9,033		7,172		4,322
Average sales prices:
Crude oil (per Bbl)
Williston Basin	$	42.98	$	37.04	$	55.30	$	62.21
Permian Basin	45.30		35.30		54.96		55.52
Total average sales price	43.36		36.75		55.27		61.84
Total average realized price after the effect of derivative settlements(1)	43.36		48.13		55.89		52.65
Natural gas (per Mcf)
Williston Basin	3.54		2.00		2.70		3.91
Permian Basin	2.56		0.94		1.48		3.29
Total average sales price(2)	3.47		1.91		2.64		3.88
Total average realized price after the effect of derivative settlements(1)(2)	3.45		1.91		2.72		3.84
Average costs (per Boe):
Production costs(3)


Williston Basin	$	11.81	$	9.96	$	11.04	$	10.08


Permian Basin	6.44		7.39		10.10		8.31
Total
Lease operating expenses	7.35		5.57		6.95		6.44
Gathering, processing and transportation expenses	3.76		4.04		4.01		3.56
Production taxes	2.45		2.14		3.50		4.44
E&P general and administrative expenses	5.04		5.92		3.39		3.63
E&P Cash G&A(4)	5.04		4.41		2.07		2.48

__________________

(1)Average realized prices after the effect of derivative settlements include the cash received or paid for the cumulative gains or losses on our commodity derivatives settled in the periods presented, but do not include proceeds from

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derivative liquidations. 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.

(3)Production costs include lease operating expenses and gathering, processing and transportation (“GPT”) expenses.

(4)E&P Cash G&A, a non-GAAP financial measure, represents general and administrative (“G&A”) expenses less non-cash equity-based compensation expenses and other non-cash charges included in our E&P segment. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for a reconciliation of G&A expenses to E&P Cash G&A.

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage by basin in which we own a working interest as of December 31, 2020. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.


	Developed acres		Undeveloped acres		Total
	Gross	Net	Gross	Net	Gross	Net
Williston Basin	466,649	355,203	78,459	46,563	545,108	401,766
Permian Basin	27,431	16,162	12,748	8,234	40,179	24,396
Total	494,080	371,365	91,207	54,797	585,287	426,162

Our total acreage that is held by production decreased to 411,652 net acres at December 31, 2020 from 415,206 net acres at December 31, 2019.

The following table sets forth the number of gross and net undeveloped acres by basin as of December 31, 2020 that will expire over the next three years unless production is established on the acreage prior to the expiration dates:


	Year ending December 31,
	2021		2022		2023
	Gross	Net	Gross	Net	Gross	Net
Williston Basin	6,030	5,769	3,599	1,108	262	161
Permian Basin	1,794	879	110	13	40	6
Total	7,824	6,648	3,709	1,121	302	167

Productive wells

The following table presents the total and operated gross and net productive wells by basin as of December 31, 2020:


	Total wells		Operated wells
	Gross	Net	Gross	Net
Williston Basin - horizontal wells	1,491	870.6	1,127	827.9
Williston Basin - other	—	—	—	—
Permian Basin - horizontal wells	172	54.1	57	53.4
Permian Basin - other	17	6.4	4	3.2
Total wells	1,680	931.1	1,188	884.5

All of our productive wells are crude oil wells. Gross wells are the number of wells, operated and non-operated, in which we own a working interest, and net wells are the total of our working interests owned in gross wells.

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Drilling and completion activity

The following table summarizes the number of gross and net wells completed during the periods presented, regardless of when drilling was initiated.


	Year ended December 31,
	2020		2019		2018
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Oil	69	34.6	123	46.2	135	84.2
Gas	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total development wells	69	34.6	123	46.2	135	84.2
Exploratory wells:
Oil	—	—	7	5.9	2	1.3
Gas	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total exploratory wells	—	—	7	5.9	2	1.3
Total wells	69	34.6	130	52.1	137	85.5

As of December 31, 2020, we had 61 gross (29.3 net) wells in the process of being drilled or completed, which includes 32 gross operated wells waiting on completion and 29 gross non-operated wells drilling or completing.

As of December 31, 2020, we had one operated rig running in the Williston Basin, and in 2021, we expect to continue running one operated rig in the Williston Basin and to add an operated rig in the Permian Basin later this year, while concentrating drilling activities within our top-tier acreage.

Description of properties

Williston Basin

Our position in the North Dakota and Montana areas of the Williston Basin is our cornerstone asset. We are one of the top producers in the Williston Basin and have been active in the area since our formation. Our management team originally targeted the Williston Basin because of its oil-prone nature, multiple producing horizons, substantial resource potential and management’s previous professional history in the basin. The Williston Basin also generally has established infrastructure and access to materials and services. Production in the Williston Basin primarily comes from two zones: the Middle Bakken and the Three Forks. Our development activity is currently focused on our top-tier operated acreage in the deepest part of the Williston Basin in McKenzie, Mountrail and Williams counties in North Dakota.

As of December 31, 2020, our total leasehold position in the Williston Basin consisted of 401,766 net acres, and we had a total of 870.6 net producing wells and 827.9 net operated producing wells in the Williston Basin. During the year ended December 31, 2020, we had average daily production of 55,853 net Boepd in the Williston Basin, 100% of which was produced from horizontal wells. As of December 31, 2020, our working interest for producing horizontal wells averaged 58% in total and 73% in the wells we operate.

Permian Basin

We entered the Permian Basin in February 2018 when we closed on an acquisition of approximately 22,000 net acres primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across Ward, Winkler, Loving and Reeves counties in West Texas (the “2018 Permian Acquisition”). Our advanced geologic position in the Permian Basin results in an over 80% oil mix and has multi-stacked pay zones, with four primary stacked zones counted in our core inventory and potential upside from four additional zones.

As of December 31, 2020, our total leasehold position in the Permian Basin consisted of 24,396 net acres, and we had a total of 60.5 net producing wells and 56.6 net operated producing wells in the Permian Basin. During the year ended December 31, 2020, we had average daily production of 8,864 net Boepd in the Permian Basin, of which 99%, or 8,818 net Boepd, was produced from horizontal wells. As of December 31, 2020, we had 53.4 net operated producing horizontal wells in the Permian Basin, and our working interest for producing horizontal wells in the Permian Basin averaged 31% in total and 94% in the wells we operate.

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Continuous development agreement. In connection with the closing of the 2018 Permian Acquisition, Forge Energy, LLC (“Forge Energy”) entered into and assigned to OP Permian a continuous development agreement (the “CDA”) with the Commissioner of the General Land Office, on behalf of the State of Texas (collectively, the “State”), as approved by the Board for Lease of University Lands (together with the State, “University Lands”). The CDA concerns certain leases covering a substantial portion of the acreage that we indirectly acquired from Forge Energy in the 2018 Permian Acquisition and under which University Lands is the lessor. Pursuant to the CDA, the tracts covered by these leases are pooled into a single development area for which we indirectly hold an eight-year initial term ending on December 31, 2025, with an additional five-year term for certain retained acreage at certain depths in the Delaware, Bone Spring and Wolfcamp formations. If OP Permian fails to meet certain drilling and development obligations, the CDA may be subject to early termination, in which case, we may be obligated to pay non-performance fees of up to approximately $100 million. See “Item 1A. Risk Factors—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.” Due to the extraordinary market conditions during 2020, we agreed with University Lands to pause operations, and on December 31, 2020, we executed an amendment to the CDA reflecting that agreement. The amendment reduced or postponed certain drilling and development obligations for the year ended December 31, 2020 and did not result in the payment of any penalty. Our current budget contemplates drilling activity which does not meet certain obligations under the CDA. We are currently in discussions with University Lands, similar to those held in 2020, in which we will seek an amendment for the reduction of our drilling obligations for 2021 similar to that previously received. We can provide no assurance that we will be successful in obtaining this amendment. Given the early stages of our discussions with University Lands on our drilling obligations for 2021 and the continuous flexibility we have with our drilling program to adjust as market and business conditions warrant, we cannot predict whether we will incur losses or estimate the amount of any potential loss.

Marketing and major customers

We principally sell our crude oil, natural gas and NGL production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities. In an effort to improve price realizations from the sale of our crude oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil and natural gas to a broad array of potential purchasers. We sell a significant amount of our crude oil production through bulk sales at delivery points on crude oil gathering systems to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but are not limited to, transportation costs. These gathering systems, which typically originate at the wellhead and are connected to multiple pipeline and rail facilities, reduce the need to transport barrels by truck from the wellhead. As of December 31, 2020, we were flowing approximately 92% of our gross operated crude oil production through crude oil gathering systems, including 93% of our gross operated crude oil production in the Williston Basin and 81% of our gross operated crude oil production in the Permian Basin. In addition, from time to time we may enter into third-party purchase and sales transactions that allow us to optimize our advantageous gathering and transportation positions and increase the value of our crude oil price realizations. We also enter into various short-term sales contracts for a portion of our portfolio at fixed differentials.

Our marketing of crude oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—The marketability of our production is dependent upon crude oil, natural gas and NGL gathering, processing and transportation facilities, some of which are owned by third parties. Market conditions or operational impediments could hinder our access to crude oil, natural gas or NGL markets, delay our production or reduce the realized prices we receive.”

For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of our total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of our total product sales. For the year ended December 31, 2019, sales to Phillips 66 Company accounted for approximately 14% of our hydrocarbon product sales. No other purchasers accounted for more than 10% of our total sales in 2020 or 2019. For the year ended December 31, 2018, no purchaser accounted for more than 10% of our total sales. We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are a number of alternative crude oil, natural gas and NGL purchasers and markets in the Williston and Permian Basins.

Delivery commitments

As of December 31, 2020, we had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 46.6 MMBbl of crude oil, 704.1 Bcf of natural gas and 28.1 MMBbl of NGLs, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less, except for one agreement with a remaining term of approximately 24 years. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum

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volume commitments under certain agreements. We believe that our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, natural gas and NGLs from third parties to satisfy our minimum volume commitments.

Midstream Operations

Our midstream business provides full service midstream solutions including natural gas services (gathering, compression, processing and gas lift supply), crude oil services (gathering, terminaling and transportation) and water services (gathering and disposal of produced and flowback water and freshwater distribution).

Our midstream operations are primarily conducted through OMP, a consolidated subsidiary and master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets. OMP conducts its operations through its four development companies: Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”) and Panther DevCo LLC. At December 31, 2020, our ownership interest in OMP consisted of a 67.5% limited partner interest, a 92% controlling interest in OMP GP LLC (“OMP GP”), which owns all of OMP’s incentive distribution rights and its non-economic general partner interest, and our retained interests in Bobcat DevCo and Beartooth DevCo of 64.7% and 30%, respectively.

Our midstream assets are strategically located with our exploration and development activities in the Williston and Permian Basins and support our upstream operations. We have several long-term contractual arrangements with OMP, pursuant to which we have dedicated significant acreage to OMP for midstream services. We have approved an expansion of our acreage dedication to OMP in South Nesson, one of our top operating areas in the Williston Basin, to now include crude oil and produced water services. We previously dedicated our South Nesson acreage to OMP for natural gas services in 2019. OMP expects volumes under each service offering to flow in 2022. As part of the arrangement, we agreed to assign to Bighorn DevCo, which is 100% owned by OMP, certain assets in Bobcat DevCo specifically built to support both existing third-party customers in South Nesson and our future development. All future midstream infrastructure in South Nesson will be built by Bighorn DevCo, which will perform, and earn the revenue for, all of OMP’s future midstream services in the area.

In addition, OMP provides services to third-party customers and has received certain commitments from third parties in both the Williston and Permian Basins, in which OMP has the right to provide its full suite of midstream services to support existing and future third-party volumes.

Competition

The oil and gas industry is worldwide and highly competitive in all phases. We encounter competition from other crude oil and natural gas companies in all areas of operation, including the acquisition of leasing options on oil and gas properties to the exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies, numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for lease options on oil and gas properties and exploratory locations and to define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.”

Title to Properties

As is customary in the crude oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with general industry standards. Prior to completing an acquisition of producing crude oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and gas properties are subject to customary royalty and other interests, liens to secure borrowings under the Oasis Credit Facility, liens for current taxes and other burdens, which we believe do not materially interfere with the use or affect our carrying value of the properties. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—We may incur losses as a result of title defects in the properties in which we invest.”

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Seasonality

Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other crude oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Regulation

Our E&P and midstream operations are substantially affected by federal, tribal, regional, state and local laws and regulations. In particular, crude oil and natural gas production, crude oil gathering and transportation, natural gas processing and related operations are, or have been, subject to price controls, taxes and numerous laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production or otherwise provide midstream services have statutory provisions regulating the exploration for and production of crude oil and natural gas or the gathering, transportation and processing of those commodities, including provisions related to permits for the drilling of wells or processing of natural gas, bonding requirements to drill or operate producing or injection wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled or processing plants are constructed, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Historically, our compliance costs with applicable laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations; however, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may occur and, thus, there can be no assurance that such costs will not be material in the future. Additionally, environmental incidents such as spills or other releases may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may be finalized and become effective.

Regulation of transportation and sales of crude oil

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of crude oil by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate crude oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for crude oil pipelines that allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index, without making a cost of service filing. Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1, and our Bighorn DevCo Johnson’s Corner line will utilize the FERC crude oil index beginning on July 1, 2022. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. Most recently, on December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index plus 0.78%. FERC has received requests for rehearing of its December 17, 2020 order, which remain pending in FERC Docket No. RM20-14-000.

Intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same

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terms and under the same rates. When crude oil pipelines operate at full capacity, access is generally governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. Due to several crude oil train derailments in the past decade, transportation safety regulators in the United States and Canada have examined the adequacy of transporting crude oil by rail, with an emphasis on the safe transport of Bakken crude oil by rail, following findings by the U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that Bakken crude oil tends to be more volatile and flammable than certain other crude oils, and thus poses an increased risk for a significant accident.

Since 2011, all new railroad tank cars that have been built to transport crude oil or other petroleum type fluids, including ethanol, have been built to more stringent safety standards. In 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, new operational protocols for trains transporting large volumes of flammable liquids and a requirement that older DOT-111 tank cars be phased out beginning in October 2017 if they are not already retrofitted to comply with new tank car design standards. In 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029, and more recently in February 2019, PHMSA published a final rule requiring railroads to develop and submit comprehensive oil spill response plans for specific route segments traveled by a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train. Additionally, the February 2019 final rule requires railroads to establish geographic response zones along various rail routes, ensure that both personnel and equipment are staged and prepared to respond in the event of an accident, and share information about high-hazard flammable train operations with state and tribal emergency response commissions.

In addition, a number of states proposed or enacted laws in recent years that encourage safer rail operations, urge the federal government to strengthen requirements for these operations or otherwise seek to impose more stringent standards on rail transport of crude oil. For example, in the absence of a current federal standard on the vapor pressure of crude oil transported by rail, the State of Washington passed a law that became effective in July 2019, prohibiting the loading or unloading of crude oil from a rail car in the state unless the crude oil vapor pressure is lower than 9 pounds per square inch. In response, the States of North Dakota and Montana filed a preemption application with PHMSA in July 2019and in May 2020, PHMSA published a Notice of Administrative Determination of Preemption, finding that the federal Hazardous Material Transportation Law preempts Washington State’s vapor pressure limit was preempted under applicable federal law.

One or more of these federal or state safety improvements or updates relating to rail tank cars and rail crude oil-related operational practices imposed by PHMSA since 2015 could drive up the cost of transport and lead to shortages in availability of tank cars. We do not currently own or operate rail transportation facilities or rail cars. However, we cannot assure that costs incurred by the railroad industry to comply with these enhanced standards resulting from PHMSA’s final rules or that restrictions on rail transport of crude oil due to state crude oil volatility standards, if not preempted by PHMSA, will not increase our costs of doing business or limit our ability to transport and sell our crude oil at favorable prices, the consequences of which could be material to our business, financial condition or results of operations. However, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

More stringent regulatory initiatives have likewise been pursued in Canada to assess and address risks from the transport of crude oil by rail. For example, since 2014, Transport Canada has issued requirements prohibiting crude oil shippers from using certain DOT-111 tank cars and imposed a phase out schedule for other tank cars that do not meet specified safety requirements, imposed a 50 mile per hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada to have an emergency response plan. Also, at or near the same time that PHMSA released its 2015 rule, Canada’s Minister of Transport announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. Likewise, Transport Canada’s rail car retrofitting and phase out timeline largely aligned with the requirements in the PHMSA rule and issued retrofitting and phase out timelines similar to those introduced by PHMSA. Transport Canada also introduced new requirements that railways carry minimum levels of insurance depending on the quantity of crude oil or dangerous goods that they transport as well as a final report recommending additional practices for the transportation of dangerous goods.

Historically, our hazardous materials transportation compliance costs have not had a material adverse effect on our results of operations; however, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement regarding hazardous material transportation may occur in the future, which could directly and indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of tank cars. We cannot assure that costs incurred to comply with PHMSA and Transport Canada standards and regulations emerging from these existing and any future rulemakings will not be material to our business, financial condition or results of operations. In addition, any derailment of crude oil from the Williston or Permian Basins involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Although we

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believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event. Nonetheless, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of transportation and sales of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”). Please see below the discussion of “Other federal laws and regulations affecting our industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.”

Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

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Regulation of production

The production of crude oil, natural gas and NGLs is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own and operate properties in North Dakota, Montana and Texas, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of crude oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, all three states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and NGLs within their jurisdictions.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Other federal laws and regulations affecting our industry

Energy Policy Act of 2005

The Energy Policy Act of 2005 (“EPAct 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,307,164 per day, adjusted annually for inflation, for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,307,164 per violation per day, adjusted annually for inflation. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, as described below. The anti-manipulation rules and enhanced civil penalty authority increased FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

FERC market transparency rules

On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1,246,249 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.

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Texas Railroad Commission crude oil and natural gas rules

The Texas Railroad Commission (the “RRC”), through its Oil and Gas Division, regulates the exploration, production and transportation of crude oil and natural gas in Texas. Among other duties, the RRC develops and adopts regulations to prevent waste of the state’s crude oil and natural resources, protects the correlative rights of different interest owners, prevents pollution and provides safety with respect to operations including, for example, hydrogen sulfide emissions. The RRC grants drilling permits based on established spacing, density and special field rules. Additionally, each month, the RRC assigns production allowables on crude oil and natural gas wells based on factors such as tested well capability, reservoir mechanics, market demand for production and past production, as well as receives operators’ production reports on crude oil leases and gas wells and audits the crude oil disposition path to ensure production did not exceed allowables. The RRC also regulates crude oil field injection and disposal wells under a federally-approved program that includes permitting, annual reporting and periodic testing activities. Through this program, fluids are injected into either productive reservoirs under enhanced recovery projects to increase production or into productive or non-productive reservoirs for disposal. In other pollution prevention activities, the RRC assures waste management is carried out by permitting pits and landfarming, discharges, waste haulers, waste minimization and hazardous waste management tasks. To prevent pollution of the state’s surface and ground water resources, the RRC has an abandoned well plugging and abandoned site remediation program that uses funds provided by industry through fees and taxes. Wells and sites are remediated with funds from this program when responsible operators cannot be found. Moreover, flaring of natural gas is subject to regulation by the RRC under its rules, but those rules allow for permitted exceptions through the use of flare permits. Flaring may provide crude oil and natural gas producers with an approved means for continuing crude oil production under certain scenarios, such as, for example, when there may be insufficient pipeline infrastructure in place to transport natural gas to market or to prevent resource waste. The imposition of more stringent requirements by the RRC or as a result of litigation contesting such flare permit practice that lessen producers’ opportunities to flare under RRC permitted exceptions could result in reduced production, which development could have an adverse effect on our and similarly situated producers’ business and results of operations.

North Dakota Industrial Commission crude oil and natural gas rules

The North Dakota Industrial Commission (the “NDIC”) regulates the drilling and production of crude oil and natural gas in North Dakota. Beginning in 2012 and continuing thereafter, the NDIC has adopted more stringent rules relating to production activities, including with respect to financial assurance for wells and underground gathering pipelines, waste discharges and storage, hydraulic fracturing and associated public disclosure on the FracFocus chemical disclosure registry, site construction, underground gathering pipelines and spill containment, which new requirements are now in effect. These requirements have increased or will increase the well costs incurred by us and similarly situated crude oil and natural gas E&P operators, and we expect to continue to incur these increased costs as well as any added costs arising from new NDIC legal requirements laws and regulations applicable to the drilling and production of crude oil and natural gas that may be issued in the future.

Furthermore, the NDIC regulates natural gas flaring and over the past decade has issued orders limiting flaring emissions. These requirements were further revised in 2020. Please see below the discussion of “Environmental protection and natural gas flaring initiatives” for more information on the natural gas flaring program. In addition, the NDIC has adopted rules that improve the safety of Bakken crude oil for transport by establishing operating standards for conditioning equipment to properly separate production fluids, limits to the vapor pressure of produced crude oil, and parameters for temperatures and pressures associated with the production equipment.

Pipeline safety regulation

Certain of our pipelines are subject to regulation by PHMSA under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) with respect to crude oil and condensates and the Natural Gas Pipeline Safety Act (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of hazardous liquid and gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCA”) and moderate consequence areas (“MCA”) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas pipelines are predicated on high-population areas (which, for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crude oil, NGL and condensate pipelines are based on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA is attributable to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. New pipeline safety laws or regulations, amendment of existing

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laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational restrictions, delays or cancellations.

Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the HLPSA and NGPSA were amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2016. The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The PIPES Act of 2016 extended PHMSA’s statutory mandate and, among other things, required PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities. The PIPES Act of 2016 also empowers PHMSA to address unsafe conditions or practices constituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or gas pipeline facilities without prior notice or an opportunity for a hearing. More recently, Congress passed the Fiscal Year 2021 Omnibus Appropriations Bill, made effective on December 27, 2020, pursuant to which Congress adopted the PIPES Act of 2020. The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions that, among other things, will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.

New regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational restrictions, delays or cancellations. In October 2019, PHMSA published a final rule, made effective July 2020, that significantly extends and expands the reach of certain PHMSA hazardous liquid integrity management requirements, such as, for example, performance of periodic assessments and expanded use of leak detection systems, regardless of the pipeline’s proximity to a HCA (for example, integrity assessments at least once every 10 years for onshore, piggable, hazardous liquid pipeline segments located outside of HCAs, and expanded use of leak detection systems outside of HCAs on all regulated hazardous liquid pipelines other than offshore gathering and regulated rural gathering pipelines). Additionally, this final rule requires all hazardous liquid pipelines in or affecting a HCA to be capable of accommodating in-line inspection tools within the next 20 years unless the basic construction of a pipeline cannot be modified to permit that accommodation. Moreover, this final rule extends annual, accident, and safety-related conditional reporting requirements to hazardous liquid gravity lines and certain gathering lines and also imposes inspection requirements on hazardous liquid pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.

Also, in October 2019, PHMSA published the first of three expected regulations relating to new or more stringent requirements for certain natural gas pipelines, that had originally been proposed in 2016 as part of PHMSA’s “gas Mega Rule,” which first final rule became effective on July 1, 2020, and imposed numerous requirements, including maximum allowable operating pressure (“MAOP”) reconfirmation through re-verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (including all MCAs and those Class 3 and Class 4 areas found not to be in HCAs) within 14 years of publication date and at least once every 10 years thereafter, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management. We are currently evaluating the operational and financial impact related to this final rule. The remaining rulemakings comprising the gas Mega Rule have not yet been published, and we cannot predict when they will be finalized; however, they are expected to include revised pipeline repair criteria as well as more stringent corrosion control requirements. New legislation or any new regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In the absence of the PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.

Environmental and occupational health and safety regulation

Our exploration, development and production operations, crude oil gathering and transportation activities, natural gas processing services and related operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct drilling or provide midstream services; govern the amounts and types of substances that may be released into the environment; limit or prohibit construction or drilling activities in environmentally-sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered species; require investigatory and remedial actions to mitigate pollution conditions; impose obligations

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to reclaim and abandon well sites, pits, processing plants and pipelines; and impose specific criteria addressing worker protection. Certain environmental laws impose joint and several strict liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of crude oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly well construction, drilling, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. We may also experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. Moreover, accidental spills or other releases may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for damage to property, natural resources or persons. While, historically, our compliance costs with environmental laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no assurance that such costs will not be material in the future as a result of such existing laws and regulations or any new laws and regulations, or that such future compliance will not have a material adverse effect on our business and operating results. Some or all of such increased compliance costs may not be recoverable from insurance.

The following is a summary of the more significant existing environmental and occupational health and safety laws, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (the “EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate ordinary industrial wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes. These wastes are instead regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. There have been efforts from time to time to remove this exclusion, which removal could significantly increase our and our customers operating costs, and it is possible that certain crude oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce crude oil and natural gas or for conducting midstream services. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control. These properties and the substances disposed or released thereon may be subject to CERCLA,

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RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial plugging or pit, processing plant or pipeline closure operations to prevent future contamination.

Air emissions

The federal Clean Air Act (the “CAA”) and comparable state laws and regulations restrict the emission of various air pollutants from many sources through air emissions standards, construction and operating permitting programs and the imposition of other monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Obtaining permits has the potential to restrict, delay or cancel the development or expansion of crude oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in 2015, the EPA under the Obama Administration issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone, and, on December 31, 2020, published a notice of final action to retain the 2015 ozone NAAQS without revision on a going-forward basis, but this December 2020 final action is subject to legal challenge, and the NAAQS may be subject to further revision under the Biden Administration. States are expected to implement more stringent regulations that could apply to our operations. Compliance with this final rule or any other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, significantly increase our capital expenditures and operating costs and reduce demand for the crude oil and natural gas that we produce, which one or more developments could adversely impact our E&P and midstream businesses.

Environmental protection and natural gas flaring initiatives

We attempt to conduct our operations in a manner that protects the health, safety and welfare of the public, our employees and the environment. We recognize the environmental and financial risks associated with air emissions, particularly with respect to flaring of natural gas from our operated well sites and are focused on reducing these emissions, consistent with applicable requirements.

We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is a historical lack of natural gas gathering infrastructure in the Williston Basin, which translates into the inability of operators to promptly connect their wells to natural gas processing and gathering infrastructure. External factors impacting such inability that are out of the control of the operator include, for example, the granting of right-of-way access by land owners, investment from third parties in the development of gas gathering systems and processing facilities, and the development and adoption of regulations. We have allocated significant resources to connect our wells to natural gas infrastructure. In both the Williston and Permian Basins, the substantial majority of our operated wells are connected to gas gathering systems, which minimizes our flared volumes of natural gas.

The NDIC has issued orders and pursued other regulatory initiatives to implement legally enforceable “gas capture percentage goals” targeting the capture of natural gas produced in the state, commencing in October 2014. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. The NDIC requires operators to develop and implement Gas Capture Plans to maintain consistency with the agency’s gas capture percentage goals, but it maintains the flexibility to exclude certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals. Wells must continue to meet or exceed the NDIC’s gas capture percentage goals on a statewide, county, per-field, or per-well basis. Failure of an operator to comply with the applicable goal at maximum efficiency rate may result in the imposition of monetary penalties and restrictions on production from subject wells. Most recently, in September 2020, the NDIC revised the gas capture policy to allow several additional exceptions for companies that flare natural gas under certain circumstances, such as gas plant outages or delays in securing a right-of-way for pipeline construction, but did not change the gas capture targets. As of December 31, 2020, we were capturing approximately 96% of our natural gas production in North Dakota, and our flared gas percentage is two-thirds less than the average for North Dakota operators. While we were satisfying the applicable gas capture percentage goals as of December 31, 2020, there is no assurance that we will remain in compliance in the future or that such future satisfaction of such goals will not have a material adverse effect on our business and results of operations.

Climate change

In the United States, no comprehensive climate change legislation has been implemented at the federal level, but President Biden has announced plans to take action with regards to climate change, has already signed several executive orders to this effect in January 2021 and, with control of Congress shifting in January 2021, is expected to pursue legislative as well as other executive and regulatory initiatives in the future to limit greenhouse gas (“GHG”) emissions. Moreover, because the U.S.

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Supreme Court has held that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, implement New Source Performance Standards (“NSPS”) directing the reduction of methane from certain new, modified or reconstructed facilities in the crude oil and natural gas sector, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States.

In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA under the Obama Administration published final regulations under the CAA establishing new performance standards for methane in 2016, but since that time the EPA under the Trump Administration undertook several measures, including publishing in September 2020 final rule policy and technical amendments to the NSPS, for stationary sources of air emissions. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile organic compound (“VOC”) requirements for the remaining sources that were established by the Obama Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s September 2020 final rules, and on January 20, 2021, President Biden issued an executive order, that among other things, directed the EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no later than September 2021. A reconsideration of the September 2020 policy amendments is expected to follow. The January 20, 2021 executive order also directed the establishment of new methane and VOC standards applicable to existing crude oil and natural gas operations, including the production, transmission, processing and storage segments.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. At the international level, the non-binding Paris Agreement requests that nations limit their GHG emissions through individually-determined reduction goals every five years after 2020. Although the U.S. had withdrawn from the Paris Agreement, President Biden has issued executive orders recommitting the U.S. to the Paris Agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement. With the U.S. recommitting to the Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the Paris Agreement’s goals.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. On January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new crude oil and natural gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. Building on this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for crude oil and natural gas E&P on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal crude oil and natural gas permitting and leasing practices. The January 20, 2021 and January 27, 2021 orders do not apply to existing leases but the January 27, 2021 order further directs applicable agencies to take measures to eliminate subsidies provided to the fossil fuel industry. These suspensions are subject to legal challenge, with at least one industry group filing a lawsuit in January 2021, in Wyoming federal district court and seeking to have the moratorium declared invalid.

Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against the largest crude oil and natural gas E&P companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. There are also increasing financial risks for fossil fuel producers as well as other companies handling fossil fuels, including owners of terminals, pipelines and refineries, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies, as President Biden signed an executive order in January 2021 calling for, among other things, the development of a climate finance plan and, separately, the Federal Reserve announced in December 2020 that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events.

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Water discharges

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) under the Obama Administration published a final rule that would significantly expand the scope of the Clean Water Act over waters of the United States, including wetlands. However, the EPA and the Corps under the Trump Administration issued a final rule, made effective in December 2019, that repealed the 2015 rule and they also published a final rule in April 2020 re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation. The April 2020 final rule is subject to various pending legal challenges; moreover, there is an expectation with the Biden Administration taking office in January 2021, there is a possibility that the new administration will review and may reconsider this April 2020 final rule. If the EPA and the Corps under the Biden Administration revise the April 2020 final rule in a manner similar to or more stringent than the 2015 final rule, or if any challenge to the April 2020 final rule is successful, the scope of the Clean Water Act’s jurisdiction in areas where we conduct operations could again be expanded and result in increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Any such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increase compliance expenditures or mitigation costs for our operations.

The Oil Pollution Act of 1990 (the “OPA”) amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of crude oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect waters of the United States. Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for crude oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from crude oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of crude oil into waters of the United States.

Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the federal Safe Drinking Water Act (the “SDWA”) Underground Injection Control (the “UIC”) program and analogous state laws. The UIC program requires permits from the EPA or analogous state agency for disposal wells that we operate, establishes minimum standards for injection well operations and restricts the types and quantities of fluids that may be injected. Any leakage from the subsurface portions of the injection wells may cause degradation of fresh water, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages and personal injuries. Moreover, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be significant.

In response to seismic events near underground injection wells used for the disposal of produced water from crude oil and natural gas activities, federal and some state agencies have investigated, and continue to investigate, whether such wells have caused increased seismic activity. In 2016, the United States Geological Survey identified Texas as being among six states with areas of increased rates of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction. Since that time, the United States Geological Survey indicates that these rates have decreased in these states, although concern continues to exist over quakes arising from induced seismic activities. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in Texas, the RRC has adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of crude oil and natural gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or our customers.

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Hydraulic fracturing activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional formations, including shales. The process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.

The hydraulic fracturing process is typically regulated by state crude oil and natural gas commissions or similar agencies, but federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities, as well as published an advance notice of proposed rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. In addition, the EPA has published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional crude oil and natural gas extraction facilities to publicly owned wastewater treatment plants. Moreover, in 2016, the federal Bureau of Land Management (the “BLM”) under the Obama Administration published a final rule imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. However, in late 2018, the BLM under the Trump Administration published a final rule rescinding the 2016 final rule. Litigation challenging the BLM's 2016 final rule as well as its 2018 final rule rescinding the 2016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final rule in July 2020, a Wyoming federal court subsequently vacated the 2016 final rule in October 2020 and, accordingly, the 2016 final rule is no longer in effect but the Wyoming decision may be appealed. Additionally, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances.

From time to time Congress has considered, but has not adopted, legislation to provide for federal regulation of hydraulic fracturing. However, with President Biden taking office and the shift in party control of the Congressional Senate in January 2021, there is a possibility that a Biden Administration will pursue such legislation. In addition to pursuing the revision of existing laws and regulations, President Biden has issued, and may continue to issue, additional executive orders in pursuit of his regulatory agenda with regards to limiting hydraulic fracturing.

In addition, some states, including North Dakota and Texas where we primarily operate, have adopted, and other states may adopt, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. States could elect to adopt certain prohibitions on hydraulic fracturing, following the approach already taken by several states. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Nevertheless, if new or more stringent federal, state or local legal restrictions or bans relating to the hydraulic fracturing process are adopted in areas where we operate, or in the future plan to operate, we could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be limited or precluded from drilling wells or in the volume that we are ultimately able to produce from our reserves.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, crude oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added delays, restrictions or cancellations in the pursuit of our operations or increased operating costs in our production of crude oil and natural gas. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Endangered Species Act considerations

The federal Endangered Species Act (the “ESA”) and comparable state laws may restrict exploration, development and production activities that may affect endangered and threatened species or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States and prohibits the taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). The U.S. Fish and Wildlife Service (the “FWS”) under the Trump Administration issued a final rule on January 7, 2021, which notably clarifies that criminal liability under the MBTA will apply only to actions “directed at” migratory birds, their nests or their eggs; however, in 2020, the U.S. District Court for the Southern District of New York vacated a Department of Interior memorandum articulating a similar interpretation. With the new Presidential Administration taking office in January 2021, it is possible that the January 2021 rule will be subject to reconsideration by the Biden Administration or be subject to legal challenges. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed or endangered species or modify their critical habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. If endangered or threatened species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment

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operations, such work could be prohibited or delayed by seasonal or permanent restrictions or require the implementation of expensive mitigation.

Moreover, the FWS may make determinations on the listing of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in more fulsome protections for non-protected or lesser-protected species pursuant to specific timelines. The issuance of more stringent conservation measures or land, water, or resource use restrictions could result in operational delays and decreased production and revenue for us and have an indirect adverse impact on the demand for our midstream services.

Operations on federal lands

Performance of crude oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs, to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. On July 16, 2020, the Council on Environmental Quality (the “CEQ”) under the Trump Administration published a final rule modifying NEPA. The modified final rule establishes a time limit of two years for preparation of environmental impact statements and one year for the preparation of environmental assessments. The modified rule also eliminates the responsibility to consider cumulative effects of a project. With the change in Presidential Administrations in January 2021, it is possible that the final rule will be delayed or not implemented as President Biden may have the CEQ under his administration reconsider or withdraw the rule and also because the final rule is being challenged in court.

Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be substantial, and be subject to delays, limitations or prohibitions in the scope of crude oil and natural gas projects or performance of midstream services. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt our or our customers’ E&P activities. President Biden has pledged to ban new leases for production of minerals on federal properties, including onshore lands and offshore waters, and recently issued a 60-day suspension of such new leases and drilling permits on federal properties. Approximately 3% of our net acreage position in the Williston Basin is federal mineral acreage, which is spread across our acreage position, and any portion of a well on federal land requires a permit. However, we believe that the vast majority of our future drilling locations are not affected by the need to obtain a federal permit.

Employee health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state regulations require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

Human Capital Resources

As of December 31, 2020, we employed 432 people. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.

We, as a company and as individuals, believe in “doing the right thing” and being passionate about our work with the goal that we all succeed together (including our employees, contractors, shareholders and the communities in which we operate). We also believe that great people and great assets create great opportunity, and these core values inform how we think about our business.

Health and safety

We are committed to protecting the safety of our employees, our contractors, and the communities in which we operate. We continually seek to develop best-in-class procedures to maintain our safety culture. We operate our worksites under a stop work authority program, under which every person on our worksites is empowered to halt operations to address a potential safety issue. In addition, we have developed and implemented a comprehensive environment, health and safety management system and regularly conduct internal and external audits of our environmental and safety programs, including contractor safety audits.

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Safety training is provided to all employees, and safety performance is integrated into the annual performance-based cash incentive awards for all employees.

During 2020, we launched a proactive response to the COVID-19 pandemic to protect the health and safety of our employees, contractors and the communities in which we operate. We took actions to adhere to recommendations by the Centers for Disease Control and Prevention regarding social distancing and limited public exposure in connection with the COVID-19 pandemic. Even though our operations were not required to close, 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. We believe regular and consistent communication with employees is important to establish new procedures and mitigate the spread of COVID-19. In light of the recent resurgence of COVID-19 and evolving data concerning the pandemic, we continue to review the guidelines from federal, state and local officials to promote the safety of our stakeholders.

Compensation and benefits

We seek to provide fair, competitive compensation and comprehensive benefits to our employees. To ensure alignment with our short- and long-term objectives, our compensation programs consist of base pay, short-term incentives and long-term incentives, including stock grants. Our wide array of benefits include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, flexible work schedules and wellness resources, including emotional well-being services through an employee Life Assistance Program as well as financial wellness tools and resources.

We invest in leadership training and professional development programs that will enable our employees to reach their potential and perform at their best. Oasis Academy for Success is our on-demand learning system, which supports job-specific training as well as soft skill and leadership development training.

Diversity and inclusion

We recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to providing a diverse and inclusive workplace to attract and retain talented employees. We maintain a work culture that treats all employees fairly and with respect, promotes inclusivity, and provides equal opportunities for the professional growth and advancement based on merit. Our Code of Business Conduct and Ethics prohibits discrimination or harassment against any employee or applicant on the basis of race, color, gender, religion, age, national origin, citizenship status, military service or veteran status, sexual orientation or disability. In addition, we seek business partners who do not engage in prohibited discrimination in hiring or in their employment practices and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria. To sustain and promote a diverse and inclusive workforce, we maintain a robust compliance program supported by annual certification by all employees to our Code of Business Conduct and Ethics, as well as training programs on affirmative action and equal employment opportunity. We evaluate ways to enhance awareness of and promote diversity and inclusion on an ongoing basis.

Offices

Our principal office is located in Houston, Texas at 1001 Fannin Street. We also own field offices in the North Dakota communities of Williston, Powers Lake, Alexander and Watford City.

Available Information

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our filings with the SEC are available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

We make available on our website at http://www.oasispetroleum.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.

Other information, such as presentations, the charters of the Audit and Reserves Committee, Compensation Committee and Nominating, Environmental, Social and Governance Committee, and the Code of Business Conduct and Ethics, are available on our website, http://www.oasispetroleum.com, under “Investors — Corporate Governance” and in print to any shareholders who provide a written request to the Corporate Secretary at 1001 Fannin Street, Suite 1500, Houston, Texas 77002.

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Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including the Chief Executive Officer and Chief Financial Officer. Within the time period required by the SEC and The Nasdaq Stock Market LLC (“Nasdaq”), as applicable, we will post on our website any modification to the Code of Business Conduct and Ethics and any waivers applicable to senior officers who are defined in the Code of Business Conduct and Ethics, as required by the Sarbanes-Oxley Act of 2002.

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Item 1A. Risk Factors

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, results of operations or cash flows could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

Risks related to our emergence from bankruptcy

We recently emerged from bankruptcy, which may adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 Cases may adversely affect our business and relationships with customers, vendors, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

•key suppliers, vendors or other contract counterparties may terminate their relationships with us, require additional financial assurances or enhanced performance from us or pursue unreasonable fee increases for their goods or services;

•our ability to renew existing contracts and compete for new business may be adversely affected;

•our ability to attract, motivate and/or retain key employees and executives may be adversely affected;

•landowners may not be willing to lease acreage to us; and

•competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, our capital structure was significantly altered by the Plan, and we adopted fresh start accounting upon our emergence from bankruptcy. Under fresh start accounting, our assets and liabilities were recorded at fair value as of the Emergence Date. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in our historical financial statements.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Pursuant to the Plan, the composition of our Board of Directors changed significantly. Our Board of Directors currently consists of six directors, none of whom served on the Board of Directors prior to our emergence from the Chapter 11 Cases. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our Board of Directors and, thus, may have different views on the issues that will determine our future. As a result, our future strategy and plans may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that

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could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity, which could adversely affect our business and results of operations.

Risks related to the oil and gas industry and our business

Events outside of our control, including a pandemic, epidemic or outbreak of an infectious disease, such as the COVID-19 pandemic, have materially adversely affected, and may further materially adversely affect, our business.

We face risks related to pandemics, epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our business and financial condition. For example, the recent global outbreak of COVID-19 has reduced demand for crude oil and natural gas because of significantly reduced global and national economic activity. On March 13, 2020, the United States declared the COVID-19 pandemic a national emergency, and several states, including Texas, North Dakota and Montana, and municipalities have declared public health emergencies. Along with these declarations, there have been extraordinary and wide-ranging actions taken by international, federal, state and local public health and governmental authorities to contain and combat the outbreak and spread of COVID-19 in regions across the United States and the world, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions.

In addition, the impact of COVID-19 or other public health events may adversely affect our operations or the health of our workforce and the workforces of our customers and service providers by rendering employees or contractors unable to work or unable to access our and their facilities for an indefinite period of time. There can be no assurance that our personnel will not be impacted by these pandemic diseases or ultimately lead to a reduction in our workforce productivity or increased medical costs or insurance premiums as a result of these health risks.

Further, the technology required for the corresponding transition to remote work increases our vulnerability to cybersecurity threats, including threats to gain unauthorized access to sensitive information or to render data or systems unusable, the impact of which may have material adverse effects on our business and operations. See “General risk factors—A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss” below.

As the potential impact from COVID-19 is uncertain due to the ongoing and dynamic nature of the circumstances, it is difficult to predict the extent to which it may negatively affect our business, including, without limitation, our operating results, financial position and liquidity, the duration of any potential disruption of our business, how and the degree to which the pandemic may impact our customers, supply chain and distribution network, the health of our employees, the productivity and sustainability of our workforce, our insurance premiums, costs attributable to our emergency measures, payments from customers and uncollectible accounts, limitations on travel, the availability of industry experts and qualified personnel and the market for our securities. Any potential impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19, the actions taken by authorities to contain it or treat its impact, and the availability and acceptance of vaccines, all of which are beyond our control. These potential impacts, while uncertain, could continue to adversely affect global economies and financial markets and result in a persistent economic downturn that could continue to have an adverse effect on the industries in which we and our customers operate and on the demand for our products, our operating results and our future prospects.

The factors described above have had, and are expected to continue to have, an adverse effect on our business, operating results, financial position and liquidity, which led to us filing the Chapter 11 Cases. We cannot predict when the continuing adverse effect on us will end, and depending on the duration of the pandemic and its severity, this adverse effect could worsen.

A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, natural gas and NGLs, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our crude oil and, to a lesser extent, natural gas and NGLs, heavily influence our revenue, profitability, cash flow from operations, access to capital and future rate of growth. Crude oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil, natural gas and NGLs have been volatile, and continue to be volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•worldwide and regional economic conditions impacting the global supply and demand for crude oil, natural gas and NGLs;

•the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC oil-producing countries, including Russia;

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•the price and quantity of imports of foreign crude oil, natural gas and NGLs;

•political conditions in or affecting other crude oil, natural gas and NGL producing countries, including the current conflicts in and among the Middle East and conditions in South America, China, India and Russia;

•the level of global exploration and production;

•the level of global crude oil, natural gas and NGL inventories;

•events that impact global market demand, including impacts from global health epidemics and concerns, such as the COVID-19 pandemic, which has reduced and may continue to reduce demand for crude oil, natural gas and NGLs because of reduced economic activity;

•localized supply and demand fundamentals and regional, domestic and international transportation availability;

•weather conditions and natural disasters;

•domestic and foreign governmental regulations and policies, including environmental requirements;

•speculation as to future commodity prices and the speculative trading of crude oil and natural gas futures contracts;

•stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil, natural gas and NGLs and related infrastructure;

•price and availability of competitors’ supplies of crude oil, natural gas and NGLs;

•technological advances affecting energy consumption; and

•the price and availability of alternative fuels.

Commodity prices have been volatile in recent years. During 2020, the daily spot prices for NYMEX West Texas Intermediate crude oil (“NYMEX WTI”) ranged from a high of $63.27 per barrel to a low of $(36.98) per barrel, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu. The significant decline in crude oil prices in early 2020 was largely attributable to the actions of Saudi Arabia and Russia, which resulted in substantial increases in the global supply of crude oil. Specifically, in March 2020, Saudi Arabia and Russia failed to agree on a plan to extend production cuts that expired on April 1, 2020 within OPEC and other non-OPEC, oil-producing countries, including Russia. Subsequently, Saudi Arabia announced plans to increase production to record levels and to reduce the prices at which they sell crude oil. These events, combined with the continued global outbreak of COVID-19, which has significantly impacted both crude oil prices and natural gas prices due to substantially reduced demand for crude oil and natural gas because of reduced global and national economic activity, contributed to a sharp drop in prices for crude oil in early 2020. The impact has not been as severe on natural gas prices, but such prices are susceptible to global actions impacting supply and demand.

In April 2020, OPEC announced an agreement among OPEC and other non-OPEC countries, including Russia, to reduce aggregate global production by approximately 10 million barrels a day in May and June of 2020, with gradually decreasing reductions in daily production through the end of 2020. While these cuts in production may offset some of the oversupply of the global crude oil market, crude oil prices have remained low and we cannot predict future impacts to crude oil production and global economic activities.

Substantially all of our crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and our NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices. Low crude oil, natural gas and NGL prices will reduce our cash flows, borrowing ability, the present value of our reserves and our ability to develop future reserves. See “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil and natural gas reserves.” below. Low crude oil, natural gas and NGL prices may also reduce the amount of crude oil, natural gas and NGLs that we can produce economically and may affect our proved reserves. See also “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below.

Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our crude oil and natural gas E&P activities are subject to numerous risks beyond our

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control, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. These levels of uncertainty may be increased with respect to our position in the Permian Basin acquired in 2018 due to less experience operating in the area. Overruns in planned expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•shortages of or delays in obtaining equipment and qualified personnel;

•facility or equipment malfunctions and/or failure;

•unexpected operational events, including accidents;

•pressure or irregularities in geological formations;

•adverse weather conditions, such as blizzards, ice storms and floods;

•reductions in crude oil, natural gas and NGL prices;

•delays imposed by or resulting from compliance with regulatory requirements;

•proximity to and capacity of transportation facilities;

•title problems; and

•limitations in the market for crude oil and natural gas.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, the following:

•spacing of wells to maximize production rates and recoverable reserves;

•landing the well bore in the desired drilling zone;

•staying in the desired drilling zone while drilling horizontally through the formation;

•running the casing the entire length of the well bore; and

•the ability to run tools and other equipment consistently through the horizontal well bore.

Risks that we face while completing our wells include, but are not limited to, the following:

•the ability to fracture stimulate the planned number of stages;

•the ability to run tools the entire length of the well bore during completion operations;

•the ability to successfully clean out the well bore after completion of the final fracture stimulation stage; and

•protecting nearby producing wells from the impact of fracture stimulation.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or crude oil, natural gas and NGL prices decline, the return on our investment for certain projects may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating crude oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “Item 1. Business—Exploration and Production Operations” for information about our estimated crude oil and natural gas reserves and the PV-10 and Standardized Measure as of December 31, 2020, 2019 and 2018.

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In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of crude oil and natural gas reserves are inherently imprecise.

Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market value of our estimated net crude oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net revenues from our estimated net proved reserves on the unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months without giving effect to derivative transactions. Actual future net revenues from our oil and gas properties will be affected by factors such as:

•actual prices we receive for crude oil and natural gas;

•actual cost of development and production expenditures;

•the amount and timing of actual production; and

•changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing and amount of actual future net revenues from estimated net proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural industry in general.

Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our estimated net proved reserves.

If crude oil, natural gas and NGL prices decline or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties.

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. In addition, we assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and gas properties, which may result in a decrease in the amount available under the Oasis Credit Facility. A write-down constitutes a non-cash charge to earnings.

During the year ended December 31, 2020, we recognized impairment charges of $4.4 billion on our proved oil and gas properties and $401.1 million on our unproved oil and gas properties. During the years ended December 31, 2019 and 2018, we recognized impairment charges on our unproved oil and gas properties of $5.4 million and $0.9 million, respectively. We also recorded an impairment charge of $383.4 million on oil and gas properties held for sale during the year ended December 31, 2018. If crude oil, natural gas and NGL prices continue to decline or for an extended period of time remain at depressed levels, we may be caused to incur impairment charges in the future, which could have a material adverse effect on our access to capital and our results of operations for the periods in which such charges are taken.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms.

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Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services or the unavailability of sufficient transportation for our production could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital plan, which could have a material adverse effect on our business, financial condition or results of operations. Additionally, compliance with new or emerging legal requirements that affect midstream operations in North Dakota or Texas may reduce the availability of transportation for our production. For example, the NDIC adopted regulations in late 2013 that impose more rigorous pipeline development standards on midstream operators, some of whom we rely on to construct and operate pipeline infrastructure to transport the crude oil and natural gas we produce.

We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

We may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

•the timing and amount of capital expenditures;

•the operator’s expertise and financial resources;

•approval of other participants in drilling wells;

•selection of technology; and

•the rate of production of reserves, if any.

This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

All of our producing properties and operations are located in the Williston Basin and the Permian Basin regions, making us vulnerable to risks associated with operating in a limited number of geographic areas.

Our producing properties are geographically concentrated in Williston Basin in northwestern North Dakota and northeastern Montana and the Permian Basin in West Texas, with these two basins comprising 86% and 14%, respectively, of our production during the year ended December 31, 2020. As a result, we may be disproportionately exposed to the impact of economics in the Williston Basin and the Permian Basin or delays or interruptions of production from those wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil or natural gas produced from the wells in those areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic crude oil and natural gas producing areas such as the Williston Basin and the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Our crude oil, natural gas and NGLs are sold in a limited number of geographic markets and each has a generally fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with crude oil, natural gas and/or NGLs, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations. Variances in quality may also cause differences in the value received for our products.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. The impact of regional economics or delays or interruptions of production in an area could have a material adverse effect on our financial condition and results of operations.

The marketability of our production is dependent upon crude oil, natural gas and NGL gathering, processing and transportation facilities, some of which are owned by third parties. Market conditions or operational impediments could hinder our access to crude oil, natural gas or NGL markets, delay our production or reduce the realized prices we receive.

Market conditions or the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. Our ability to market our production depends in part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned by midstream operators, including third parties and OMP. Our failure to obtain such midstream services on acceptable terms could materially harm our business. The shutdown, unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells, the flaring of natural gas that could result in restrictions on production or monetary sanctions, or the delay, or discontinuance of, development plans for properties. The

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transportation of our production can be interrupted by other customers that have firm arrangements. In addition, these midstream operators may also impose specifications for the products that they are willing to accept. If the total mix of a product fails to meet the applicable product quality specifications, the midstream operators may refuse to accept all or a part of the products or may invoice us for the costs to handle or damages from receiving the out-of-specification products. In those circumstances, we may be required to delay the delivery of or find alternative markets for that product, or shut-in the producing wells that are causing the products to be out of specification, potentially reducing our revenues.

The disruption of midstream operators’ facilities due to maintenance, weather or other interruptions of service could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market. A total shut-in of our production could materially affect us due to a resulting lack of cash flows, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.

In addition, the impact of pending and future legal proceedings on these systems, pipelines and facilities can affect our ability to market our products and have a negative impact on realized pricing. On July 6, 2020, the operator of the Dakota Access Pipeline (“DAPL”) was ordered by a U.S. District court to halt oil flow and empty the pipeline within 30 days while an environmental impact study (“EIS”) is completed. On July 15, 2020, the U.S. Court of Appeals for the District of Columbia Circuit issued a temporary administrative stay while the court considers the merits of a longer-term emergency stay order through the appeals process. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit upheld the U.S. District court’s ruling that an EIS is needed and also reaffirmed its earlier decision which allows DAPL to operate through the EIS process. We regularly use DAPL in addition to other outlets to market our crude oil in the Williston Basin to end markets. To mitigate the risks associated with a potential shutdown of DAPL, we have proactively arranged for portions of our Williston Basin crude oil volumes to be sold at alternative outlets at fixed differentials to NYMEX WTI. In the event DAPL were to cease operating, we would anticipate Williston Basin crude oil prices to weaken materially before improving as the market adapts to rail transportation.

A portion of our crude oil and NGL production is transported to market centers by rail. Potential crude oil or NGL train derailments or crashes as well as state or federal restrictions on the vapor pressure of crude oil transported by, or loaded on or unloaded from, railcars could also impact our ability to market and deliver our products and cause significant fluctuations in our realized crude oil and natural gas prices due to tighter safety regulations imposed on crude-by-rail transportation and interruptions in service. See “Item 1. Business—Regulation—Regulation of transportation and sales of crude oil” for more information about the regulations relating to the transport of crude oil by rail.

The crude oil business environment has historically been characterized by periods when crude oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for NYMEX WTI crude oil. In the past, there have been periods when this discount has substantially increased due to the production of crude oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on crude oil transportation out of the Williston Basin and the Permian Basin and improved basin differentials received at the lease. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Prices” for information about our realized crude oil prices and average price differentials relative to NYMEX WTI for the years ended December 31, 2020, 2019 and 2018.

Additionally, the refining capacity in the U.S. Gulf Coast is insufficient to refine all of the light sweet crude oil being produced in the United States. The United States imports heavy crude oil and exports light crude oil to utilize the U.S. Gulf Coast refineries that have more heavy refining capacity. If light sweet crude oil production remains at current levels or continues to increase, demand for our light crude oil production could result in widening price discounts to the world crude oil prices and potential shut-in or reduction of production due to a lack of sufficient markets despite the lift on prior restrictions on the exporting of crude oil and natural gas from the United States.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 29% of our estimated net proved reserves were classified as proved undeveloped as of December 31, 2020. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, the Oasis Credit Facility and derivative contracts. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

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Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our estimated net proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Our business is subject to operating risks that could result in substantial losses or liability claims, and we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Additionally, certain of our insurance policies also provide coverage to OMP and as a result, a claim by OMP against one of our shared insurance policies may reduce the remaining amount of coverage available to us. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our E&P activities are subject to all of the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:

•environmental hazards, such as natural gas leaks, crude oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas, such as hydrogen sulfide, or other pollutants into the environment;

•abnormally pressured formations;

•shortages of, or delays in, obtaining water for hydraulic fracturing activities;

•mechanical difficulties, such as stuck oilfield drilling and service tools and casing failure;

•personal injuries and death; and

•natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

•injury or loss of life;

•damage to and destruction of property, natural resources and equipment;

•pollution and other environmental damage;

•regulatory investigations and penalties;

•suspension of our operations; and

•repair and remediation costs.

Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Also, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Drilling locations that we decide to drill may not yield crude oil or natural gas in commercially viable quantities.

Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of crude oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators

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in the Williston Basin and the Permian Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our potential drilling location inventories are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our execution strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, crude oil and natural gas prices, costs and drilling results. These levels of uncertainty may be increased with respect to our positions in the Permian Basin acquired in 2018 due to less experience operating in the area. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations. See also “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil and natural gas reserves.”

Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

As of December 31, 2020, approximately 98% and 74% of our total net acreage in the Williston Basin and the Permian Basin, respectively, was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. In the Williston Basin, our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. In the Permian Basin, our acreage must be drilled before lease or term assignment expiration and, in some leases, must be further perpetuated via additional drilling activity to satisfy continuous drilling and development provisions, including under the CDA. Additionally, certain leases and term assignments in the Permian Basin require development at various depths in order to perpetuate our ownership as to those depths. If we fail to meet certain drilling and development obligations under the CDA, the CDA may be subject to early termination, in which case, we would lose rights to certain non-productive acreage and depths and may be obligated to pay non-performance fees of up to approximately $100 million. As of December 31, 2020, we had an aggregate of 6,648 net acres expiring in 2021, 1,121 net acres expiring in 2022 and 167 net acres expiring in 2023 in the Williston and Permian Basins. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. During the years ended December 31, 2020, 2019 and 2018, the Predecessor recorded non-cash impairment charges of $401.1 million, $5.4 million and $0.9 million, respectively, on our unproved properties due to expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of our unproved properties. Due to the extraordinary market conditions during 2020, we agreed with University Lands to pause operations, and on December 31, 2020, we executed an amendment to the CDA reflecting that agreement. The amendment reduced or postponed certain drilling and development obligations for the year ended December 31, 2020 and did not result in the payment of any penalty. Our current budget contemplates drilling activity which does not meet certain obligations under the CDA. We are currently in discussions with University Lands similar to those held in 2020, in which we will seek an amendment for the reduction of our drilling obligations for 2021 similar to that previously received. We can provide no assurance that we will be successful in obtaining this amendment. Given the early stages of our discussions with University Lands on our drilling obligations for 2021 and the continuous flexibility we have with our drilling program to adjust as market and business conditions warrant, we cannot predict whether we will incur losses or estimate the amount of any potential loss.

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Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.

Our crude oil and natural gas E&P operations, midstream operations and related operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety aspects, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations and services. The trend of more expansive and stringent environmental and occupational health and safety legislation and regulations applied to the oil and gas industry could continue, resulting in material increases in our costs of doing business and consequently affecting profitability. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these environmental and occupational health and safety matters. Compliance with existing environmental and occupational safety and health laws, regulations, executive orders and other regulatory initiatives, or any other such new legal requirements, could, among other things, require us or our customers to install new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly increased capital or operating expenditures, which costs may be significant. One or more of these developments that impact us or our customers could have a material adverse effect on our business, results of operations and financial condition and reduce demand for our midstream services.

Failure to comply with federal, state and local laws and regulations could adversely affect our ability to produce, gather and transport our crude oil and natural gas and may result in substantial penalties.

Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the regulation of crude oil and natural gas production and transportation. These laws and regulations include regulation of crude oil and natural gas exploration and production and related operations, including a variety of activities related to the drilling of wells, and the interstate transportation of crude oil and natural gas by federal agencies such as FERC, as well as state agencies. We may incur substantial costs in order to maintain compliance with these laws and regulations. Due to recent incidents involving the release of crude oil and natural gas and fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state levels to restrict crude oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of crude oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arise out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on our business, financial condition and results of operations. With regard to our physical purchases and sales of energy commodities, we must also comply with anti-market manipulation laws and related regulations enforced by FERC, the CFTC and the FTC. To the lesser extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate capacity. Should we fail to comply with all applicable statutes, rules, regulations and orders of FERC, the CFTC or the FTC, we could be subject to substantial penalties and fines.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.

The threat of climate change continues to attract considerable attention in the United States and foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to eliminate such future emissions. As a result, our operations as well as the operations of our midstream customers are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on the threat of climate change and restriction of GHG emissions. The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas industry or otherwise restrict the areas in which this industry may produce crude oil and natural gas or generate GHG emissions could result in increased compliance costs or costs of consuming fossil fuels. Such legislation, executive actions or regulations could result in increased costs of our or our customers’ compliance or costs of consuming, and thereby reduce demand for crude oil and natural gas, which could reduce demand for our midstream services. Additionally, political, financial and litigation risks may result in us or our customers restricting, delaying or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the ability to continue to operate in an economic manner, which also could reduce demand for our midstream and services. The occurrence of one or more of these developments could have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal and biofuels) could reduce demand for hydrocarbons, and therefore for our products and services, which would lead to a reduction in our revenues.

Increasing attention and federal actions in regards to ESG matters may impact our business.

Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. Companies which do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or which are

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perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our hydrocarbon products and midstream services, reduced profits, increased governmental investigations and private litigation against us, and negative impacts on our stock price and access to capital markets.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of our common stock from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of us by certain investors.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations. The process involves the injection of water, sand or other proppant and chemical additives under pressure into the targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing continues to be controversial in certain parts of the country, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal and state agencies and local municipalities. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these hydraulic fracturing matters. The adoption of any federal, state or local laws or the implementation of regulations or issuance of executive orders restricting hydraulic fracturing activities or locations or suspending or delaying the performance of hydraulic fracturing on federal properties or other locations could potentially result in an increase in our and our customers’ compliance costs, a decrease in the completion of our or our customers’ new crude oil and natural gas wells, and a decrease in demand for our midstream services, which could have a material adverse effect on our liquidity, results of operations, and financial condition. Restrictions, delays or bans on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we or our customers are ultimately able to produce in commercial quantities, which adversely impacts our revenues and profitability.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Water is an essential component of shale crude oil and natural gas production during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third-party businesses with more senior contractual or permitting rights to the water. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our E&P operations or midstream services and have a corresponding adverse effect on our business, financial condition and results of operations. Additionally, operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the UIC program established under the SDWA. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on seismicity matters. Compliance with current and future environmental laws, executive orders, regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing activities, the injection of waste streams into disposal wells, or any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our or our customers’ flowback and produced water on economic terms may increase our or our customers’ operating costs and cause delays, interruptions or termination of our or our customers’ operations, the extent of which cannot be predicted but that could be materially adverse to our business and results of operations.

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Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls, substantial changes to existing integrity management programs or more stringent enforcement of applicable legal requirements could subject us to increased capital and operating costs and operational delays.

Certain of our pipelines are subject to regulation by PHMSA under the HLPSA with respect to crude oil and condensate and the NGPSA with respect to natural gas. Those pipeline systems are required to maintain compliance with applicable pipeline integrity management programs. Additionally, those pipeline systems are subject to pipeline safety requirements that may impose more stringent safety obligations, require installation of new or modified safety controls, or perform capital or operating projects on an accelerated basis. New legislation or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. See “Item 1. Business—Regulation—Pipeline safety regulation” for more discussion on pipeline safety matters. Our compliance with these applicable PHMSA pipeline safety requirements could have a material adverse effect on our operations, financial position, cash flows and our ability to maintain current distribution levels to the unitholders of OMP to the extent the increased costs are not recoverable through rates.

We do not own all of the land on which our pipelines and associated facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and associated facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Additionally, the federal Tenth Circuit Court of Appeals has held that tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position and ability to make cash distributions to the unitholders of OMP.

Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, market crude oil and natural gas and secure equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. Further, the COVID-19 pandemic that began in early 2020 provides an illustrative example of how a pandemic or epidemic can also impact our operations and business by affecting the health of these qualified or trained personnel and rendering them unable to work or travel. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining qualified personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect our operations.

To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our operations. The public health concerns posed by COVID-19 could pose a risk to our personnel and may render our personnel unable to work or travel. The extent to which COVID-19 may impact our personnel, and subsequently our business, cannot be predicted at this time. We continue to monitor the situation, have actively implemented policies and practices to address the situation, and may adjust our current policies and practices as more information and guidance become available. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

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Seasonal weather conditions adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Our crude oil and natural gas operations are adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other crude oil and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability to operate during such conditions. Results of operations in the Permian Basin may also be negatively affected by inclement weather during the winter months to a lesser extent. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs.

We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting crude oil and natural gas prices and future development, production and marketing costs, and the integration of significant acquisitions may be difficult.

We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

•recoverable reserves;

•future crude oil and natural gas prices and their appropriate differentials;

•development and operating costs;

•potential for future drilling and production;

•validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and

•potential environmental and other liabilities, together with associated litigation of such matters.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis. Indemnification from the sellers will generally be effective only during a limited time period after the closing and subject to certain dollar limitations and minimums. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.

Significant acquisitions and other strategic transactions may involve other risks, including:

•diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

•the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

•difficulty associated with coordinating geographically separate organizations;

•an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and

•the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. The success of an acquisition will depend, in part, on our ability to realize anticipated opportunities from combining the acquired assets or operations with those of ours. Even if we successfully integrate the assets acquired, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, in oil and gas industry conditions, by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure

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to retain key personnel, an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may be adversely affected.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring crude oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of crude oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of a crude oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in the title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Disputes or uncertainties may arise in relation to our royalty obligations.

Our production is subject to royalty obligations which may be prescribed by government regulation or by contract. These royalty obligations may be subject to changes in interpretation as business circumstances change and the law in jurisdictions in which we operate continues to evolve. For example, in 2019, the Supreme Court of North Dakota issued an opinion indicating a change in its interpretation of how certain gas royalty payments are calculated under North Dakota law with respect to certain state leases, which may require us to make additional royalty payments and reduce our revenues. Such changes in interpretation could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, such changes in interpretation could result in legal or other proceedings. Please see “We are from time to time involved in legal, governmental and regulatory proceedings that could result in substantial liabilities” for a discussion of risks related to such proceedings.

Risks related to our financial position

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned operating results.

Our revolving credit facilities contain operating and financial restrictions that may restrict our business and financing activities.

Our revolving credit facilities, including the Oasis Credit Facility and the OMP Credit Facility, contain a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

•sell assets, including equity interests in our subsidiaries;

•pay distributions on, redeem or repurchase our common stock or redeem or repurchase our debt;

•make investments;

•incur or guarantee additional indebtedness or issue preferred stock;

•create or incur certain liens;

•make certain acquisitions and investments;

•redeem or prepay other debt;

•enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

•consolidate, merge or transfer all or substantially all of our assets;

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•engage in transactions with affiliates;

•create unrestricted subsidiaries;

•enter into sale and leaseback transactions; and

•engage in certain business activities.

As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of the covenants and restrictions contained in our revolving credit facilities may be affected by events beyond our control. If market or other economic conditions deteriorate or if crude oil, natural gas and NGL prices decline substantially or for an extended period of time from their current levels, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facilities or any future indebtedness could result in an event of default under our revolving credit facilities or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.

If an event of default under either of our revolving credit facilities occurs and remains uncured, the lenders under the applicable Revolving Credit Facility:

•would not be required to lend any additional amounts to us;

•could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

•may have the ability to require us to apply all of our available cash to repay these borrowings; or

•may prevent us from making debt service payments under our other agreements.

Our obligations under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our oil and gas assets, including mortgage liens on oil and gas properties having at least 90% of the reserve value as determined by reserve reports, and if we are unable to repay our indebtedness under the Oasis Credit Facility, the lenders could seek to foreclose on our assets. OMP’s obligations under the OMP Credit Facility are collateralized by mortgages and other security interests on substantially all of OMP’s and its subsidiaries’ properties and assets, including the equity interests in all present and future subsidiaries (subject to certain exceptions). Some or all of the collateral owned by Bobcat DevCo and Beartooth DevCo is subject to an intercreditor agreement between Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent for the OMP Credit Facility, and Wells Fargo as the administrative agent for the Oasis Credit Facility, and acknowledged by Oasis Midstream Services LLC, Bobcat DevCo and Beartooth DevCo. If OMP is unable to repay its indebtedness under the OMP Credit Facility, the lenders could seek to foreclose on OMP’s assets. However, there are no cross-default rights between the Oasis Credit Facility and the OMP Credit Facility. Therefore, an acceleration of the OMP Credit Facility will not trigger automatically an acceleration of the Oasis Credit Facility, and vice versa. Please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our level of indebtedness may increase and reduce our financial flexibility.

As of December 31, 2020 (Successor), we had $260.0 million of outstanding borrowings and $6.8 million of outstanding letters of credit under the Oasis Credit Facility, $450.0 million of outstanding borrowings and a de minimis outstanding letter of credit under the OMP Credit Facility, and an aggregate amount of $433.2 million available for future secured borrowings under the revolving credit facilities. Please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

An increase in our level of indebtedness could affect our operations in several ways, including the following:

•a significant portion of our cash flows could be used to service our indebtedness;

•a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

•the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

•our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

•a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

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•a high level of debt may make it more likely that a reduction in our borrowing base under the Oasis Credit Facility following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

•a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness would increase the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to maintain or reduce our level of indebtedness depends on our future performance. General economic conditions, crude oil, natural gas and NGL prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. If crude oil, natural gas and NGL prices decline substantially or for an extended period of time from their current levels, we may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In addition, the Oasis Credit Facility borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings under the Oasis Credit Facility due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We may not be able to generate enough cash flows to meet our debt obligations.

We expect our earnings and cash flows to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flows may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flows from operations and to pay our debt obligations. Many of these factors, such as crude oil, natural gas and NGL prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. Specifically, the actions of OPEC and other non-OPEC, oil-producing countries, including Russia, have caused substantial increases in the global supply of crude oil which have contributed to sharp declines in crude oil prices in 2020, and therefore negatively affected our ability to generate cash flows from operations. In addition, economic recessions, including those brought on by the COVID-19 pandemic, have a negative effect on the demand for crude oil and natural gas and will and have had a negative effect on our ability to generate cash flows from operations. If we do not generate enough cash flows from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

•selling assets;

•reducing or delaying capital investments;

•seeking to raise additional capital; or

•refinancing or restructuring our debt.

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, and our lenders could compel us to apply all of our available cash to repay our borrowings. If amounts outstanding under our revolving credit facilities were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders. Please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our derivative activities could result in financial losses or could reduce our income.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of crude oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our crude oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

•production is less than the volume covered by the derivative instruments;

•the counterparty to the derivative instrument defaults on its contract obligations; or

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•there is an increase in the differential between the underlying price in the derivative instrument and actual price received.

In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for crude oil and natural gas and may expose us to cash margin requirements.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil and natural gas reserves.

Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of crude oil and natural gas reserves. DeGolyer and MacNaughton projects that we will incur capital costs of $463.3 million over the next five years to develop the proved undeveloped reserves in the Williston and Permian Basins covered by its December 31, 2020 reserve report. Additionally, OMP will continue to invest in midstream assets to support our E&P business segment as well as third-party customers. Please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for more information about our capital expenditures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

We intend to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowings under our revolving credit facilities and cash settlements of derivative contracts; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional debt or equity securities or the sale of non-strategic assets. The issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions or to pay dividends. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under the Oasis Credit Facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities.

Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:

•our estimated net proved reserves;

•the level of crude oil, natural gas and NGLs we are able to produce from existing wells and new projected wells;

•the prices at which our crude oil, natural gas and NGLs are sold;

•the costs of developing and producing our crude oil and natural gas production;

•our ability to acquire, locate and produce new reserves;

•the ability and willingness of our banks to lend; and

•our ability to access the equity and debt capital markets.

If the borrowing base under our Oasis Credit Facility or our revenues decrease as a result of low crude oil, natural gas or NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our Oasis Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.

The inability of one or more of our customers or affiliates to meet their obligations to us may adversely affect our financial results.

Our principal exposures to credit risk are through receivables resulting from the sale of our crude oil and natural gas production ($161.5 million in receivables at December 31, 2020), which we market to energy marketing companies, other producers, power generators, local distribution companies, refineries and affiliates, and joint interest receivables ($31.9 million at December 31, 2020).

We are subject to credit risk due to the concentration of our crude oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the Successor period of November 20, 2020 through December 31, 2020, sales

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to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of our total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of our total product sales. For the year ended December 31, 2019, sales to Phillips 66 Company accounted for approximately 14% of our hydrocarbon product sales. No other purchasers accounted for more than 10% of our total sales in 2020 or 2019. For the year ended December 31, 2018, no purchaser accounted for more than 10% of our total sales. We do not require all of our customers to post collateral. 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.

Joint interest receivables arise from billing entities who own a 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 year ended December 31, 2020, we recorded a credit of $0.2 million for changes in our estimate of expected credit losses.

In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. At December 31, 2020, we had derivatives in place with eight counterparties and a total net derivative liability of $94.1 million.

We may not be able to utilize a portion of our net operating losses (“NOLs”) 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.

As of December 31, 2020, we had significant federal and state income tax NOLs. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. As a result of our emergence from the Chapter 11 Cases and related transactions, our NOLs will be reduced by the amount of discharge of indebtedness income we recognized under Section 108 of the Internal Revenue Code of 1986, as amended (the “Code”). Following such reduction, the federal NOLs are not subject to expiration, however the state NOLs will begin to expire in 2023.

If a corporation experiences an “ownership change,” any NOLs, losses or deductions attributable to a “net unrealized built-in loss” and other tax attributes could be substantially limited, and timing of the usage of such tax attributes could be substantially delayed, under Section 382 of the Code (“Section 382”). 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. As a result of our emergence from the Chapter 11 Cases and related transactions, we experienced an ownership change that subjected certain of our tax attributes, including NOLs, to limitations under Section 382. Determining the limitations under Section 382 is technical and highly complex, and no assurance can be given that upon further analysis our ability to take advantage of our NOLs may be limited to a greater extent than we currently anticipate.

If we are limited in our ability to use our NOLs in future years in which we have taxable income, we will pay more taxes than if we were able to utilize our NOLs fully, which could have a negative impact on our financial position, results of operations and cash flows. Additionally, 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 further limitations being placed on our ability to utilize our federal NOLs, which could adversely affect our financial position, results of operations and cash flows.

The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business.

On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed new regulations to set position limits for certain futures, options and swap contracts in designated physical commodities, including, among others, crude oil and natural gas. The Dodd-Frank Act and CFTC rules have also designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent that we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with the clearing and exchange trading requirements or to take steps to qualify for an exemption to such requirements. In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the non-financial end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the non-financial end-user exception, we could be required

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to post initial or variation margin, which would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows. Other regulations to be promulgated under the Dodd-Frank Act also remain to be finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations.

Risks related to our common stock

Our ability to declare and pay dividends is subject to certain considerations and limitations.

We declared a dividend of $0.375 per share of common stock payable on March 22, 2021 to shareholders of record as of March 8, 2021. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. Certain covenants in the Oasis Credit Facility may limit our ability to pay dividends. We can provide no assurance that we will continue to pay dividends at the current rate or at all.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•advance notice provisions for stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of stockholders; and

•limitations on the ability of our stockholders to call special meetings.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.

The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.

As of the date of filing this report, we have outstanding Warrants (as defined in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Emergence from voluntary reorganization under Chapter 11”) to purchase approximately 1.6 million shares of our common stock at an initial exercise price of $94.57. In addition, as of December 31, 2020, approximately 2.4 million shares of our common stock were reserved for future issuance under the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”). The exercise of equity awards, including any stock options that we may grant in the future, the Warrants, and the sale of shares of our common stock underlying any such options or Warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares.

There is a limited trading market for our common stock and the market price of our common stock is subject to volatility.

Upon our emergence from bankruptcy, our Predecessor common stock was cancelled, and we issued new common stock. Since the Emergence Date, liquidity for our common shares has been below historical levels, reflecting a concentrated shareholder base, undeveloped market and fewer shares outstanding. The market price of the new common stock could be subject to wide fluctuations in response to, and the level of trading that develops with the new common stock may be affected by, numerous

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factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our new common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results.

General risk factors

We are from time to time involved in legal, governmental and regulatory proceedings that could result in substantial liabilities.

Like other similarly-situated oil and gas companies, we are from time to time involved in various legal, governmental and regulatory proceedings in the ordinary course of business including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. The outcome of such matters often cannot be predicted with certainty. If our efforts to defend ourselves in legal, governmental and regulatory matters are not successful, it is possible the outcome of one or more such proceedings could result in substantial liability, penalties, sanctions, judgments, consent decrees or orders requiring a change in our business practices, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Judgments and estimates to determine accruals related to legal, governmental and regulatory proceedings could change from period to period, and such changes could be material.

Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of our potential customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Also, destructive forms of protests and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against crude oil and natural gas development and production or midstream processing or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our operations. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as crude oil and natural gas pipelines. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber attack could include gaining unauthorized access to digital systems or data for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.

Our technologies, systems, networks and data, and those of our business partners, may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information or other disruption of our business operations. In addition, certain cyber incidents, such as unauthorized surveillance or a cyber breach, may remain undetected for an extended period.

A cyber incident involving our information systems or data and related infrastructure, or that of our business partners, including any vendor or service provider, could disrupt our business plans and negatively impact our operations in the following ways, among others:

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•supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

•delays in delivering or failure to deliver product at the tailgate of our facilities, resulting in a loss of revenues;

•operational disruption resulting in loss of revenues;

•events of non-compliance that could lead to regulatory fines or penalties; and

•business interruptions that could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.

Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Ineffective internal controls could impact our business and financial results.

Our internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed and we could fail to meet our financial reporting obligations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information required by Item 2. is contained in Item 1. Business.

Item 3. Legal Proceedings

See “Part II, Item 8. Financial Statements and Supplementary Data—Note 24—Commitments and Contingencies” and “—Note 2—Emergence from Voluntary Reorganization under Chapter 11,” which are incorporated herein by reference, for a discussion of material legal proceedings.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for Registrant’s Common Equity. Our Predecessor common stock was listed on the Nasdaq under the symbol “OAS” through October 11, 2020. On October 12, 2020, our Predecessor common stock was suspended from trading on the Nasdaq and commenced trading on the OTC Pink Marketplace under the symbol “OASPQ.” On the Emergence Date and pursuant to the Plan, all existing shares of our Predecessor common stock were cancelled and we issued 20,000,000 shares of the Successor’s common stock. Our Successor common stock commenced trading on the Nasdaq on November 20, 2020.

Dividends. We declared a dividend of $0.375 per share of common stock payable as of March 22, 2021 to shareholders of record as of March 8, 2021. We have not paid cash dividends on our common stock in the past, and future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant.

Holders. As of February 22, 2021, the number of record holders of our common stock was six. Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately 2,179 as of February 22, 2021.

On March 5, 2021, the last sale price of our common stock, as reported on the Nasdaq, was $58.68 per share.

Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2020.

Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended December 31, 2020:


Period	Total Number of Shares Exchanged(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
October 1 – October 31, 2020 (Predecessor)	2,674	$	0.20	—	—
November 1 – November 19, 2020 (Predecessor)	851,537	0.12		—	—


November 20 – November 30, 2020 (Successor)	—	—		—	—
December 1 – December 31, 2020 (Successor)	—	—		—	—

__________________

(1)Represent shares that employees surrendered back to us that equaled in value the amount needed to pay payroll tax withholding obligations upon the vesting of equity awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.

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Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.

The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) for the period of November 20, 2020 (the date the Successor’s common stock commenced trading) through December 31, 2020. The comparison was prepared based upon the following assumptions:

1.$100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on November 20, 2020 at the closing price on such date; and

2.Dividends were reinvested.

Item 6. Selected Financial Data

We have early adopted the SEC’s Disclosure Modernization Final Rule, effective February 10, 2021, for Item 301 of Regulation S-K. As such, Item 6. Selected Financial Data has not been provided.

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Item 7. 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 our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this report for an explanation of these types of statements.

For discussion related to changes in financial condition and results of operations for the years ended December 31, 2019 and 2018, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020.

Overview

We are an independent E&P company focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States. OPNA and OP Permian conduct our E&P activities and own our oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Permian Basin, respectively. In addition to our E&P segment, we also operate a midstream business primarily through OMP, a premier gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets in North America. We own a substantial majority of the general partner and a majority of the outstanding units of OMP. We derive significant cash flows from the midstream segment through distributions from our ownership of OMP limited partner units, distributions from the general partner and our retained ownership of equity interests in certain OMP subsidiaries.

Recent Developments

Emergence from voluntary reorganization under Chapter 11

Due to the volatile market environment that drove a severe downturn in crude oil and natural gas prices in early 2020, as well as the unprecedented impact of the COVID-19 pandemic, we evaluated strategic alternatives to reduce our debt, increase financial flexibility and position us for long-term success, and on September 30, 2020, the Debtors filed the Chapter 11 Cases. On November 10, 2020, the Bankruptcy Court confirmed the Plan, and the Debtors emerged from bankruptcy on November 19, 2020.

Although we are no longer a debtor-in-possession, the Debtors operated as debtors-in-possession through the pendency of the Chapter 11 Cases. As such, certain aspects of the Chapter 11 Cases and related matters are described below in order to provide context to our financial condition and results of operations for the period presented.

In accordance with the Plan, the following significant transactions occurred on the Emergence Date:

•Shares of the Predecessor’s common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, we issued (i) 20,000,000 shares of the Successor’s common stock pro rata to holders of the Predecessor’s Notes (as defined below) and (ii) 1,621,622 warrants (the “Warrants”) pro rata to holders of the Predecessor’s common stock. The Warrants are exercisable to purchase one share of the Successor’s common stock per Warrant at an initial exercise price of $94.57 and expire on November 19, 2024.

•All outstanding obligations under the following notes (collectively, the “Notes”) issued by the Predecessor were cancelled: (i) 6.50% senior unsecured notes due 2021; (ii) 6.875% senior unsecured notes due 2022; (iii) 6.875% senior unsecured notes due 2023; (iv) 6.250% senior unsecured notes due 2026; and (v) 2.625% senior unsecured convertible notes due 2023.

•Oasis Petroleum Inc., as parent, OPNA, as borrower, and Wells Fargo, as administrative agent, issuing bank and swingline lender, and the lenders party thereto entered into a reserves-based credit agreement (the “Oasis Credit Facility”) with maximum aggregate commitments in the amount of $1,500.0 million and an initial borrowing base of $575.0 million.

•The Amended and Restated Credit Agreement, dated as of October 16, 2018 (as amended prior to the Emergence Date, the “Predecessor Credit Facility”), by and among the Predecessor, as borrower, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and holders of claims under the Predecessor Credit Facility had such obligations refinanced through the Oasis Credit Facility. Notwithstanding the foregoing, the Specified Default Interest (as defined in “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt”) related to the Predecessor Credit Facility was discharged, released and deemed waived by the lenders.

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•The Senior Secured Superpriority Debtor-in-Possession Credit Agreement, dated as of October 2, 2020 (the “DIP Credit Facility”), by and among the Predecessor, as borrower, our subsidiaries party thereto, as guarantors, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and the holders of claims under the DIP Credit Facility had such obligations refinanced through the Oasis Credit Facility.

•Mirada Claims (as defined in the Plan) were treated in accordance with the Settlement and Mutual Release Agreement dated September 28, 2020 (the “Mirada Settlement Agreement”) with Mirada Energy, LLC and certain related parties (collectively, “Mirada”).

•The holders of other secured claims, other priority claims and general unsecured claims received payment in full in cash upon emergence or through the ordinary course of business after the Emergence Date.

•We adopted the 2020 LTIP effective on the Emergence Date and reserved 2,402,402 shares of our Successor’s common stock for distribution under the 2020 LTIP. No shares were issued under the 2020 LTIP as of the Emergence Date.

In addition, on the Emergence Date, the conditions were satisfied for the waiver, discharge and forgiveness of the OMP Specified Default Interest (as defined in “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt”) related to the revolving credit facility among OMP, as parent, OMP Operating LLC, a subsidiary of OMP, as borrower, Wells Fargo, as administrative agent, and the lenders party thereto (the “OMP Credit Facility”), and payment of the OMP Specified Default Interest was permanently waived by the lenders party to the OMP Credit Facility.

As of the Emergence Date, by operation of and in accordance with the Plan, the Board of Directors consisted of seven members, comprised of our Chief Executive Officer, Thomas B. Nusz, and six new members, Douglas E. Brooks, Samantha Holroyd, John Jacobi, Robert McNally, Cynthia L. Walker and John Lancaster.

Change in Chief Executive Officer

On December 22, 2020, Thomas B. Nusz retired as Chief Executive Officer and as a director of Oasis Petroleum Inc. In light of Mr. Nusz’s retirement, the Board of Directors appointed Douglas E. Brooks to serve as Chief Executive Officer during the period that it conducts a search for a new Chief Executive Officer. Mr. Brooks will continue to serve as Board Chair, in addition to his role as Chief Executive Officer.

Market conditions and COVID-19

On March 13, 2020, the United States declared the COVID-19 pandemic a national emergency, and most states, including Texas, North Dakota and Montana, and many municipalities have declared public health emergencies. Along with these declarations, there have been extraordinary and wide-ranging actions taken by international, federal, state and local public health and governmental authorities to contain and combat the outbreak and spread of COVID-19 in regions across the United States and the world, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. These containment measures, while aiding in the prevention of further outbreak of COVID-19, have resulted in a severe drop in energy demand and general economic activity. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions. We have taken, and continue to take, proactive steps to manage any disruption in our business caused by COVID-19. For instance, even though our operations were not required to close, we were early adopters in employing a work-from-home system and have deployed additional safety protocols at our operating sites in order to keep our employees and contractors safe and to keep our operations running without material disruption.

The rapid and unprecedented decreases in energy demand have impacted certain elements of our distribution channels. We are also experiencing impacts from downstream markets, as certain pipelines no longer have the ability to transport production as refineries reduce activity or exercise force majeure clauses. Additionally, inventory surpluses have overwhelmed U.S. storage capacity, leading to a further strain on the supply chain. We elected to shut in production of certain wells, primarily during the second quarter of 2020, and the constraints on the supply chain could force us to shut in production in the future.

In March 2020, OPEC and non-OPEC, oil-producing countries, including Russia, failed to agree to production cuts which were intended to stabilize and support global crude oil commodity prices. With no agreement in place, certain large international crude oil producers, including Saudi Arabia and Russia, began to deeply discount sales of their crude oil and committed to ramping up production in an attempt to protect, or increase, their global market share. The impact of this increased production was coupled with significant demand declines caused by the global response to COVID-19. These extreme supply and demand dynamics contributed to significant crude oil price declines, which have and will continue to negatively impact U.S. producers, including us. Although in April 2020, OPEC and other non-OPEC oil-producing countries, including Russia, came to an agreement to cut limited amounts of production, we cannot predict future impacts to crude oil production and global economic activities.

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In response to the foregoing market conditions, we suspended our drilling and completion operations in the second quarter of 2020 and significantly reduced our planned capital expenditures for 2020. In addition, as a result of the low commodity price environment coupled with uncertainty related to the continuing economic impact of the COVID-19 pandemic, we reduced our workforce during the second quarter of 2020 to adjust to a lower level of activity and operate in a cost-efficient manner in the current environment.

Dakota Access Pipeline

Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by midstream operators. The impact of pending and future legal proceedings on these systems, pipelines and facilities can affect our ability to market our products and have a negative impact on realized pricing. On July 6, 2020, the operator of DAPL was ordered by a U.S. District court to halt oil flow and empty the pipeline within 30 days while an EIS is completed. On July 15, 2020, the U.S. Court of Appeals for the District of Columbia Circuit issued a temporary administrative stay while the court considers the merits of a longer-term emergency stay order through the appeals process. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit upheld the U.S. District court’s ruling that an EIS is needed and also reaffirmed its earlier decision which allows DAPL to operate through the EIS process. We regularly use DAPL in addition to other outlets to market our crude oil in the Williston Basin to end markets. To mitigate the risks associated with a potential shutdown of DAPL, we have proactively arranged for portions of our Williston Basin crude oil volumes to be sold at alternative outlets at fixed differentials to NYMEX WTI. In the event DAPL were to cease operating, we would anticipate Williston Basin crude oil prices to weaken materially before improving as the market adapts to rail transportation.

Commodity Prices

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

Due to a combination of the foregoing COVID-19 pandemic-related pressures and geopolitical pressures on the global supply and demand balance for crude oil and related products, commodity prices sharply declined in the first half of 2020. While crude oil prices have increased since hitting historic lows in early 2020, prices remain at depressed levels. The commodity price environment is expected to continue to remain depressed for some time based on oversupply, the global economic recession, and uncertainties related to the COVID-19, including the impact new virus strains, the risk of renewed restrictions and the pace of deployment of vaccines. If prices for crude oil, natural gas and NGLs decline or for an extended period of time remain at depressed levels, such commodity price environment could materially and adversely affect our financial position, our results of operations, the quantities of crude oil and natural gas reserves that we can economically produce and our access to capital.

In an effort to improve price realizations from the sale of our crude oil, 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 broad 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. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single crude oil, natural gas or NGL customer would have a material adverse effect on our results of operations or cash flows. Please see “Part I, Item 1. Business—Exploration and Production Operations—Marketing and major customers.”

Our average net realized crude oil prices and average price differentials are shown in the tables below for the periods presented:


	Predecessor												Successor
	2020									Period from October 1, 2020 through November 19, 2020			Period from November 20, 2020 through December 31, 2020
	Q1			Q2			Q3
Average Realized Crude Oil Prices ($/Bbl)(1)	$	43.22		$	24.45		$	38.52		$	37.67		$	43.36
Average Price Differential ($/Bbl)(2)	$	3.19		$	2.90		$	2.44		$	2.07		$	3.16
Average Price Differential Percentage(2)	7		%	11		%	6		%	5		%	7		%

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	2019 (Predecessor)												Year ended December 31, 2019 (Predecessor)
	Q1			Q2			Q3			Q4
Average Realized Crude Oil Prices ($/Bbl)(1)	$	53.52		$	58.87		$	55.12		$	53.66		$	55.27
Average Price Differential ($/Bbl)(2)	$	1.30		$	0.96		$	1.30		$	3.23		$	1.68
Average Price Differential Percentage(2)	2		%	2		%	2		%	6		%	3		%


	2018 (Predecessor)												Year ended December 31, 2018 (Predecessor)
	Q1			Q2			Q3			Q4
Average Realized Crude Oil Prices ($/Bbl)(1)	$	61.75		$	65.82		$	68.33		$	52.01		$	61.84
Average Price Differential ($/Bbl)(2)	$	1.12		$	2.07		$	1.16		$	6.79		$	2.88
Average Price Differential Percentage(2)	2		%	3		%	2		%	12		%	4		%

__________________

(1)Realized crude oil prices do not include the effect of derivative contract settlements.

(2)Price differential reflects the difference between our realized crude oil prices and NYMEX WTI crude oil index prices.

We sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. As of December 31, 2020, 92% of our gross operated crude oil production was connected to gathering systems, which originate at the wellhead and reduce the need to transport barrels by truck from the wellhead. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Expansions of both rail and pipeline facilities in both the Williston and Permian Basins have reduced prior constraints on crude oil takeaway capacity in the areas and improved our price differentials received at the lease.

Expected future commodity prices play a significant role in determining impairment of proved oil and gas properties. As a result of the significant decline in commodity prices in the first quarter of 2020, we recorded impairment charges of $3.8 billion and $637.3 million on our proved oil and gas properties in the Williston Basin and in the Permian Basin, respectively, as of March 31, 2020 (Predecessor). Upon adoption of fresh start accounting, our proved oil and gas properties were recorded at their estimated fair values as of the Emergence Date. NYMEX WTI forward strip prices increased between the Emergence Date and December 31, 2020. However, commodity prices remain volatile, and if expected future commodity prices decline, we may record impairment charges in the future.

Results of Operations

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, most notably, depreciation, depletion and amortization (“DD&A”) and impairment.

Highlights

During the year ended December 31, 2020:

•We emerged from bankruptcy with a best-in-class balance sheet.

•Our production volumes averaged 64,717 Boepd (66.8% oil).

•E&P and other capital expenditures, excluding capitalized interest, were $14.9 million for the period from November 20, 2020 through December 31, 2020 (the “2020 Successor Period”) and $194.6 million for the period from January 1, 2020 through November 19, 2020 (the “2020 Predecessor Period”).

•Lease operating expenses decreased $1.20 per Boe in 2020 from $6.95 per Boe in 2019.

•Reported year-end estimated net proved reserves of 182.5 MMBoe with a Standardized Measure of $948.9 million and PV-10 of $1,115.0 million.

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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 recorded on a gross basis when 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 services (gathering, compression, processing and gas lift supply, as well as sales of residue gas and NGLs related to third-party natural gas purchase arrangements), crude oil services (gathering, terminaling and transportation) and water services (gathering and disposal of produced and flowback water and freshwater distribution). Our other services revenues are derived from equipment rentals, and also included revenues for well completion services and product sales prior to our transition of our well fracturing services from Oasis Well Services LLC (“OWS”), a wholly-owned subsidiary, to a third-party provider during the first quarter of 2020 (the “Well Services Exit”). A portion of our midstream revenues and substantially all of our other services revenues are from services provided to 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.

The following table summarizes our revenues for the periods presented (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year ended December 31,
					2019		2018


Revenues
Crude oil revenues	$	69,075	$	522,812	$	1,261,413	$	1,425,409
Natural gas revenues	17,367		80,773		147,358		164,615
Purchased oil and gas sales	7,227		186,367		408,791		550,344
Midstream revenues	26,031		166,631		212,208		120,504
Other services revenues	215		6,836		41,974		61,075
Total revenues	$	119,915	$	963,419	$	2,071,744	$	2,321,947

Crude oil and natural gas revenues. Crude oil and natural gas revenues decreased $718.7 million, or 51%, from $1,408.8 million during the year ended December 31, 2019. This decrease was attributable to a $438.4 million decrease due to lower crude oil and natural gas sales prices coupled with a $280.2 million decrease due to lower crude oil and natural gas production sold year over year. During the year ended December 31, 2020, our crude oil and natural gas revenues were negatively impacted by recent market conditions, which caused a significant decline in our realized prices for crude oil, natural gas and NGLs. Excluding the effect of derivative settlements, average crude oil sales prices decreased 32%, and average natural gas sales prices, which include the value for natural gas and NGLs, decreased 21% year over year. Due to the depressed commodity price environment in 2020, we reduced our E&P capital expenditures, curtailed flush production on newly completed wells and temporarily shut in certain wells during the second and third quarters of 2020. Average daily production sold decreased by 23,344 Boepd year over year, primarily driven by temporary well shut-ins, partially offset by new well completions. During the year ended December 31, 2020, we completed 20.6 total net wells in the Williston Basin and 14.0 total net wells in the Permian Basin.

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The following table summarizes the changes in production and average realized prices for the periods presented:


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year ended December 31,
					2019
Production data
Williston Basin
Crude oil (MBbls)	1,336		11,858		20,722
Natural gas (MMcf)	4,644		38,844		52,813
Oil equivalents (MBoe)	2,111		18,331		29,524
Average daily production (Boepd)	50,256		56,579		80,889
Permian Basin
Crude oil (MBbls)	257		2,368		2,102
Natural gas (MMcf)	364		3,355		3,093
Oil equivalents (MBoe)	317		2,927		2,618
Average daily production (Boepd)	7,553		9,033		7,172
Total average daily production (Boepd)	57,809		65,612		88,061
Average sales prices
Crude oil (per Bbl)
Average sales price	$	43.36	$	36.75	$	55.27
Effect of derivative settlements(1)	—		11.38		0.62
Average realized price after the effect of derivative settlements(1)	$	43.36	$	48.13	$	55.89
Natural gas (per Mcf)(2)
Average sales price	$	3.47	$	1.91	$	2.64
Effect of derivative settlements(1)	(0.02)		—		0.08
Average realized price after the effect of derivative settlements(1)	$	3.45	$	1.91	$	2.72

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(1)The effect of derivative settlements includes the cash received or paid for the cumulative gains or losses on our commodity derivatives settled in the periods presented, but does not include proceeds from derivative liquidations. 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.

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, decreased $215.2 million in 2020 from $408.8 million for the year ended December 31, 2019, primarily due to lower crude oil volumes purchased and then subsequently sold in the Williston Basin coupled with lower crude oil sales prices, partially offset by an increase in crude oil volumes purchased and then subsequently sold in the Permian Basin.

Midstream revenues. Midstream revenues decreased $19.6 million in 2020 from $212.2 million for the year ended December 31, 2019. This decrease was primarily driven by a $9.5 million decrease due to lower sales related to third-party natural gas purchase agreements driven by lower NGL and residue gas prices during the year ended December 31, 2020 as compared to the year ended December 31, 2019, coupled with a $5.1 million decrease in produced and flowback water gathering and disposal revenues and a $4.0 million decrease in crude oil gathering, terminaling and transportation revenues. The lower midstream revenues for water and crude oil services were primarily attributable to a decrease in production from our E&P business segment year over year.

Other services revenues. Other services revenues decreased by $34.9 million from $42.0 million for the year ended December 31, 2019, which was primarily attributable to a decrease in well completion revenues due to the Well Services Exit in the first quarter of 2020.

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Expenses and other income

The following table summarizes our operating expenses, gain (loss) on sale of properties, other income and expenses, income tax benefit, net income attributable to non-controlling interests and net loss attributable to Oasis for the periods presented (in thousands, except per Boe of production):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year ended December 31,
					2019		2018


Operating expenses
Lease operating expenses	$	17,841	$	118,372	$	223,384	$	193,912
Midstream expenses	10,572		42,987		62,146		32,758
Other services expenses	—		6,658		28,761		41,200
Gathering, processing and transportation expenses	9,124		85,896		128,806		107,193
Purchased oil and gas expenses	7,357		185,893		409,180		553,461
Production taxes	5,938		45,439		112,592		133,696
Depreciation, depletion and amortization	16,094		291,115		787,192		636,296
Exploration expenses	—		2,748		6,658		27,432
Rig termination	—		1,279		384		—
Impairment	—		4,937,143		10,257		384,228
General and administrative expenses	14,224		145,294		123,506		121,346
Litigation settlement	—		22,750		20,000		—
Total operating expenses	81,150		5,885,574		1,912,866		2,231,522
Gain (loss) on sale of properties	11		10,396		(4,455)		28,587
Operating income (loss)	38,776		(4,911,759)		154,423		119,012
Other income (expense)
Net gain (loss) on derivative instruments	(84,615)		233,565		(106,314)		28,457
Interest expense, net of capitalized interest	(3,168)		(181,484)		(176,223)		(159,085)
Gain (loss) on extinguishment of debt	—		83,867		4,312		(13,848)
Reorganization items, net	—		786,831		—		—
Other income	(402)		1,407		440		121
Total other income (expense), net	(88,185)		924,186		(277,785)		(144,355)
Loss before income taxes	(49,409)		(3,987,573)		(123,362)		(25,343)
Income tax benefit	3,447		262,962		32,715		5,843
Net loss including non-controlling interests	(45,962)		(3,724,611)		(90,647)		(19,500)
Less: Net income attributable to non-controlling interests	3,950		(84,283)		37,596		15,796
Net loss attributable to Oasis	$	(49,912)	$	(3,640,328)	$	(128,243)	$	(35,296)
Costs and expenses (per Boe of production)
Lease operating expenses	$	7.35	$	5.57	$	6.95	$	6.44
Gathering, processing and transportation expenses	3.76		4.04		4.01		3.56
Production taxes	2.45		2.14		3.50		4.44

Lease operating expenses. Lease operating expenses decreased $87.2 million in 2020 from $223.4 million for the year ended December 31, 2019. This decrease was primarily due to lower workover expenses and fixed costs driven by lower activity. Lease operating expenses decreased $1.20 per Boe in 2020 from $6.95 per Boe in 2019.

Midstream expenses. Midstream expenses represent costs of product sales related to third-party natural gas purchase arrangements as well as non-affiliated interest owners’ share of operating expenses incurred by our midstream business. The $8.6 million decrease for the year ended December 31, 2020 as compared to the year ended December 31, 2019 was primarily related to a $3.7 million decrease in natural gas operating and maintenance expenses driven by a decrease in our operated Williston Basin production and a $2.6 million decrease in natural gas purchases from third parties due to lower prices,

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coupled with decreases in expenses related to crude oil and water services of $1.1 million and $1.0 million, respectively, as a result of lower activity.

Other services expenses. Other services expenses represent non-affiliated working interest owners’ share of expenses incurred by OWS 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 $22.1 million decrease for the year ended December 31, 2020 as compared to the year ended December 31, 2019 was primarily attributable to a decrease in well completion expenses due to decreased activity as a result of the Well Services Exit in the first quarter of 2020.

Gathering, processing and transportation expenses. GPT expenses decreased $33.8 million year over year, which was attributable to a $20.7 million decrease in natural gas gathering and processing expenses and a $13.1 million decrease in crude oil gathering and transportation expenses, both related to a decrease in our production volumes. Cash GPT expenses, which excludes non-cash valuation adjustments, increased $0.03 per Boe in 2020 from $3.93 for the year ended December 31, 2019. For a definition of Cash GPT and a reconciliation of GPT to Cash GPT, see “Non-GAAP Financial Measures” below.

Purchased oil and gas expenses. Purchased oil and gas expenses, which represent the crude oil purchased primarily to optimize transportation costs, for blending at our crude oil terminal or to cover production shortfalls, decreased $215.9 million from $409.2 million for the year ended December 31, 2019 primarily due to lower crude oil volumes purchased in the Williston Basin, coupled with lower crude oil prices, partially offset by an increase in crude oil volumes purchased in the Permian Basin.

Production taxes. Production taxes decreased $61.2 million in 2020 from $112.6 million for the year ended December 31, 2019, primarily due to the decrease in crude oil and natural gas revenues and production volumes year over year. The production tax rate as a percentage of crude oil and natural gas sales decreased 0.5% year over year from 8.0% in 2019, primarily due to an increase in the proportion of our total production volumes from the Permian Basin, which bear a lower average production tax rate than our production in the Williston Basin.

Depreciation, depletion and amortization. DD&A expense decreased $480.0 million, or 61%, from $787.2 million for the year ended December 31, 2019. This decrease was primarily due to a decrease in DD&A related to oil and gas properties of $482.3 million, of which $282.4 million was due to a lower average unit-of-production rate and $199.9 million was due to the decrease in production volumes year over year. The average unit-of-production DD&A rate decreased $11.92 per Boe, or 50%, in 2020 as compared to 2019 primarily due to the impairment charge recorded by the Predecessor on our proved oil and gas properties in the first quarter of 2020 due to the significant decline in commodity prices. The average unit-of-production DD&A rate for the 2020 Successor Period was $5.25 per Boe, which is based on the estimated fair value of proved oil and gas properties recorded on the Emergence Date under fresh start accounting. The decrease in DD&A for oil and gas properties year over year was offset by an increase in DD&A for other properties of $2.4 million, which was related to additional assets placed into service, coupled with the acceleration of DD&A expense on assets related to mechanical refrigeration units which were decommissioned at our natural gas processing complex in Wild Basin.

Exploration expenses. Exploration expenses decreased $4.0 million in 2020 from $6.7 million for the year ended December 31, 2019. This decrease was primarily due to a $2.9 million decrease in write-off costs related to exploratory well locations that are no longer in our current development plan, coupled with a $0.7 million decrease in geological and geophysical expenses.

Rig termination. As a result of our reducing our capital expenditure program in 2020, we elected to early terminate certain drilling rig contracts in the Permian Basin and the Predecessor recorded rig termination expense of $1.3 million during the 2020 Predecessor Period, as compared to early termination fees of $0.4 million recorded during the year ended December 31, 2019. The Successor has not incurred any rig termination charges.

Impairment. No impairment charges were recorded during the 2020 Successor Period. Impairment expense increased to $4.9 billion for the 2020 Predecessor Period as compared to $10.3 million for the year ended December 31, 2019, 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, during the 2020 Predecessor Period due to the significant decline in commodity prices. No impairment charges on proved oil and gas properties were recorded for the year ended December 31, 2019.

•Unproved oil and gas properties. We recorded impairment losses on our unproved oil and gas properties of $401.1 million and $5.4 million for the 2020 Predecessor Period and the year ended December 31, 2019, respectively, 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. During the 2020 Predecessor Period, 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 for our midstream assets driven by the significant decline in expected future

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commodity prices during the first quarter of 2020. No impairment charges were recorded on our midstream assets for the year ended December 31, 2019.

•Assets held for sale. During the 2020 Predecessor Period and the year ended December 31, 2019, we recorded impairment losses of $1.4 million and $4.4 million, respectively, to adjust the carrying value of certain inventory and equipment held for sale related to the Well Services Exit to the estimated fair value less costs to sell (see “Item 8. Financial Statements and Supplementary Data—Note 13—Assets Held for Sale”). In addition, we recorded an impairment loss of $14.5 million during the 2020 Predecessor Period related to certain well services equipment previously classified as held for sale that was no longer probable to be sold within one year.

•Inventory. During the 2020 Predecessor Period, we recorded impairment losses of $7.4 million, $1.8 million and $1.4 million to adjust the carrying values of our crude oil inventory, equipment and materials inventory and long-term linefill inventory, respectively, to their net realizable values. During the year ended December 31, 2019, we recorded an impairment loss of $0.5 million to adjust the carrying value of our long-term linefill inventory to its net realizable value.

•Right-of-use asset. During the 2020 Predecessor Period, we recorded an impairment loss of $1.1 million primarily related to the impairment of a right-of-use asset associated with decommissioning leased mechanical refrigeration units at our natural gas processing complex in Wild Basin. No impairment charges were recorded on our right-of-use assets for the year ended December 31, 2019.

General and administrative expenses. Our G&A expenses increased $36.0 million in 2020 from $123.5 million for the year ended December 31, 2019 primarily due to pre-petition restructuring expenses of $34.7 million incurred prior to the Petition Date of the Chapter 11 Cases. G&A expenses included non-cash amortization for equity-based compensation of $31.6 million and $33.6 million in the 2020 Predecessor Period and the year ended December 31, 2019, respectively. All outstanding share-based equity awards vested as of the Emergence Date, and the remaining unrecognized compensation cost for the vested awards was expensed in the 2020 Predecessor Period. In the 2020 Successor Period, G&A expenses included $0.3 million of non-cash equity-based compensation expenses primarily related to OMP GP Class B units and OMP restricted unit awards (see “Item 8. Financial Statements and Supplementary Data—Note 18—Equity-Based Compensation”). E&P Cash G&A expenses, which excludes non-cash equity-based compensation expenses, other non-cash charges and G&A expenses attributable to midstream and other services, increased $2.40 per Boe in 2020 from $2.07 per Boe for the year ended December 31, 2019. For a definition of E&P Cash G&A and a reconciliation of G&A to E&P Cash G&A, see “Non-GAAP Financial Measures” below.

Litigation settlement. During the year ended December 31, 2019, we recorded a $20.0 million loss contingency accrual, which represented our estimate of the probable amount that would be incurred from our legal proceedings with Mirada based upon available information at that time. On September 28, 2020, we entered into the Mirada Settlement Agreement, which provides for, among other things, payment of $42.8 million to certain Mirada related parties and the release of all claims asserted in the case Mirada filed against us. We recorded the incremental $22.8 million loss accrual for the settlement during the 2020 Predecessor Period. See “Item 8. Financial Statements and Supplementary Data—Note 24—Commitments and Contingencies” for more information about our legal proceedings.

Gain (loss) on sale of properties. For the 2020 Predecessor Period, we recognized a $10.4 million net gain on sale of properties, primarily related to certain oil and gas properties located in the Williston Basin. For the year ended December 31, 2019, we recognized a $4.5 million net loss primarily due to completing the final closing statements for the 2018 divestitures of non-strategic oil and gas properties and certain other property and equipment in the Williston Basin (see “Item 8. Financial Statements and Supplementary Data—Note 12—Acquisitions and Divestitures”).

Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip commodity price changes, we recognize gains or losses on our derivative instruments for the change in their fair value during the period. During the 2020 Successor Period, we recognized an $84.6 million loss on derivative instruments, including net cash settlement payments of $0.1 million, for the decrease in the fair value of our derivative contracts as a result of an increase in forward commodity prices during the period. During the 2020 Predecessor Period, we recognized a $233.6 million gain on derivative instruments, including net cash settlement receipts of $224.4 million, of which $62.6 million was received for derivative contracts liquidated prior to their maturities (see “Item 8. Financial Statements and Supplementary Data—Note 10—Derivative Instruments”). For the year ended December 31, 2019, we recognized a $106.3 million net loss on derivative instruments, including net cash settlement receipts of $19.1 million.

Interest expense, net of capitalized interest. Interest expense increased $8.4 million from $176.2 million for the year ended December 31, 2019 primarily due to Specified Default Interest and OMP Specified Default Interest of $30.3 million and $28.0 million, respectively, which were recorded in interest expense during the 2020 Predecessor Period, and subsequently waived on the Emergence Date, the discharge of which was recognized in reorganization items, net during the 2020 Predecessor Period (see “Item 8. Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting” and “—Note 15—Long-Term

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Debt” for more information). This increase was coupled with a $5.4 million decrease in capitalized interest due to lower work in progress activity, and was offset by a $44.8 million decrease in interest expense related to the Predecessor’s Notes due to repurchases of Notes in the first quarter of 2020 as well as the cancellation of the remaining outstanding Notes pursuant to the Plan. In addition, interest expense related to revolving credit facilities, excluding default interest charges, decreased $9.3 million primarily due to lower weighted average borrowings outstanding year over year.

Gain (loss) on extinguishment of debt. During the 2020 Predecessor Period, we repurchased an aggregate principal amount of $156.8 million of our outstanding Notes for an aggregate cost of $68.0 million, including fees. As a result, we recognized a pre-tax gain in the 2020 Predecessor Period of $83.9 million, which included write-offs of unamortized debt discount of $4.2 million, unamortized deferred financing costs of $1.0 million and the equity component of the senior unsecured convertible notes of $0.3 million. During the year ended December 31, 2019, we repurchased an aggregate principal amount of $56.8 million of our outstanding Notes for an aggregate cost of $45.8 million and recognized a pre-tax gain related to the repurchases of $4.3 million, which included the write-off of unamortized deferred financing costs and unamortized debt discount of $6.7 million.

Reorganization items, net. During the 2020 Predecessor Period, we recorded $786.8 million of reorganization items related to the Chapter 11 Cases, consisting of (i) gains on settlement of obligations under our Notes upon consummation of the Plan, (ii) fresh start accounting fair value adjustments, (iii) professional fees recognized between the Petition Date and the Emergence Date, (iv) the write-off of unamortized deferred financing costs and unamortized debt discount and (v) DIP Credit Facility fees. See “Item 8. Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting” for more information on amounts recorded to reorganization items, net.

Income tax benefit. Our income tax benefit for the 2020 Successor Period and 2020 Predecessor Period was recorded at 7.0% and 6.6%, respectively. These rates were significantly lower than the statutory rate primarily due to the impacts of recording a valuation allowance against our net deferred tax assets, as well as the impacts of discharge of debt and other reorganization items, partially offset by state income taxes. Our income tax benefit for the year ended December 31, 2019 was recorded at 26.5% of pre-tax loss. Our effective tax rates for the 2020 Successor Period and the 2020 Predecessor Period were significantly lower than the effective tax rate for the year ended December 31, 2019 primarily due to (i) the impacts of recording a valuation allowance against our net deferred tax assets during 2020, (ii) the impact of discharge of debt and other reorganization items recorded during 2020 and (iii) the impacts of non-controlling interests.

Liquidity and Capital Resources

For the 2020 Successor Period, our primary sources of liquidity have been cash flows from operations, and our primary uses of cash have been for net principal payments under the Oasis Credit Facility and the development of oil and gas properties. For the 2020 Predecessor Period, our primary sources of liquidity have been derivative settlements (including derivative contract liquidations), cash flows from operations and proceeds from sales of properties, and our primary uses of cash have been for the development of oil and gas properties and midstream infrastructure, debt repurchases and distributions to non-controlling interests.

We are committed to our rigorous capital discipline strategy and intend to invest well within our cash flows from operations and cash settlements of derivative contracts. As a result of the Chapter 11 restructuring, we strengthened our balance sheet, reducing our total indebtedness by $1.8 billion by issuing equity in a reorganized entity to the holders of our Notes. We believe our strong balance sheet will allow us to generate significant free cash flow and corporate-level returns.

Our cash flows depend on many factors, including the price of crude oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in crude oil and natural gas prices on a portion of our production, thereby mitigating our exposure to crude oil and natural gas price declines, but these transactions may also limit our cash flow in periods of rising crude oil and natural gas prices. As of December 31, 2020, our derivative contracts in place cover 22.7 MMBbls of our crude oil production in 2021 through 2024. For additional information on the impact of changing prices and our derivative arrangements on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk as well as “Part I, Item 1A. Risk Factors”.”

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations under our revolving credit facilities, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and operating and finance lease obligations. 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

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deficiency payments under these contracts. The estimable future commitments under these agreements were approximately $525.0 million as of December 31, 2020.

We believe we have adequate liquidity to fund our capital expenditures and to meet our obligations during the next 12 months and the foreseeable future. As of December 31, 2020, we had $449.0 million of liquidity available, including $15.9 million in cash and cash equivalents and $433.2 million of aggregate unused borrowing capacity available under the Oasis Credit Facility and the OMP Credit Facility.

Senior secured revolving line of credit. On the Emergence Date, we entered into the Oasis Credit Facility, which has an overall senior secured line of credit of $1,500.0 million and an aggregate amount of commitments of $575.0 million as of December 31, 2020. The Oasis Credit Facility has a maturity date of May 19, 2024. As of December 31, 2020, we had $260.0 million of borrowings at a weighted average interest rate of 4.3% and $6.8 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $308.2 million. See “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt” for more information.

OMP Operating LLC revolving line of credit. Through our controlling interest in and consolidation of OMP, we include the OMP Credit Facility in our consolidated financial statements. OMP uses this credit facility to fund working capital and to finance acquisitions and other capital expenditures specifically attributable to OMP. As of December 31, 2020, the OMP Credit Facility has an aggregate amount of commitments of $575.0 million and has a maturity date of September 25, 2022. As of December 31, 2020, OMP had $450.0 million of borrowings outstanding at a weighted average interest rate of 2.2% and a de minimis outstanding letter of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $125.0 million. See “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt” for more information.

Senior unsecured notes and senior unsecured convertible notes. Upon emergence from the Chapter 11 Cases on November 19, 2020, we issued 20,000,000 shares of the Successor’s common stock to the holders of the Predecessor’s Notes in settlement of the outstanding principal and related accrued interest. Upon such settlement, we no longer have any Notes outstanding. See “Item 8. Financial Statements and Supplementary Data—Note 2—Emergence from Voluntary Reorganization under Chapter 11” and “—Note 15—Long-Term Debt” for more information.

Cash flows

The following table summarizes our change in cash flows (in thousands):


	Successor		Predecessor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year ended December 31,
					2019		2018

Net cash provided by operating activities	$	95,255	$	202,936	$	892,853	$	996,421
Net cash used in investing activities	(9,881)		(92,403)		(828,756)		(1,613,536)
Net cash provided by (used in) financing activities	(85,702)		(109,998)		(66,268)		622,585
Net change in cash and cash equivalents	$	(328)	$	535	$	(2,171)	$	5,470

Cash flows provided by operating activities

Net cash provided by operating activities decreased from the year ended December 31, 2019 primarily due to lower realized commodity prices and production volumes, coupled with higher G&A expenses. 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 our exploratory and development initiatives and the impact of our outstanding derivative instruments. We had a working capital deficit of $69.6 million and $165.5 million at December 31, 2020 (Successor) and December 31, 2019 (Predecessor), respectively. However, we believe we have adequate liquidity to meet our working capital requirements. Our working capital deficit decreased year over year due to decreases in accrued liabilities for capital expenditures and crude oil and natural gas purchases, partially offset by a decrease in accounts receivable and an increase in the net liability related to our short-term derivative instruments.

Cash flows used in investing activities

Net cash used in investing activities decreased from the year ended December 31, 2019 due to a decrease in cash capital expenditures primarily for drilling and development costs, coupled with an increase in derivative settlements received as a result of lower commodity prices and liquidated derivative contracts.

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Cash flows provided by (used in) financing activities

Net cash used in financing activities increased from the year ended December 31, 2019 due to an increase in net principal payments on our revolving credit facilities coupled with an increase in repurchases of our Predecessor Notes prior to the Chapter 11 Cases. In addition, we capitalized costs incurred in connection with obtaining the Oasis Credit Facility, resulting in an increase in deferred financing costs year over year.

Capital expenditures

Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table (in thousands):


	Successor		Predecessor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year ended December 31,
					2019		2018

Capital expenditures
E&P	$	14,839	$	194,004	$	594,217	$	942,179
Other capital expenditures(1)	179		7,071		15,760		31,778
Capital expenditures before acquisitions and midstream	15,018		201,075		609,977		973,957
Midstream(2)	3,054		24,266		212,381		277,626
Total capital expenditures before acquisitions	18,072		225,341		822,358		1,251,583
Acquisitions	—		—		21,010		951,870
Total capital expenditures(3)	$	18,072	$	225,341	$	843,368	$	2,203,453

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(1)Other capital expenditures includes administrative capital and capitalized interest.

(2)Midstream capital expenditures attributable to OMP were $1.8 million for the 2020 Successor Period, $17.5 million for the 2020 Predecessor Period, and $198.6 million and $116.6 million for the years ended December 31, 2019 and 2018, respectively.

(3)Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our 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. In addition, for the year ended December 31, 2018, total capital expenditures (including acquisitions) reflected in the table includes consideration paid through the issuance of common stock in connection with the 2018 Permian Acquisition (see “Item 8. Financial Statements and Supplementary Data—Note 12—Acquisitions and Divestitures”).

In 2020, our capital expenditures decreased 71% as compared to the $843.4 million spent during 2019. Given the low commodity price environment in early 2020, our E&P segment moved from a four-rig development program to suspending our drilling and completions operations in the Williston and Permian Basins in April 2020. During the fourth quarter of 2020, we operated one drilling rig in the Williston Basin. As a result, drilling and completion activity decreased $385.4 million year over year. In addition, midstream capital expenditures decreased $185.1 million primarily due to a decrease in gathering infrastructure capital expenditures.

Our planned 2021 capital expenditures are as follows:


			Plan for the year ended December 31, 2021(1)

			(In millions)
E&P and other capital(2)			$225 - $235
Midstream capital			63 - 68
Total capital expenditures			288 - 303
Less: Midstream capital funded by OMP			(56 - 60)

Total capital expenditures attributable to Oasis			$231 - $243

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(1)Totals may not calculate precisely due to rounding.

(2)E&P and other capital expenditures includes administrative capital and excludes capitalized interest of approximately $6 million.

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In 2021, we are planning to complete approximately 23 to 25 gross operated wells in the Williston Basin and 6 to 8 gross operated wells in the Permian Basin, with a focus on rigorous capital discipline and generating free cash flow.

While we have planned approximately $231 million to $243 million for total capital expenditures attributable to Oasis in 2021, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Our capital plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If crude oil prices decline substantially or for an extended period of time, we could defer a significant portion of our planned capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Furthermore, we actively review acquisition opportunities on an ongoing basis. If we acquire additional acreage, our capital expenditures may be higher than planned. However, our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

We believe that cash on hand, cash flows from operating activities, including cash settlement receipts or payments under our derivative contracts, and availability under our revolving credit facilities should be sufficient to fund our 2021 capital expenditure plan and to meet our future obligations. However, because the operated wells funded by our 2021 drilling plan represent only a small percentage of our potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drilling locations should we elect to do so.

Dividends

We declared a dividend of $0.375 per share of common stock payable as of March 22, 2021 to shareholders of record as of March 8, 2021. We have not paid cash dividends on our common stock in the past, and future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant.

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our audited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments used in preparation of our consolidated financial statements below. See “Item 8. Financial Statements and Supplementary Data—Note 4—Summary of Significant Accounting Policies” for a discussion of additional accounting policies and estimates made by management as well as the expected impact of recent accounting pronouncements on our consolidated financial statements.

Fresh start accounting

At the Emergence Date, we were required to adopt fresh start accounting in accordance with ASC 852 as (i) the holders of existing voting shares of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of our assets immediately prior to confirmation of the Plan was less than the total of post-petition liabilities and allowed claims. The adoption of fresh start accounting resulted in a new basis of accounting and us becoming a new entity for financial reporting purposes. We allocated our reorganization value to our individual assets and liabilities based on their fair values (except for deferred income taxes) in conformity with Accounting Standards Codification 805, Business Combinations. Deferred income tax amounts were determined in accordance with Accounting Standards Codification 740, Income Taxes (“ASC 740”). As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor. See “Item 8. Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting” for further details, including significant assumptions used to estimate the fair values of our assets and liabilities on the Emergence Date.

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Method of accounting for oil and gas properties

Crude oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value.

The provision for DD&A of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate in which case a gain or loss is recognized currently.

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in our Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Crude oil and natural gas reserve quantities and Standardized Measure of discounted future net cash flows

Our independent reserve engineers and technical staff prepare our estimates of crude oil and natural gas reserves and associated future net revenues. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC’s rules define proved reserves as the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent reserve engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Revenue recognition

We recognize revenue in accordance with Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the

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contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Crude oil, natural gas and NGL revenues from our interests in producing wells are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Substantially all of our crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and our NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for crude oil, natural gas and NGL, we sell the majority of our production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.

Our purchased crude oil and natural gas sales are derived from the sales of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when 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 in accordance with Accounting Standards Codification 845, Nonmonetary Transactions.

Midstream revenues consist of revenues from services provided by our midstream business segment, primarily through OMP, including (i) natural gas gathering, compression, processing and gas lift supply, (ii) crude oil gathering, terminaling and transportation, (iii) produced and flowback water gathering and disposal and (iv) freshwater distribution. Midstream revenues are earned through fee-based arrangements, under which we receive fees for midstream services it provides to customers and recognizes revenue based upon the transaction price at month-end under the right to invoice practical expedient, or through purchase arrangements, under which we take control of the product prior to sale and act as the principal in the transaction, and therefore, recognize revenues and expenses on a gross basis. Other services revenues result from equipment rentals, and prior to the Well Services Exit, well completion services and product sales. Midstream and other services revenues are recognized when services have been performed or related volumes or products have been delivered. A portion of our midstream revenues and substantially all of our other services revenues are from services provided to our operated wells. The revenues related to 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 our Consolidated Statements of Operations.

Impairment of proved properties

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties by field and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to our judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, our estimated undiscounted future cash flows and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.

Impairment of unproved properties

The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.

We recognize impairment expense for unproved properties at the time when the lease term has expired or sooner based on management’s periodic assessments. We consider the following factors in our assessment of the impairment of unproved properties:

•the remaining amount of unexpired term under our leases;

•our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

•our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

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•our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Permian Basin by us or by other operators in areas adjacent to or near our unproved properties.

Impairment of goodwill and intangible assets

Goodwill represents the excess of consideration paid (or with respect to fresh start accounting, the excess of reorganization value) over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of November 30 or more frequently if events or changes in circumstances indicate that the carrying amount might be impaired.

For the purpose of the goodwill impairment test, we first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value of the reporting unit and evaluates whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. Our midstream segment is the reporting unit that carries our goodwill balance as of December 31, 2020. The fair value of the reporting unit is estimated using a combination of an income and market approach. Significant inputs used are subject to management’s judgment and expertise and include, but are not limited to, estimated throughput volumes, estimated fixed and variable operating costs, estimated capital costs, estimated useful life of the asset group and discount rate.

Indefinite lived intangible assets are evaluated for impairment when indicators of impairment are present based on expected future profitability and undiscounted expected cash flows and their contribution to our overall operations. If the carrying value is not recoverable, an impairment charge would be recorded to write down the related intangible asset to its estimated fair value.

Business combinations

We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Asset retirement obligations

We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The asset retirement obligation (“ARO”) represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our Consolidated Statements of Operations.

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Some of our midstream assets, including certain pipelines and our natural gas processing plants, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. We are not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable.

We determine the ARO 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 timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future revisions, which could result in an increase to the existing ARO liability and could ultimately result in a higher potential impact on our operations and cash flows for settlement charges. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Derivatives

We record all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. The significant inputs used to estimate fair value are crude oil and natural gas prices, volatility, skew, discount rate and the contract terms of the derivative instruments. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. We have not designated any derivative instruments as hedges for accounting purposes, and we do not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported under other income (expense) in our Consolidated Statements of Operations. Our cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on our derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in our Consolidated Statements of Cash Flows.

Equity-based compensation

We may grant various types of equity-based awards, including restricted stock awards, restricted stock units, performance share units, phantom units, and other awards under any long-term incentive plan then in effect to employees and non-employee directors. We determine the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. Cash-settled awards are classified as liabilities. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, risk-free interest rates, stock price volatility, initial value, stock price on the date of grant and correlation coefficients.

See “Item 8. Financial Statements and Supplementary Data—Note 18—Equity-Based Compensation” for additional information regarding our equity-based compensation.

Income taxes

Our provision for taxes includes both federal and state income taxes. We record our income taxes in accordance with ASC 740, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain.

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The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

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

Non-GAAP Financial Measures

Cash GPT, E&P Cash G&A, Cash Interest, E&P Cash Interest, Adjusted EBITDA, E&P Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP financial measures should not be considered in isolation or as a substitute for GPT expenses, G&A expenses, interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities, earnings (loss) per share or any other measures prepared under GAAP. Because 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.

Cash GPT

We define Cash GPT as the total GPT expenses less non-cash valuation charges on pipeline imbalances. Cash GPT is not a measure of GPT expenses as determined by GAAP. Management believes that the presentation of Cash GPT provides 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 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 measure of Cash GPT for the periods presented (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
						2019		2018


Gathering, processing and transportation expenses	$	9,124	$	85,896		$	128,806	$	107,193
Pipeline imbalances	189		(1,346)			(2,446)		(4,331)
Cash GPT	$	9,313	$	84,550		$	126,360	$	102,862

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.

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
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018


General and administrative expenses	$	14,224	$	145,294	$	123,506	$	121,346
Equity-based compensation expenses	—		(29,746)		(32,251)		(27,910)
G&A expenses attributable to midstream and other services	(1,989)		(21,791)		(24,805)		(18,864)

E&P Cash G&A	$	12,235	$	93,757	$	66,450	$	74,572

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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 E&P Cash Interest provides 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
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020(1)		Year Ended December 31,
						2019		2018


Interest expense	$	3,168	$	181,484		$	176,223	$	159,085
Capitalized interest	128		6,428			11,964		17,226
Amortization of deferred financing costs	(277)		(7,830)			(8,832)		(7,590)
Amortization of debt discount	—		(8,317)			(12,164)		(11,120)
Cash Interest	3,019		171,765			167,191		157,601
Cash Interest attributable to OMP	(1,024)		(38,996)			(16,673)		(6,688)
E&P Cash Interest	$	1,995	$	132,769		$	150,518	$	150,913

___________________

(1)For the 2020 Predecessor Period, interest expense, Cash Interest and E&P Cash Interest include Specified Default Interest charges of $30.3 million related to the Predecessor Credit Facility. In addition, for the 2020 Predecessor Period, interest expense, Cash Interest and Cash Interest attributable to OMP include OMP Specified Default Interest charges of $28.0 million related to the OMP Credit Facility. The Specified Default Interest and OMP Specified Default Interest were waived upon our emergence from the Chapter 11 Cases.

Adjusted EBITDA

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

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


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
						2019		2018


Net loss including non-controlling interests	$	(45,962)	$	(3,724,611)		$	(90,647)	$	(19,500)
(Gain) loss on sale of properties	(11)		(10,396)			4,455		(28,587)
(Gain) loss on extinguishment of debt	—		(83,867)			(4,312)		13,848
Net (gain) loss on derivative instruments	84,615		(233,565)			106,314		(28,457)
Derivative settlements	(76)		224,416			19,098		(213,528)
Interest expense, net of capitalized interest	3,168		181,484			176,223		159,085
Depreciation, depletion and amortization	16,094		291,115			787,192		636,296
Impairment	—		4,937,143			10,257		384,228
Rig termination	—		1,279			384		—
Exploration expenses	—		2,748			6,658		27,432
Equity-based compensation expenses	270		31,315			33,607		29,273
Litigation settlement	—		22,750			20,000		—
Reorganization items, net	—		(786,831)			—		—
Income tax benefit	(3,447)		(262,962)			(32,715)		(5,843)
Other non-cash adjustments	468		2,324			3,035		4,435
Adjusted EBITDA	55,119		592,342			1,039,549		958,682
Adjusted EBITDA attributable to non-controlling interests	5,430		41,716			51,525		21,703
Adjusted EBITDA attributable to Oasis	$	49,689	$	550,626		$	988,024	$	936,979


Net cash provided by operating activities	$	95,255	$	202,936		$	892,853	$	996,421
Derivative settlements	(76)		224,416			19,098		(213,528)
Interest expense, net of capitalized interest	3,168		181,484			176,223		159,085
Rig termination	—		1,279			384		—
Exploration expenses	—		2,748			6,658		27,432
Deferred financing costs amortization and other	(6,824)		(41,811)			(27,263)		(29,057)
Current tax (benefit) expense	—		(36)			(16)		23
Changes in working capital	(36,872)		(25,953)			(51,423)		13,871
Litigation settlement	—		22,750			20,000		—
Cash paid for reorganization items	—		22,205			—		—
Other non-cash adjustments	468		2,324			3,035		4,435
Adjusted EBITDA	55,119		592,342			1,039,549		958,682
Adjusted EBITDA attributable to non-controlling interests	5,430		41,716			51,525		21,703
Adjusted EBITDA attributable to Oasis	$	49,689	$	550,626		$	988,024	$	936,979

Segment Adjusted EBITDA and E&P Free Cash Flow

We define E&P Free Cash Flow as Adjusted EBITDA for our E&P segment plus distributions to Oasis for our ownership of (i) OMP limited partner units, (ii) a controlling interest in OMP’s general partner, OMP GP, and (iii) retained interests in Bobcat DevCo LLC and Beartooth DevCo LLC (together, the “DevCo Interests”); less E&P Cash Interest, capital expenditures for E&P and other (excluding capitalized interest) and midstream capital expenditures attributable to our 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 E&P business as compared to our peers and our ability to generate cash from our E&P operations and

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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 tables present reconciliations of the GAAP financial measure of income (loss) before income taxes including non-controlling interests to the non-GAAP financial measure of Adjusted EBITDA for our two reportable business segments and to the non-GAAP financial measure of E&P Free Cash Flow for our E&P segment for the periods presented (in thousands):


Exploration and Production(1)
	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018


Loss before income taxes including non-controlling interests	$	(68,499)	$	(4,114,847)	$	(336,706)	$	(157,222)
(Gain) loss on sale of properties	(11)		(10,396)		4,455		(38,188)
(Gain) loss on extinguishment of debt	—		(83,867)		(4,312)		13,848
Net (gain) loss on derivative instruments	84,615		(233,565)		106,314		(28,457)
Derivative settlements	(76)		224,416		19,098		(213,528)
Interest expense, net of capitalized interest	2,145		141,836		159,287		156,742
Depreciation, depletion and amortization	13,789		271,002		771,640		623,133
Impairment	—		4,825,530		10,257		384,228
Exploration expenses	—		2,748		6,658		27,432
Rig termination	—		1,279		384		—
Equity-based compensation expenses	—		29,794		32,755		28,393
Litigation settlement	—		22,750		20,000		—
Reorganization items, net	—		(665,916)		—		—
Other non-cash adjustments	459		3,208		3,035		4,435
Adjusted EBITDA	$	32,422	$	413,972	$	792,865	$	800,816
Distributions to Oasis from OMP and DevCo Interests(2)	7,734		123,057		150,388		160,640
E&P Cash Interest(3)	(1,995)		(132,769)		(150,518)		(150,913)
E&P and other capital expenditures	(15,018)		(201,075)		(630,987)		(1,925,827)


Midstream capital expenditures attributable to DevCo Interests	(1,173)		(6,147)		(14,353)		(148,386)
Capitalized interest	128		6,428		11,964		17,226
E&P Free Cash Flow(3)	$	22,098	$	203,466	$	159,359	$	(1,246,444)

____________________

(1)As a result of our Well Services Exit in the first quarter of 2020, the well services business is no longer a separate reportable segment, and the remaining services performed by OWS are included in the E&P segment. Prior period amounts have been restated to reflect the change in reportable segments.

(2)Represents distributions to Oasis for our ownership of (i) OMP limited partner units, (ii) a controlling interest in OMP’s general partner, OMP GP, and (iii) DevCo Interests.

(3)For the 2020 Predecessor Period, E&P Cash Interest includes the impact of Specified Default Interest charges of $30.3 million related to the Predecessor Credit Facility, which was waived pursuant to the Plan on the Emergence Date. The offsetting discharge of the Specified Default Interest was recorded in reorganization items, net for the 2020 Predecessor Period, and as a result, there is no net impact on E&P Free Cash Flow related to these charges.

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Midstream
	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
						2019		2018

					(In thousands)
Income before income taxes including non-controlling interests	$	19,678	$	136,616		$	224,096	$	141,001
Loss on sale of properties	—		—			—		9,622
Interest expense, net of capitalized interest	1,023		39,648			16,936		2,343
Depreciation, depletion and amortization	4,199		36,670			37,152		29,282
Impairment	—		111,613			—		—

Equity-based compensation expenses	270		1,930			1,744		1,547
Reorganization items, net	—		(76,463)			—		—
Other non-cash adjustments	9		(884)			—		—
Adjusted EBITDA	$	25,179	$	249,130		$	279,928	$	183,795

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

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

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


	Successor			Predecessor
	Period from November 20, 2020 through December 31, 2020			Period from January 1, 2020 through November 19, 2020			Year Ended December 31,
								2019			2018


Net loss attributable to Oasis	$	(49,912)		$	(3,640,328)			$	(128,243)		$	(35,296)
(Gain) loss on sale of properties	(11)			(10,396)				4,455			(28,587)
(Gain) loss on extinguishment of debt	—			(83,867)				(4,312)			13,848
Net (gain) loss on derivative instruments	84,615			(233,565)				106,314			(28,457)
Derivative settlements	(76)			224,416				19,098			(213,528)
Impairment(1)	—			4,910,477				10,257			384,228
Additional interest charges(2)	—			49,206				—			—
Amortization of deferred financing costs(3)	277			7,476				8,832			7,591
Amortization of debt discount	—			8,317				12,164			11,120
Non-cash reorganization items, net(2)	—			(799,942)				—			—
Litigation settlement	—			22,750				20,000			—
Other non-cash adjustments	468			2,324				3,035			4,435
Tax impact(4)	(20,167)			(968,987)				(42,691)			(35,759)


Other tax adjustments(5)	9,168			638,729				—			—
Adjusted Net Income Attributable to Oasis	$	24,362		$	126,610			$	8,909		$	79,595

Diluted loss attributable to Oasis per share	$	(2.50)		$	(11.46)			$	(0.41)		$	(0.11)
Adjustment to diluted weighted average shares outstanding(6)	—			0.02				—			—
(Gain) loss on sale of properties	—			(0.03)				0.01			(0.09)
(Gain) loss on extinguishment of debt	—			(0.26)				(0.01)			0.04
Net (gain) loss on derivative instruments	4.23			(0.73)				0.34			(0.09)
Derivative settlements	—			0.71				0.06			(0.69)
Impairment(1)	—			15.43				0.03			1.24
Additional interest charges(2)	—			0.15				—			—
Amortization of deferred financing costs(3)	0.01			0.02				0.03			0.02
Amortization of debt discount	—			0.03				0.04			0.04
Non-cash reorganization items, net(2)	—			(2.51)				—			—
Litigation settlement	—			0.07				0.06			—
Other non-cash adjustments	0.02			0.01				0.01			0.01
Tax impact(4)	(1.00)			(3.06)				(0.13)			(0.11)


Other tax adjustments(5)	0.46			2.01				—			—
Adjusted Diluted Earnings Attributable to Oasis Per Share	$	1.22		$	0.40			$	0.03		$	0.26

Diluted weighted average shares outstanding(6)	19,991			318,253				315,324			310,860

Effective tax rate applicable to adjustment items(4)	23.7		%	23.7		%		23.7		%	23.7		%

____________________

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(1)For the 2020 Predecessor Period, OMP recorded an impairment expense of $103.4 million which is included in our Consolidated Statements of Operations. The portion of OMP impairment expense attributable to non-controlling interests of $26.7 million is excluded from impairment expense in the table above for the 2020 Predecessor Period.

(2)For the 2020 Predecessor Period, we recorded Specified Default Interest charges of $30.3 million related to the Predecessor Credit Facility and OMP Specified Default Interest charges of $28.0 million related to the OMP Credit Facility. The Specified Default Interest and OMP Specified Default Interest were waived upon our emergence from the Chapter 11 Cases. The offsetting discharge of the Specified Default Interest and OMP Specified Default Interest was recorded in non-cash reorganization items, net for the 2020 Predecessor Period, and as a result, there is no net impact on Adjusted Net Income (Loss) Attributable to Oasis related to these charges. The portion of OMP Specified Default Interest attributable to non-controlling interests of $9.1 million is excluded from additional interest charges and non-cash reorganization items, net in the table for the 2020 Predecessor Period.

(3)The portion of amortization of deferred financing costs attributable to non-controlling interests of $0.4 million is excluded from amortization of deferred financing costs in the table above for the 2020 Predecessor Period.

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

(5)Other tax adjustments include the deferred tax asset valuation allowance and tax impact of non-deductible restructuring fees in the 2020 Predecessor Period. These items are adjusted to reflect the tax impact of the other adjustments using an assumed effective tax rate that excludes their impact.

(6)For the 2020 Predecessor Period, and the years ended December 31, 2019 and 2018, we included the dilutive effect of unvested stock awards of 609,000, 322,000 and 3,379,000, respectively, in computing Adjusted Diluted Earnings Attributable to Oasis Per Share, which were excluded from the GAAP calculation of diluted loss attributable to Oasis per share due to the anti-dilutive effect.

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Item 7A. 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.

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.

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. During 2020, crude oil and NGL prices have weakened to historic lows as a result of the impacts of the actions of Saudi Arabia and Russia and the global COVID-19 pandemic. 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 derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our Consolidated Balance Sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 8. Financial Statements and Supplementary Data—Note 10 — Derivative Instruments” and “—Note 9—Fair Value Measurements” for additional information regarding our commodity derivative contracts.

The fair value of our derivative instruments was a net liability of $94.1 million at December 31, 2020. A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $111.4 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $111.4 million, prior to credit risk adjustments. As further described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” and “—Commodity Prices,” the commodity price environment has been recently depressed due to oversupply and decreasing demand, and we cannot predict future impacts to crude oil production and global economic activity. Please see “Part I, Item 1A. Risk Factors” for more information regarding commodity price risks.

Interest rate risk. At December 31, 2020, we had $260.0 million of borrowings and $6.8 million of outstanding letters of credit issued under the Oasis Credit Facility, which were subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a London interbank offered rate (“LIBOR”) loan (defined in the Oasis Credit Facility as a Eurodollar loan) or a domestic bank prime interest rate loan (defined in the Oasis Credit Facility as an Alternate Based Rate or “ABR” loan). At December 31, 2020, the outstanding borrowings under the Oasis Credit Facility bore interest at LIBOR (including a 1% LIBOR floor) plus a 3.25% margin. The unused borrowing base capacity is subject to a commitment fee of 0.500%.

At December 31, 2020, OMP had $450.0 million of borrowings and a de minimis outstanding letter of credit issued under the OMP Credit Facility, which were subject to varying rates of interest based on (i) OMP’s most recently calculated consolidated total leverage ratio and (ii) whether the loan is a LIBOR loan (defined in the OMP Credit Facility as a Eurodollar loan) or a domestic bank prime interest rate loan (defined in the OMP Credit Facility as an ABR loan). At December 31, 2020, the outstanding borrowings under the OMP Credit Facility bore interest at LIBOR plus a 2.00% margin. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%.

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. Our credit losses on joint interest receivables were immaterial in 2020.

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

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oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.

In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. 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.

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Item 8. Financial Statements and Supplementary Data

Index to Financial Statements


Reports of Independent Registered Public Accounting Firm			82

Consolidated Balance Sheets at December 31, 2020 (Successor) and December 31, 2019 (Predecessor)			87

Consolidated Statements of Operations for the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Years Ended December 31, 2019 and 2018 (Predecessor)			89

Consolidated Statements of Changes in Stockholders’ Equity for the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Years Ended December 31, 2019 and 2018 (Predecessor)			90

Consolidated Statements of Cash Flows for the Period from November 20, 2020 through December 31, 2020 (Successor), the Period from January 1, 2020 through November 19, 2020 (Predecessor) and the Years Ended December 31, 2019 and 2018 (Predecessor)			91

Notes to Consolidated Financial Statements

1. Organization and Operations of the Company			93
2. Emergence from Voluntary Reorganization under Chapter 11			93
3. Fresh Start Accounting			94
4. Summary of Significant Accounting Policies			102
5. Oasis Midstream Partners			112
6. Revenue Recognition			113
7. Inventory			117
8. Additional Balance Sheet Information			117
9. Fair Value Measurements			117
10. Derivative Instruments			120
11. Property, Plant and Equipment			122
12. Acquisitions and Divestitures			123
13. Assets Held for Sale			125
14. Goodwill and Intangible Assets			126
15. Long-Term Debt			127
16. Asset Retirement Obligations			131
17. Income Taxes			132
18. Equity-Based Compensation			134
19. Stockholders' Equity			138
20. Earnings (Loss) Per Share			139
21. Business Segment Information			140
22. Leases			143
23. Significant Concentrations			145
24. Commitments and Contingencies			145
25. Subsequent Events			147
26. Supplemental Oil and Gas Disclosures — Unaudited			147
27. Supplemental Oil and Gas Reserve Information — Unaudited			148
28. Quarterly Financial Data			152

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Oasis Petroleum Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet of Oasis Petroleum Inc. and its subsidiaries (Successor) (the “Company”) as of December 31, 2020, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for the period from November 20, 2020 through December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and the results of its operations and its cash flows for the period from November 20, 2020 through December 31, 2020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the "plan") on November 10, 2020. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before November 19, 2020 and terminates all rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on November 19, 2020 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of November 19, 2020.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's report on internal control over financial reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the

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company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Gas Properties, Net

As described in Notes 4 and 11 to the consolidated financial statements, the Company’s consolidated proved oil and natural gas properties, net balance was $757 million as of December 31, 2020. Depreciation, depletion and amortization (DD&A) expense for the period from November 20, 2020 to December 31, 2020 was $16 million. Oil and natural gas exploration and development activities are accounted for using the successful efforts method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. As disclosed by management, periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. The estimates of oil and natural gas reserves have been developed by the Company’s internal petroleum engineers and independent petroleum engineers (collectively “management’s specialists”).

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserve volumes.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of management’s specialists’ findings.

/s/PricewaterhouseCoopers LLP

Houston, Texas

March 8, 2021

We have served as the Company’s auditor since 2007.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Oasis Petroleum Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Oasis Petroleum Inc. and its subsidiaries (Predecessor) (the “Company”) as of December 31, 2019, and the related consolidated statements of operations, of changes in stockholders' equity and of cash flows for the period from January 1, 2020 through November 19, 2020, and for each of the two years in the period ended December 31, 2019 including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019, and the results of its operations and its cash flows for the period from January 1, 2020 through November 19, 2020, and for each of the two years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

Basis of Accounting

As discussed in Note 2 to the consolidated financial statements, Oasis Petroleum Inc. and certain of its affiliates (the “Debtor Affiliates”) filed petitions on September 30, 2020 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates was substantially consummated on November 19, 2020 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting. This matter is also described in the “Critical Audit Matters” section of our report.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Gas Properties, Net

As described in Notes 3 and 4 to the consolidated financial statements, the Company’s consolidated proved oil and natural gas properties, net balance was $755 million as of November 19, 2020. Depreciation, depletion and amortization (DD&A) expense for the period from January 1, 2020 to November 19, 2020 was $291 million. Oil and natural gas exploration and development activities are accounted for using the successful efforts method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. As disclosed by management, periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and

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of engineering and geological interpretation and judgment. The estimates of oil and natural gas reserves have been developed by the Company’s internal petroleum engineers and independent petroleum engineers (collectively “management’s specialists”).

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of management’s specialists’ findings.

Impairment Assessment of Proved Oil and Natural Gas Properties

As described in Notes 3, 4, and 11 to the consolidated financial statements, the Company’s proved oil and natural gas properties, net balance was $755 million as of November 19, 2020, and impairment expense on proved properties for the period from January 1, 2020 to November 19, 2020 was $4.4 billion. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, management will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include the Company’s estimated undiscounted future cash flows and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

The principal considerations for our determination that performing procedures relating to the impairment assessment of certain proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fair value measurement of proved oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future commodity prices, future production, and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures also included, among others (i) testing management’s process for developing the fair value measurement of proved oil and natural gas properties; (ii) evaluating the appropriateness of the discounted cash flow model; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions used by management related to future commodity prices, future production, and the discount rate. Evaluating the reasonableness of management’s assumptions related to future commodity prices involved comparing the prices against observable market data and evaluating differentials through inspection of the underlying contracts. Professionals with specialized skill and knowledge were used to assist in assessing the appropriateness of the discounted cash flow model and the reasonableness of the discount rate. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net” and the reasonableness of the future production. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of management’s specialists’ findings.

Fresh Start Fair Value Adjustments to Proved Oil and Natural Gas Properties

As described above and in Notes 2 and 3 to the consolidated financial statements, Oasis Petroleum Inc. and its Debtor Affiliates emerged from bankruptcy on November 19, 2020 and the Company adopted fresh start accounting, which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes. Under fresh start accounting,

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reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities. The Company’s reorganization items, net was $787 million for the period from January 1, 2020 through November 19, 2020, which included a fresh start fair value adjustment to property, plant, and equipment of $8,579.7 million, of which a significant portion relates to proved oil and natural gas properties. The fair value of proved oil and natural gas properties was estimated using a discounted cash flow model, which is subject to management’s judgment and expertise and includes, but is not limited to, estimates of proved reserves, future commodity pricing, future production estimates, estimates of operating and development costs and a discount rate.

The principal considerations for our determination that performing procedures relating to the fresh start fair value adjustments to proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fresh start fair value adjustments of proved oil and natural gas properties; (ii) a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future commodity prices, future production, future development costs, and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others (i) evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of underlying data used in the discounted cash flow model; and (iii) evaluating the significant assumptions used by management related to future commodity prices, future production, future development costs, and the discount rate. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of estimates of proved oil and natural gas reserves as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net” and the reasonableness of the future production used in the discounted cash flow model. As a basis for using this work, management’s specialists’ qualifications were understood and the company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of management’s specialists’ findings. Evaluating the reasonableness of management’s assumptions relating to future commodity prices and future development costs involved evaluating whether the assumptions used by management were reasonable considering the current performance of the Company, the consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in assessing the appropriateness of the discounted cash flow model and the reasonableness of the discount rate.

/s/PricewaterhouseCoopers LLP

Houston, Texas

March 8, 2021

We have served as the Company's auditor since 2007.

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Oasis Petroleum Inc.

Consolidated Balance Sheets

(In thousands, except share data)


	Successor		Predecessor
	December 31, 2020		December 31, 2019

ASSETS
Current assets
Cash and cash equivalents	$	15,856	$	20,019
Restricted cash	4,370		—

Accounts receivable, net	206,539		371,181
Inventory	33,929		35,259
Prepaid expenses	9,729		10,011
Derivative instruments	467		535
Other current assets	727		346
Total current assets	271,617		437,351
Property, plant and equipment
Oil and gas properties (successful efforts method)	810,328		9,463,038
Other property and equipment	935,950		1,279,653
Less: accumulated depreciation, depletion, amortization and impairment	(17,491)		(3,764,915)
Total property, plant and equipment, net	1,728,787		6,977,776
Assets held for sale, net	5,500		21,628
Derivative instruments	—		639
Long-term inventory	14,522		13,924
Operating right-of-use assets	6,083		18,497
Intangible assets	43,667		—
Goodwill	70,534		—
Other assets	18,327		29,438
Total assets	$	2,159,037	$	7,499,253
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	3,242	$	17,948
Revenues and production taxes payable	146,497		233,090
Accrued liabilities	126,284		281,079
Accrued interest payable	980		37,388
Derivative instruments	56,944		19,695
Advances from joint interest partners	2,723		4,598
Current operating lease liabilities	2,607		6,182
Other current liabilities	1,954		2,903
Total current liabilities	341,231		602,883
Long-term debt	710,000		2,711,573
Deferred income taxes	984		267,357
Asset retirement obligations	46,363		56,305

Derivative instruments	37,614		120
Operating lease liabilities	2,362		17,915
Other liabilities	7,744		6,019
Total liabilities	1,146,298		3,662,172
Commitments and contingencies (Note 24)

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Stockholders’ equity
Predecessor common stock, $0.01 par value: 900,000,000 shares authorized; 324,198,057 shares issued and 321,231,319 shares outstanding at December 31, 2019	—		3,189
Predecessor treasury stock, at cost: 2,966,738 shares at December 31, 2019	—		(33,881)
Successor common stock, $0.01 par value: 60,000,000 shares authorized; 20,093,017 shares issued and 20,093,017 shares outstanding at December 31, 2020	200		—
Additional paid-in capital	965,654		3,112,384
Retained earnings (accumulated deficit)	(49,912)		554,446
Oasis share of stockholders’ equity	915,942		3,636,138
Non-controlling interests	96,797		200,943
Total stockholders’ equity	1,012,739		3,837,081
Total liabilities and stockholders’ equity	$	2,159,037	$	7,499,253

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

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Oasis Petroleum Inc.

Consolidated Statements of Operations

(In thousands, except per share data)


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018

Revenues
Oil and gas revenues	$	86,442	$	603,585	$	1,408,771	$	1,590,024
Purchased oil and gas sales	7,227		186,367		408,791		550,344
Midstream revenues	26,031		166,631		212,208		120,504
Other services revenues	215		6,836		41,974		61,075
Total revenues	119,915		963,419		2,071,744		2,321,947
Operating expenses
Lease operating expenses	17,841		118,372		223,384		193,912
Midstream expenses	10,572		42,987		62,146		32,758
Other services expenses	—		6,658		28,761		41,200
Gathering, processing and transportation expenses	9,124		85,896		128,806		107,193
Purchased oil and gas expenses	7,357		185,893		409,180		553,461
Production taxes	5,938		45,439		112,592		133,696
Depreciation, depletion and amortization	16,094		291,115		787,192		636,296
Exploration expenses	—		2,748		6,658		27,432
Rig termination	—		1,279		384		—
Impairment	—		4,937,143		10,257		384,228
General and administrative expenses	14,224		145,294		123,506		121,346
Litigation settlement	—		22,750		20,000		—
Total operating expenses	81,150		5,885,574		1,912,866		2,231,522
Gain (loss) on sale of properties	11		10,396		(4,455)		28,587
Operating income (loss)	38,776		(4,911,759)		154,423		119,012
Other income (expense)
Net gain (loss) on derivative instruments	(84,615)		233,565		(106,314)		28,457
Interest expense, net of capitalized interest	(3,168)		(181,484)		(176,223)		(159,085)
Gain (loss) on extinguishment of debt	—		83,867		4,312		(13,848)
Reorganization items, net	—		786,831		—		—
Other income (expense)	(402)		1,407		440		121
Total other income (expense), net	(88,185)		924,186		(277,785)		(144,355)
Loss before income taxes	(49,409)		(3,987,573)		(123,362)		(25,343)
Income tax benefit	3,447		262,962		32,715		5,843
Net loss including non-controlling interests	(45,962)		(3,724,611)		(90,647)		(19,500)
Less: Net income (loss) attributable to non-controlling interests	3,950		(84,283)		37,596		15,796
Net loss attributable to Oasis	$	(49,912)	$	(3,640,328)	$	(128,243)	$	(35,296)
Loss attributable to Oasis per share:
Basic (Note 20)	$	(2.50)	$	(11.46)	$	(0.41)	$	(0.11)
Diluted (Note 20)	(2.50)		(11.46)		(0.41)		(0.11)
Weighted average shares outstanding:
Basic (Note 20)	19,991		317,644		315,002		307,480
Diluted (Note 20)	19,991		317,644		315,002		307,480

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

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Oasis Petroleum Inc.

Consolidated Statements of Changes in Stockholders’ Equity


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

	(In thousands)
Balance as of December 31, 2017 (Predecessor)	269,295	$	2,668	1,332	$	(22,179)	$	2,677,217	$	717,985	$	137,888	$	3,513,579
Permian Basin Acquisition issuance	46,000	460		—	—		370,760		—		—		371,220

Equity-based compensation	3,842	29		—	—		30,659		—		356		31,044
Issuance of Oasis Midstream Partners common units	—	—		—	—		—		—		44,503		44,503
Distributions to non-controlling interest owners	—	—		—	—		—		—		(14,114)		(14,114)
Treasury stock - tax withholdings	(760)	—		760	(6,846)		—		—		—		(6,846)
Other	—	—		—	—		(881)		—		(125)		(1,006)
Net income (loss)	—	—		—	—		—		(35,296)		15,796		(19,500)
Balance as of December 31, 2018 (Predecessor)	318,377	3,157		2,092	(29,025)		3,077,755		682,689		184,304		3,918,880

Equity-based compensation	3,729	32		—	—		34,982		—		378		35,392
Distributions to non-controlling interest owners	—	—		—	—		—		—		(21,270)		(21,270)
Treasury stock - tax withholdings	(875)	—		875	(4,856)		—		—		—		(4,856)

Other	—	—		—	—		(353)		—		(65)		(418)
Net income (loss)	—	—		—	—		—		(128,243)		37,596		(90,647)
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	1,080	44		—	—		31,454		—		236		31,734
Distributions to non-controlling interest owners	—	—		—	—		—		—		(24,080)		(24,080)
Equity component of senior unsecured convertible notes repurchased	—	—		—	—		(337)		—		—		(337)
Treasury stock - tax withholdings	(2,010)	—		2,010	(2,756)		—		—		—		(2,756)

Net loss	—	—		—	—		—		(3,640,328)		(84,283)		(3,724,611)

Cancellation of Predecessor equity	(320,301)	(3,233)		(4,977)	36,637		(3,143,501)		3,086,292		—		(23,805)

Issuance of Successor common stock	20,000	200		—	—		941,610		—		—		941,810
Issuance of Successor warrants	—	—		—	—		23,805		—		—		23,805
Balance as of November 19, 2020 (Predecessor)	20,000	$	200	—	$	—	$	965,415	$	—	$	92,816	$	1,058,431


Balance as of November 20, 2020 (Successor)	20,000	$	200	—	$	—	$	965,415	$	—	$	92,816	$	1,058,431
Equity-based compensation	93	—		—	—		239		—		31		270
Net income (loss)	—	—		—	—		—		(49,912)		3,950		(45,962)


Balance as of December 31, 2020 (Successor)	20,093	$	200	—	$	—	$	965,654	$	(49,912)	$	96,797	$	1,012,739

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

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Oasis Petroleum Inc.

Consolidated Statements of Cash Flows

(In thousands)


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018

Cash flows from operating activities:
Net loss including non-controlling interests	$	(45,962)	$	(3,724,611)	$	(90,647)	$	(19,500)
Adjustments to reconcile net loss including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	16,094		291,115		787,192		636,296
(Gain) loss on extinguishment of debt	—		(83,867)		(4,312)		13,848
(Gain) loss on sale of properties	(11)		(10,396)		4,455		(28,587)
Impairment	—		4,937,143		10,257		384,228
Deferred income taxes	(3,447)		(262,926)		(32,699)		(5,866)
Derivative instruments	84,615		(233,565)		106,314		(28,457)
Equity-based compensation expenses	270		31,315		33,607		29,273
Non-cash reorganization items, net	—		(809,036)		—		—
Deferred financing costs amortization and other	6,824		41,811		27,263		29,057
Working capital and other changes:
Change in accounts receivable, net	68,322		96,436		13,729		(23,508)
Change in inventory	1,902		(4,005)		(5,893)		(14,346)
Change in prepaid expenses	(2,976)		1,674		325		(2,354)


Change in accounts payable, interest payable and accrued liabilities	(24,573)		(62,694)		53,051		26,116


Change in other assets and liabilities, net	(5,803)		(5,458)		(9,789)		221
Net cash provided by operating activities	95,255		202,936		892,853		996,421
Cash flows from investing activities:
Capital expenditures	(9,805)		(332,007)		(869,221)		(1,148,961)
Acquisitions	—		—		(21,009)		(581,650)
Proceeds from sale of properties	—		15,188		42,376		333,229
Costs related to sale of properties	—		—		—		(2,850)
Derivative settlements	(76)		224,416		19,098		(213,528)


Other	—		—		—		224
Net cash used in investing activities	(9,881)		(92,403)		(828,756)		(1,613,536)
Cash flows from financing activities:
Proceeds from revolving credit facilities	29,000		686,189		1,982,000		3,224,000
Principal payments on revolving credit facilities	(114,500)		(686,189)		(1,972,500)		(2,586,000)
Repurchase of senior unsecured notes	—		(68,060)		(45,790)		(423,340)
Proceeds from issuance of senior unsecured notes	—		—		—		400,000
Deferred financing costs	—		(7,260)		(1,052)		(13,862)
Debtor-in-possession credit facility fees	—		(5,853)		—		—

Proceeds from sale of Oasis Midstream Partners common units, net of offering costs	—		—		—		44,503
Purchases of treasury stock	—		(2,756)		(4,856)		(6,846)
Distributions to non-controlling interests	—		(24,080)		(21,270)		(14,114)
Payments on finance lease liabilities	(202)		(1,989)		(2,382)		—

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Other	—		—		(418)		(1,756)
Net cash provided by (used in) financing activities	(85,702)		(109,998)		(66,268)		622,585
Increase (decrease) in cash, cash equivalents and restricted cash	(328)		535		(2,171)		5,470
Cash, cash equivalents and restricted cash:
Beginning of period	20,554		20,019		22,190		16,720
End of period	$	20,226	$	20,554	$	20,019	$	22,190
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$	2,411	$	152,416	$	155,833	$	141,196
Cash paid for income taxes	1		109		111		38
Cash received for income tax refunds	28		282		146		25
Cash paid for reorganization items	—		22,205		—		—
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	7,938	$	(107,725)	$	(82,414)	$	68,946
Change in asset retirement obligations	377		(10,268)		4,917		3,880


Issuance of shares in connection with acquisition	—		—		—		371,220

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

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Oasis Petroleum Inc.

Notes to Consolidated Financial Statements

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”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct the Company’s E&P activities and own its oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Permian Basin, respectively. In addition to its E&P segment, the Company also operates a midstream business segment primarily through Oasis Midstream Partners LP (“OMP”), a consolidated subsidiary of the Company. OMP is a gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets.

2. Emergence from Voluntary Reorganization under Chapter 11

Due to the volatile market environment that drove a severe downturn in crude oil and natural gas prices in early 2020, as well as the unprecedented impact of the novel coronavirus 2019 (“COVID-19”) pandemic, the Company evaluated strategic alternatives to reduce its debt, increase financial flexibility and position the Company for long-term success. On September 30, 2020 (the “Petition Date”), Oasis Petroleum Inc. and its affiliates Oasis Petroleum LLC (“OP LLC”), OPNA, Oasis Well Services LLC (“OWS”), Oasis Petroleum Marketing LLC, OP Permian, OMS Holdings LLC, Oasis Midstream Services (“OMS”) and OMP GP LLC (“OMP GP”) (collectively, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) for relief under chapter 11 of title 11 (“Chapter 11”) of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On November 10, 2020, the Bankruptcy Court confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (the “Plan”), and on November 19, 2020 (the “Emergence Date”), the Debtors implemented the Plan and emerged from the Chapter 11 Cases. OMP and its subsidiaries, OMP Operating LLC (“OMP Operating”), Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”), Bighorn DevCo LLC (“Bighorn DevCo”) and Panther DevCo LLC (“Panther DevCo”), were not included in the Chapter 11 Cases.

At the Emergence Date, the Company adopted fresh start accounting in accordance with Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification 852, Reorganizations (“ASC 852”), which resulted in a new basis of accounting and the Company becoming a new entity for financial reporting purposes (see Note 3—Fresh Start Accounting). As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements after the Emergence Date are not comparable to the 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.

Although the Company is no longer a debtor-in-possession, the Predecessor operated as a debtor-in-possession from the Petition Date through the Emergence Date. As such, certain aspects of the Chapter 11 Cases and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.

In accordance with the Plan, the following significant transactions occurred on the Emergence Date:

•Shares of the Predecessor’s common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, the Company issued (i) 20,000,000 shares of the Successor’s common stock pro rata to holders of the Predecessor’s Notes (as defined below) and (ii) 1,621,622 warrants (the “Warrants”) pro rata to holders of the Predecessor’s common stock. The Warrants are exercisable to purchase one share of the Successor’s common stock per Warrant at an initial exercise price of $94.57 and expire on November 19, 2024.

•Oasis Petroleum Inc., as parent, OPNA, as borrower, and Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, issuing bank and swingline lender, and the lenders party thereto entered into a reserves-based credit agreement (the “Oasis Credit Facility”) with maximum aggregate commitments in the amount of $1,500.0 million and an initial borrowing base of $575.0 million.

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Facility had such obligations refinanced through the Oasis Credit Facility. Notwithstanding the foregoing, the Specified Default Interest (as defined in Note 15—Long-Term Debt) related to the Predecessor Credit Facility was discharged, released and deemed waived by the lenders.

•The Senior Secured Superpriority Debtor-in-Possession Credit Agreement, dated as of October 2, 2020 (the “DIP Credit Facility”), by and among the Predecessor, as borrower, its subsidiaries party thereto, as guarantors, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and the holders of claims under the DIP Credit Facility had such obligations refinanced through the Oasis Credit Facility.

•The Company adopted the Oasis Petroleum Inc. 2020 Long Term Incentive Plan (the “2020 LTIP”) effective on the Emergence Date and reserved 2,402,402 shares of its Successor’s common stock for distribution under the 2020 LTIP. No shares were issued under the 2020 LTIP as of the Emergence Date.

In addition, on the Emergence Date, the conditions were satisfied for the waiver, discharge and forgiveness of the OMP Specified Default Interest (as defined in Note 15—Long-Term Debt) under the revolving credit facility among OMP, as parent, OMP Operating, as borrower, Wells Fargo, as administrative agent, and the lenders party thereto (the “OMP Credit Facility”), and payment of the OMP Specified Default Interest was permanently waived by the lenders party to the OMP Credit Facility.

As of the Emergence Date, by operation of and in accordance with the Plan, the Board of Directors consisted of seven members, comprised of the Company’s Chief Executive Officer, Thomas B. Nusz, and six new members, Douglas E. Brooks, Samantha Holroyd, John Jacobi, Robert McNally, Cynthia L. Walker and John Lancaster. Subsequently, on December 22, 2020, Thomas B. Nusz retired as Chief Executive Officer and as a director of Oasis Petroleum Inc. In order to eliminate the Board vacancy created by Mr. Nusz’s departure, the size of the Board of Directors was reduced from seven to six. The Board of Directors appointed Douglas E. Brooks to serve as Chief Executive Officer, in addition to his role as Board Chair, during the period that it conducts a search for a new Chief Executive Officer.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors were entitled to assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The Debtors did not reject any executory contracts and, under the terms of the Plan, all executory contracts or unexpired leases not otherwise assumed or rejected were deemed assumed by the applicable Debtor.

Liabilities Subject to Compromise

During bankruptcy, the Debtors’ liabilities were segregated into those subject to compromise and those not subject to compromise under ASC 852. Liabilities subject to compromise represent pre-petition obligations that were not fully secured and that had at least a possibility of not being repaid at the full claim amount. The Predecessor presented liabilities subject to compromise at the expected amount of allowed claims and aggregated as a single line item on its balance sheet. See Note 3—Fresh Start Accounting for further details on the settlement of liabilities subject to compromise in accordance with the Plan.

As of the Petition Date, the Company reclassified its Notes to liabilities subject to compromise and discontinued recording interest on its Notes. The contractual interest expense on the Notes not accrued in the Company’s Consolidated Statements of Operations was $15.6 million for the period from the Petition Date through the Emergence Date.

3. Fresh Start Accounting

At the Emergence Date, the Company was required to adopt fresh start accounting in accordance with ASC 852 as (i) the holders of existing voting shares of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan of $2.2 billion was less than the total of post-petition liabilities and allowed claims of $3.2 billion. Refer to Note 2—Emergence from Voluntary Reorganization under Chapter 11 for the terms of the Plan.

Reorganization Value

Under fresh start accounting, reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities based on their fair values (except for deferred income taxes) in conformity with Accounting Standards Codification 805, Business

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Combinations. Deferred income tax amounts were determined in accordance with Accounting Standards Codification 740, Income Taxes (“ASC 740”).

Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and stockholders’ equity. As set forth in the Plan and related disclosure statement approved by the Bankruptcy Court, the enterprise value of the Successor was estimated to be between $1.3 billion and $1.7 billion. The enterprise value was prepared using reserve information, development schedules, other financial information and financial projections, and applying standard valuation techniques, including risked net asset value analysis, discounted cash flow analysis, public comparable company analysis and precedent transactions analysis. At the Emergence Date, the Company estimated the enterprise value to be $1.3 billion based on the estimates and assumptions used in determining the enterprise value coupled with consideration of the indicated enterprise value implied by the trading value of the Company’s Notes prior to the Emergence Date, as the reorganized Successor’s equity would be issued to the holders of the Notes under the Plan.

The Company’s principal E&P segment assets are its oil and gas properties, which were valued using primarily an income approach. The fair value of proved oil and natural gas properties was estimated using a discounted cash flow model, which is subject to management’s judgment and expertise and includes, but is not limited to, estimates of proved reserves, future commodity pricing, future production estimates, estimates of operating and development costs and a discount rate. Estimated proved reserves were risked by reserve category and were limited to wells included in the Company's five-year development plan. The underlying future commodity prices used to estimate future cash flows were based on NYMEX forward strip prices as of Emergence Date through 2022, escalating 2% per year thereafter (based on historical average annual consumer price index percentage changes) until reaching $75 per barrel for crude oil and $4.80 per Mcf for natural gas in 2051 after which prices were held flat. These prices were adjusted for transportation fees and quality and geographical differentials. Future operating and development costs were estimated based on the Company's recent actual costs, excluding the cost benefits the Company realizes from consolidating its midstream business segment. The cash flow models also included estimates not typically included in proved reserves, such as general and administrative expenses and income tax expenses, and estimated future cash flows were discounted using a weighted average cost of capital discount rate of 11%. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location were considered when estimating the fair value of the Company’s acreage.

The Company’s midstream business segment is primarily operated through OMP. OMP’s enterprise value was determined using the market approach based on a volume weighted average price calculation for OMP’s outstanding limited partner units. The Company estimated the fair value of its retained interests in Bobcat DevCo and Beartooth DevCo of 64.7% and 30%, respectively, using an income approach, which was based on the anticipated future cash flows associated with the respective DevCos and discounted using a weighted average cost of capital discount rate of 13%.

The midstream segment’s tangible assets primarily consist of pipelines, natural gas processing plants, compressor stations, produced water gathering lines and disposal wells, tanks, other facilities and equipment and rights of way. The estimated fair value of these midstream assets was determined using primarily a cost approach, based on current replacement costs of the assets less depreciation based on the estimated useful lives of the assets and ages of the assets. Economic and functional obsolescence were also considered and applied in the form of inutility and excess capital costs. The midstream segment’s identifiable intangible assets include third-party customer contracts and its interest in OMP GP. The Company determined the estimated fair value of customer contracts based on the excess earnings method of the income approach, which consists of estimating the incremental after-tax cash flows attributable to the intangible assets only. The Company estimated the fair value of its interest in OMP GP using a combination of an income approach and market approach.

The excess reorganization value over the fair value of identified tangible and intangible assets was recorded as goodwill on the Successor’s Consolidated Balance Sheet.

Although the Company believes the assumptions and estimates used to develop enterprise value and reorganization value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities.

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The following table reconciles the Company’s enterprise value to the estimated fair value of the Successor’s stockholders’ equity at the Emergence Date:


	November 19, 2020

	(In thousands)
Enterprise value	$	1,300,000
Plus: Cash(1)	5,615
Less: Fair value of Oasis Credit Facility(2)	(340,000)
Fair value of Oasis share of Successor stockholders’ equity(3)	965,615
Plus: Fair value of non-controlling interests	92,816
Fair value of total Successor stockholders’ equity	$	1,058,431

__________________

(1)Cash excludes $4.5 million of cash attributable to OMP and includes $1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above.

(2)Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, only the fair value of debt under the Oasis Credit Facility is subtracted in order to determine the value of the Successor’s stockholders’ equity.

(3)Reflects Successor equity issued in accordance with the Plan, including 20,000,000 shares of common stock and 1,621,622 Warrants.

The following table reconciles the Company’s enterprise value to the estimated reorganization value as of the Emergence Date:


	November 19, 2020

	(In thousands)
Enterprise value	$	1,300,000
Plus: Fair value of OMP Credit Facility(1)	455,500
Plus: Fair value of non-controlling interests	92,816
Plus: Cash(2)	5,615
Plus: Current liabilities	305,592
Plus: Asset retirement obligations (non-current portion)	45,986
Plus: Other non-current liabilities	32,482
Reorganization value of Successor assets	$	2,237,991

_________________

(1)Enterprise value includes the value of the Company’s interests in OMP and OMP GP, which is net of debt under the OMP Credit Facility, and as such, the fair value of the OMP Credit Facility is considered in the reconciliation of enterprise value to the reorganization value of the Successor’s assets.

(2)Cash excludes $4.5 million of cash attributable to OMP and includes $1.4 million that was initially classified as restricted cash as of November 19, 2020 but subsequently released from escrow and returned to the Successor. A total of $10.4 million of restricted cash as of November 19, 2020 was used to pay professional fees and is not included in the table above.

Condensed Consolidated Balance Sheet

The adjustments set forth in the following fresh start Condensed Consolidated Balance Sheet reflect the effect of the transactions contemplated by the Plan (“Reorganization Adjustments”) and the fair value and other required adjustments as a result of applying fresh start accounting (“Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine fair values as well as significant assumptions.

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	As of November 19, 2020
	Predecessor		Reorganization Adjustments			Fresh Start Adjustments			Successor
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	74,071	$	(65,317)	(a)	$	—		$	8,754
Restricted cash	—		11,800		(b)	—			11,800
Accounts receivable, net	274,679		—			—			274,679
Inventory	33,729		—			2,102		(p)	35,831
Prepaid expenses	10,864		(4,325)		(c)	—			6,539
Derivative instruments	728		—			—			728
Other current assets	754		—			—			754
Total current assets	394,825		(57,842)			2,102			339,085
Property, plant and equipment
Oil and gas properties (successful efforts method)	9,256,532		—			(8,461,285)		(q)	795,247
Other property and equipment	1,311,240		—			(373,068)		(q)	938,172
Less: accumulated depreciation, depletion, amortization and impairment	(8,579,696)		—			8,579,696		(q)	—
Total property, plant and equipment, net	1,988,076		—			(254,657)			1,733,419
Assets held for sale, net	1,380		—			4,120		(r)	5,500
Derivative instruments	47		—			—			47
Long-term inventory	14,107		—			413		(p)	14,520
Operating right-of-use assets	13,260		—			(797)		(s)	12,463
Intangible assets	667		—			43,000		(t)	43,667
Goodwill	—		—			70,534		(u)	70,534
Other assets	21,393		7,017		(d)	(9,654)		(v)	18,756
Total assets	$	2,433,755	$	(50,825)		$	(144,939)		$	2,237,991
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	9,206	$	21,809	(e)	$	—		$	31,015
Revenues and production taxes payable	130,487		—			—			130,487
Accrued liabilities	72,513		57,470		(f)	1,885		(w)	131,868
Current maturities of long-term debt	360,640		(360,640)		(g)	—			—
Accrued interest payable	60,988		(60,510)		(h)	—			478
Derivative instruments	4,902		49		(i)	18		(x)	4,969
Advances from joint interest partners	170		2,555		(i)	—			2,725
Current operating lease liabilities	1,050		924		(i)	(76)		(s)	1,898
Other current liabilities	412		1,774		(i)	(34)		(s)	2,152
Total current liabilities	640,368		(336,569)			1,793			305,592

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Long-term debt	455,500		340,000		(j)	—			795,500
Deferred income taxes	1,097		9,746		(k)	(6,412)		(y)	4,431
Asset retirement obligations	2,246		57,306		(i)	(13,566)		(w)	45,986
Derivative instruments	5,316		—			41		(x)	5,357
Operating lease liabilities	914		15,462		(i)	(740)		(s)	15,636
Other liabilities	3,634		3,456		(i)	(32)		(s)	7,058
Liabilities subject to compromise	2,051,294		(2,051,294)		(l)	—			—
Total liabilities	3,160,369		(1,961,893)			(18,916)			1,179,560
Commitments and contingencies
Stockholders’ equity (deficit)
Predecessor common stock	3,233		(3,233)		(m)	—			—
Successor common stock	—		200		(n)	—			200
Predecessor treasury stock, at cost	(36,637)		36,637		(m)	—			—
Predecessor additional paid-in capital	3,131,446		(3,131,446)		(m)	—			—
Successor additional paid-in capital	—		965,415		(n)	—			965,415
Retained earnings (accumulated deficit)	(3,995,209)		4,034,401		(o)	(39,192)		(z)	—
Oasis share of stockholders’ equity (deficit)	(897,167)		1,901,974			(39,192)			965,615
Non-controlling interests	170,553		9,094		(o)	(86,831)		(z)	92,816
Total stockholders’ equity (deficit)	(726,614)		1,911,068			(126,023)			1,058,431
Total liabilities and stockholders’ equity (deficit)	$	2,433,755	$	(50,825)		$	(144,939)		$	2,237,991

Reorganization Adjustments

(a)The table below reflects the uses of cash on the Emergence Date from the implementation of the Plan:


	(In thousands)




Payment of Oasis Credit Facility principal(1)	$	20,640
Payment pursuant to the Mirada Settlement Agreement	20,000
Funding of the professional fees escrow account	11,800
Payment of Oasis Credit Facility fees	6,900
Payment of professional fees	3,766
Payment of DIP Credit Facility accrued interest and fees	1,375
Payment of Predecessor Credit Facility accrued interest and fees	836
Total uses of cash	$	65,317

_________________

(1)On the Emergence Date, the principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, were converted to principal amounts of revolving loans under the Oasis Credit Facility in accordance with the Plan.

(b)Reflects the funding of an escrow account for professional fees associated with the Chapter 11 Cases, as required by the Plan.

(c)Reflects the remaining unamortized amount of prepaid cash incentives under the 2020 Incentive Compensation Program (as defined in Note 18—Equity-Based Compensation), which vested on the Emergence Date as a result of implementing the Plan, and was recorded in general and administrative expenses.

(d)Represents $7.3 million of fees related to the Oasis Credit Facility paid or accrued on the Emergence Date, which were capitalized as deferred financing costs and will be amortized to interest expense through the maturity date of May 19, 2024, offset by approximately $0.2 million of deferred financing costs related to the Predecessor Credit Facility, which were eliminated with a corresponding charge to reorganization items, net.

(e)Represents the reinstatement of $19.9 million of accounts payable included in liabilities subject to compromise to be satisfied in the ordinary course of business, coupled with a $1.9 million reclassification from accrued liabilities to

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accounts payable related to certain equity-based compensation awards classified as liabilities that vested on the Emergence Date.

(f)Changes in accrued liabilities include the following:


	(In thousands)
Reinstatement of accrued expenses from liabilities subject to compromise	$	73,778
Accrual for professional fees incurred upon Emergence Date	4,603
Vesting of equity-based compensation awards classified as liabilities	1,142
Payment pursuant to Mirada Settlement Agreement	(20,000)
Reclassification of payable for vested liability awards to accounts payable	(1,913)
Payment of certain professional fees accrued prior to Emergence Date	(140)
Net impact to accrued liabilities	$	57,470

(g)Reflects the refinancing of the borrowings outstanding under the DIP Credit Facility and Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, through the Oasis Credit Facility on the Emergence Date.

(h)Reflects the write-off of Specified Default Interest and OMP Specified Default Interest of $30.3 million and $28.0 million, respectively, which was waived on the Emergence Date, and the payment of accrued interest for the DIP Credit Facility and Predecessor Credit Facility of $1.4 million and $0.8 million, respectively, on the Emergence Date.

(i)Reflects the reinstatement of obligations that were classified as liabilities subject to compromise.

(j)Reflects borrowings drawn under the Oasis Credit Facility on the Emergence Date, consisting of principal amounts that were converted from principal amounts under the DIP Credit Facility and the Predecessor Credit Facility of $300.0 million and $60.6 million, respectively, in accordance with the Plan, partially offset by a principal repayment amount of $20.6 million. Refer to Note 15—Long-Term Debt for more information on the Oasis Credit Facility.

(k)Reflects an increase in the deferred tax liability recorded as a result of an ownership change under Section 382 (as defined in Note 17—Income Taxes), which limits the use of tax attributes and other deductions in future tax years.

(l)On the Emergence Date, liabilities subject to compromise were settled in accordance with the Plan as follows:


	(In thousands)
Notes	$	1,825,757
Accrued interest on Notes	50,337
Asset retirement obligations	57,306
Accounts payable and accrued liabilities	93,674
Other liabilities	24,220
Total liabilities subject to compromise of the Predecessor	2,051,294
Reinstatement of liabilities for general unsecured claims	(175,200)
Issuance of common stock to Notes holders	(941,810)
Gain on settlement of liabilities subject to compromise	$	934,284

(m)Reflects the cancellation of the Predecessor’s accumulated deficit, common stock and treasury stock and changes in the Predecessor’s additional paid-in capital as follows:


	(In thousands)
Cancellation of accumulated deficit	$	(3,086,292)
Cancellation of common stock	3,233
Cancellation of treasury stock	(36,637)
Equity-based compensation for vesting of awards classified as equity	12,055
Issuance of Warrants to Predecessor common stockholders	(23,805)
Net impact to Predecessor additional paid-in capital	$	(3,131,446)

(n)Reflects the distribution of Successor equity instruments in accordance with the Plan, including the issuance of 20,000,000 shares of common stock at a par value of $0.01 per share and 1,621,622 Warrants. The fair value of the

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Warrants was estimated at $14.68 per Warrant using a Black-Scholes model. See Note 19—Stockholders’ Equity for additional information.


	(In thousands)
Common stock to Notes holders	$	941,810
Warrants to Predecessor common stockholders	23,805
Total fair value of Successor equity	$	965,615

(o)The table below reflects the cumulative impact of the reorganization adjustments discussed above:


	(In thousands)
Gain on settlement of liabilities subject to compromise	$	934,284
Write-off of Specified Default Interest	30,285
Write-off of OMP Specified Default Interest	28,014
Gain on debt discharge	992,583
Professional fees incurred on the Emergence Date	(7,869)
Write-off of Predecessor Credit Facility deferred financing costs	(243)
Total reorganization items from reorganization adjustments	984,471
Equity-based compensation expense for vesting of awards on Emergence Date	(13,197)
Vesting of prepaid cash incentive compensation	(4,325)
Income from reorganization adjustments before income taxes	966,949
Income tax expense	(9,746)
Net income from reorganization adjustments including non-controlling interests	957,203
Less: Net income from reorganization adjustments attributable to non-controlling interests	(9,094)
Net income from reorganization adjustments attributable to Oasis	948,109
Cancellation of accumulated deficit	3,086,292
Net impact to Predecessor retained earnings (accumulated deficit)	$	4,034,401

Fresh Start Adjustments

(p)Reflects fair value adjustments to the Company’s crude oil inventory, equipment inventory, and long-term linefill inventory of $1.6 million, $0.5 million and $0.4 million, respectively, based on market prices as of the Emergence Date. Crude oil prices were estimated using NYMEX West Texas Intermediate crude oil index prices (“NYMEX WTI”) based on the estimated timing of liquidation and adjusted for quality and location differentials.

(q)Reflects adjustments to present the Company's proved oil and gas properties, unproved acreage and other property and equipment at their estimated fair values based on the valuation methodology discussed above as well as the elimination

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of accumulated depreciation, depletion, amortization and impairment. The following table summarizes the components of property, plant and equipment as of the Emergence Date:


	Fair Value		Historical Book Value
	(In thousands)
Proved oil and gas properties	$	755,247	$	9,081,974
Less: Accumulated depreciation, depletion, amortization and impairment	—		(8,259,334)
Proved oil and gas properties, net	755,247		822,640
Unproved oil and gas properties	40,000		174,558
Other property and equipment	938,172		1,311,240
Less: Accumulated depreciation and impairment	—		(320,362)
Other property and equipment, net	938,172		990,878
Total property, plant and equipment, net	$	1,733,419	$	1,988,076

(r)Reflects fair value adjustments to the Company’s assets held for sale based on the sales price agreed upon with the buyer, less estimated costs to sell.

(s)Reflects adjustments required to present at fair value operating lease right-of-use assets and operating and finance lease liabilities. The Company's remaining lease obligations were remeasured using incremental borrowing rates applicable to the Company as of the Emergence Date and commensurate with the Successor's capital structure. The incremental borrowing rates ranged from 3.06% to 6.58% based on the tenor of the leases. Finance lease liabilities are included in other current liabilities and other liabilities on the Company’s Consolidated Balance Sheet.

(t)Reflects adjustments to present identified intangible assets at their estimated fair values based on the valuation methodology discussed above. The following table summarizes the components of property, plant and equipment as of the Emergence Date:


	Fair Value		Historical Book Value
	(In thousands)
Interest in OMP GP	$	28,000	$	—
Customer contracts	15,000		—
Seismic data	667		667
Total intangible assets	$	43,667	$	667

(u)Adjustment to record the excess of the reorganization value over the fair value of identified tangible and intangible assets as goodwill.

(v)Reflects adjustments to eliminate certain deferred costs determined to have no fair value, including electrical infrastructure costs of $8.1 million and deferred financing costs related to the OMP Credit Facility of $1.5 million, and a $0.1 million adjustment to present finance lease right-of-use assets at fair value.

(w)Adjustment to present at fair value the Company's asset retirement obligations (“ARO”) using assumptions as of the Emergence Date, including an inflation factor of 2% and an estimated 30-year credit-adjusted risk-free rate of 8.5%.

(x)Reflects fair value adjustment to the Company’s derivative instruments using the Company’s estimated credit-adjusted risk-free rate as of the Emergence Date of 5.12%.

(y)Reflects the adjustment to deferred income taxes to reflect the change in the financial reporting basis of assets as a result of the adoption of fresh start accounting.

(z)The table below reflects the cumulative impact of the fresh start adjustments discussed above:


	(In thousands)
Loss on revaluation adjustments	$	(132,435)
Income tax benefit	6,412
Net loss from fresh start adjustments including non-controlling interests	(126,023)
Less: Net loss from fresh start adjustments attributable to non-controlling interests	86,831
Net loss from fresh start adjustments attributable to Oasis	$	(39,192)

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Reorganization Items, Net

Any expenses, gains and losses that were realized or incurred between the Petition Date and the Emergence Date and as a direct result of the Chapter 11 Cases and the implementation of the Plan are recorded in reorganization items, net in the Company’s Consolidated Statements of Operations. The following table summarizes the components of reorganization items, net:


	(In thousands)
Gain on debt discharge	$	992,583
Loss on revaluation adjustments	(132,435)
Write-off of unamortized debt discount	(38,373)
Professional fees	(16,352)
Write-off of unamortized deferred financing costs	(12,739)
DIP Credit Facility fees	(5,853)
Total reorganization items, net	$	786,831

4. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income.

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

Going concern. The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. During the Chapter 11 Cases, the Company’s ability to continue as a going concern was subject to a high degree of risk and uncertainty until the Plan was confirmed and the Company emerged from the Chapter 11 Cases. As a result of implementing the Plan, there is no longer substantial doubt about the Company’s ability to continue as a going concern.

Bankruptcy and Fresh Start Accounting

Subsequent to the Petition Date, the Company applied ASC 852 in preparing its consolidated financial statements. At the Emergence Date, the Company adopted fresh start accounting in accordance with ASC 852, 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 and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor. See Note 2—Emergence from Voluntary Reorganization under Chapter 11 and Note 3—Fresh Start Accounting for further details.

Use of Estimates

Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved crude oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain crude oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.

Estimates of crude oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a

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subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense.

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, and continue to be, very volatile and there can be no assurance that crude oil and natural gas prices will not be subject to wide fluctuations in the future.

A substantial or extended decline in prices for crude oil and, to a lesser extent, natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of crude oil and natural gas reserves that may be economically produced.

COVID-19. Management considered the impact of the ongoing COVID-19 pandemic on the assumptions and estimates used in the consolidated financial statements. The effects of COVID-19 and concerns regarding its global spread have negatively impacted global demand for crude oil and natural gas, which has and could continue to contribute to price volatility, impact prices the Company receives for crude oil, natural gas and NGLs, and materially and adversely affect the demand for and marketability of its production, as well as lead to temporary curtailment or shut-ins of production due to lack of downstream demand or storage capacity. As a result of impairment indicators identified as of March 31, 2020, including the significant decline in commodity prices partially driven by the COVID-19 pandemic, the Company recognized material asset impairment charges during the Predecessor period from January 1, 2020 through November 19, 2020. Management’s estimates and assumptions were based on historical data and consideration of future market conditions. The potential additional impacts from COVID-19 on the Company’s financial position, results of operations and cash flows will depend on uncertain factors, including future developments and new information that may emerge regarding the severity and duration of COVID-19, the actions taken by authorities to contain it or treat its impact, and the availability and acceptance of vaccines, all of which are beyond the Company’s control and difficult to predict.

Cash Equivalents and Restricted Cash

The Company invests 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. Restricted cash consists of funds in an escrow account for professional fees associated with the Chapter 11 Cases.

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


	Successor		Predecessor
	December 31, 2020		November 19, 2020		December 31, 2019

Cash and cash equivalents	$	15,856	$	8,754	$	20,019
Restricted cash	4,370		11,800		—
Total cash, cash equivalents and restricted cash	$	20,226	$	20,554	$	20,019

Accounts Receivable

Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil and natural gas purchasers and joint interest owners on properties the Company operates.

The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil and natural gas receivables are collected within two months.

In the first quarter of 2020, the Company adopted Accounting Standards Update No. 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which replaces the incurred

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loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information, including forecasts, to develop credit loss estimates. The Company’s exposure to credit losses is primarily related to its joint interest and crude oil and natural gas sales receivables. In accordance with ASU 2016-13, the Company estimates expected credit losses on its accounts receivable at each reporting date, which may result in earlier recognition of credit losses than under previous GAAP. These estimates are based on historical data, current and future economic and market conditions to determine expected collectability. To date, the Company’s credit losses on joint interest and crude oil and natural gas sales receivables have been immaterial. The Company continually monitors the creditworthiness of its counterparties by reviewing credit ratings, financial statements and payment history. The adoption of ASU 2016-13 was applied using a modified retrospective approach by recognizing a cumulative-effect adjustment to retained earnings (accumulated deficit) of $0.4 million in the first quarter of 2020 to increase its allowance for expected credit losses, and prior periods were not retrospectively adjusted. The adoption of ASU 2016-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations (see Note 8— Additional Balance Sheet Information).

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 exploration and production activities and spare parts and equipment for the Company’s midstream assets. Crude oil inventory includes crude oil in tanks and linefill. Linefill that represents the minimum volume of product in a pipeline system that enables the system to operate is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil 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 Consolidated Balance Sheets (see Note 7—Inventory).

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

Joint Interest Partner Advances

The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to joint interest partners are included in other current assets on the Company’s Consolidated Balance Sheets.

Property, Plant and Equipment

Proved Oil and Gas Properties

Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future

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cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.

Unproved Oil and Gas Properties

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:

•the remaining amount of unexpired term under its leases;

•its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

•its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

•its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin and Bone Spring and Wolfcamp formations in the Permian Basin by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.

For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Capitalized Interest

The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. For the Successor period of November 20, 2020 through December 31, 2020 and the Predecessor period of January 1, 2020 through November 19, 2020, the Company capitalized interest costs of $0.1 million and $6.4 million, respectively. For the years ended December 31, 2019 and 2018 (Predecessor), the Company capitalized interest costs of $12.0 million and $17.2 million, respectively. These amounts are amortized over the life of the related assets.

Other Property and Equipment

The Company’s produced and flowback water disposal facilities, natural gas processing plants, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of 30 years for its produced and flowback water disposal facilities, natural gas processing plants and pipelines, 20 years for its buildings, two to seven years for its furniture, software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations.

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Exploration Expenses

Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.

Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.

Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		December 31,
					2019		2018


Beginning of period	$	—	$	—	$	4,457	$	—
Exploratory well cost additions (pending determination of proved reserves)	—		—		—		26,497
Exploratory well cost reclassifications (successful determination of proved reserves)	—		—		(4,222)		(22,040)
Exploratory well dry hole costs (unsuccessful in adding proved reserves)	—		—		(235)		—

End of period	$	—	$	—	$	—	$	4,457

As of December 31, 2020 (Successor), the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.

Goodwill and Intangible Assets

For the purpose of the goodwill impairment test, the Company first assesses qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, the Company determines the drivers of fair value of the reporting unit and evaluates whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. The midstream segment is the reporting unit that carries the Company’s goodwill balance as of December 31, 2020. The fair value of the reporting unit is estimated using a combination of an income and market approach. Significant inputs used are subject to management’s judgment and expertise and include, but are not limited to, estimated throughput volumes, estimated fixed and variable operating costs, estimated capital costs, estimated useful life of the asset group and discount rate.

The Company’s indefinite-lived intangible assets consist of its interest in OMP GP as well as access to certain seismic data. Indefinite lived intangible assets are evaluated for impairment when indicators of impairment are present based on expected

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future profitability and undiscounted expected cash flows and their contribution to our overall operations. If the carrying value is not recoverable, an impairment charge would be recorded to write down the related intangible asset to its estimated fair value.

The Company’s definite-lived intangible assets include third-party customer contracts, which are amortized on a straight-line basis over the useful lives of five to 14 years based on the associated contract terms, and the amortization is included in depreciation, depletion and amortization expenses on the Company’s Consolidated Statements of Operations.

Business Combinations

The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and gas properties within the same regions and uses that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties.

Assets Held for Sale

The Company occasionally markets non-core oil and gas properties and other property and equipment. At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, indicative bids or indicative market pricing, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale.

Deferred Financing Costs

The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the Company’s revolving credit facilities are included in other assets on the Company’s Consolidated Balance Sheets. Deferred financing costs related to the Predecessor’s Notes were historically included in long-term debt on the Company’s Consolidated Balance Sheets prior to being eliminated as a result of the Chapter 11 Cases.

Asset Retirement Obligations

In accordance with the FASB authoritative guidance on ARO, the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using

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the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statements of Operations.

Some of the Company’s midstream assets, including certain pipelines and the natural gas processing plants, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. The Company is not able to reasonably estimate the fair value of the ARO for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The Company will record the ARO for these assets in the periods in which the settlement dates are reasonably determinable.

The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 9—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Revenue Recognition

The Company recognizes revenue in accordance with Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Enhanced disclosures in accordance with ASC 606 have been provided in Note 6—Revenue Recognition.

The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Crude oil, natural gas and natural gas liquids (“NGL”) revenues from the Company’s interests in producing wells are recognized when it satisfies a performance obligation by transferring control of a product to a customer. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for crude oil, natural gas and NGLs, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.

The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts 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, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with Accounting Standards Codification 845, Nonmonetary Transactions (“ASC 845”).

Midstream revenues consist of revenues from services provided by the Company’s midstream business segment, primarily through OMP, 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 distribution. Midstream revenues are earned through fee-based arrangements, under which the Company receives fees for midstream services it provides to customers and recognizes revenue based upon the transaction price at month-end under the right to invoice practical expedient, or through purchase arrangements, under which the Company takes control of the product prior to sale and is the principal in the transaction, and therefore, recognizes revenues and expenses on a gross basis. Other services revenues result from equipment rentals, and also included revenues for well completion services and product sales prior to the Company transitioning its well fracturing services from OWS to a third-party provider during the first quarter of 2020 (the “Well Services Exit”). Midstream and other services revenues are recognized when services have been performed or related volumes or products have been delivered. A portion of the Company’s midstream revenues and substantially all of its other services revenues are from services provided to its operated wells. The revenues related to work performed for the Company’s ownership interests are eliminated in consolidation, and only the revenues related to non-affiliated interest owners and other third-party customers are included in the Company’s Consolidated Statements of Operations.

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Revenues and Production Taxes Payable

The Company calculates and pays taxes and royalties on crude oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.

Leases

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842), which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than 12 months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by Accounting Standards Update No. 2018-01, Land easement practical expedient for transition to Topic 842; Accounting Standards Update No. 2018-10, Codification Improvements to Topic 842; Accounting Standards Update No. 2018-11, Targeted Improvements; and Accounting Standards Update No. 2019-01, Leases (Topic 842): Codification Improvements.

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

ASU 2018-01 provided a number of optional practical expedients in transition. The Company elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight line basis.

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

As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company has determined their respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases. See Note 22—Leases for the disclosures required by ASC 842.

Fair Value Measurement

In the first quarter of 2020, the Company adopted Accounting Standards Update No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the effectiveness of the disclosure requirements for fair value measurements. The adoption of ASU 2018-13 did not result in a material impact to the Company’s financial position, cash flows or results of operations. See Note 9 — Fair Value Measurements for disclosures in accordance with ASU 2018-03.

Concentrations of Market and Credit Risk

The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. Commodity prices have been volatile in recent years. Due to a combination of the impacts of the COVID-19 pandemic and geopolitical pressures on the global supply and demand balance for crude oil and related products, commodity prices sharply declined in the first half of 2020, which adversely affected the Company’s business, operating results and liquidity. A substantial or extended decline in the price of crude oil could have a further material adverse effect on the Company’s financial position, cash flows and results of operations.

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The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, including the current commodity price environment, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term.

The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.

Risk Management

The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. As of December 31, 2020, the Company utilized fixed price swaps to reduce the volatility of crude oil prices on a significant portion of its future expected crude oil production (see Note 10—Derivative Instruments).

The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.

Derivative financial instruments that hedge the price of crude oil and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. At December 31, 2020 (Successor), the Company had derivatives in place with eight counterparties which are all lenders under the Oasis Credit Facility. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.

The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Oasis Credit Facility. The Oasis Credit Facility requires the Company to hedge certain minimum percentages of forecasted crude oil production volumes. As of December 31, 2020 (Successor), the Company was in compliance with these requirements.

Contingencies

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

If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but

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cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 24—Commitments and Contingencies for additional information regarding the Company’s contingencies.

Environmental Costs

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

Equity-Based Compensation

The Company may grant various types of equity-based awards, including restricted stock awards, restricted stock units, performance share units, phantom units, and other awards under any long-term incentive plan then in effect to employees and non-employee directors. The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. Cash-settled awards are classified as liabilities. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period.

The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment (see Note 18—Equity-Based Compensation for a description of the inputs used in this model).

Any excess tax benefit arising from the Company’s equity-based compensation plan is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.

Treasury Stock

Treasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards. The Company includes the withheld shares as treasury stock on its Consolidated Balance Sheets and separately pays the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not have a publicly announced program to repurchase shares of its common stock. The Company did not have any treasury stock at December 31, 2020 (Successor), as the Predecessor’s treasury stock was eliminated on the Emergence Date in accordance with the Plan.

Income Taxes

The Company’s provision for taxes includes both federal and state income taxes. The Company records its income taxes in accordance with ASC 740, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.

The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with

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the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability for the years ended December 31, 2020 (Successor) and 2019 (Predecessor). All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets.

In the fourth quarter of 2020, the Company adopted Accounting Standards Update No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 related to the approach for intraperiod tax allocation and calculating income taxes in interim periods, among other changes. The adoption of ASU 2019-12 did not result in a material impact to the Company’s financial position, cash flows or result of operations

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”). The amendments provide optional guidance for a limited time to ease the potential burden in accounting for reference rate reform. The new guidance provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments apply 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. These amendments are 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.

5. Oasis Midstream Partners

OMP is a premier gathering and processing master limited partnership formed by the Company to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the crude oil and natural gas operations of Oasis and are strategically positioned to capture volumes from other producers. OMP’s assets are located in the Williston and Permian Basins. At December 31, 2020, the Company owned 67.5% of OMP’s outstanding limited partner units, a 92% controlling interest in its general partner, OMP GP, and retained interests in Bobcat DevCo and Beartooth DevCo of 64.7% and 30%, respectively. As discussed in Note 2—Emergence from Voluntary Reorganization under Chapter 11, OMP and its subsidiaries did not file for bankruptcy and were not included in the Chapter 11 Cases.

Contractual arrangements

The Company entered into several long-term, fee-based contractual arrangements with OMP for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services; (ii) crude oil gathering, terminaling and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater distribution services. In addition, the Company provides substantial labor and overhead support for OMP pursuant to a services and secondment agreement, under which the Company performs centralized corporate, general and administrative services for OMP, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. The Company has also seconded to OMP certain of its employees to operate, construct, manage and maintain its assets, and OMP reimburses the Company for direct general and administrative expenses incurred by the Company for the provision of the above services. The expenses of executive officers and non-executive employees are allocated to OMP based on the amount of time spent managing its business and operations.

Oasis Midstream Partners LP public offering and dropdown

On November 14, 2018, OMP completed a public offering of 2,300,000 common units (including 300,000 common units issued pursuant to the underwriters’ option to purchase additional common units) representing limited partnership interests, at a price to the public of $20.00 per common unit. OMP received net proceeds from the public offering of $44.5 million, after deducting underwriting discounts, commissions and offering costs, which were used to fund a portion of its acquisition of additional ownership interest in Bobcat DevCo and Beartooth DevCo.

In connection with the OMP public offering, on November 19, 2018, OMP acquired an additional 15% ownership interest in Bobcat DevCo increasing its ownership to 25% and an additional 30% ownership interest in Beartooth DevCo increasing its ownership to 70% in exchange for consideration of $251.4 million (“OMP Dropdown”).

The $251.4 million consideration consisted of $172.4 million in cash and 3,950,000 common units representing limited partner interests in OMP. OMP funded the cash portion of the consideration with a combination of borrowings under the OMP Credit Facility and proceeds from its public offering of common units. The effective date of the OMP Dropdown was July 1, 2018, and the OMP Dropdown closed on November 19, 2018. The OMP Dropdown did not have a material impact on the Company’s

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consolidated financial statements. After the OMP Dropdown, OMS owned 75% of the non-controlling interests of Bobcat DevCo and 30% of the non-controlling interests of Beartooth DevCo.

2019 Capital Expenditures Arrangement

On February 22, 2019, the Company entered into a memorandum of understanding (the “MOU”) with OMP regarding the funding of Bobcat DevCo’s expansion capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the MOU, in exchange for increasing its percentage ownership interest in Bobcat DevCo, OMP agreed to make up to $80.0 million of the capital contributions to Bobcat DevCo that OMS would otherwise have been required to contribute. During the year ended December 31, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $73.0 million. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 64.7% as of December 31, 2019. The 2019 Capital Expenditures Arrangement ended on December 31, 2019.

Assignment of midstream assets in Permian Basin

Effective November 1, 2019, the Company assigned to Panther DevCo, an indirect, wholly-owned subsidiary of OMP, certain crude oil gathering and produced water gathering and disposal assets (the “Delaware Midstream Assets”) under development to support the Company’s production in the Permian Basin. OMP agreed to reimburse the Company for all capital expenditures previously made with respect to the Delaware Midstream Assets, which were approximately $24.9 million. OMP funded this amount with borrowings under its revolving credit facility. Also, effective November 1, 2019, Panther DevCo entered into long-term commercial agreements with the Company, including a Crude Oil Gathering Agreement and a Produced Water Gathering and Disposal Agreement (collectively, the “Permian Basin Commercial Agreements”), for crude oil and produced water midstream services in the Permian Basin, which generally contain terms similar to those contained in the existing commercial agreements between OMP and the Company for midstream services in the Williston Basin. The Permian Basin Commercial Agreements additionally provide the Company with certain purchase rights with respect to the Permian Midstream Assets, and provide Panther DevCo with certain sale rights with respect to the Delaware Midstream Assets, in the event of a change of control of OMP or Panther DevCo, which purchase and sale rights will expire after two years.

6. Revenue Recognition

Exploration and production revenues

The Company’s E&P revenues are derived from contracts for crude oil, natural gas and NGL sales and other services, as described below. Generally, for the crude oil, natural gas, and NGL contracts: (i) each unit (barrel (“bbl”), mcf, gallon, etc.) of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the customer obtains control of the commodity product and the Company’s performance obligation is satisfied. The sales of crude oil, natural gas and NGLs as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, natural gas and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of crude oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. The Company’s contracts with customers typically require payments for crude oil, natural gas and NGL sales within 30 days following the calendar month of delivery.

Crude oil revenues. The Company sells a substantial majority of its crude oil through bulk sales at delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold to the customer at a specified delivery point. The customer pays a market-based transaction price, which incorporates differentials that include, but are not limited to, transportation costs.

Natural gas and NGL revenues. The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales. Unprocessed gas is sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its sale of the bifurcated NGLs and residue gas, less any associated fees. Revenue is recorded on a net basis, with processing fees deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point. Residue gas from the Company’s gas processing plants located in Wild Basin is sold at the tailgate or transported and sold at other downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold. NGLs from the Company’s gas processing plants located in Wild Basin are sold at the tailgate or trucked and sold at other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.

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Purchased crude oil and natural gas sales. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from a third party. The Company sells the purchased commodities to a variety of customers under short-term contracts that include specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point. The customer pays a market-based transaction price, which is based on the price index applicable for the location of the sale. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts 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, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845.

Other Services. The Company’s other services revenues are from services provided by OWS for the Company’s operated wells, including equipment rental revenues and, prior to the Well Services Exit, hydraulic fracturing revenues. Intercompany revenues for work performed for the Company’s working interests are eliminated in consolidation, and only the revenues related to non-affiliated working interest owners are included in consolidated revenues.

•Equipment rental revenues. Equipment rental revenue is generated when OWS provides equipment rentals to the Company’s operated wells. Equipment rental revenues are calculated based on the equipment’s daily rental rate and the number of days that the equipment was rented by the customer. The Company’s performance obligation is satisfied when the entire rental period is completed. Equipment rental revenues are recognized over a period of time due to the customer simultaneously receiving and consuming the benefits of the rental equipment provided by the Company on a daily basis. Satisfaction of the Company’s performance obligation is measured at the completion of each day of the rental period, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized at the time of invoicing for the entire rental period under the right to invoice practical expedient.

•Hydraulic fracturing revenues. Prior to the Company’s Well Services Exit, hydraulic fracturing revenues were generated when OWS provided hydraulic fracturing services and related materials to the Company’s operated wells. These services were composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component was not distinct, as it could not be used on its own or together with a resource readily available to the customer. The Company’s performance obligation was satisfied when the hydraulic fracturing of a well was completed. Revenue was recognized over a period of time upon the completion of each stage of hydraulic fracturing of a well.

Revenues associated with 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
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018


Crude oil revenues	$	69,075	$	522,812	$	1,261,413	$	1,425,409
Purchased crude oil sales	6,771		160,420		401,554		540,633
Natural gas and NGL revenues	17,367		80,773		147,358		164,615
Purchased natural gas sales	366		5,047		7,207		6,078
Other services revenues	215		6,836		41,974		61,075
Total E&P revenues	$	93,794	$	775,888	$	1,859,506	$	2,197,810

Midstream revenues

The Company’s midstream revenues are derived from its contracts with customers for midstream services and product sales under the following arrangements:

Fee-based arrangements. Under fee-based arrangements, the Company receives a fee for midstream services provided to its customers, and revenues are recognized using the output method for measuring the satisfaction of performance obligations. Revenues earned under fee-based arrangements are generally directly related to the volume of crude oil, natural gas and produced and flowback water that flows through the Company’s systems, and the Company generally does not take ownership to the volumes it handles for its customers. Payments under fee-based arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under fee-based arrangements as follows:

•Crude oil, natural gas and NGL revenues. The Company is party to certain contracts for crude oil gathering, stabilization, blending, storage and transportation, as well as natural gas gathering, compression, processing and gas lift supply services. Under these contracts, the Company provides daily integrated midstream services on a

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stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient.

•Produced and flowback water revenues. The Company is party to certain contracts with customers for produced and flowback water gathering and disposal services, under which it provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient.

Purchase arrangements. Under purchase arrangements, revenues and expenses are recognized on a gross basis since the Company takes control of the product prior to sale and is the principal in the transaction. Revenues are recognized using the output method for measuring the satisfaction of performance obligations based upon the volume of crude oil, natural gas, NGLs or freshwater delivered to customers. Payments under purchase arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under purchase arrangements as follows:

•Purchased crude oil sales. The Company purchases and sells crude oil at various delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be sold and delivered to the customer at a specified delivery point. The Company purchases and sells the crude oil to different counterparties at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale.

•Crude oil, natural gas and NGL revenues. The Company is party to certain purchase arrangements with third parties pursuant to which the Company purchases natural gas from third parties at a connection point and obtains control prior to performing services and is the principal in the transaction. The Company gathers, compresses and/or processes the natural gas and then redelivers the residue gas and NGLs to different counterparties at market-based prices.

•Freshwater revenues. Under these contracts, the Company supplies and distributes freshwater to its customers for hydraulic fracturing and production optimization. These contracts contain multiple distinct performance obligations since each freshwater barrel can be sold separately and is not dependent nor highly interrelated with other barrels.

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 associated with contracts with customers for midstream services were as follows for the periods presented (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018


Midstream service revenues
Crude oil, natural gas and NGL revenues	$	8,912	$	82,466	$	95,399	$	73,028
Produced and flowback water revenues	3,512		31,932		40,534		37,791
Total midstream service revenues	$	12,424	$	114,398	$	135,933	$	110,819
Midstream product revenues
Purchased crude oil sales	$	90	$	20,900	$	30	$	3,633
Crude oil, natural gas and NGL revenues	13,150		48,883		70,746		1,464
Freshwater revenues	457		3,350		5,529		8,221
Total midstream product revenues	$	13,697	$	73,133	$	76,305	$	13,318
Total midstream revenues	$	26,121	$	187,531	$	212,238	$	124,137

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

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the related performance period is completed and the customer is billed. Revenue recognized for accrued deficiency fees associated with minimum volume commitments is included in midstream revenues on the Company’s Consolidated Statements of Operations. 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 the timing of when the Company expects to receive cash for contract assets or recognize revenue for contract liabilities. Contract assets are included in other current assets on the Company’s Consolidated Balance Sheets, and contract liabilities are included in other current liabilities and other liabilities on the Company’s Consolidated Balance Sheets. The Company’s contract asset balances were not material as of December 31, 2020 or 2019.

The following table reflects the changes in the Company’s contract liabilities for the periods presented (in thousands):


	Successor		Predecessor
	December 31, 2020		December 31, 2019

Beginning of the period	$	2,105	$	—
Cash received	2,267		2,174
Revenues recognized	(406)		(69)
End of the period	$	3,966	$	2,105

Performance obligations

The Company records revenue when the performance obligations under the terms of its contracts with customers 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 2020 Successor and Predecessor periods and the years ended December 31, 2019 and 2018 (Predecessor), revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Remaining performance obligations

ASC 606 requires presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of December 31, 2020 (Successor):


	(In thousands)
2021	$	16,921
2022	17,175
2023	10,896
2024	11,089
2025	2,768
Total	$	58,849

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

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

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7. Inventory

The following table sets forth the Company’s inventory (in thousands):


	Successor		Predecessor
	December 31, 2020		December 31, 2019

Inventory
Crude oil inventory	$	8,826	$	18,296
Equipment and materials	25,103		16,963
Total inventory	$	33,929	$	35,259

Long-term inventory
Linefill in third-party pipelines	$	14,522	$	13,924
Long-term inventory	$	14,522	$	13,924

Total	$	48,451	$	49,183

8. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following (in thousands):


	Successor		Predecessor
	December 31, 2020		December 31, 2019

Accounts receivable, net
Trade accounts	$	161,519	$	276,629
Joint interest accounts	31,920		82,112
Other accounts	13,206		13,699
Total	206,645		372,440
Allowance for credit losses	(106)		(1,259)
Total accounts receivable, net	$	206,539	$	371,181

Revenues and production taxes payable
Revenue suspense	$	66,602	$	78,950
Royalties payable	65,412		133,092
Production taxes payable	14,483		21,048
Total revenue and production taxes payable	$	146,497	$	233,090

Accrued liabilities
Accrued capital costs	$	39,380	$	128,592
Accrued lease operating expenses	18,635		34,151
Accrued oil and gas purchases	8,967		51,087
Accrued general and administrative expenses	35,249		41,843
Accrued midstream and other services operating expenses	15,051		17,958
Other accrued liabilities	9,002		7,448
Total accrued liabilities	$	126,284	$	281,079

9. 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

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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 ARO (see Note 16—Asset Retirement Obligations) and proved oil and gas properties upon impairment (see Note 11—Property, Plant and Equipment), at fair value on a non-recurring basis.

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

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

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

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

Level 3 — Pricing inputs are generally 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 December 31, 2020
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Money market funds	$	—	$	—	$	—	$	—
Commodity derivative instruments (see Note 10)	—		467		—		467
Total assets	$	—	$	467	$	—	$	467
Liabilities:
Commodity derivative instruments (see Note 10)	$	—	$	94,558	$	—	$	94,558
Total liabilities	$	—	$	94,558	$	—	$	94,558

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	Predecessor
	Fair value at December 31, 2019
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Money market funds	$	146	$	—	$	—	$	146
Commodity derivative instruments (see Note 10)	—		1,174		—		1,174
Total assets	$	146	$	1,174	$	—	$	1,320
Liabilities:
Commodity derivative instruments (see Note 10)	$	—	$	19,815	$	—	$	19,815
Total liabilities	$	—	$	19,815	$	—	$	19,815

The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions and are included in cash and cash equivalents on the Company’s Consolidated Balance Sheets. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.

The Level 2 instruments presented in the tables above consist of commodity derivative instruments (see Note 10—Derivative Instruments). The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are commodity prices, volatility, skew, discount rate and the contract terms of the derivative instruments. The Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in commodity forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the 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 $4.3 million at December 31, 2020 (Successor) and an adjustment to reduce the fair value of its net derivative liability by $0.5 million at December 31, 2019 (Predecessor).

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.

Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, estimates of crude oil and natural gas proved reserves, future commodity pricing, future rates of production, estimates of operating and development costs, risk-adjusted discount rates and estimates of throughput volumes for the Company’s midstream assets. These inputs are classified as Level 3 inputs, except the underlying commodity price assumptions are based on NYMEX forward strip prices (Level 1) and adjusted for price differentials. As a result of the significant decline in expected future commodity prices in the first quarter of 2020, the Company reviewed its properties for impairment as of March 31, 2020. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of March 31, 2020 for five years, escalating 2.5% per year thereafter. The estimated future cash flows also included a 2.5% inflation factor applied to the future operating and development costs after five years and every year thereafter. The estimated future cash flows for the Company’s proved oil and gas properties and midstream assets were discounted at market-based weighted average costs of capital of 12.7% and 10.4%, respectively (see Note 11—Property, Plant and Equipment).

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Fresh start accounting. On the Emergence Date, the Company emerged from the Chapter 11 Cases and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of November 19, 2020. The inputs utilized in the valuation of the Company’s most significant assets, its oil and gas properties and midstream long-lived assets, included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials) as of November 19, 2020, operating and development costs, expected future development plans for the properties, estimated replacement costs and weighted-average cost of capital discount rates. The Company also recorded its ARO at fair value as a result of fresh start accounting. The inputs utilized in valuing the ARO liability, which are discussed above, are mostly Level 3 unobservable inputs. Refer to Note 3—Fresh Start Accounting for a detailed discussion of the fair value approaches and significant inputs used by the Company.

10. Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. The Company’s crude oil contracts will settle monthly based on the average NYMEX WTI. The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).

At December 31, 2020 (Successor), the Company utilized fixed price swaps to reduce the volatility of crude oil and natural gas prices on a significant portion of its future expected crude oil and natural gas production. The Company’s fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor), which the Company will receive for the volumes under contract.

All derivative instruments are recorded on the Company’s Consolidated Balance Sheets as either assets or liabilities measured at their fair value (see Note 9—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 Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when cash settlements on matured or liquidated derivative contracts result in making a payment to or receiving a payment from a counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.

In June 2020, following a decrease in crude oil commodity prices and the related increase in the fair value of derivative assets, the Company liquidated a portion of its crude oil three-way costless collar contracts prior to the expiration of their contractual maturities, resulting in cash proceeds of $25.3 million, which are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020.

On September 15, 2020, the Company entered into a Direction Letter and Specified Swap Liquidation Agreement (the “Letter Agreement”), which, among other things, amended its Predecessor Credit Facility. Pursuant to the Letter Agreement, beginning on September 15, 2020 and ending on the earlier of (1) October 15, 2020 and (2) the occurrence of an event of default under the Predecessor Credit Facility, the Company was required to use commercially reasonable efforts with respect to each of its swap agreements, to either (x) terminate such swap agreement or (y) reset such swap agreement to current market terms in existence at the time of such reset in exchange for a lump-sum cash payment substantially similar to the payment it would have received in respect of a termination of such swap agreement (each a “Specified Swap Liquidation”). The Letter Agreement also contained an agreement by the Company to apply the proceeds of any such Specified Swap Liquidation to prepayment of its loans under the Predecessor Credit Facility. Each Specified Swap Liquidation reduced the borrowing base and the aggregate elected commitment amounts under the Predecessor Credit Facility by an amount equal to any prepayment of the loans using the proceeds of such Specified Swap Liquidation (see Note 15—Long-Term Debt). During the period from September 15, 2020 through the Petition Date of the Chapter 11 Cases, which constituted an event of default under the Predecessor Credit Facility, the Company liquidated its outstanding swap agreements and received cash proceeds of $37.4 million for Specified Swap Liquidations, which are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows during the Predecessor period from January 1, 2020 through November 19, 2020.

In order to secure exit financing upon emerging from the Chapter 11 Cases, the Oasis Credit Facility included certain conditions that were required before closing, including minimum hedge volumes and prices. In the event the actual hedge prices were less than the target hedge prices, the borrowing base could have been subject to an availability block, set based on the shortfall. Specifically, OPNA, as borrower, was required to enter into hedges covering minimum hedge volumes of (i) 10,303 MBbl for the first year after the closing date, (ii) 6,761 MBbl for the second year after the closing date and (iii) 4,945 MBbl for the third year after the closing date; provided that, two-thirds of such hedging shall be entered into on the closing date of the Oasis Credit Facility, with the remainder to be entered into 30 days after the closing date. The target pricing for the hedges shall not be less

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than (i) $43.04 per barrel for the first year after the closing date, (ii) $43.94 per barrel for the second year after the closing date and (iii) $44.79 per barrel for the third year after the closing date. The Company had met the minimum hedging requirements as of the Emergence Date.

At December 31, 2020 (Successor), the Company had the following outstanding commodity derivative instruments:



Commodity	Settlement Period	Derivative Instrument	Index	Volumes		Weighted Average Prices		Fair Value Assets (Liabilities)

								(In thousands)
Crude oil	2021	Fixed price swaps	NYMEX WTI	9,748,000	Bbl	$	42.09		$	(59,262)
Crude oil	2022	Fixed price swaps	NYMEX WTI	7,245,000	Bbl	$	42.66		(27,759)
Crude oil	2023	Fixed price swaps	NYMEX WTI	5,265,000	Bbl	$	43.57		(10,054)
Crude oil	2024	Fixed price swaps	NYMEX WTI	434,000	Bbl	$	43.68		(613)
Natural gas	2021	Fixed price swaps	NYMEX HH	14,600,000	MMBtu	$	2.84		2,785
Natural gas	2022	Fixed price swaps	NYMEX HH	5,430,000	MMBtu	$	2.82		812
									$	(94,091)

Subsequent to December 31, 2020, the Company entered into new two-way costless collar options for crude oil with a weighted average floor price of $45.00 per barrel. The commodity contracts included total notional amounts of 459,000 barrels and 636,000 barrels which settle in 2021 and 2022, respectively, based on NYMEX WTI.

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


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
Statement of Operations Location					2019		2018


Net gain (loss) on derivative instruments	$	(84,615)	$	233,565	$	(106,314)	$	28,457

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 Consolidated Balance Sheets.

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


		Successor
		December 31, 2020
Commodity	Balance Sheet Location	Gross Recognized Assets/Liabilities		Gross Amount Offset		Net Recognized Fair Value Assets/Liabilities

		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	467	$	—	$	467
Commodity contracts	Derivative instruments — non-current assets	—		—		—
Total derivatives 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

		Predecessor
		December 31, 2019
Commodity	Balance Sheet Location	Gross Recognized Assets/Liabilities		Gross Amount Offset		Net Recognized Fair Value Assets/Liabilities

		(In thousands)
Derivatives assets:
Commodity contracts	Derivative instruments — current assets	$	633	$	(98)	$	535
Commodity contracts	Derivative instruments — non-current assets	3,295		(2,656)		639
Total derivatives assets		$	3,928	$	(2,754)	$	1,174
Derivatives liabilities:
Commodity contracts	Derivative instruments — current liabilities	$	33,812	$	(14,117)	$	19,695
Commodity contracts	Derivative instruments — non-current liabilities	686		(566)		120
Total derivatives liabilities		$	34,498	$	(14,683)	$	19,815

11. Property, Plant and Equipment

The following table sets forth the Company’s property, plant and equipment (in thousands):


	Successor		Predecessor
	December 31, 2020		December 31, 2019


Proved oil and gas properties	$	770,117	$	8,724,376
Less: Accumulated depreciation, depletion, amortization and impairment	(12,403)		(3,601,019)
Proved oil and gas properties, net	757,714		5,123,357
Unproved oil and gas properties	40,211		738,662
Other property and equipment	935,950		1,279,653
Less: Accumulated depreciation and impairment	(5,088)		(163,896)
Other property and equipment, net	930,862		1,115,757
Total property, plant and equipment, net	$	1,728,787	$	6,977,776

With the adoption of fresh start accounting, the Company recorded its property, plant and equipment at fair value as of the Emergence Date (refer to Note 3—Fresh Start Accounting).

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Impairment

The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. The Company determined no impairment indicators existed for its asset groups as of December 31, 2020 (Successor).

Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the proved oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed under Note 9—Fair Value Measurements.

As a result of the significant decline in expected future commodity prices coupled with the Company’s liquidity concerns, and the resulting decrease in its estimated proved reserves, the Company reviewed its proved oil and gas properties in both the Williston Basin and the Delaware Basin for impairment in the first quarter of 2020. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charges of $4.4 billion, including $3.8 billion related to the Williston Basin and $637.3 million related to the Permian Basin, to reduce the carrying values of its proved oil and gas properties to their estimated fair values. For the years ended December 31, 2019 and 2018 (Predecessor), the Company did not record impairment of proved oil and gas properties.

Unproved oil and gas properties. The Company assessed its unproved oil and gas properties for impairment and recorded impairment charges on its unproved oil and gas properties of $401.1 million for the period from January 1, 2020 through November 19, 2020 (Predecessor), and $5.4 million and $0.9 million for the years ended December 31, 2019 and 2018 (Predecessor), respectively, as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties.

Other property and equipment. The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Due to the significant decline in expected future commodity prices during the first quarter of 2020, the Company and other crude oil and natural gas producers changed their development plans, which resulted in lower forecasted throughput volumes for the Company’s midstream assets. As a result, the Company reviewed its midstream assets, grouped by commodity for each basin, for impairment as of March 31, 2020. The carrying amounts exceeded the estimated undiscounted future cash flows for certain midstream asset groups in the Williston Basin and the Delaware Basin, and as a result, the Company recorded impairment charges of $108.3 million during the period from January 1, 2020 through November 19, 2020 (Predecessor) to reduce the carrying values of these midstream assets to their estimated fair values. In addition, during the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded impairment charge of $1.6 million on certain midstream equipment, including a right-of-use asset associated with mechanical refrigeration units leased at the Company’s natural gas processing complex in the Williston Basin. No impairment charges were recorded on the Company’s midstream assets for the years ended December 31, 2019 and 2018 (Predecessor).

12. Acquisitions and Divestitures

Acquisitions

The Company actively reviews acquisition opportunities on an ongoing basis and acquires additional acreage and producing assets to supplement its existing operations. No significant acquisitions occurred during the year ended December 31, 2020.

2018 Permian Acquisition. On February 14, 2018 (Predecessor), the Company and OP Permian, a wholly owned subsidiary of the Company, acquired from Forge Energy, LLC (“Forge Energy”) approximately 22,000 net acres in the Permian Basin (the “2018 Permian Acquisition”) for aggregate consideration consisting of approximately $549.8 million in cash, inclusive of a $47.3 million deposit paid to Forge Energy in December 2017, and 46,000,000 shares of the Company’s common stock (the “Purchase Price”), including customary post close adjustments. In connection with the closing of the 2018 Permian Acquisition, the Company and Forge Energy entered into a Registration Rights Agreement that granted the equity holders of Forge Energy certain customary registration rights for the stock portion of the Purchase Price. The Company funded the cash portion of the Purchase Price with borrowings under the Predecessor Credit Facility and proceeds from the Company’s December 2017 issuance of Predecessor common stock.

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The 2018 Permian Acquisition represents the Company’s initial entry into the Permian Basin. The assets underlying the 2018 Permian Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the Permian sub-basin, across Ward, Winkler, Loving and Reeves Counties, Texas.

The 2018 Permian Acquisition qualified as a business combination. As such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the February 14, 2018 acquisition date. The 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). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 9—Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the 2018 Permian Acquisition at their estimated fair value of $921.0 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The 2018 Permian Acquisition is considered a taxable transaction; therefore, no deferred tax amounts were recognized at the acquisition date as the tax basis of the assets acquired and liabilities assumed were also recorded at fair value.

The following table summarizes the consideration paid for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date.


	Predecessor
	At February 14, 2018
	(In thousands)
Consideration paid to Forge Energy:
Cash	$	549,770
Common stock: 46,000,000 shares issued	371,220
	$	920,990
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	110,325
Proved undeveloped properties	166,552
Unproved lease acquisition costs	645,068
Inventory	293
Intangible assets	1,000
Asset retirement obligations	(2,248)
	$	920,990

The results of operations for the 2018 Permian Acquisition have been included in the Company’s consolidated financial statements since the February 14, 2018 closing date, including $71.7 million of total revenue and $15.6 million of operating income for the year ended December 31, 2018 (Predecessor).

Summarized below are the consolidated results of operations for the year ended December 31, 2018, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2017. The unaudited pro forma financial information was derived from the historical consolidated statements of operations of the Company and the statement of revenues and direct operating expenses for the 2018 Permian Acquisition properties, which were derived from the historical accounting records of Forge Energy. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.

Predecessor

Year Ended December 31, 2018

(In thousands, except per share data)

Unaudited

Revenues

2,327,476

Net loss attributable to Oasis

(30,754)

Net loss attributable to Oasis per share — basic and diluted

(0.10)

Other Delaware Acquisition. On September 12, 2018 (Predecessor), the Company completed the initial closing with undisclosed sellers to acquire certain E&P assets adjacent to the Company’s existing Permian position (the “Other Delaware

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Acquisition”) for total cash consideration of $59.5 million. The acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired as of the acquisition date. The Company recorded the oil and gas properties acquired at their estimated fair value of $59.5 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.

The results of operations for the Other Delaware Acquisition have been included in the Company’s consolidated financial statements since the closing date. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the Company’s Consolidated Statements of Operations.

Divestitures

The Company reviews portfolio opportunities on an ongoing basis and has engaged in various divestiture transactions over recent years. The Predecessor sold certain oil and gas properties in its E&P segment through various transactions and recognized a net gain on sale of properties of $11.1 million and a net loss on sale of properties of $0.4 million during the period from January 1, 2020 through November 19, 2020 and the year ended December 31, 2019, respectively.

2018 Divestitures. In 2018, the Company sold certain non-strategic properties in the Williston Basin through various divestitures (the “2018 Divestitures”). The 2018 Divestitures consisted of oil and gas properties in the Company’s E&P segment and included certain other property and equipment in the Company’s midstream segment. During the years ended December 31, 2019 and 2018 (Predecessor), the Company recognized a $4.0 million net loss on sale of properties and a $26.4 million net gain on sale of properties, respectively, in its Consolidated Statements of Operations related to the 2018 Divestitures.

13. Assets Held for Sale

During the fourth quarter of 2019, the Company began an active program to locate buyers for certain well services inventory and equipment in connection with the Well Services Exit. The assets expected to be sold related to the Well Services Exit met the criteria for assets held for sale and were classified as such as of December 31, 2019. The Well Services Exit did not represent a strategic shift that would have a major effect on the Company’s operations and financial results, and therefore, was not reported as discontinued operations. During the year ended December 31, 2019 (Predecessor), the Company recorded an impairment loss of $4.4 million, which was included in impairment on its Consolidated Statements of Operations, to adjust the carrying value of the assets held for sale to their estimated fair value less costs to sell, determined primarily based on indicative bids and indicative market pricing.

The Company completed various agreements for the sales of certain well services equipment related to the Well Services Exit and recognized a net loss on sale of properties of $0.7 million in its Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020 (Predecessor). The divested assets were included in the Company’s E&P segment, as the Company eliminated its well services business segment during the first quarter of 2020 in conjunction with the Well Services Exit.

During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded an impairment loss of $15.9 million, which was included in impairment on its Consolidated Statements of Operations, to write-off certain well services equipment no longer probable to be sold within one year and to adjust the carrying value of the remaining equipment held for sale to its estimated fair value less costs to sell. In addition, the Company recorded a non-cash charge of $1.5 million to adjust the carrying value of inventory held for sale to its net realizable value, which was included in other services expenses on the Company’s Consolidated Statements of Operations for the period from January 1, 2020 through November 19, 2020 (Predecessor).

Upon emergence from bankruptcy and the adoption of fresh start accounting, the Company’s assets held for sale were adjusted to their estimated fair value, less estimated costs to sell. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments.

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The Company’s assets held for sale consists of the following (in thousands):


	Successor		Predecessor
	December 31, 2020		December 31, 2019

Inventory	$	580	$	3,124
Other property and equipment	4,920		95,560
Less: Accumulated depreciation and impairment	—		(77,056)
Total assets held for sale, net	$	5,500	$	21,628

In 2018 (Predecessor), certain oil and gas properties included in the 2018 Divestitures were classified as held for sale, and the Company recorded a loss of $383.4 million, which was included in impairment on its Consolidated Statements of Operations, to adjust the carrying value of these assets, net of the associated ARO liabilities, to their estimated fair value, less costs to sell.

14. Goodwill and Intangible Assets

The Company’s amortizable intangible assets relate to third-party customer contracts, which were $15.0 million at December 31, 2020 (Successor). Accumulated amortization of intangible assets was immaterial at December 31, 2020 (Successor). The Company’s non-amortizable intangible assets at December 31, 2020 (Successor) were $28.7 million, consisting of the Company’s interest in OMP GP and seismic data. In addition, the excess of the Successor’s reorganization value over the fair value of identified tangible and intangible assets as of the Emergence Date was reported separately on the Company’s Consolidated Balance Sheets as goodwill. The Company’s non-amortizable intangible assets at December 31, 2019 (Predecessor) were $0.7 million, consisting of seismic data.

Based on the carrying value of amortizable intangible assets at December 31, 2020 (Successor), amortization expense for the subsequent five years is estimated as follows:


	(In thousands)
2021	$	2,723
2022	2,723
2023	2,723
2024	2,723
2025	959
Thereafter	3,149

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15. Long-Term Debt

The Company’s long-term debt consists of the following (in thousands):


	Successor		Predecessor
	December 31, 2020		December 31, 2019


Predecessor Credit Facility	$	—	$	337,000
Oasis Credit Facility	260,000		—
OMP Credit Facility	450,000		458,500
Senior unsecured notes
6.50% senior unsecured notes due November 1, 2021	—		71,835
6.875% senior unsecured notes due March 15, 2022	—		890,980
6.875% senior unsecured notes due January 15, 2023	—		351,953
6.25% senior unsecured notes due May 1, 2026	—		400,000
2.625% senior unsecured convertible notes due September 15, 2023	—		267,800
Total principal of senior unsecured notes	—		1,982,568
Less: unamortized deferred financing costs on senior unsecured notes	—		(15,618)
Less: unamortized debt discount on senior unsecured convertible notes	—		(50,877)
Total long-term debt	$	710,000	$	2,711,573

The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2020 is $710.0 million, which includes $260.0 million of borrowings under the Oasis Credit Facility and $450.0 million under the OMP Credit Facility. The Oasis Credit Facility and the OMP Credit Facility are recorded at values that approximate fair value since their variable interest rates are tied to current market rates.

The Oasis Credit Facility and the OMP Credit Facility mature in 2024 and 2022, respectively. The Company does not have any other debt that matures within the five years ending December 31, 2025.

Successor senior secured revolving line of credit

On the Emergence Date, Oasis Petroleum Inc., as parent, OPNA, as borrower, and certain of the Company’s subsidiaries, as guarantors (collectively, the “Credit Parties”) entered into the Oasis Credit Facility with Wells Fargo Bank, as administrative agent, swingline lender and the letter of credit issuer, and certain other financial institutions party thereto, as lenders. The Oasis Credit Facility refinanced the borrowings under the DIP Credit Facility and the Predecessor Credit Facility, both discussed below. As of December 31, 2020, the Oasis Credit Facility has an overall senior secured line of credit of $1,500.0 million and an aggregate amount of commitments of $575.0 million. The Oasis Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year, with one interim “wildcard” redetermination available to each of the Company and the administrative agent between scheduled redeterminations during any 12-month period. The next scheduled redetermination will be on or around April 1, 2021. The Oasis Credit Facility has a maturity date of May 19, 2024.

A portion of the Oasis Credit Facility, in an aggregate amount not to exceed $100.0 million, may be used for the issuance of letters of credit. Additionally, the Oasis Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million.

Borrowings under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Credit Parties’ assets, including mortgage liens on oil and gas properties having at least 90% of the reserve value as determined by reserve reports. OMP and its subsidiaries are not Credit Parties to 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 LIBOR loan (defined in the Oasis Credit Facility as a Eurodollar loan) or a domestic bank prime interest rate loan (defined in the Oasis Credit Facility as an Alternate Based Rate or “ABR” loan). As of December 31, 2020, any outstanding Eurodollar and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:

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Total Commitment Utilization Percentage	Applicable Margin for Eurodollar Loans		Applicable Margin for ABR Loans
Less than 25%	2.000	%	3.000	%
Greater than or equal to 25% but less than 50%	2.250	%	3.250	%
Greater than or equal to 50% but less than 75%	2.500	%	3.500	%
Greater than or equal to 75% but less than 90%	2.750	%	3.750	%
Greater than or equal to 90%	3.000	%	4.000	%

A loan may be repaid at any time before the scheduled maturity of the Oasis Credit Facility upon the Company providing advance notification to the lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a Eurodollar loan upon providing advance notification to the lenders. The minimum available loan term is one month and the maximum available loan term is six months for Eurodollar loans (or 12 months with the consent of each leader). Interest for Eurodollar loans is paid at the end of the applicable interest period for each loan or every three months for Eurodollar loans that have loan terms greater than three months. At the end of a Eurodollar loan term, the Oasis Credit Facility allows the Company to elect to repay the borrowing, continue a Eurodollar loan with the same or differing loan term or convert the borrowing to an ABR loan.

On a quarterly basis, the Company also pays a commitment fee of 0.500% on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter. Solely for purposes of calculating the commitment fee, swingline loans will not be deemed to be a utilization of the Company’s commitments.

The Oasis Credit Facility contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, investments, asset dispositions, fundamental changes, restricted payments, transactions with affiliates, and other customary covenants. On February 19, 2021, the Company entered into the first amendment to the Oasis Credit Facility, which amends the existing restricted payments negative covenant to provide additional restricted payment capacity under the Oasis Credit Facility until October 1, 2021. The additional restricted payment capacity, which is subject to certain restrictions, permits restricted payments in an aggregate amount not to exceed $25 million, of which, no more than $10 million of the added capacity may be used during any single fiscal quarter.

The financial covenants in the Oasis Credit Facility, commencing with the test period ending March 31, 2021, include:

•a requirement that the Company maintain a Ratio of Total Net Debt to EBITDAX (as defined in the Oasis Credit Facility, the “Leverage Ratio”) of less than 3.00 to 1.00 as of the last day of any fiscal quarter; and

•a requirement that the Company maintain a Current Ratio (as defined in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.

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

As of December 31, 2020 (Successor), the Company had $260.0 million of borrowings at a weighted average interest rate of 4.3% and $6.8 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $308.2 million.

Deferred financing costs. As of December 31, 2020 (Successor), the Company had $8.0 million of deferred financing costs related to the Oasis Credit Facility included in other assets on the Company’s Consolidated Balance Sheets, which are being amortized over the term of the Oasis Credit Facility. During the period from November 20, 2020 through December 31, 2020 (Successor), the Company recorded amortization of deferred financing costs of $0.3 million, which is included in interest expense on the Company’s Consolidated Statements of Operations.

Debtor-in-possession senior secured superpriority line of credit

On October 2, 2020, in connection with the Chapter 11 Cases, the Company entered into the DIP Credit Facility with certain consenting Predecessor Credit Facility lenders and Wells Fargo, as administrative agent and as issuing bank. The DIP Credit Facility had an aggregate line of credit of $450.0 million consisting of (i) new money revolving credit in an aggregate principal amount equal to $150.0 million ($100.0 million of which amount may also be used for the issuance of new letters of credit or deemed reissuance of pre-petition letters of credit) and (ii) a roll-up of the Predecessor Credit Facility pre-petition secured indebtedness in an aggregate amount of up to $300.0 million. The DIP Credit Facility, among other things, was used to finance the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases.

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Any loans (including loans incurred to repay disbursements of any pre-petition letters of credit refinanced under the DIP Credit Facility) rolled up and refinanced as post-petition secured indebtedness under the DIP Credit Facility accrued interest, at the Company’s election, at (x) the adjusted LIBO rate (subject to a 1.00% interest rate floor) plus 4.25% or (y) the alternate base rate (subject to a 2.00% interest rate floor) plus 3.25% per annum. Letters of credit (whether rolled-up or in the form of new money) under the DIP Credit Facility were also subject to a participation fee payable ratably to the DIP Credit Facility lenders in the amount of (x) with respect to new money letters of credit, 5.50% per annum and (y) with respect to rolled-up and refinanced letters of credit, 4.25% per annum.

On the Emergence Date, the DIP Credit Facility was terminated and the outstanding borrowings of $300.0 million were refinanced through the Oasis Credit Facility and the accrued interest of $1.4 million was paid in cash.

Predecessor senior secured revolving line of credit

The Predecessor Credit Facility had an overall senior secured line of credit of $3,000.0 million and aggregate elected commitments of $1,100.0 million prior to the filing of the Chapter 11 Cases. Amounts outstanding under the Predecessor Credit Facility bore interest at specified margins over the base rate of 0.75% to 1.75% for ABR loans or 2.25% to 3.25% for Eurodollar loans. These margins fluctuated based on the Company’s utilization of the facility. As a result of filing the Chapter 11 Cases, a default penalty of an additional 2% went into effect and increased the Predecessor Credit Facility interest rates above those interest rates noted above.

On April 24, 2020, the Company entered into that certain Limited Waiver and Fourth Amendment to the Predecessor Credit Facility, which included a waiver and forbearance agreement with respect to a third-party surety indemnity obligation (the “Surety Bond”) the Company obtained in support of commitments for a transportation agreement. The administrative agent advised the Company on April 2, 2020 that the Surety Bond constituted additional Debt (as defined in the Predecessor Credit Facility) not permitted under the Predecessor Credit Facility and that the Company’s certifications had failed to reflect the existence of the Surety Bond in its borrowing request. The lenders under the Predecessor Credit Facility granted a one-time waiver of these Defaults (as defined in the Predecessor Credit Facility), other than with respect to additional interest owed (the “Specified Default Interest”) of $30.3 million, which is included in interest expense on the Company’s Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020 (Predecessor). On the Emergence Date and pursuant to the Plan, the Specified Default Interest related to the Predecessor Credit Facility was discharged, released and deemed waived by the lenders, and the discharge was included in reorganization items, net on the Company’s Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020 (Predecessor).

On the Emergence Date, the Predecessor Credit Facility was terminated and the outstanding borrowings of $60.6 million were refinanced through the Oasis Credit Facility and accrued interest of $0.8 million was paid in cash.

Deferred financing costs. During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company recorded amortization of deferred Predecessor Credit Facility financing costs of $7.0 million. Amortization of deferred Predecessor Credit Facility financing costs recorded for the Predecessor years ended December 31, 2019 and 2018 were $6.4 million and $7.1 million, respectively. These costs are included in interest expense on the Company’s Consolidated Statements of Operations. For the year ended December 31, 2019 (Predecessor), the Company’s interest expense included $1.6 million for unamortized deferred financing costs related to the Predecessor Credit Facility, which were written off in proportion to the decrease in borrowing base. For the year ended December 31, 2018 (Predecessor), the Company’s interest expense included $0.3 million for unamortized deferred financing costs related to the Predecessor Credit Facility, which were written off in proportion to the two lenders leaving the bank group.

OMP Operating LLC revolving line of credit

Through its controlling interest in and consolidation of OMP, the Company includes the OMP Credit Facility in its consolidated financial statements. OMP uses this credit facility to fund working capital and to finance acquisitions and other capital expenditures specifically attributable to OMP. As of December 31, 2020, the OMP Credit Facility has an aggregate amount of commitments of $575.0 million and has a maturity date of September 25, 2022.

The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. All obligations of OMP Operating, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and several basis by OMP, Bighorn DevCo and Panther DevCo.

Borrowings under the OMP Credit Facility are subject to varying rates of interest based on (i) OMP’s most recently calculated consolidated total leverage ratio and (ii) whether the loan is a LIBOR loan (defined in the OMP Credit Facility as a Eurodollar loan) or a domestic bank prime interest rate loan (defined in the OMP Credit Facility as an ABR loan).

As of December 31, 2020, the borrowings under the OMP Credit Facility would have borne their respective interest rates plus the applicable margin indicated in the following table:

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Consolidated Total Leverage Ratio	Applicable Margin for Eurodollar Loans		Applicable Margin for ABR Loans		Commitment Fee Rate
Less than or equal to 3.00 to 1.00	1.75	%	0.75	%	0.375	%
Greater than 3.00 to 1.00 but less than or equal to 3.50 to 1.00	2.00	%	1.00	%	0.375	%
Greater than 3.50 to 1.00 but less than or equal to 4.00 to 1.00	2.25	%	1.25	%	0.500	%
Greater than 4.00 to 1.00 but less than or equal to 4.50 to 1.00	2.50	%	1.50	%	0.500	%
Greater than 4.50 to 1.00	2.75	%	1.75	%	0.500	%

The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Agreement).

In the second quarter of 2020, OMP identified that a Control Agreement (as defined in the OMP Credit Facility) had not been executed for a certain bank account before the account was initially funded with cash, which represented an event of default. In May 2020, the Partnership executed a Control Agreement with respect to the bank account, thereby completing the documentation required under the OMP Credit Facility. On September 29, 2020, OMP executed a Waiver, Discharge and Forgiveness Agreement and Forbearance Extension (the “Waiver and Forbearance Agreement”) to permanently waive payment of additional interest owed arising from this event of default (“OMP Specified Default Interest”) of $28.0 million, which is included in interest expense on the Predecessor Company’s Consolidated Statements of Operations during the period from January 1, 2020 through November 19, 2020. Such conditions were satisfied on November 19, 2020, and payment of OMP Specified Default Interest was permanently waived. Refer to Note 2 — Emergence from Voluntary Reorganization under Chapter 11 and Note 3 — Fresh Start Accounting for more information.

As of December 31, 2020, OMP had $450.0 million of borrowings and no outstanding letters of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $125.0 million. As of December 31, 2019, OMP had $458.5 million of borrowings under the OMP Credit Facility, resulting in an unused borrowing capacity of $114.8 million. As of December 31, 2020 and 2019, the weighted average interest rate on borrowings under the OMP Credit Facility was 2.2% and 3.8%, respectively. OMP Operating was in compliance with the financial covenants of the OMP Credit Facility as of December 31, 2020.

Deferred financing costs. Upon emergence from bankruptcy and the adoption of fresh start accounting, the Company wrote-off $1.5 million of deferred OMP Credit Facility financing costs previously included in other assets on the Company’s Consolidated Balance Sheets. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments. Prior to the aforementioned write-off, the Predecessor Company amortized deferred financing costs over the term of the OMP Credit Facility. These costs are included in interest expense on the Predecessor Company’s Consolidated Statements of Operations. During the period from January 1, 2020 through November 19, 2020, the Predecessor Company recorded amortization of deferred OMP Credit Facility financing costs of $0.8 million. Amortization of deferred OMP Credit Facility financing costs recorded for the Predecessor years ended December 31, 2019 and 2018 were $0.9 million and $0.5 million, respectively.

Predecessor senior unsecured notes and senior unsecured convertible notes

Prior to the Emergence Date, the Predecessor Company had outstanding Notes consisting of (i) $43.6 million 6.500% senior unsecured notes due 2021, (ii) $834.5 million 6.875% senior unsecured notes due 2022, (iii) $307.7 million 6.875% senior unsecured notes due 2023 and (iv) $395.1 million 6.250% senior unsecured notes due 2026 (the “Senior Notes”), and (v) $244.8 million 2.625% senior unsecured convertible notes due 2023 (the “Senior Convertible Notes”). The Notes were unsecured obligations of the Predecessor Company in the Chapter 11 Cases and were therefore included in liabilities subject to compromise on the Consolidated Balance Sheets of the Predecessor as of the Petition Date. On the Emergence Date, through implementation of the Plan, all outstanding obligations under the Notes were cancelled and 20,000,000 shares of Successor common stock were issued to the holders of the Predecessor’s Notes. In addition, the remaining unamortized deferred financing costs and debt discount were written off and included in reorganization items, net in the Consolidated Statements of Operations. Refer to Note 2 — Emergence from Voluntary Reorganization under Chapter 11 and Note 3 — Fresh Start Accounting for more information.

During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company repurchased an aggregate principal amount of $133.9 million of its outstanding Senior Notes for an aggregate cost of $52.9 million. The repurchases consisted of $28.2 million principal amount of the 6.50% senior unsecured notes due November 1, 2021, $56.5 million principal amount of the 6.875% senior unsecured notes due March 15, 2022, $44.2 million principal amount of the 6.875% senior unsecured notes due January 15, 2023 and $4.9 million principal amount of the 6.25% senior unsecured notes due May 1, 2026. As a result of these repurchases, the Company recognized a pre-tax gain of $80.2 million, which was net of unamortized

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deferred financing costs write-offs of $0.8 million, and is reflected in gain on extinguishment of debt on the Company’s Consolidated Statements of Operations for the period from January 1, 2020 through November 19, 2020.

During the period from January 1, 2020 through November 19, 2020 (Predecessor), the Company repurchased a principal amount of $23.0 million of its outstanding Senior Convertible Notes, for an aggregate cost of $15.2 million. As a result of these repurchases, the Company recognized a pre-tax gain of $3.7 million, which was net of write-offs of unamortized debt discount of $4.2 million, the equity component of the senior unsecured convertible notes of $0.3 million and unamortized deferred financing costs of $0.2 million, and is reflected in gain on extinguishment of debt on the Predecessor Company’s Consolidated Statements of Operations for the period from January 1, 2020 through November 19, 2020.

During 2019 (Predecessor), the Company repurchased an aggregate principal amount of $24.6 million of its outstanding Senior Notes, consisting of $10.5 million principal amount of the 6.875% senior unsecured notes due March 15, 2022 and $14.1 million principal amount of the 6.875% senior unsecured notes due January 15, 2023, for an aggregate cost of $22.8 million. As a result of these repurchases, the Company recognized a pre-tax gain of $1.6 million, which was net of unamortized deferred financing costs write-offs of $0.2 million, and is reflected in gain on extinguishment of debt in the Predecessor Company’s Consolidated Statements of Operations for the year ended December 31, 2019.

During 2019 (Predecessor), the Company repurchased a principal amount of $32.2 million of its outstanding Senior Convertible Notes, for an aggregate cost of $23.0 million. As a result of these repurchases, the Company recognized a pre-tax gain of $2.7 million, which was net of the unamortized debt discount write-offs of $6.2 million and the unamortized deferred financing costs write-offs of $0.3 million, and is reflected in gain on extinguishment of debt in the Predecessor Company’s Consolidated Statements of Operations for the year ended December 31, 2019.

16. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO (in thousands):



Asset retirement obligation as of December 31, 2018 (Predecessor)	$	52,449
Liabilities incurred during period	1,519
Liabilities settled during period(1)	(770)
Accretion expense during period	2,939
Revisions to estimates	647
Asset retirement obligation as of December 31, 2019 (Predecessor)	$	56,784
Liabilities incurred during period	535
Liabilities settled during period(1)	(196)
Accretion expense during period	2,775


Fresh start adjustment(2)	(11,681)
Asset retirement obligation as of November 19, 2020 (Predecessor)	$	48,217


Asset retirement obligation as of November 20, 2020 (Successor)	$	48,217
Liabilities incurred during period	35
Accretion expense during period	342

Asset retirement obligation as of December 31, 2020 (Successor)	$	48,594

__________________

(1)Liabilities settled during the period from January 1, 2020 through November 19, 2020 and the year ended December 31, 2019 included ARO related to sold properties (see Note 12—Acquisitions and Divestitures).

(2)Upon emergence from bankruptcy and the adoption of fresh start accounting, ARO liabilities were adjusted to their estimated fair value. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments.

Accretion expense is included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations. At December 31, 2020 (Successor), November 19, 2020 (Predecessor) and December 31, 2019 (Predecessor), the current portion of the total ARO balance was approximately $2.2 million, $0.3 million and $0.5 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.

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17. Income Taxes

The Company’s income tax benefit consists of the following (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018


Current:
Federal	$	—	$	(36)	$	(43)	$	(70)
State	—		—		27		93
	—		(36)		(16)		23
Deferred:
Federal	(2,918)		(221,277)		(28,148)		(3,553)
State	(529)		(41,649)		(4,551)		(2,313)
	(3,447)		(262,926)		(32,699)		(5,866)
Total income tax benefit	$	(3,447)	$	(262,962)	$	(32,715)	$	(5,843)

The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below:


	Successor				Predecessor
	Period from November 20, 2020 through December 31, 2020				Period from January 1, 2020 through November 19, 2020				Year Ended December 31,
									2019				2018

	(%)		(In thousands)		(%)		(In thousands)		(%)		(In thousands)		(%)		(In thousands)
U.S. federal tax statutory rate	21.00	%	$	(10,376)	21.00	%	$	(837,391)	21.00	%	$	(25,906)	21.00	%	$	(5,322)
State income taxes, net of federal income tax benefit	2.78	%	(1,373)		2.33	%	(93,063)		2.90	%	(3,573)		2.08	%	(527)
Effects of non-controlling interest	1.68	%	(830)		(0.44)	%	17,699		6.40	%	(7,895)		13.09	%	(3,317)
Non-deductible executive compensation	—	%	—		(0.03)	%	1,372		(1.70)	%	2,094		(9.50)	%	2,408
Equity-based compensation windfall (shortfall)	—	%	—		(0.22)	%	8,687		(1.75)	%	2,163		(3.68)	%	932
State deferred tax rate change	—	%	—		—	%	—		—	%	—		13.73	%	(3,479)
Change in valuation allowance	(18.09)	%	8,936		(13.88)	%	553,580		—	%	—		(6.74)	%	1,707
Impact of U.S. tax reform	—	%	—		—	%	—		—	%	—		(7.34)	%	1,859
Discharge of debt and other reorganization items	(0.47)	%	232		(2.14)	%	85,149		—	%	—		—	%	—
Other	0.07	%	(36)		(0.03)	%	1,005		(0.33)	%	402		0.41	%	(104)
Annual effective tax benefit	6.97	%	$	(3,447)	6.59	%	$	(262,962)	26.52	%	$	(32,715)	23.05	%	$	(5,843)

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Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2020 and 2019, were as follows (in thousands):


	Successor		Predecessor
	December 31, 2020		December 31, 2019


Deferred tax assets
Net operating loss carryforward	$	34,691	$	191,022
Oil and natural gas properties	566,856		—
Bonus and equity-based compensation	1,732		8,799
Derivative instruments	22,248		3,946
Other tax attribute carryovers	1,663		1,643
Other deferred tax assets	5,761		—
Total deferred tax assets	632,951		205,410
Less: Valuation allowance	(565,409)		(2,915)
Total deferred tax assets, net	$	67,542	$	202,495
Deferred tax liabilities
Oil and gas properties	$	—	$	426,130
Derivative instruments	—		—
Investment in partnerships	67,210		38,015
Other deferred tax liabilities	1,316		5,707
Total deferred tax liabilities	$	68,526	$	469,852
Total deferred tax liabilities, net	$	984	$	267,357

As of December 31, 2020 (Successor), the Company had federal net operating loss carryforwards of $141.8 million, after attribute reduction related to cancellation of indebtedness, which will not expire, and $148.1 million of state net operating loss carryforwards, after attribute reduction related to cancellation of indebtedness, which expire between 2023 and 2039. Our net operating losses will be subject to limitation under Section 382.The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not, and when the future utilization of some portion of the carryforwards is determined not to be more likely than not a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2020 (Successor) and 2019 (Predecessor), the Company’s valuation allowance balance was $565.4 million and $2.9 million, respectively. Based on the material write-down of the carrying value of the Company’s oil and gas properties recognized in 2020 and the Company’s operating results for 2020, the Company is in a net deferred tax asset position at 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 to estimate whether sufficient future taxable income will be generated to realize the benefit of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. 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 are reduced or increased 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 will continue to assess the valuation allowance on an ongoing basis.

Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”) addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As discussed in Note 2—Emergence from Voluntary Reorganization under Chapter 11, the Company’s common stock outstanding immediately prior to the Emergence Date was cancelled and new common stock was issued resulting in the Company experiencing an ownership change under Section 382. Further, certain of the transactions that occurred upon the Company’s emergence from bankruptcy on November 19, 2020 materially impacted the Company’s tax attributes. Cancellation of indebtedness income resulting from these transactions reduced the Company’s tax attributes, including but not limited to federal net operating loss carryforwards, in the amount of $1.4 billion. The ownership change did not result in a current federal tax liability at December 31, 2020.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2020 and 2019, the Company had no unrecognized tax benefits. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The

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Company files income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. The statute of limitation for the year ended December 31, 2020 will expire in 2024. The Company’s earliest open year in its key jurisdictions is 2017 for both the U.S. federal jurisdiction and various U.S. states. The Company has carried forward NOLs from previous years to utilize in 2020, which will allow the IRS to examine the closed loss years, the earliest of which is 2010.

18. Equity-Based Compensation

Successor equity-based compensation

Successor management incentive plan. On the Emergence Date and pursuant to the Plan, the Board of Directors adopted the 2020 LTIP, which provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, performance awards or any combination of the foregoing. The Company has reserved 2,402,402 shares of Successor common stock for grants of awards pursuant to the 2020 LTIP, which represent 10% of the total new Successor equity at Emergence Date. In addition, the Plan required the Board of Directors to allocate 5% of the 10% total new equity reserved under the 2020 LTIP no later than 45 days after emergence. The Plan also required that the allocated equity consist solely of restricted stock units on terms, including performance metrics and vesting criteria, agreed upon between the Company’s management and the Compensation Committee of the Board of Directors (the “Compensation Committee”). On January 18, 2021, in order to satisfy this equity allocation requirement, the Compensation Committee approved the grant of certain awards under the 2020 LTIP, which consists of the following:

•Restricted stock units. Restricted stock units that will vest over a four-year period to promote retention of key executives.

•Performance share units. Performance share units (“PSUs”) that may be earned based on the level of achievement with respect to the applicable performance metric. 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. Depending on the Company’s TSR performance relative to the defined peer group, award recipients may earn between 0% and 150% of the initial granted PSUs over three-year and four-year performance periods.

•Leveraged stock units. Leveraged stock units (“LSUs”) that may be earned over applicable performance periods depending upon 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 the initial granted LSUs over three-year and four-year performance periods.

Restricted stock awards. In addition, the Company granted restricted stock awards to directors under its 2020 LTIP, which will vest over a three-year period. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant, and compensation expense is recognized ratably over the requisite service period. The following table summarizes information related to restricted stock held by the Company’s directors for the periods presented:


	Successor
	Shares	Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding November 20, 2020	—	$	—
Granted	93,000	37.35
Vested	—	—
Forfeited	—	—
Non-vested shares outstanding December 31, 2020	93,000	$	37.35

Unrecognized expense as of December 31, 2020 (Successor) for all outstanding restricted stock awards was $3.5 million and will be recognized over a weighted average period of three years.

Predecessor equity-based compensation

The Predecessor granted equity awards to its officers, employees and directors under the Amended and Restated 2010 Long Term Incentive Plan (the “2010 LTIP”). The maximum number of shares available for grant under the 2010 LTIP was 16,050,000.

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2020 Incentive Compensation Program. In order to effectively incentivize employees in the then-current environment, the Board of Directors approved a revised 2020 incentive compensation program applicable to all employees effective June 12, 2020 (the “2020 Incentive Compensation Program”).

Under the 2020 Incentive Compensation Program, all 2020 equity-based awards, including restricted stock awards, performance share units (“PSUs”) and the OMP phantom unit awards (the “OMP Phantom Units”), previously granted under the 2010 LTIP, were forfeited and concurrently replaced with cash retention incentives, which were accounted for as modifications of such 2020 awards. In addition, all employees waived participation in the Company’s 2020 annual cash incentive plan and instead became eligible to earn cash performance incentives based on the achievement of certain specified incentive metrics measured on a quarterly basis from July 1, 2020 to June 30, 2021. The 2020 Incentive Compensation Program resulted in $15.6 million being paid in June 2020 with the remainder of the target amount under such program payable over the following 12 months.

For the Company’s officers and certain other senior employees, the prepaid cash incentives paid in June 2020 could be clawed back if (i) certain specified incentive metrics measured on a quarterly basis were not achieved from July 1, 2020 to December 31, 2020 and (ii) such individuals do not remain employed for a period of up to 12 months, unless such individuals are terminated without cause or resign for good reason. The after-tax value of the cash incentives paid to the Company’s officers and certain other senior employees of $8.8 million was capitalized to prepaid expenses and is being amortized over the relevant service periods. The Company immediately expensed the difference between the cash and after-tax value of the prepaid cash incentives of $4.1 million, which is not subject to the clawback provisions of the 2020 Incentive Compensation Program, and recognized additional compensation expenses of $0.4 million to adjust for the grant date fair value of certain original 2020 equity-based awards that exceeded the replacement cash retention incentives less amounts previously recognized for the original 2020 equity-based awards. On the Emergence Date and pursuant to the Plan, the remaining unamortized amount of prepaid cash incentives of $4.3 million was vested and included in general and administrative expenses on the Company’s Consolidated Statements of Operations.

For all other employees, the June 2020 incentive payment of $2.7 million was not subject to any clawback provisions, and $2.1 million, which represents the excess of the cash retention payment over amounts previously recognized for the original 2020 equity-based awards the cash incentives replaced, was immediately expensed.

The expenses related to the 2020 Incentive Compensation Program are included in general and administrative expenses on the Company’s Consolidated Statements of Operations.

Restricted stock awards. The Company granted restricted stock awards to its employees and directors under the 2010 LTIP, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period.

The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented:


	Shares	Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding December 31, 2019 (Predecessor)	5,736,167	$	8.77
Granted	3,516,579	3.06
Vested	(6,054,387)	7.92
Forfeited(1)	(3,198,359)	3.20
Non-vested shares outstanding November 19, 2020 (Predecessor)	—	$	—

___________________

(1)On June 12, 2020, all restricted stock awards issued to employees and non-employee directors in 2020 were forfeited and concurrently replaced with cash incentives under the 2020 Incentive Compensation Program. Refer to “2020 Incentive Compensation Program” above for more information.

Equity-based compensation expense recorded for restricted stock awards was $19.0 million for the period from January 1, 2020 through November 19, 2020, and $24.0 million and $20.1 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of awards vested was $47.3 million for the period from January 1, 2020 through November 19, 2020, and $14.6 million and $17.3 million for the years ended December 31, 2019 and 2018, respectively. The weighted average grant date fair value of restricted stock awards granted was $3.06 per share for the period from January 1, 2020 through November 19, 2020, and $6.61 per share and $10.20 per share for the years ended December 31, 2019 and 2018, respectively. On the Emergence

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Date and pursuant to the Plan, all outstanding unvested restricted stock awards were vested and the Company accelerated $6.7 million of expense during the period from January 1, 2020 through November 19, 2020.

Performance share units. The Company granted PSUs to its officers under the 2010 LTIP. The PSUs are awards of restricted stock units that may be earned based on the level of achievement with respect to the applicable performance metric, and each PSU that is earned represents the right to receive one share of the Company’s common stock.

The Company accounted for the PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the TSR achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 240% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.

The following table summarizes information related to PSUs held by the Company’s officers for the periods presented:


	Units	Weighted Average Grant Date Fair Value per Unit
Non-vested PSUs at December 31, 2019 (Predecessor)	3,027,224	$	9.12
Granted	2,429,747	2.56
Vested	(913,346)	8.29
Forfeited(1)	(2,396,524)	3.13
Cancelled	(2,147,101)	8.31
Non-vested PSUs November 19, 2020 (Predecessor)	—	$	—

___________________

(1)On June 12, 2020, all PSUs issued to the Company’s officers in 2020 were forfeited and concurrently replaced with cash incentives under the 2020 Incentive Compensation Program. Refer to “2020 Incentive Compensation Program” above for more information.

Equity-based compensation expense recorded for PSUs was $11.2 million for the period from January 1, 2020 through November 19, 2020, and $9.0 million and $8.5 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of PSUs vested was $7.6 million for the period from January 1, 2020 through November 19, 2020, and $2.6 million and $5.3 million for the years ended December 31, 2019 and 2018, respectively. The weighted average grant date fair value of PSUs granted was $2.56 per share for the period from January 1, 2020 through November 19, 2020, $6.80 per share and $12.71 per share for the years ended December 31, 2019 and 2018, respectively. On the Emergence Date and pursuant to the Plan, all outstanding PSUs were cancelled and the Company accelerated $4.7 million of expense during the period from January 1, 2020 through November 19, 2020.

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

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the periods presented:


	2020			2019			2018
Forecast period (years)	2 - 4			2 - 4			2 - 4
Risk-free interest rates	1.53% - 1.55%			2.55% - 2.56%			2.08% - 2.31%
Oasis stock price volatility	68.56		%	71.17		%	72.88		%
Oasis initial value	$	3.19		$	5.85		$	8.82
Oasis stock price on date of grant	$	2.77		$	6.63		$	9.27

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Associated tax benefit. For the years ended December 31, 2019 and 2018, the Company had an associated tax benefit of $7.8 million and $6.8 million, respectively, related to all equity-based compensation. The Company did not have any associated tax benefits related to equity-based compensation during the period from January 1, 2020 through November 19, 2020 (Predecessor) as a result of recording a valuation allowance on its deferred tax assets or during the period from November 20, 2020 through December 31, 2020 (Successor) as a result of the vesting of equity-based awards on the Emergence Date.

OMP phantom unit awards. The Company granted OMP Phantom Units to its employees under the 2010 LTIP. Each OMP Phantom Unit represents the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one OMP common unit on the day prior to the date it vests (the “Vesting Date”). Award recipients are also entitled to Distribution Equivalent Rights (“DER”) with respect to each OMP Phantom Unit received. Each DER represents the right to receive, upon vesting of the award, a cash payment equal to the value of the distributions paid on one OMP common unit between the grant date and the applicable Vesting Date. The OMP Phantom Units generally vest in equal installments each year over a three-year period from the date of grant, and compensation expense will be recognized over the requisite service period and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations.

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

The following table summarizes information related to OMP Phantom Units held by certain employees of Oasis for the periods presented:


	Phantom Units	Weighted Average Fair Value per Unit
Non-vested units outstanding December 31, 2019 (Predecessor)	362,002	$	19.09
Granted	242,500	8.65
Vested	(242,360)	14.01
Forfeited(1)	(315,615)	8.64
Non-vested units outstanding November 19, 2020 (Predecessor)	46,527	$	11.77
Granted	—	—
Vested	(19,927)	12.21
Forfeited	—	—
Non-vested units outstanding December 31, 2020 (Successor)	26,600	$	12.55

___________________

(1)On June 12, 2020, all OMP Phantom Units issued to certain employees of Oasis in 2020 were forfeited and concurrently replaced with cash incentives under the 2020 Incentive Compensation Program. Refer to “2020 Incentive Compensation Program” above for more information.

Equity-based compensation expense recorded for the OMP Phantom Units for the period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018 was $1.5 million, $2.5 million and $0.5 million, respectively. The fair value of OMP Phantom Units vested was $3.4 million for the period from January 1, 2020 through November 19, 2020 and $0.8 million and $0.6 million for the years ended December 31, 2019 and 2018, respectively. For the period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018, the weighted average grant date fair value of OMP Phantom Units granted was $8.65 per unit, $18.57 per unit and $23.91 per unit, respectively. On the Emergence Date and pursuant to the Plan, outstanding unvested OMP Phantom Units for certain employees were vested and the Company accelerated $1.1 million of expense during the period from January 1, 2020 through November 19, 2020.

Equity-based compensation expense recorded for the OMP Phantom Units was $0.2 million for the Successor 2020 Period. As of December 31, 2020 (Successor), unrecognized compensation cost for all outstanding OMP Phantom Units was $0.2 million, which is expected to be recognized over a weighted average period of 1.3 years.

Class B units in OMP GP. In May 2017, OMP GP granted restricted Class B units to certain employees, including OMP’s executive officers, as consideration for services to Oasis, which vest over a ten-year period. The restricted Class B units represent 8% of the outstanding units of OMP GP as of December 31, 2020 (Successor). Compensation expense is recognized ratably over the requisite service period. Equity-based compensation expense recorded for the Class B units was $0.2 million and $0.9 million for the Successor period from November 20, 2020 through December 31, 2020 and Predecessor period from January 1, 2020 through November 19, 2020, respectively, and $0.2 million and $0.3 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements

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of Operations. On the Emergence Date and pursuant to the Plan, outstanding unvested Class B units for certain employees were vested and the Company accelerated $0.7 million of expense during the period from January 1, 2020 through November 19, 2020.

OMP equity-based compensation

The Oasis Midstream Partners LP 2017 Long Term Incentive Plan (the “OMP LTIP”) provides for the grant, at the discretion of the board of directors of OMP GP, of equity-based awards by OMP. As of December 31, 2020 (Successor), the aggregate number of OMP common units that may be issued pursuant to any and all awards under the OMP LTIP is equal to 2,793,360 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the OMP LTIP. On January 1 of each calendar year following the adoption and prior to the expiration of the OMP LTIP, the total number of common units that may be issued pursuant to the OMP LTIP automatically increases by a number of common units equal to one percent of the number of common units outstanding on a fully diluted basis as of the close of business on the immediately preceding December 31 (calculated by adding to the number of common units outstanding, all outstanding securities convertible into common units on such date on an as converted basis). As a result of this adjustment, an additional 338,114 common units were reserved for issuance pursuant to awards under the OMP LTIP on January 1, 2021.

OMP restricted unit awards. OMP has granted restricted unit awards to independent directors of the general partner under the OMP LTIP, which vest over a one-year period from the date of grant. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. The fair value of restricted unit awards is based on the closing sales price of OMP’s common units on the date of grant, and compensation expense is recognized ratably over the requisite service period.

The following table summarizes information related to restricted units held by certain directors of OMP for the periods presented:


	Restricted Units	Weighted Average Grant Date Fair Value per Unit
Non-vested units outstanding December 31, 2019 (Predecessor)	16,170	$	18.57
Granted	16,170	16.69
Vested	(16,170)	18.57
Forfeited	—	—
Non-vested units outstanding November 19, 2020 (Predecessor)	16,170	$	16.69
Granted	—	—
Vested	—	—
Forfeited	—	—
Non-vested units outstanding December 31, 2020 (Successor)	16,170	$	16.69

Equity-based compensation expense recorded for OMP restricted unit awards was $0.2 million for the period from January 1, 2020 through November 19, 2020, and $0.4 million for the years ended December 31, 2019 and 2018, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of OMP restricted unit awards vested was $0.3 million for the period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018, respectively. The weighted average grant date fair value of OMP restricted stock awards granted was $16.69 per unit for the period from January 1, 2020 through November 19, 2020 and $18.57 per unit and $17.55 per unit for the years ended December 31, 2020, 2019 and 2018, respectively.

The Successor recorded immaterial equity-based compensation expense recorded for OMP restricted unit awards for the period from November 20, 2020 through December 31, 2020. Unrecognized expense as of December 31, 2020 (Successor) for all outstanding OMP restricted unit awards was $0.01 million, and will be recognized over a weighted average period of 0.1 years.

19. Stockholders’ Equity

Dividends. The Company declared a $0.375 per share dividend for the fourth quarter of 2020 for shareholders of record as of March 8, 2021, payable on March 22, 2021. Covenants contained in the Oasis Credit Facility restrict the payment of cash dividends on its common stock.

Common Stock. On the Emergence Date, the Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, the authority to issue a total of 65,000,000 shares of all classes of capital stock, of which 60,000,000 shares are common stock, par value $0.01 per share and 5,000,000 shares are preferred stock, par value $0.01 per share.

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Warrants. On the Emergence Date and pursuant to the Plan, the Company issued 1,621,622 Warrants pro rata to holders of the Predecessor’s common stock. The Warrants, which are classified as equity, are initially exercisable to purchase one share of Successor common stock per Warrant at an initial exercise price of $94.57 per Warrant (the “Exercise Price”). 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 Successor common stock will terminate. The number of shares of Successor 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 Successor common stock or (2) a reclassification in respect of Successor common stock.

The following assumptions were used for the Black-Scholes option pricing model to determine the fair value for the Warrants upon issuance:


	Successor
	2020
Risk-free interest rate	0.31		%
Dividend yield	—		%
Expected life (years)	4
Expected volatility	65.0		%
Common stock per share	$	47.09
Calculated fair value	$	23,805

20. Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of unvested restricted stock awards, contingently issuable shares related to PSUs, senior convertible notes and warrants during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share.

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
	Period from November 20, 2020 through December 31, 2020	Period from January 1, 2020 through November 19, 2020	Year Ended December 31,
			2019	2018


Weighted average common shares outstanding:
Basic and diluted	19,991	317,644	315,002	307,480



Anti-dilutive weighted average common shares:
Unvested restricted stock awards and PSUs	9	5,216	9,242	6,980

During the period from November 20, 2020 through December 31, 2020 (Successor), the Company incurred a net loss, and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested stock awards. In addition, the diluted earnings per share calculation for the period from November 20, 2020 through December 31, 2020 (Successor) excludes the dilutive effect of warrants outstanding that were anti-dilutive under the treasury stock method. During the period from January 1, 2020 through November 19, 2020 (Predecessor) and the years ended December 31, 2019 and 2018 (Predecessor), the Company incurred a net loss, and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested stock awards.

The Company has the option to settle conversions of its Predecessor Senior Convertible Notes (see Note 15—Long-Term Debt) with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. The conversion value did not exceed the principal amount of the

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Predecessor notes during the period from January 1, 2020 through November 19, 2020 and the years ended December 31, 2019 and 2018 and accordingly, there was no impact to diluted earnings per share.

21. Business Segment Information

The Company has two reportable segments: E&P and midstream. Prior to the Well Services Exit in the first quarter of 2020, the Company also had a well services segment, which is no longer a reportable segment and the remaining services performed by OWS are reported within the Company’s E&P segment. To conform to the current period reportable segments presentation, the prior periods have been restated to reflect the change in reportable segments.

The Company’s E&P segment is engaged in the acquisition and development of oil and gas properties. Revenues for the E&P segment are derived from the sale of crude oil and natural gas production.

The Company’s midstream segment performs midstream services including: (i) natural gas gathering, compression, processing and gas lift supply; (ii) crude oil gathering, terminaling and transportation; (iii) produced and flowback water gathering and disposal; and (iv) freshwater distribution. Revenues for the midstream segment are derived from performing these midstream services to support the E&P operations of the Company as well as third-party producers. The revenues and expenses related to goods and 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 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.

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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
Period from November 20, 2020 through December 31, 2020
Revenues from external customers	$	93,794	$	26,121	$	—	$	119,915
Inter-segment revenues	—		17,136		(17,136)		—
Total revenues	93,794		43,257		(17,136)		119,915
Operating income (loss)	18,662		20,702		(588)		38,776
Other income (expense), net	(87,161)		(1,024)		—		(88,185)
Income (loss) before income taxes including non-controlling interests	$	(68,499)	$	19,678	$	(588)	$	(49,409)
Total assets(1)	$	1,093,253	$	1,066,060	$	(276)	$	2,159,037
Property, plant and equipment, net	837,020		892,043		(276)		1,728,787
Capital expenditures(2)	15,403		3,054		(385)		18,072
Depreciation, depletion and amortization	13,789		4,199		(1,894)		16,094
General and administrative	12,234		3,850		(1,860)		14,224
Equity-based compensation	—		270		—		270

Predecessor
Period from January 1, 2020 through November 19, 2020
Revenues from external customers	$	775,888	$	187,531	$	—	$	963,419
Inter-segment revenues	—		189,284		(189,284)		—
Total revenues	775,888		376,815		(189,284)		963,419
Operating income	(4,957,630)		51,989		(6,118)		(4,911,759)
Other income (expense), net	842,783		84,627		(3,224)		924,186
Income (loss) before income taxes including non-controlling interests	$	(4,114,847)	$	136,616	$	(9,342)	$	(3,987,573)


Capital expenditures(2)	$	203,847	$	24,266	$	(2,772)	$	225,341
Depreciation, depletion and amortization	271,002		36,670		(16,557)		291,115
General and administrative	125,818		34,103		(14,627)		145,294
Equity-based compensation	29,794		1,930		(409)		31,315
Impairment	4,825,530		111,613		—		4,937,143

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Predecessor
Year Ended December 31, 2019
Revenues from external customers	$	1,859,506	$	212,238	$	—	$	2,071,744
Inter-segment revenues	—		276,189		(276,189)		—
Total revenues	1,859,506		488,427		(276,189)		2,071,744
Operating income (loss)	(75,986)		241,161		(10,752)		154,423
Other expense, net	(260,720)		(17,065)		—		(277,785)
Income (loss) before income taxes including non-controlling interests	$	(336,706)	$	224,096	$	(10,752)	$	(123,362)
Total assets(1)	$	6,418,610	$	1,121,159	$	(40,516)	$	7,499,253
Property, plant and equipment, net	5,939,389		1,078,903		(40,516)		6,977,776
Capital expenditures(2)	642,352		212,381		(11,365)		843,368
Depreciation, depletion and amortization	771,640		37,152		(21,600)		787,192
General and administrative	108,945		31,737		(17,176)		123,506
Equity-based compensation	32,755		1,744		(892)		33,607
Impairment	10,257		—		—		10,257
Predecessor
Year Ended December 31, 2018
Revenues from external customers	$	2,197,810	$	124,137	$	—	$	2,321,947
Inter-segment revenues	—		162,505		(162,505)		—
Total revenues	2,197,810		286,642		(162,505)		2,321,947
Operating income (loss)	(14,992)		143,126		(9,122)		119,012
Other expense	(142,230)		(2,125)		—		(144,355)
Income (loss) before income taxes including non-controlling interests	$	(157,222)	$	141,001	$	(9,122)	$	(25,343)
Total assets(1)	$	6,747,616	$	907,677	$	(29,151)	$	7,626,142
Property, plant and equipment, net	6,162,975		893,285		(29,151)		7,027,109
Capital expenditures(2)	1,934,970		277,626		(9,143)		2,203,453
Depreciation, depletion and amortization	623,133		29,282		(16,119)		636,296
General and administrative	109,323		24,700		(12,677)		121,346
Equity-based compensation	28,393		1,547		(667)		29,273
Impairment	384,228		—		—		384,228

__________________

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

(2)Capital expenditures reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the Company’s Consolidated Statements of Cash Flows because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statements of Cash Flows are presented on a cash basis. Acquisitions totaled $21.0 million and $951.9 million for the years ended December 31, 2019 (Predecessor) and 2018 (Predecessor), respectively, in the E&P segment. There were no significant acquisitions during the period from January 1, 2020 through November 19, 2020 (Predecessor) and period from November 20, 2020 through December 31, 2020 (Successor). Additionally, capital expenditures reflected in the table includes consideration paid through the issuance of common stock in connection with the 2018 Permian Acquisition for the year ended December 31, 2018.

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22. Leases

As discussed in Note 4—Summary of Significant Accounting Policies, the Company adopted ASC 842 as of January 1, 2019. The Company’s leases consist primarily of office space, drilling rigs, vehicles and other property and equipment used in its operations. The components of lease costs were as follows for the periods presented (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019


Operating lease costs	$	751	$	5,797	$	26,341
Variable lease costs(1)	437		2,678		9,189
Short-term lease costs	554		9,807		4,657
Finance lease costs:
Amortization of ROU assets	153		1,987		2,543
Interest on lease liabilities	11		167		260
Total lease costs	$	1,906	$	20,436	$	42,990

___________________

(1)Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.

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

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

For the year ended December 31, 2018 (Predecessor), the Company had operating leases for office space and other property and equipment used in its operations, which it accounted for as operating leases in accordance with GAAP under ASC 840. For the year ended December 31, 2018 (Predecessor), the Company incurred operating rental expenses of $10.6 million which were included in general and administrative expenses on its Consolidated Statements of Operations.

As of December 31, 2020 (Successor), maturities of the Company’s lease liabilities were as follows (in thousands):


	Successor
	Operating Leases		Finance Leases


2021	$	2,744	$	1,722
2022	1,548		1,210
2023	787		260
2024	102		45
2025	—		45
Thereafter	—		594
Total future lease payments	5,181		3,876
Less: Imputed interest	211		346
Present value of future lease payments	$	4,970	$	3,530

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Supplemental balance sheet information related to the Company’s leases were as follows (in thousands):


		Successor(1)		Predecessor
	Balance Sheet Location	December 31, 2020		December 31, 2019


Assets
Operating lease assets	Operating right-of-use assets	$	6,083	$	18,497
Finance lease assets(2)	Other assets	3,419		6,303
Total lease assets		$	9,502	$	24,800
Liabilities
Current
Operating lease liabilities	Current operating lease liabilities	$	2,607	$	6,182
Finance lease liabilities	Other current liabilities	1,626		2,413
Long-term
Operating lease liabilities	Operating lease liabilities	2,362		17,915
Finance lease liabilities	Other liabilities	1,904		3,958
Total lease liabilities		$	8,499	$	30,468

___________________

(1)Upon emergence from bankruptcy and the adoption of fresh start accounting, operating lease ROU assets and operating and finance lease liabilities were adjusted to their estimated fair value. Refer to Note 3—Fresh Start Accounting for more information on Fresh Start Adjustments.

(2)Finance lease ROU assets are recorded net of accumulated amortization of $0.2 million as of December 31, 2020 (Successor) and $2.3 million as of December 31, 2019 (Predecessor).

Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019

Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	1,992	$	6,624	$	30,316
Operating cash flows from finance leases	9		145		260
Financing cash flows from finance leases	202		1,989		2,382
ROU assets obtained in exchange for lease obligations
Operating leases	$	—	$	797	$	12,746
Finance leases	—		24		3,433
Reductions to ROU assets resulting from reductions to lease obligations
Operating leases(1)	$	(6,255)	$	—	$	—

___________________

(1)Includes amounts added to or reduced from the carrying amount of ROU assets resulting from lease modifications and remeasurements in connection with the Company’s bankruptcy emergence.

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

Successor

Predecessor

December 31, 2020

December 31, 2019

Operating Leases

Weighted average remaining lease term

2.6 years

7.1 years

Weighted average discount rate

3.9

4.1

Finance Leases

Weighted average remaining lease term

4.6 years

4.1 years

Weighted average discount rate

3.6

3.9

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23. Significant Concentrations

Major customers. For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of the Company’s total product sales. For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of the Company’s total product sales. For the year ended December 31, 2019 (Predecessor), sales to Phillips 66 Company accounted for approximately 14% of the Company’s hydrocarbon product sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2020 or 2019. For the year ended December 31, 2018 (Predecessor), no purchaser accounted for more than 10% of the Company’s total sales. Additionally, the majority of the Company’s midstream revenues are derived from providing services to the Company’s operated wells.

Substantially all of the Company’s accounts receivable result from sales of crude oil, natural gas and NGLs as well as joint interest billings to third-party companies who have working interest payment obligations in projects completed by the Company. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions, including the current downturn in crude oil prices. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, natural gas and NGL purchasers in the Company’s producing regions.

24. Commitments and Contingencies

Included below is a discussion of various future commitments of the Company as of December 31, 2020. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of December 31, 2020, the Company’s material off-balance sheet arrangements and transactions include $6.8 million in outstanding letters of credit issued under its Oasis Credit Facility and $49.0 million in net surety bond exposure issued as financial assurance on certain agreements.

Volume commitment agreements. As of December 31, 2020, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 46.6 MMBbl of crude oil, 704.1 Bcf of natural gas, 28.1 MMBbl of NGLs and 8.7 MMBbl of water, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less, except for one agreement with a remaining term of approximately 24 years. These amounts are recognized as gathering, processing and transportation expense in the Company’s Consolidated Statements of Operations.

The estimable future commitments under these volume commitment agreements as of December 31, 2020 are as follows:


	(In thousands)
2021	$	89,118
2022	102,038
2023	96,174
2024	83,543
2025	69,287
Thereafter	84,836
	$	524,996

The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.

The Company enters into long-term contracts to provide production flow assurance in oversupplied basins and/or areas with limited infrastructure. This strategic tactic provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.

Continuous development agreement. In connection with the closing of the 2018 Permian Acquisition, Forge Energy entered into and assigned to OP Permian a continuous development agreement (the “CDA”) with the Commissioner of the General Land Office, on behalf of the State of Texas (collectively, the “State”), as approved by the Board for Lease of University Lands

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(together with the State, “University Lands”). The CDA concerns certain leases covering a substantial portion of the acreage that the Company indirectly acquired from Forge Energy in the 2018 Permian Acquisition and under which University Lands is the lessor. Pursuant to the CDA, the tracts covered by these leases are pooled into a single development area for which the Company indirectly holds an eight-year initial term ending on December 31, 2025, with an additional five-year term for certain retained acreage at certain depths in the Delaware, Bone Spring and Wolfcamp formations. If OP Permian fails to meet certain drilling and development obligations, the CDA may be subject to early termination, in which case, the Company may be obligated to pay non-performance fees of up to approximately $100 million. Due to the extraordinary market conditions during 2020, the Company agreed with University Lands to pause operations, and on December 31, 2020, executed an amendment to the CDA reflecting that agreement. The amendment reduced or postponed certain drilling and development obligations for the year ended December 31, 2020 and did not result in the payment of any penalty. The Company’s current budget contemplates drilling activity which does not meet certain obligations under the CDA. The Company is currently in discussions with University Lands, similar to those held in 2020, in which it will seek an amendment for the reduction of its drilling obligations for 2021 similar to that previously received. The Company can provide no assurance that it will be successful in obtaining this amendment. Given the early stages of the Company’s discussions with University Lands on its drilling obligations for 2021 and the continuous flexibility the Company has with its drilling program to adjust as market and business conditions warrant, the Company cannot predict whether it will incur losses or estimate the amount of any potential loss.

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

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

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

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

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

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

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

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

On March 13, 2020, Mirada filed a seventh amended petition that did not assert any new causes of action and did not add any new parties. Mirada did add an allegation that Oasis breached its implied duty of good faith and fair dealing with respect to certain contracts.

On April 30, 2020, Mirada abandoned its prior claims related to overstating the estimated costs of proposed well operations in Wild Basin.

On September 28, 2020, the Oasis Entities entered into a Settlement and Mutual Release Agreement (the “Mirada Settlement Agreement”) with Mirada. The Mirada Settlement Agreement provides for, among other things, payment by OPNA to certain Mirada related parties of $42.8 million ($20.0 million was paid on the effective date of the Plan, and the balance is due on or before 180 days after the effective date of the Plan) and mutual releases, including, without limitation, release of all claims asserted in the Mirada litigation against the Oasis Entities. The Company obtained approval of the Mirada Settlement Agreement by the Bankruptcy Court pursuant to the Plan and paid Mirada $20.0 million on the Emergence Date. The Company has an accrual for the $22.8 million balance due recorded in accrued liabilities on its Consolidated Balance Sheet as of December 31, 2020.

Solomon litigation. On or about August 28, 2019, OP LLC, a wholly-owned subsidiary of the Company, was named as a defendant in the lawsuit styled Andrew Solomon, on behalf of himself and those similarly situated v. Oasis Petroleum, LLC, pending in the United States District Court for the District of North Dakota. The lawsuit alleged violations of the federal Fair Labor Standards Act and Title 29 of the North Dakota Century Code as the result of OP LLC’s alleged practice of paying the plaintiff and similarly situated current and former employees overtime at rates less than required by applicable law, or failing to pay for certain overtime hours worked. The lawsuit requested that: (i) its federal claims be advanced as a collective action, with a class of all operators, technicians and all other employees in substantially similar positions employed by OP LLC who were paid hourly for at least one week during the three year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or eight or more hours on at least one workday; and (ii) its state claims be advanced as a class action, with a class of all operators, technicians, and all other employees in substantially similar positions employed by OP LLC in North Dakota during the two year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or worked eight or more hours in a day on at least one workday.

On September 14, 2020, OP LLC entered into a Settlement Agreement and Release of All Claims with Mr. Solomon which provides for, among other things, payment by OP LLC of $15,000 and a release by Mr. Solomon of claims against OP LLC and its affiliates, which includes, but is not limited to, all claims asserted, or which could have been asserted, against OP LLC and its affiliates arising out of or relating in any way to the Solomon litigation. On September 25, 2020, the Solomon litigation was dismissed with prejudice.

25. Subsequent Events

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

26. Supplemental Oil and Gas Disclosures — Unaudited

The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities.

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Capitalized Costs

The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities at December 31 (in thousands):



	Successor		Predecessor
	December 31, 2020		December 31, 2019


Proved oil and gas properties	$	770,117	$	8,724,376
Less: Accumulated depreciation, depletion, amortization and impairment	(12,403)		(3,601,019)
Proved oil and gas properties, net	757,714		5,123,357
Unproved oil and gas properties	40,211		738,662
Total oil and gas properties, net	$	797,925	$	5,862,019

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018


Acquisition costs:
Proved oil and gas properties	$	—	$	—	$	—	$	260,034
Unproved oil and gas properties	336		536		23,058		696,293
Exploration costs	105		1,225		67,470		53,928
Development costs	14,624		199,537		542,133		923,562
Asset retirement costs	35		181		2,083		5,804
Total costs incurred	$	15,100	$	201,479	$	634,744	$	1,939,621

Results of Operations for Oil and Gas Producing Activities

The following table sets forth the results of operations for oil and gas producing activities, which exclude general and administrative expenses and interest expense, for the periods presented (in thousands):


	Successor		Predecessor
	Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
					2019		2018


Revenues	$	86,442	$	603,585	$	1,408,771	$	1,590,024
Production costs	32,903		249,707		464,782		434,801
Depreciation, depletion and amortization	12,745		264,822		759,900		613,928
Exploration costs	—		2,748		6,658		27,432
Rig termination	—		1,279		384		—
Impairment	—		4,800,785		5,389		384,228
Income tax (benefit) expense	9,648		(1,115,276)		40,745		30,770
Results of operations for oil and gas producing activities	$	31,146	$	(3,600,480)	$	130,913	$	98,865

27. Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on crude oil and natural gas reserve estimation and disclosures. All of the Company’s oil and gas reserves are attributable to properties within the United States.

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Proved oil and gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

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Estimated Quantities of Proved Crude Oil and Natural Gas Reserves

The following table summarizes changes in quantities of the Company’s estimated net proved reserves for the periods presented:


	Crude Oil (MBbl)	Natural Gas (MMcf)	MBoe(1)
2018
Proved reserves
Beginning balance (Predecessor)	224,960	523,456	312,204
Revisions of previous estimates	(17,352)	3,019	(16,850)
Extensions, discoveries and other additions	30,640	46,309	38,358
Sales of reserves in place	(12,470)	(20,735)	(15,926)
Purchases of reserves in place	25,688	43,107	32,873
Production	(23,050)	(42,430)	(30,122)
Net proved reserves at December 31, 2018 (Predecessor)	228,416	552,726	320,537
Proved developed reserves, December 31, 2018 (Predecessor)	144,533	339,444	201,107
Proved undeveloped reserves, December 31, 2018 (Predecessor)	83,883	213,282	119,430
2019
Proved reserves
Beginning balance (Predecessor)	228,416	552,726	320,537
Revisions of previous estimates	(51,965)	(68,301)	(63,349)
Extensions, discoveries and other additions	49,297	87,382	63,861
Sales of reserves in place	(2,136)	(2,368)	(2,531)

Production	(22,825)	(55,906)	(32,142)
Net proved reserves at December 31, 2019 (Predecessor)	200,787	513,533	286,376
Proved developed reserves, December 31, 2019 (Predecessor)	113,418	314,000	165,751
Proved undeveloped reserves, December 31, 2019 (Predecessor)	87,369	199,533	120,625
2020
Proved reserves
Beginning balance (Predecessor)	200,787	513,533	286,376
Revisions of previous estimates	(69,782)	(98,815)	(86,251)
Extensions, discoveries and other additions	4,578	8,659	6,021


Production	(15,818)	(47,207)	(23,686)
Net proved reserves at December 31, 2020 (Successor)	119,765	376,170	182,460
Proved developed reserves, December 31, 2020 (Successor)	85,428	262,676	129,207
Proved undeveloped reserves, December 31, 2020 (Successor)	34,337	113,494	53,253

__________________

(1)Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.

Revisions of Previous Estimates

In 2020, the Company had net negative revisions of 86.3 MMBoe, or 30% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 60.1 MMBoe associated with alignment to the five-year development plan and 31.9 MMBoe due to lower realized prices, offset by positive revisions of 5.6 MMBoe for the addition of proved undeveloped reserves (“PUDs”) that were previously removed from the five-year development plan. Proved developed revisions were primarily due to negative revisions of 29.3 MMBoe due to lower realized prices, partially offset by positive revisions of 1.5 MMBoe due to lower operating expenses. The PUD revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 2.6 MMBoe due to lower realized price.

In 2019, the Company had net negative revisions of 63.3 MMBoe, or 20% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 51.2 MMBoe due to well performance, 11.2 MMBoe due to lower realized prices and 7.6 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 6.7 MMBoe due to lower operating expenses. Proved developed revisions were primarily due to

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negative revisions of 30.2 MMBoe for performance largely related to higher than anticipated decline rates in recently developed spacing units and 9.6 MMBoe due to lower realized prices, partially offset by positive revisions of 5.1 MMBoe due to lower operating expenses. The PUD revisions were primarily due to negative revisions of 21.1 MMBoe for performance largely related to reductions in the anticipated hydrocarbon recoveries of proved areas during full field development due to changes in anticipated well densities and well performance and 7.0 MMBoe associated with alignment to the anticipated five-year development plan, offset by positive revisions of 1.7 MMBoe due to lower operating expenses.

In 2018, the Company had net negative revisions of 16.9 MMBoe, or 5% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 42.3 MMBoe due to well performance and 9.4 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 14.7 MMBoe for the addition of PUDs that were previously removed from the five-year development plan, 14.4 MMBoe due to higher realized prices and 5.4 MMBoe for ownership adjustments. The proved developed net negative revisions of 20.2 MMBoe were primarily due to negative revisions of 33.0 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, partially offset by positive revisions of 12.2 MMBoe due to higher realized prices. The PUD revisions were primarily due to positive revisions of 14.7 MMBoe for the addition of PUDs that were previously removed from the five-year development plan, 5.6 MMBoe for ownership adjustments and 2.2 MMBoe due to higher realized prices, offset by negative revisions of 9.4 MMBoe associated with alignment to the anticipated five-year development plan and 9.3 MMBoe for performance largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units.

Extensions, Discoveries and Other Additions

In 2020, the Company had a total of 6.0 MMBoe of additions due to extensions and discoveries. An estimated 3.2 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2020, with 99% of these reserves from wells producing in the Permian Basin and 1% of these reserves from wells producing in the Williston Basin. An additional 2.8 MMBoe of PUDs were added in the Williston Basin associated with the Company’s anticipated five-year development plan.

In 2019, the Company had a total of 63.9 MMBoe of additions due to extensions and discoveries. An estimated 10.3 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2019, with 60% of these reserves from wells producing in the Bakken or Three Forks formations and 40% of reserves from wells producing in the Permian Basin. An additional 53.6 MMBoe of PUDs were added in the Williston and Permian Basins associated with the Company’s anticipated five-year development plan, with 63% of these PUDs in the Bakken or Three Forks formations and 37% in the Permian Basin.

In 2018, the Company had a total of 38.4 MMBoe of additions due to extensions and discoveries. An estimated 9.0 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2018, with 77% of these reserves from wells producing in the Bakken or Three Forks formations and 23% of reserves from wells producing in the Permian Basin. An additional 29.4 MMBoe of PUDs were added in the Williston and Permian Basins associated with the Company’s anticipated five-year drilling plan, with 76% of these PUDs in the Bakken or Three Forks formations and 24% in the Permian Basin.

Sales of Reserves in Place

In 2020, there were no proved reserves divested. In 2019 and 2018, the Company divested 2.5 MMBoe and 15.9 MMBoe, respectively, of reserves associated with reservoirs in the Bakken or Three Forks formations (see Note 12—Acquisitions and Divestitures).

Purchases of Reserves in Place

In 2020 and 2019, there were no proved reserves purchased from acquisitions. In 2018, the Company purchased estimated net proved reserves of 32.9 MMBoe from acquisitions in the Permian Basin (see Note 12—Acquisitions and Divestitures).

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.

The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas, $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas and $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas for the years ended December 31, 2020, 2019 and 2018, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses

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or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end.

The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2020, 2019 and 2018:


	At December 31,
	2020		2019		2018

	(In thousands)
Future cash inflows	$	5,197,220	$	12,385,040	$	16,652,405
Future production costs	(2,792,921)		(5,509,127)		(6,609,097)
Future development costs	(610,658)		(1,490,521)		(1,701,672)
Future income tax expense	(232,849)		(188,823)		(968,466)
Future net cash flows	1,560,792		5,196,569		7,373,170
10% annual discount for estimated timing of cash flows	(611,915)		(2,352,200)		(3,322,864)
Standardized measure of discounted future net cash flows	$	948,877	$	2,844,369	$	4,050,306

The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented:


	2020		2019		2018

	(In thousands)
January 1	$	2,844,369	$	4,050,306	$	3,300,695
Net changes in prices and production costs	(1,088,936)		(1,070,192)		1,003,008
Net changes in future development costs	4,640		131,003		(89,304)
Sales of crude oil and natural gas, net	(407,417)		(943,989)		(1,155,223)
Extensions	47,693		437,700		461,196

Purchases of reserves in place	—		—		385,763
Sales of reserves in place	—		(36,907)		(197,867)
Revisions of previous quantity estimates	(694,320)		(732,253)		(115,015)
Previously estimated development costs incurred	87,640		246,311		303,364
Accretion of discount	293,445		467,426		368,374
Net change in income taxes	(76,066)		533,872		(240,908)
Changes in timing and other	(62,171)		(238,908)		26,223
December 31	$	948,877	$	2,844,369	$	4,050,306

28. Quarterly Financial Data

The Company early adopted the SEC’s Disclosure Modernization Final Rule, effective February 10, 2021, for Item 302 of Regulation S-K. As such, tabular quarterly financial data has not been provided.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated 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 December 31, 2020. 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 the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2020 at the reasonable assurance level.

Management’s report on internal control over financial reporting

Management, including our CEO and CFO, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP.

As of December 31, 2020, management assessed the effectiveness of our internal control over financial reporting. In making this assessment, management, including our CEO and CFO, used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, our CEO and CFO have concluded that our internal control over financial reporting was effective as of December 31, 2020.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2020 and has issued an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2020. Please see their “Report of Independent Registered Public Accounting Firm” included in “Item 8. Financial Statements and Supplementary Data.”

Changes in internal control over financial reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2021 Annual Meeting of Stockholders.

The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Controller (the “Code of Ethics”) can be found on the Company’s website located at http://www.oasispetroleum.com, under “Investor Relations — Corporate Governance.” Any stockholder may request a printed copy of the Code of Ethics by submitting a written request to the Company’s Corporate Secretary.

If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company will disclose the information on its website. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of the Code of Ethics applicable to such persons by posting such information on our website.

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accountant Fees and Services

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PART IV

Item 15. Exhibits, Financial Statement Schedules

a. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:

(1)Financial Statements:

See Item 8. Financial Statements and Supplementary Data.

(2)Financial Statement Schedules:

None.

(3)Exhibits:

The following documents are included as exhibits to this report:


Exhibit No.						Description of Exhibit

2.1						Joint Chapter 11 Plan of Reorganization of Oasis Petroleum Inc. and its Debtor Affiliates (Technical Modifications) (filed as Exhibit 2.1 to Oasis’s Current Report on Form 8-K filed on November 13, 2020, and incorporated herein by reference).

3.1						Conformed version of Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc., as amended by amendment filed on July 25, 2018 (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q on August 7, 2018, and incorporated herein by reference).

3.2						Amended and Restated Certificate of Incorporation of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).

3.3						Amended and Restated Bylaws of Oasis Petroleum Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on February 28, 2019, and incorporated herein by reference).

3.4						Amended and Restated Bylaws of Oasis Petroleum Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).

3.5						Second Amended and Restated Bylaws of Oasis Petroleum Inc. adopted as of December 15, 2020 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on December 18, 2020, and incorporated herein by reference).

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

4.2						Registration Rights Agreement, dated February 14, 2018, between the Oasis Petroleum Inc. and Forge Energy, LLC (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on February 16, 2018, and incorporated herein by reference).

4.3						Description of Registrant’s Securities Registered Under Section 12 of the Exchange Act (filed as Exhibit 4.23 to the Company’s Annual Report on Form 10-K on February 27, 2020, and incorporated herein by reference).

10.1**						Form of Indemnification Agreement between Oasis Petroleum Inc. and each of the directors and executive officers thereof (filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K on February 27, 2014, and incorporated herein by reference).

10.2**						Amended and Restated 2010 Annual Incentive Compensation Plan of Oasis Petroleum Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on August 6, 2014, and incorporated herein by reference).

10.3**						Amended and Restated Executive Change in Control and Severance Benefit Plan dated as of March 1, 2012 (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on March 2, 2012, and incorporated herein by reference).

10.4						Letter Agreement dated as of March 4, 2015 between the Company and SPO Advisory Corp. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 9, 2015, and incorporated herein by reference).

10.5**						Third Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Thomas B. Nusz (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein by reference).

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Exhibit No.						Description of Exhibit
10.6**						Fourth Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Taylor L. Reid (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein by reference).

10.7**						Second Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Michael H. Lou (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein by reference).

10.8**						Second Amended and Restated Employment Agreement effective as of March 20, 2015 between Oasis Petroleum Inc. and Nickolas J. Lorentzatos (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on March 20, 2015, and incorporated herein by reference).

10.9						Contribution Agreement, dated as of September 25, 2017, by and among Oasis Midstream Partners LP, Oasis Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLC and OMP Operating LLC (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K on September 29, 2017, and incorporated herein by reference).

10.10						Omnibus Agreement, dated as of September 25, 2017, by and among Oasis Midstream Partners LP, the Company, Oasis Petroleum LLC, OMS Holdings LLC, Oasis Midstream Services LLC, OMP GP LLC and OMP Operating LLC (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K on September 29, 2017, and incorporated herein by reference).

10.11						Services and Secondment Agreement, dated as of September 25, 2017, by and between Oasis Midstream Partners LP and the Company (filed as Exhibit 10.4 to the Company's Current Report on Form 8-K on September 29, 2017 and incorporated herein by reference).

10.12						Third Amended and Restated Credit Agreement, dated as of October 16, 2018, by and among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 19, 2018, and incorporated herein by reference).

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

10.14						Second Amendment to the Third Amended and Restated Credit Agreement, dated as of July 2, 2019, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q on August 9, 2019, and incorporated herein by reference).

10.15						Third Amendment to the Third Amended and Restated Credit Agreement, dated as of November 4, 2019, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party thereto, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on November 6, 2019, and incorporated herein by reference).

10.16**						Fourth Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis Petroleum Inc. and Thomas B. Nusz (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 22, 2018, and incorporated herein by reference).

10.17**						Fifth Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis Petroleum Inc. and Taylor L. Reid (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 22, 2018, and incorporated herein by reference).

10.18**						Third Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis Petroleum Inc. and Michael H. Lou (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on March 22, 2018, and incorporated herein by reference).

10.19**						Third Amended and Restated Employment Agreement effective as of March 20, 2018 between Oasis Petroleum Inc. and Nickolas J. Lorentzatos (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on March 22, 2018, and incorporated herein by reference).

10.20**						Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on May 4, 2018, and incorporated herein by reference).

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

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Exhibit No.						Description of Exhibit

10.22**						Form of Phantom Unit Award Grant Notice (filed as Exhibit 10.43 to the Company’s Annual Report on Form 10-K on March 1, 2019, and incorporated herein by reference).

10.23**						Form of Phantom Unit Award Agreement (filed as Exhibit 10.44 to the Company’s Annual Report on Form 10-K on March 1, 2019, and incorporated herein by reference).

10.24**						Second Amendment to the Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.46 to the Company’s Annual Report on Form 10-K on February 27, 2020, and incorporated herein by reference).

10.25**						Third Amendment to the Amended and Restated 2010 Long Term Incentive Plan of Oasis Petroleum Inc. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 28, 2020, and incorporated herein by reference).

10.26						Limited Waiver and Fourth Amendment to the Third Amended and Restated Credit Agreement, dated as of April 24, 2020, among Oasis Petroleum North America LLC, as borrower, the guarantors thereto, Wells Fargo Bank, N.A., as administrative agent and issuing bank and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on April 30, 2020, and incorporated herein by reference).

10.27**						Form of Incentive Clawback Agreement (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q on August 5, 2020, and incorporated herein by reference).

10.28						Direction Letter and Specified Swap Liquidation Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 21, 2020, and incorporated herein by reference)

10.29						Restructuring Support Agreement, dated September 29, 2020 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).

10.30						DIP Commitment Letter, dated September 29, 2020 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).

10.31						Exit Commitment Letter, dated September 29, 2020 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).

10.32**						Amendment to Fourth Amended and Restated Employment Agreement effective as of September 29, 2020 between Oasis Petroleum Inc. and Thomas B. Nusz (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).

10.33**						Amendment to Fifth Amended and Restated Employment Agreement effective as of September 29, 2020 between Oasis Petroleum Inc. and Taylor L. Reid (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).

10.34**						Amendment to Third Amended and Restated Employment Agreement effective as of September 29, 2020 between Oasis Petroleum Inc. and Michael H. Lou (filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).

10.35**						Amendment to Third Amended and Restated Employment Agreement effective as of September 29, 2020 between Oasis Petroleum Inc. and Nickolas J. Lorentzatos (filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K on September 30, 2020, and incorporated herein by reference).

10.36						Senior Secured Superpriority Debtor-in-Possession Revolving Credit Agreement, dated as of October 2, 2020, by and among Oasis Petroleum Inc., Oasis Petroleum North America LLC, the Guarantors party thereto, the Lenders party from time to time thereto, and Wells Fargo Bank, National Association (filed as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q on November 5, 2020, and incorporated herein by reference).

10.37†						Credit Agreement dated as of November 19, 2020, among Oasis Petroleum Inc., as parent, Oasis Petroleum North America LLC, as borrower, the other credit parties party hereto, Wells Fargo Bank, N.A., as administrative agent, issuing bank and swingline lender and the lenders party hereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).

10.38						Warrant Agreement, dated as of November 19, 2020, by and between Oasis Petroleum Inc., and Computershare Trust Company, N.A. (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).

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Exhibit No.						Description of Exhibit

10.39						Registration Rights Agreement, dated as of November 19, 2020, by and between the Oasis Petroleum Inc. and the holders party thereto (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).

10.40**						Form of Indemnification Agreement, by and between Oasis Petroleum Inc. and its officers and directors (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).

10.41**						Oasis Petroleum Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).

10.42**						Employment Agreement dated December 22, 2020 between Oasis Petroleum Inc. and Douglas E. Brooks (filed as Exhibit 99.2 to the Company’s Current Report on Form 8-K on December 28, 2020, and incorporated herein by reference).

21.1(a)						List of Subsidiaries of Oasis Petroleum Inc.

23.1(a)						Consent of DeGolyer and MacNaughton.

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.

99.1						Report of DeGolyer and MacNaughton (filed as Exhibit 99.2 to the Company’s Current Report on Form 8-K on February 25, 2021, and incorporated herein by reference).

101(a)						The following financial information from Oasis’s Annual Report on Form 10-K for the year ended December 31, 2020, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.

104(a)						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

__________________

(a)Filed herewith.

(b)Furnished herewith.

**Management contract or compensatory plan or arrangement.

† Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request.

Item 16. Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on March 8, 2021.


OASIS PETROLEUM INC.

By:						/s/ Douglas E. Brooks
						Douglas E. Brooks Board Chair and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:

Signature

Title

Date

/s/ Douglas E. Brooks

Board Chair and Chief Executive Officer
(Principal Executive Officer)

March 8, 2021

Douglas E. Brooks

/s/ Taylor L. Reid

President and Chief Operating Officer

March 8, 2021

Taylor L. Reid

/s/ Michael H. Lou

Executive Vice President and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)

March 8, 2021

Michael H. Lou

/s/ Samantha Holroyd

Director

March 8, 2021

Samantha Holroyd

/s/ John Jacobi

Director

March 8, 2021

John Jacobi

/s/ N. John Lancaster, Jr.

Director

March 8, 2021

N. John Lancaster, Jr.

/s/ Robert McNally

Director

March 8, 2021

Robert McNally

/s/ Cynthia L. Walker

Director

March 8, 2021

Cynthia L. Walker

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GLOSSARY OF TERMS

The terms defined in this section are used throughout this Annual Report on Form 10-K:

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas liquids or fresh water.

“Bcf.” One billion cubic feet of natural gas.

“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil.

“Boepd.” Barrels of oil equivalent per day.

“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.

“Development well.” A well drilled within the proved area of a natural gas or crude oil reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“Environmental assessment.” An environmental assessment, a study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.

“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or crude oil in another reservoir or to extend a known reservoir.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“MBbl.” One thousand barrels of crude oil, condensate, natural gas liquids or fresh water.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBbl.” One million barrels of crude oil, condensate, natural gas liquids or fresh water.

“MMBoe.” One million barrels of oil equivalent.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“NGL.” Natural gas liquids.

“NYMEX.” The New York Mercantile Exchange.

“Plug.” A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

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“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proppant.” Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

“Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.” Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Proved undeveloped reserves.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission.

“Reasonable certainty.” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserves.” Estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Resource play.” An expansive contiguous geographical area with known accumulations of crude oil or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.

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“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Throughput.” The volume of product passing through a pipeline, plant, terminal or other facility.

“Unconventional resource.” An umbrella term for crude oil and natural gas that is produced by means that do not meet the criteria for conventional production. What has qualified as “unconventional” at any particular time is a complex function of resource characteristics, the available E&P technologies, the economic environment, and the scale, frequency and duration of production from the resource. Perceptions of these factors inevitably change over time and often differ among users of the term. At present, the term is used in reference to crude oil and natural gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, fractured reservoirs and tight gas sands are considered unconventional resources.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Well stimulation.” A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.

“Wellbore.” The hole drilled by the bit that is equipped for crude oil or gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

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