Chord Energy Corp 10-K

oas-20201231 T able of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _______________________________________ FORM 10-K _______________________________________ ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31 , 2020 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 1-34776 _______________________________________ Oasis Petroleum Inc. (Exact name of registrant as specified in its charter) _______________________________________ Delaware 80-0554627 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 1001 Fannin Street , Suite 1500 Houston , Texas 77002 (Address of principal executive offices) (Zip Code) ( 281 ) 404-9500 (Registrant’s telephone number, including area code) Securities Registered Pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered Common Stock , 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 _______________________________________ 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. i T able of Contents 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 1 T able of Contents 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; 2 T able of Contents • 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. 3 T able of Contents 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. 4 T able of Contents • 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. 5 T able of Contents 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.” 6 T able of Contents 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 7 T able of Contents 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 8 T able of Contents 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. 9 T able of Contents 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. 10 T able of Contents 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 11 T able of Contents 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 12 T able of Contents 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 13 T able of Contents 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. 14 T able of Contents 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. 15 T able of Contents 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 16 T able of Contents 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.” 17 T able of Contents 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 18 T able of Contents 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 19 T able of Contents 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. 20 T able of Contents 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. 21 T able of Contents 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 22 T able of Contents 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 23 T able of Contents 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, 24 T able of Contents 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. 25 T able of Contents 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. 26 T able of Contents 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. 27 T able of Contents 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 28 T able of Contents 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. 29 T able of Contents 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. 30 T able of Contents 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. 31 T able of Contents 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 32 T able of Contents 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; 33 T able of Contents • 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 34 T able of Contents 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. 35 T able of Contents 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. 36 T able of Contents 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 37 T able of Contents 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. 38 T able of Contents 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, c rude 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 39 T able of Contents 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. 40 T able of Contents 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 41 T able of Contents 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. 42 T able of Contents 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. 43 T able of Contents 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 44 T able of Contents 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; 45 T able of Contents • 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; 46 T able of Contents • 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 47 T able of Contents • 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 48 T able of Contents 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 49 T able of Contents 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 50 T able of Contents 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: 51 T able of Contents • 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. 52 T able of Contents 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. 53 T able of Contents 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. 54 T able of Contents 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. 55 T able of Contents • 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. 56 T able of Contents 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 % 57 T able of Contents 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 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. 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. 58 T able of Contents 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. 59 T able of Contents 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 __________________ (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. 60 T able of Contents 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, 61 T able of Contents 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 62 T able of Contents 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 63 T able of Contents 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 64 T able of Contents 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. 65 T able of Contents 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 __________________ (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 __________________ (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. 66 T able of Contents 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. 67 T able of Contents 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 68 T able of Contents 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 69 T able of Contents • 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. T he 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. 70 T able of Contents 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. 71 T able of Contents 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 72 T able of Contents 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. 73 T able of Contents 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 74 T able of Contents 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. 75 T able of Contents 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. 76 T able of Contents 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 % ____________________ 77 T able of Contents (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. 78 T able of Contents 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 79 T able of Contents 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. 80 T able of Contents Item 8. Financial Stateme