Chord Energy Corp 10-K

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