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Item 7. Management’s Discussion and Analysis

2022-02-25 compared with 2021-03-08 · 310 added, 512 removed, 316 unchanged (72% of the section changed)

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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.

The Consolidated Balance Sheets and Consolidated Statements of Operations have been recast from prior periods to reflect the OMP Merger (defined below) as a discontinued operation.

Refer to “Part II, Item 8.

Financial Statements and Supplementary Data—Note 6—Discontinued Operations.” In addition, 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.

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For discussion related to changes in financial condition and results of operations for the years ended December 31, 2020 and 2019, 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.

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.

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, 2020, filed with the SEC on March 8, 2021.

We are an independent E&P company with quality and sustainable long-lived assets in the North Dakota and Montana regions of the Williston Basin.

Our mission is to improve lives by safely and responsibly providing affordable, reliable and abundant energy.

We are uniquely positioned with a best-in-class balance sheet and are focused on rigorous capital discipline and generating free cash flow by operating efficiently, safely and responsibly to develop our unconventional onshore oil-rich resources in the continental United States.

Recent Developments

Emergence from voluntary reorganization under Chapter 11

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

On November 10, 2020, the Bankruptcy Court confirmed the Plan, and the Debtors emerged from bankruptcy on November 19, 2020.

Although we are no longer a debtor-in-possession, the Debtors operated as debtors-in-possession through the pendency of the Chapter 11 Cases.

As such, certain aspects of the Chapter 11 Cases and related matters are described below in order to provide context to our financial condition and results of operations for the period presented.

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

• Shares of the Predecessor’s common stock outstanding immediately prior to the Emergence Date were cancelled, and on the Emergence Date, we issued (i) 20,000,000 shares of the Successor’s common stock pro rata to holders of the Predecessor’s Notes (as defined below) and (ii) 1,621,622 warrants (the “Warrants”) pro rata to holders of the Predecessor’s common stock.

The Warrants are exercisable to purchase one share of the Successor’s common stock per Warrant at an initial exercise price of $94.57 and expire on November 19, 2024.

• All outstanding obligations under the following notes (collectively, the “Notes”) issued by the Predecessor were cancelled:

(i) 6.50% senior unsecured notes due 2021;

(ii) 6.875% senior unsecured notes due 2022;

(iii) 6.875% senior unsecured notes due 2023;

(iv) 6.250% senior unsecured notes due 2026;

and (v) 2.625% senior unsecured convertible notes due 2023.

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

• The Amended and Restated Credit Agreement, dated as of October 16, 2018 (as amended prior to the Emergence Date, the “Predecessor Credit Facility”), by and among the Predecessor, as borrower, the lenders party thereto, and Wells Fargo, as administrative agent, was terminated and holders of claims under the Predecessor Credit Facility had such obligations refinanced through the Oasis Credit Facility.

Notwithstanding the foregoing, the Specified Default Interest (as defined in “Item 8.

Financial Statements and Supplementary Data—Note 15—Long-Term Debt”) related to the Predecessor Credit Facility was discharged, released and deemed waived by the lenders.

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

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

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

• We adopted the 2020 LTIP effective on the Emergence Date and reserved 2,402,402 shares of our Successor’s common stock for distribution under the 2020 LTIP.

No shares were issued under the 2020 LTIP as of the Emergence Date.

In addition, on the Emergence Date, the conditions were satisfied for the waiver, discharge and forgiveness of the OMP Specified Default Interest (as defined in “Item 8.

Financial Statements and Supplementary Data—Note 15—Long-Term Debt”) related to the revolving credit facility among OMP, as parent, OMP Operating LLC, a subsidiary of OMP, as borrower, Wells Fargo, as administrative agent, and the lenders party thereto (the “OMP Credit Facility”), and payment of the OMP Specified Default Interest was permanently waived by the lenders party to the OMP Credit Facility.

As of the Emergence Date, by operation of and in accordance with the Plan, the Board of Directors consisted of seven members, comprised of our Chief Executive Officer, Thomas B.

Nusz, and six new members, Douglas E.

Brooks, Samantha Holroyd, John Jacobi, Robert McNally, Cynthia L.

Walker and John Lancaster.

Return of Capital Plan

On February 9, 2022, we announced a plan to return $280 million of capital to shareholders over the next year ($70 million per quarter) through a combination of a base dividend (approximately $45 million), variable dividends and share repurchases.

This return of capital plan represents a balanced approach that reflects our strategic goals of exercising capital discipline while delivering both return on and return of capital to shareholders.

The Board of Directors has increased the quarterly base dividend by 17% from $0.50 per share of common stock to $0.585 per share of common stock and expects to pay an aggregate base dividend of $11.3 million per quarter during 2022.

The Board of Directors declared the base dividend for the fourth quarter of 2021 of $0.585 per share of common stock ($2.34 per share annualized) payable on March 4, 2022 to shareholders of record as of February 21, 2022.

In addition, the Board of Directors authorized a new $150.0 million share repurchase program to replace the $100.0 million share repurchase program that was fully utilized in 2021.

We expect to return capital proportionately each quarter through 2022.

After the end of each quarter, we expect to announce a variable dividend based on $70 million less cash utilized to pay the base dividend and repurchase shares during the prior quarter.

See “Liquidity and Capital Resources” below for additional information.

Williston Basin Acquisition

On October 21, 2021, we completed our acquisition of approximately 95,000 net acres in the Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy, Inc.

for total cash consideration of $585.8 million (the “Williston Basin Acquisition”).

The total cash consideration paid was comprised of a deposit of $74.5 million paid on May 3, 2021 and $511.3 million paid at closing on October 21, 2021.

The Williston Basin Acquisition was funded with cash on hand, which included proceeds from the Permian Basin Sale (defined below) and the Oasis Senior Notes (defined below).

Permian Basin Sale

On June 29, 2021, we completed the sale of our upstream assets in the Texas region of the Permian Basin, effective March 1, 2021, to Percussion Petroleum Operating II, LLC (“Percussion”) for an aggregate purchase price of $450.0 million (the “Primary Permian Basin Sale”).

The purchase price consisted of $375.0 million cash at closing and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX West Texas Intermediate (“NYMEX WTI”) crude oil exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”).

We received cash proceeds of $342.3 million after purchase price adjustments that were primarily related to cash flows from the effective date to the close date.

The total consideration remains subject to earn-out payments related to the Permian Basin Sale Contingent Consideration.

In addition to the Primary Permian Basin Sale, we also divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 (the “Additional Permian Basin Sale” and together with the Primary

Permian Basin Sale, the “Permian Basin Sale”).

We received cash proceeds from the Additional Permian Basin Sale of $30.0 million.

On October 25, 2021, OMP and OMP GP entered into the OMP Merger pursuant to which we agreed to sell to Crestwood our entire ownership of OMP common units and all of the limited liability company interests of OMP GP in exchange for $160.0 million in cash and approximately 21 million common units representing limited partner interests of Crestwood.

The OMP Merger was unanimously approved by the Board of Directors of both Oasis and Crestwood and was also unanimously approved by the Board of Directors and Conflicts Committee of OMP GP.

The OMP Merger was completed on February 1, 2022 and we own approximately 21.7% of Crestwood’s issued and outstanding common units, and we are Crestwood’s largest single customer.

In connection with the closing of the OMP Merger, the Company and Crestwood executed a director nomination agreement pursuant to which we designated two directors to the Board of Directors of Crestwood GP.

The OMP Merger represents a strategic shift for the Company and qualified for reporting as a discontinued operation.

Financial Statements and Supplementary Data—Note 5—Oasis Midstream Partners.”

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.

Brooks will continue to serve as Board Chair, in addition to his role as Chief Executive Officer.

On April 13, 2021, Daniel E.

Brown was appointed Chief Executive Officer of the Company.

At the same time, Mr.

Brown was also appointed to the Company’s Board of Directors.

Brown replaced Douglas E.

Brooks, who was previously appointed to serve as Chief Executive Officer on an interim basis.

Brooks continues to serve in his role as Board Chair.

Market Conditions and COVID-19

On March 13, 2020, the United States declared the COVID-19 pandemic a national emergency, and most states, including Texas, North Dakota and Montana, and many municipalities have declared public health emergencies.

Along with these declarations, there have been extraordinary and wide-ranging actions taken by international, federal, state and local public health and governmental authorities to contain and combat the outbreak and spread of COVID-19 in regions across the United States and the world, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations.

These containment measures, while aiding in the prevention of further outbreak of COVID-19, have resulted in a severe drop in energy demand and general economic activity.

To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions.

We have taken, and continue to take, proactive steps to manage any disruption in our business caused by COVID-19.

For instance, even though our operations were not required to close, we were early adopters in employing a work-from-home system and have deployed additional safety protocols at our operating sites in order to keep our employees and contractors safe and to keep our operations running without material disruption.

The rapid and unprecedented decreases in energy demand have impacted certain elements of our distribution channels.

We are also experiencing impacts from downstream markets, as certain pipelines no longer have the ability to transport production as refineries reduce activity or exercise force majeure clauses.

Additionally, inventory surpluses have overwhelmed U.S.

storage capacity, leading to a further strain on the supply chain.

We elected to shut in production of certain wells, primarily during the second quarter of 2020, and the constraints on the supply chain could force us to shut in production in the future.

In March 2020, OPEC and non-OPEC, oil-producing countries, including Russia, failed to agree to production cuts which were intended to stabilize and support global crude oil commodity prices.

With no agreement in place, certain large international crude oil producers, including Saudi Arabia and Russia, began to deeply discount sales of their crude oil and committed to ramping up production in an attempt to protect, or increase, their global market share.

The impact of this increased production was coupled with significant demand declines caused by the global response to COVID-19.

These extreme supply and demand dynamics contributed to significant crude oil price declines, which have and will continue to negatively impact U.S.

producers, including us.

Although in April 2020, OPEC and other non-OPEC oil-producing countries, including Russia, came to an agreement to cut limited amounts of production, we cannot predict future impacts to crude oil production and global economic activities.

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In response to the foregoing market conditions, we suspended our drilling and completion operations in the second quarter of 2020 and significantly reduced our planned capital expenditures for 2020.

In addition, as a result of the low commodity price environment coupled with uncertainty related to the continuing economic impact of the COVID-19 pandemic, we reduced our workforce during the second quarter of 2020 to adjust to a lower level of activity and operate in a cost-efficient manner in the current environment.

Dakota Access Pipeline

Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by midstream operators.

The impact of pending and future legal proceedings on these systems, pipelines and facilities can affect our ability to market our products and have a negative impact on realized pricing.

On July 6, 2020, the operator of DAPL was ordered by a U.S.

District court to halt oil flow and empty the pipeline within 30 days while an EIS is completed.

On July 15, 2020, the U.S.

Court of Appeals for the District of Columbia Circuit issued a temporary administrative stay while the court considers the merits of a longer-term emergency stay order through the appeals process.

COVID-19 remains a global health crisis and there continues to be considerable uncertainty regarding the extent to which COVID-19 and its variants will continue to spread.

Despite improvements in global economic activity levels and higher energy demand compared to 2020, the impacts of COVID-19 continue to be unpredictable, including the impacts of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines.

We are unable to reasonably estimate the period of time that related conditions could exist or the extent to which they could impact our business, results of operations, financial condition or cash flows.

Commodity prices have risen from historic lows in 2020;

however, further negative impacts from COVID-19 may require us to adjust our business plan.

We are committed to the health and safety of our employees, contractors and communities.

We have established appropriate policies and procedures while we have continued to operate during the COVID-19 pandemic.

All managers and supervisors have been trained on how to address positive COVID-19 cases, including procedures on notifying, tracking and communicating COVID-19 cases.

Our Crisis Management Team continuously monitors public health data and guidance, engages with peer companies, and participates with industry associations to ensure alignment with guidance for employee health and safety.

In September 2021, President Biden announced a COVID-19 action plan that would have the Occupational Safety and Health Administration (“OSHA”) develop an Emergency Temporary Standard (“ETS”) which may include new obligations for employers with one hundred or more employees with respect to vaccinations, testing and paid time off.

In November 2021, OSHA published an ETS that requires covered employers to take affirmative steps to address COVID-19 safety, including having a written COVID-19 vaccination policy and having a process in place where employees are able to confidentially submit proof of vaccination status.

The ETS also requires any employee who is not fully vaccinated to wear a face covering at the workplace, effective January 20, 2022, and be subject to regular COVID-19 testing, effective February 9, 2022.

In connection with the ETS, we established a policy to comply with OSHA’s ETS on vaccination, testing and face coverings that applies to all of our employees.

On January 13, 2022, 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.

Supreme Court stayed the OSHA ETS.

We monitor mandates related to COVID-19 at both the federal and state levels on an ongoing basis and continue to assess the potential impacts of those mandates.

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.

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy.

Prices for crude oil, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.

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 customer would have a material adverse effect on our results of operations or cash flows.

Please see “Part I, Item 1.

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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

2021 (Successor) Year ended December 31, 2021 (Successor)

Average Realized Crude Oil Prices ($/Bbl) (1)

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3 % 1 % 1 % 0.3 % 1 %

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2019 (Predecessor) Year ended December 31, 2019 (Predecessor)

Predecessor Successor

2020 Period from October 1, 2020 through November 19, 2020 Period from November 20, 2020 through

December 31, 2020

Average Realized Crude Oil Prices ($/Bbl) (1)

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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.

Expansions of both rail and pipeline facilities in the Williston Basin has reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.

Results of Operations

Upon emergence from bankruptcy, we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes.

The OMP Merger qualified for reporting as a discontinued operation.

Accordingly, the results of operations of OMP have been classified as discontinued operations in the Consolidated Statement of Operations for the year ended December 31, 2021 (Successor).

Prior periods have been recast so that the basis of presentation is consistent with that of the 2021 consolidated financial statements.

Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for additional information.

In addition, we emerged from bankruptcy on November 19, 2020 (the “Emergence Date”) and 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.

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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.

During the year ended December 31, 2020:

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

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

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

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

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

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During the year ended December 31, 2021 (Successor):

• Production volumes averaged 58,032 Boepd (64% oil).

• Lease operating expenses were $9.63 per Boe, compared to $9.27 per Boe during the period from November 20, 2020 through December 31, 2020 (Successor) and $7.55 per Boe during the period from January 1, 2020 through November 19, 2020 (Predecessor).

• E&P and other capital expenditures, excluding capitalized interest and acquisition capital, were $168.4 million.

• Estimated net proved reserves were 250.9 MMBoe as of December 31, 2021, with a Standardized Measure of $2.7 billion and PV-10 of $3.1 billion.

• Paid regular cash dividends of $1.625 per share of common stock and a special dividend of $4.00 per share of common stock.

• Completed $100.0 million share repurchase program.

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.

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 to meet pipeline specifications 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.

Substantially all of our other services revenues are from services provided to our operated wells.

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,

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

Crude oil revenues $ 910,381 $ 69,075 $ 522,812 $ 1,261,413

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Purchased oil and gas sales 378,983 20,633 237,111 481,014

Midstream revenues 26,031 166,631 212,208 120,504

Other services revenues 687 215 6,836 41,974

Total revenues $ 1,579,926 $ 106,993 $ 845,457 $ 1,930,797

Crude oil and natural gas revenues .

Crude oil and natural gas revenues decreased $718.7 million, or 51%, from $1,408.8 million during the year ended December 31, 2019.

This decrease was attributable to a $438.4 million decrease due to lower crude oil and natural gas sales prices coupled with a $280.2 million decrease due to lower crude oil and natural gas production sold year over year.

During the year ended December 31, 2020, our crude oil and natural gas revenues were negatively impacted by recent market conditions, which caused a significant decline in our realized prices for crude oil, natural gas and NGLs.

Excluding the effect of derivative settlements, average crude oil sales prices decreased 32%, and average natural gas sales prices, which include the value for natural gas and NGLs, decreased 21% year over year.

Due to the depressed commodity price environment in 2020, we reduced our E&P capital expenditures, curtailed flush production on newly completed wells and temporarily shut in certain wells during the second and third quarters of 2020.

Average daily production sold decreased by 23,344 Boepd year over year, primarily driven by temporary well shut-ins, partially offset by new well completions.

During the year ended December 31, 2020, we completed 20.6 total net wells in the Williston Basin and 14.0 total net wells in the Permian Basin.

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

Successor Predecessor

Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year ended December 31,

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020

Production data

Williston Basin

Crude oil (MBbls) 13,489 1,593 14,226

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Average daily production (Boepd) 58,032 57,809 65,612

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

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Effect of derivative settlements (1)

(18.94) — 11.38

Average realized price after the effect of derivative settlements (1)

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__________________

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

Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

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

Crude oil and natural gas revenues.

Crude oil and natural gas revenues increased $512.6 million, or 75%, in 2021.

This increase was attributable to a $676.3 million increase due to higher crude oil and natural gas sales prices, partially offset by a $163.8 million decrease due to lower crude oil and natural gas production sold.

During the year ended December 31, 2021 (Successor), our crude oil and natural gas revenues were positively impacted by higher commodity prices compared to the previous year due largely to higher energy demand as a result of increased economic activity following severe COVID-19 restrictions during 2020.

Excluding the effect of derivative settlements, average crude oil sales prices increased 80%, and average natural gas sales prices, which include the value for natural gas and NGLs, increased 209% year over year.

Average daily production sold decreased by 6,685 Boepd year over year, primarily driven by a decrease of 5,353 Boepd due to the divestiture of our upstream assets in the Permian Basin on June 29, 2021.

We closed the Williston Basin Acquisition on October 21, 2021, and average daily production from the Williston Basin Acquisition asset between the close date to December 31, 2021 was 21,226 Boepd.

During the year ended December 31, 2021 (Successor), we completed and placed on production 22.3 total net operated wells in the Williston Basin.

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.

Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls, increased $121.2 million to $379.0 million for the year ended December 31, 2021 (Successor), primarily due to higher crude oil sales prices period over period, partially offset by lower crude oil volumes purchased and then subsequently sold.

Other services revenues.

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

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Other services revenues decreased by $6.4 million to $0.7 million during the year ended December 31, 2021 (Successor), which was primarily attributable to a decrease in well completion revenues due to the Well Services Exit in the first quarter of 2020.

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):

The following table summarizes our operating expenses, gain (loss) on sale of properties, other income and expenses, income tax benefit, net income (loss) from continuing operations, income from discontinued operations attributable to Oasis, net of income tax and net income (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,

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

Operating expenses

Lease operating expenses $ 203,933 $ 22,517 $ 160,406 $ 288,690

Midstream expenses 10,572 42,987 62,146 32,758

Other services expenses 47 — 6,658 28,761

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Interest expense, net of capitalized interest (30,806) (2,020) (141,836) (159,287)

Gain (loss) on extinguishment of debt — 83,867 4,312 (13,848)

Gain on extinguishment of debt — — 83,867 4,312

Reorganization items, net — — 665,916 —

Other income (402) 1,407 440 121

Other income (expense) (1,010) (401) 1,271 569

Total other income (expense), net (621,457) (87,036) 842,783 (260,720)

Loss before income taxes (49,409) (3,987,573) (123,362) (25,343)

Income (loss) from continuing operations 187,987 (70,555) (4,128,816) (350,895)

Income tax benefit 973 3,447 262,962 32,715

Net loss including non-controlling interests (45,962) (3,724,611) (90,647) (19,500)

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)

Net income (loss) from continuing operations 188,960 (67,108) (3,865,854) (318,180)

Income from discontinued operations attributable to Oasis, net of income tax 130,642 17,196 225,526 189,937

Net income (loss) attributable to Oasis $ 319,602 $ (49,912) $ (3,640,328) $ (128,243)

Costs and expenses (per Boe of production)

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Lease operating expenses.

Lease operating expenses decreased $87.2 million in 2020 from $223.4 million for the year ended December 31, 2019.

This decrease was primarily due to lower workover expenses and fixed costs driven by lower activity.

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

Midstream expenses .

Midstream expenses represent costs of product sales related to third-party natural gas purchase arrangements as well as non-affiliated interest owners’ share of operating expenses incurred by our midstream business.

The $8.6 million decrease for the year ended December 31, 2020 as compared to the year ended December 31, 2019 was primarily related to a $3.7 million decrease in natural gas operating and maintenance expenses driven by a decrease in our operated Williston Basin production and a $2.6 million decrease in natural gas purchases from third parties due to lower prices,

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

Lease operating expenses (“LOE”) increased $21.0 million year over year to $203.9 million for the year ended December 31, 2021 (Successor).

This increase was due to a $32.0 million increase in the Williston Basin related to higher costs for gas lift of $10.9 million, fixed costs of $10.5 million and workover expenses of $9.3 million.

These increases were offset by a decrease of $11.0 million for LOE in the Permian Basin due to the divestiture of those assets in June of 2021.

LOE increased $1.91 per Boe to $9.63 per Boe due to a combination of higher costs and lower production volumes.

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.

The $6.6 million decrease year over year was primarily attributable to a decrease in well completion expenses due to 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.

Gathering, processing and transportation (“GPT”) expenses decreased $8.5 million year over year, which was attributable to a $3.4 million decrease in natural gas gathering and processing expenses and a $2.2 million decrease in crude oil gathering and transportation expenses, both related to a decrease in our production volumes.

In addition, there was a decrease of $2.8 million related to non-cash valuation adjustments for pipeline imbalances.

GPT per Boe was $5.79 for the year ended December 31, 2021 (Successor) and increased year over year due to lower production volumes.

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.

Purchased oil and gas expenses, which represent the crude oil purchased primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls, increased $130.7 million year over year to $380.0 million for the year ended December 31, 2021 (Successor) primarily due to higher crude oil prices period over period, partially offset by lower crude oil volumes purchased.

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.

Production taxes increased $25.5 million year over year to $76.8 million for the year ended December 31, 2021 (Successor) primarily due to higher crude oil and natural gas revenues.

The production tax rate as a percentage of crude oil and natural gas sales was 6.4% for the year ended December 31, 2021(Successor), compared to 6.9% for the period from November 20, 2020 through December 31, 2020 (Successor) and 7.6% for the period from January 1, 2020 through November 19, 2020 (Predecessor).

The production tax rate decreased year over year primarily due to a lower crude oil production mix 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.

Depreciation, depletion and amortization (“DD&A”) expense decreased $158.4 million, or 56%, year over year to $126.4 million for the year ended December 31, 2021 (Successor).

This decrease was primarily due to a decrease in DD&A related to oil and gas properties in the Williston Basin of $136.5 million, of which $133.8 million was due to a lower average unit-of-production rate and $2.7 million was due to lower production volumes.

In the Williston Basin, the average unit-of-production DD&A rate decreased $6.55 per Boe, or 56%, in 2021 as compared to 2020 primarily due to a lower basis in our oil and gas properties due to write-downs during 2020.

In addition, DD&A expense decreased $31.2 million due to a partial year of depletion expense on our Permian Basin properties that were sold in June of 2021.

These decreases were offset by an increase in depreciation expense related to our fixed assets of $9.9 million due to a higher book basis in well fracturing equipment as a result of fresh start accounting fair value adjustments made in November 2020.

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.

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:

There were no rig termination expenses recorded during the year ended December 31, 2021 (Successor) or for the period from November 20, 2020 through December 31, 2020 (Successor).

We recorded $1.3 million of rig termination expenses for the period from January 1, 2020 through November 19, 2020 (Predecessor) to early terminate certain drilling rig contracts in the Permian Basin.

Impairment expenses were immaterial for the year ended December 31, 2021 (Successor).

There were no impairment expenses for the period from November 20, 2020 through December 31, 2020 (Successor).

We recorded impairment expenses of $4.8 billion for the period from January 1, 2020 through November 19, 2020 (Predecessor), 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.

The Predecessor recorded an impairment charge of $4.4 billion on its proved oil and gas properties, including $3.8 billion in the Williston Basin and $637.3 million in the Permian Basin for the period ended November 19, 2020, primarily due to a significant decline in commodity prices.

• Unproved oil and gas properties .

We recorded impairment losses on our unproved oil and gas properties of $401.1 million and $5.4 million for the 2020 Predecessor Period and the year ended December 31, 2019, respectively, as a result of leases expiring or expected to expire as well as drilling plan uncertainty on certain acreage of unproved properties.

• Other property and equipment .

During the 2020 Predecessor Period, we recorded impairment charges of $108.3 million to reduce the carrying values of our midstream assets to their estimated fair values as a result of lower forecasted throughput volumes for our midstream assets driven by the significant decline in expected future

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commodity prices during the first quarter of 2020.

No impairment charges were recorded on our midstream assets for the year ended December 31, 2019.

• Assets held for sale .

During the 2020 Predecessor Period and the year ended December 31, 2019, we recorded impairment losses of $1.4 million and $4.4 million, respectively, to adjust the carrying value of certain inventory and equipment held for sale related to the Well Services Exit to the estimated fair value less costs to sell (see “Item 8.

Financial Statements and Supplementary Data—Note 13—Assets Held for Sale”).

In addition, we recorded an impairment loss of $14.5 million during the 2020 Predecessor Period related to certain well services equipment previously classified as held for sale that was no longer probable to be sold within one year.

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.

The Predecessor recorded impairment losses on its unproved oil and gas properties of $401.1 million for the period ended November 19, 2020 as a result of leases expiring or expected to expire, as well as drilling plan uncertainty on certain acreage of unproved properties.

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.

Our general and administrative (“G&A”) expenses decreased $78.8 million year over year to $80.7 million for the year ended December 31, 2021 (Successor).

This decrease was primarily due to lower employee compensation expenses due to a 21% decrease in employee headcount year over year, coupled with restructuring related expenses incurred during 2020.

Cash G&A, a non-GAAP financial measure, was $2.18 per Boe during the year ended December 31, 2021 (Successor), compared to $5.04 per Boe during the period from November 20, 2020 through December 31, 2020 (Successor) and $4.52 per Boe during the period from January 1, 2020 through November 19, 2020 (Predecessor).

For a definition of Cash G&A and a reconciliation of G&A to 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.

Financial Statements and Supplementary Data—Note 24—Commitments and Contingencies” for more information about our legal proceedings.

There were no litigation settlement expenses recorded during the year ended December 31, 2021 (Successor) or for the period from November 20, 2020 through December 31, 2020 (Successor).

During the period from January 1, 2020 through November 19, 2020 (Predecessor), we recorded a loss accrual of $22.8 million for the remaining settlement of legal proceedings with Mirada Energy, LLC and certain related parties.

Financial Statements and Supplementary Data—Note 22—Commitments and Contingencies” for more information.

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.

For the year ended December 31, 2021 (Successor), we recognized a $222.8 million net gain on sale of properties primarily related to the Permian Basin Sale.

For the period from January 1, 2020 through November 19,

2020 (Predecessor), we recognized a $10.4 million net gain on sale of properties primarily related to the sale of certain oil and gas properties in the Williston Basin.

For more information on our divestitures, see “Item 8.

Financial Statements and Supplementary Data—Note 13—Acquisitions and Divestitures”.

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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 year ended December 31, 2021 (Successor), we recorded a $589.6 million net loss on derivative instruments, primarily due to an unrealized loss of $319.5 million and a realized loss of $270.1 million.

The unrealized loss includes a loss of $331.5 million related to our commodity derivative contracts, partially offset by a gain of $12.0 million related to the Permian Basin Sale Contingent Consideration.

The realized loss includes $255.5 million related to settlement payments on crude oil derivative contracts and $14.7 million related to settlement payments on natural gas derivative contracts.

During the 2020 Successor Period, we recognized an $84.6 million loss on derivative instruments, including net cash settlement payments of $0.1 million, for the decrease in the fair value of our derivative contracts as a result of an increase in forward commodity prices during the period.

During the 2020 Predecessor Period, we recognized a $233.6 million gain on derivative instruments, including net cash settlement receipts of $224.4 million, of which $62.6 million was received for derivative contracts liquidated prior to their maturities (see “Item 8.

Financial Statements and Supplementary Data—Note 10—Derivative Instruments”).

For the year ended December 31, 2019, we recognized a $106.3 million net loss on derivative instruments, including net cash settlement receipts of $19.1 million.

Interest expense, net of capitalized interest.

Interest expense increased $8.4 million from $176.2 million for the year ended December 31, 2019 primarily due to Specified Default Interest and OMP Specified Default Interest of $30.3 million and $28.0 million, respectively, which were recorded in interest expense during the 2020 Predecessor Period, and subsequently waived on the Emergence Date, the discharge of which was recognized in reorganization items, net during the 2020 Predecessor Period (see “Item 8.

Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting” and “—Note 15—Long-Term

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Debt” for more information).

This increase was coupled with a $5.4 million decrease in capitalized interest due to lower work in progress activity, and was offset by a $44.8 million decrease in interest expense related to the Predecessor’s Notes due to repurchases of Notes in the first quarter of 2020 as well as the cancellation of the remaining outstanding Notes pursuant to the Plan.

In addition, interest expense related to revolving credit facilities, excluding default interest charges, decreased $9.3 million primarily due to lower weighted average borrowings outstanding year over year.

Gain (loss) on extinguishment of debt.

During the 2020 Predecessor Period, we repurchased an aggregate principal amount of $156.8 million of our outstanding Notes for an aggregate cost of $68.0 million, including fees.

As a result, we recognized a pre-tax gain in the 2020 Predecessor Period of $83.9 million, which included write-offs of unamortized debt discount of $4.2 million, unamortized deferred financing costs of $1.0 million and the equity component of the senior unsecured convertible notes of $0.3 million.

During the year ended December 31, 2019, we repurchased an aggregate principal amount of $56.8 million of our outstanding Notes for an aggregate cost of $45.8 million and recognized a pre-tax gain related to the repurchases of $4.3 million, which included the write-off of unamortized deferred financing costs and unamortized debt discount of $6.7 million.

Interest expense decreased $113.1 million year over year to $30.8 million for the year ended December 31, 2021 (Successor).

The decrease was primarily due to interest expense related to the Predecessor’s senior unsecured notes of $92.5 million and the Predecessor’s revolving credit facility of $21.0 million that were recorded during the period from January 1, 2020 through November 19, 2020 (Predecessor), coupled with a specified default interest charge of $30.3 million that was incurred during the period from January 1, 2020 through November 19, 2020 (Predecessor) and was subsequently waived on the Emergence Date.

These decreases were offset by interest expense recorded during the year ended December 31, 2021 (Successor) related to the Oasis Senior Notes (defined below) of $13.7 million and the Oasis Credit Facility (defined below) of $9.3 million, coupled with a fee of $7.8 million that was incurred to enter into a commitment letter for a senior secured second lien facility.

The senior secured second lien facility was terminated prior to being drawn and was replaced with financing from the Oasis Senior Notes (defined below).

For the year ended December 31, 2021 (Successor), the weighted average debt outstanding under the Oasis Credit Facility (defined below) was $65.5 million, and the weighted average interest rate incurred on outstanding borrowings under the Oasis Credit Facility (defined below) was 4.2%.

Interest capitalized during the year ended December 31, 2021 (Successor) was $2.1 million.

Gain on extinguishment of debt.

There was no extinguishment of debt during the year ended December 31, 2021 (Successor).

During the period from January 1, 2020 through November 19, 2020 (Predecessor), we repurchased an aggregate principal amount of $156.8 million of senior unsecured notes for an aggregate cost of $68.0 million and recognized a pre-tax gain of $83.9 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.

During the period from January 1, 2020 through November 19, 2020 (Predecessor), we recorded $665.9 million of net reorganization items related to our emergence from bankruptcy, consisting of (i) gains on the settlement of obligations under the Predecessor senior unsecured notes, (ii) fresh start accounting fair value adjustments, (iii) professional fees, (iv) the write-off of unamortized deferred financing costs and an unamortized debt discount and (v) fees associated with a debtor-in-possession credit facility.

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.

Our income tax benefit for the year ended December 31, 2021 (Successor) was recorded at (0.3)% of pre-tax income.

Our income tax benefit for the period from January 1, 2020 through November 19, 2020 (Predecessor) and the period from November 20, 2020 through December 31, 2020 (Successor) was recorded at 6.6% and 7.0% of pre-tax loss, respectively.

Our effective tax rate for the year ended December 31, 2021 (Successor) was lower than the effective tax rate for the previous year primarily due to the impacts of the change in the valuation allowance, reorganization impacts and the impacts of non-controlling interests.

Income from discontinued operations attributable to Oasis, net of income tax.

Income from discontinued operations attributable to Oasis, net of income tax decreased $112.1 million year over year to $130.6 million during the year ended December 31, 2021 (Successor).

The decrease was primarily due to $120.9 million of reorganization items recorded during the period from January 1, 2020 through November 19, 2020 (Predecessor) related to our emergence from bankruptcy, consisting of (i) fresh start accounting adjustments of $92.9 million and (ii) reorganization adjustments of $28.0 million.

This decrease was coupled with higher midstream expenses of $68.5 million due to an increase in natural gas purchase costs and higher depreciation expense of $9.5 million, offset by higher midstream revenues of $61.6 million due to an increase in natural gas revenues and higher intercompany eliminations for LOE and GPT of $29.2 million.

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 primary sources of liquidity during the period covered by this report have been cash flows from operations, proceeds from the Permian Basin Sale, the issuance of the Oasis Senior Notes and OMP Senior Notes and proceeds from the OMP Equity Offering.

Our primary uses of cash have been for net principal payments under the OMP Credit Facility (defined below), payments for derivative settlements and modifications, acquisition and development of oil and gas properties, interest payments on our long-term debt, dividends paid to our shareholders, payments to repurchase common stock under our share repurchase program and distributions to non-controlling interests.

Upon closing of the OMP Merger on February 1, 2022, the OMP Senior Notes (defined below) were assumed by Crestwood and the OMP Credit Facility (defined below) was paid in full by Crestwood.

In addition, following the OMP Merger, we will no longer make distributions to non-controlling interests, which represented the minority interest ownership of OMP.

Crestwood has historically declared cash distributions to its common unitholders, and we expect to receive cash distributions from Crestwood of approximately $54 million in 2022.

We have announced a plan to return $280 million of capital to shareholders over the next year (approximately $70 million per quarter) through a combination of a base dividend (approximately $45 million), variable dividends and share repurchases.

This return of capital plan represents a balanced approach that reflects our strategic goals of exercising capital discipline while delivering both return on and return of capital to shareholders.

We expect to return capital proportionately each quarter through 2022.

After the end of each quarter, we expect to announce a variable dividend based on $70 million less cash utilized to pay the base dividend and repurchase shares during the prior quarter.

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.

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 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.

During 2021, we entered into a series of transactions with derivative counterparties to modify the strike price of certain crude oil swap contracts.

We modified the strike price on our 2022 crude oil swap contracts covering total notional volumes of 6,935 MBbls to a NYMEX WTI price of $70.00 per barrel from a weighted average price of $40.89 per barrel.

In addition, we modified the strike price on our 2023 crude oil swap contracts covering total notional volumes of 5,110 MBbls to a NYMEX WTI price of $50.00 per barrel from a weighted average price of $43.68 per barrel.

As of December 31, 2021, our derivative contracts in place cover 22,495 MBbls of our crude oil production from 2022 through 2023.

For additional information on the impact of changing prices and our derivative arrangements on our financial position, see “Item 7A.

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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.

Our material cash requirements from known obligations include repayment of outstanding principal and interest payment obligations under the Oasis Senior Notes, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and payment obligations pursuant to our operating and finance leases.

There were no borrowings outstanding under the Oasis Credit Facility (defined below) as of December 31, 2021;

however, on a quarterly basis, we pay a commitment fee of 0.5% on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

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, the majority of which are ten years or less.

Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract.

However, we believe that our production and reserves are sufficient to fulfill the volume commitments, and therefore, we expect to avoid any material

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deficiency payments under these contracts.

The estimable future commitments under these agreements were approximately $547.7 million as of December 31, 2021.

We recorded a liability as of December 31, 2021 on the Consolidated Balance Sheet of $11.9 million related to unfavorable contracts assumed in connection with the Williston Basin Acquisition where we determined it was probable we would not meet the minimum volume commitment.

The future commitments related to these contracts are included in the above total estimable future commitments as of December 31, 2021.

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.

As of December 31, 2021, we had $619.7 million of liquidity available, including $172.1 million in cash and cash equivalents and $447.6 million of aggregate unused borrowing capacity available under the Oasis Credit Facility (defined below).

Oasis Credit Facility.

We have a reserves-based credit agreement (the “Oasis Credit Facility”), which has an overall senior secured line of credit of $1,500.0 million, an aggregate amount of elected commitments of $450.0 million and a borrowing base of $900.0 million as of December 31, 2021.

The Oasis Credit Facility matures on May 19, 2024.

As of December 31, 2021, we had no borrowings outstanding and $2.4 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $447.6 million.

As of December 31, 2020, we had $260.0 million and $6.8 million of outstanding letters of credit issued under the Oasis Credit Facility.

For the year ended December 31, 2021 (Successor), the weighted average interest rate incurred on borrowings under the Oasis Credit Facility was 4.2%, compared to 3.6% for the period from January 1, 2020 through November 19, 2020 (Predecessor) and 4.6% for the period from November 20, 2020 through December 31, 2020 (Successor).

During the year ended December 31, 2021, the Company entered into various amendments to the Oasis Credit Facility which, among other things, removed a requirement for the Company to enter into hedges covering minimum production volumes, provide for increased flexibility of restricted payments to shareholders, removed a cap on cash netting in the calculation of the leverage ratio if no borrowings are outstanding under the Oasis Credit Facility (other than letters of credit) and otherwise increased the cap on cash netting to $90.0 million and increased the anti-cash hoarding thresholds from $50.0 million to $90.0 million.

We were in compliance with the financial covenants in the Oasis Credit Facility at December 31, 2021.

Financial Statements and Supplementary Data—Note 14—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.

Oasis Senior Notes.

On June 9, 2021, we issued in a private placement $400.0 million of 6.375% senior unsecured notes due June 1, 2026 (the “Oasis Senior Notes”).

The Oasis Senior Notes were issued at par and resulted in net proceeds of $391.6 million.

We used the proceeds from the Oasis Senior Notes offering to fund a portion of the Williston Basin Acquisition.

Interest is payable semi-annually on June 1 and December 1 of each year.

Financial Statements and Supplementary Data—Note 14—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.

Financial Statements and Supplementary Data—Note 2—Emergence from Voluntary Reorganization under Chapter 11” and “—Note 15—Long-Term Debt” for more information.

OMP Credit Facility.

OMP had a senior secured revolving credit facility (the “OMP Credit Facility”) among OMP, as parent, OMP Operating LLC, as borrower, Wells Fargo, as administrative agent and the lenders party thereto.

The OMP Credit Facility was paid in full by Crestwood at the closing of the OMP Merger and has been classified as held for sale on the Consolidated Balance Sheets.

As of December 31, 2021, OMP had $203.0 million of borrowings and $5.5 million of letters of credit outstanding under the OMP Credit Facility.

Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for more information.

OMP Senior Notes.

On March 30, 2021, OMP issued in a private placement $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”).

The OMP Senior Notes were issued at par and resulted in net proceeds of $442.1 million.

Interest on the OMP Senior Notes is payable semi-annually on April 1 and October 1 of each year.

The OMP Senior Notes were assumed by Crestwood at closing of the OMP Merger and have been classified as held for sale on the Consolidated Balance Sheets.

Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for more information.

The Consolidated Statements of Cash Flows have not been recast for discontinued operations, therefore the discussion below concerning cash flows from operating activities, investing activities and financing activities includes the results of both continuing operations and discontinued operations.

Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for disclosure of cash flow impacts attributable to discontinued operations.

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,

Successor Predecessor

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

Net cash provided by operating activities $ 914,136 $ 95,255 $ 202,936 $ 892,853

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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.

Net cash provided by operating activities increased during the year ended December 31, 2021 (Successor) primarily due to higher oil and gas revenues, coupled with lower interest expense related to the cancellation of the Predecessor senior unsecured notes and lower general and administrative 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.

Our working capital fluctuates primarily as a result of changes in commodity prices and production volumes, capital spending to fund our development program and the impact of our outstanding derivative instruments.

Excluding the effects of assets held for sale from discontinued operations, we had a working capital surplus of $60.6 million at December 31, 2021, compared to a working capital deficit of $73.8 million at December 31, 2020.

Our working capital increased year over year due to increases in cash and cash equivalents and accounts receivable, offset by increases in revenues and production taxes payable, accrued liabilities and current derivative liabilities.

Cash flows used in investing activities

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

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Net cash used in investing activities increased during the year ended December 31, 2021 (Successor) primarily due to an increase in payments for derivative settlements, coupled with payments to modify the terms of outstanding derivative contracts.

In addition, we paid total cash consideration (excluding transaction costs) of $585.8 million for the Williston Basin Acquisition.

Financial Statements and Supplementary Data—Note —13 — Acquisitions and Divestitures” for more information.

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.

Net cash provided by financing activities increased during the year ended December 31, 2021 (Successor) primarily due to the issuance of the Oasis Senior Notes and OMP Senior Notes, partially offset by cash payments for dividends to shareholders and share repurchases.

Capital expenditures

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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,

Successor Predecessor

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

Capital expenditures

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2,277 179 7,071 15,760

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

Total E&P and other capital expenditures 170,466 15,018 201,075 609,977

Acquisitions 586,030 — — 21,010

Total capital expenditures from continuing operations 756,496 15,018 201,075 630,987

Discontinued operations (2)

49,123 3,054 24,266 212,381

Total capital expenditures (3)

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

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

(2) Represents capital expenditures attributable to our midstream assets that were classified as discontinued operations.

See “Recent Developments — OMP Merger” for additional information.

(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)

Midstream capital 63 - 68

Total capital expenditures 288 - 303

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.

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

While we have planned approximately $231 million to $243 million for total capital expenditures attributable to Oasis in 2021, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses.

In 2021, our total E&P and other capital expenditures were $170.5 million, a decrease of 21% as compared to 2020.

The decrease was primarily due to a reduction in capital expenditures for drilling and completions in the Permian Basin of $68.8 million due to the divestiture of those assets in June of 2021.

This was partially offset by an increase in capital expenditures for drilling and completions in the Williston Basin of $40.0 million due to higher activity compared to 2020 when we temporarily suspended drilling and completions activity.

As of December 31, 2021, we had two operated rigs running.

In addition, midstream capital expenditures, which have been classified as discontinued operations, increased $21.8 million primarily due to an increase in capital expenditures for gathering infrastructure.

Our planned 2022 E&P capital expenditures are expected to approximate $295 million.

We expect to run two operated rigs during 2022 and plan to complete 40 to 42 gross operated wells with an average working interest of approximately 72%.

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.

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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.

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.

We believe that cash on hand, cash flows from operating activities, including cash settlement receipts or payments under our derivative contracts, and availability under the Oasis Credit Facility should be sufficient to fund our 2022 capital expenditure plan and to meet our future obligations.

During 2021, we paid regular cash dividends of $1.625 per share of common stock totaling $32.3 million and a special dividend of $4.00 per share of common stock totaling $80.0 million.

On February 9, 2022, we declared a dividend of $0.585 per share of common stock ($2.34 per share annualized) payable on March 4, 2022 to shareholders of record as of February 21, 2022.

We recently announced an updated return of capital plan and expect to pay a base dividend and a variable dividend in 2022.

The base dividend is expected to be $11.3 million in aggregate per quarter, and we expect to announce a variable dividend after each quarter based on $70 million less cash utilized to pay the base dividend and repurchase shares during the prior quarter.

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 the Board of Directors deems relevant.

Share Repurchase Program

In March 2021, the Board of Directors authorized a share-repurchase program covering up to $100.0 million of the Company's common stock.

During the year ended December 31, 2021, we repurchased 871,018 shares of common stock at a weighted average price of $114.79 per common share for a total cost of $100.0 million.

The Board of Directors has authorized a new $150.0 million share repurchase program, which replaces the $100.0 million share repurchase program that was fully utilized in 2021.

The $150.0 million share repurchase program will be in place through the end of 2022 and is part of the Company’s plan to return $280 million of capital to shareholders over the next year.

Tax Benefits Preservation Plan

Upon emergence from bankruptcy in November 2020, the Company experienced an “ownership change” as defined by Section 382 of the Code.

Under Section 382 of the Code, the Company’s Tax Benefits are potentially subject to various limitations going forward.

However, the Company believes that it qualified for, and as a result, utilized an exception under Section 382(l)(5) of the Code from the limitation that would otherwise be imposed under Section 382 of the Code.

In August 2021, the Board of Directors adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s Tax Benefits.

Adopting the Tax Plan reduced the likelihood that changes in the Company’s investor base would limit the Company’s future use of its Tax Benefits.

On February 1, 2022, the Company announced the termination of the Tax Plan after the Board of Directors determined the Tax Plan was no longer necessary or desirable for the preservation of the Tax Benefits.

Critical accounting policies and estimates

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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.

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.

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.

Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting” for further details, including significant assumptions used to estimate the fair values of our assets and liabilities on the Emergence Date.

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Method of accounting for oil and gas properties

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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.

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

ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Crude oil, natural gas and 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.

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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

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

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

Impairment of goodwill and intangible assets

Goodwill represents the excess of consideration paid (or with respect to fresh start accounting, the excess of reorganization value) over the fair value of identified tangible and intangible assets.

Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of November 30 or more frequently if events or changes in circumstances indicate that the carrying amount might be impaired.

For the purpose of the goodwill impairment test, we first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment.

When performing a qualitative assessment, we determine the drivers of fair value of the reporting unit and evaluates whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment.

Our evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions.

If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed.

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.

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

Asset retirement obligations

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The accretion expense is recorded as a component of depreciation, depletion and amortization in our Consolidated Statements of Operations.

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Some of our midstream assets, including certain pipelines and our natural gas processing plants, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned.

We are not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance.

We will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable.

We determine the ARO by calculating the present value of estimated future cash flows related to the liability.

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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 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.

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During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain.

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

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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.

Cash G&A, Cash Interest, Adjusted EBITDA and Adjusted Free Cash Flow 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 G&A expenses, interest expense, net income (loss), or net cash provided by (used in) operating activities or any other measures prepared under GAAP.

Because these non-GAAP financial measures exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.

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,

Gathering, processing and transportation expenses $ 9,124 $ 85,896 $ 128,806 $ 107,193

Pipeline imbalances 189 (1,346) (2,446) (4,331)

$ 9,313 $ 84,550 $ 126,360 $ 102,862

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):

We define Cash G&A as total G&A expenses less G&A expenses attributable to discontinued operations, G&A expenses attributable to shared service allocations to our midstream operations, non-cash equity-based compensation expenses and other non-cash charges.

Cash G&A is not a measure of G&A expenses as determined by GAAP.

Management believes that the presentation of Cash G&A provides useful additional information to investors and analysts to assess our operating costs in comparison to peers without regard to G&A expenses that were allocated to our midstream operations, equity-based compensation programs and other non-cash items, 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 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,

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

General and administrative expenses $ 84,881 $ 14,224 $ 145,294 $ 123,506

General and administrative expenses attributable to discontinued operations 4,193 (579) 594 (5,089)

General and administrative expenses attributable to continuing operations 80,688 14,803 144,700 128,595

G&A expenses attributable to shared services (19,443) (2,569) (18,881) (19,648)

Equity-based compensation expenses (14,663) — (29,794) (32,755)

G&A expenses attributable to midstream and other services (1,989) (21,791) (24,805) (18,864)

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

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Cash Interest and E&P Cash Interest

We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense, and E&P Cash Interest is defined as total Cash Interest less Cash Interest attributable to OMP.

Cash Interest and E&P Cash Interest are not measures of interest expense as determined by GAAP.

Management believes that the presentation of E&P Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt to finance our E&P activities, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.

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

Other non-cash adjustments (371) — — —

Cash G&A $ 46,211 $ 12,234 $ 96,025 $ 76,192

Cash Interest

We define Cash Interest as interest expense less interest expense attributable to discontinued operations plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts.

Cash Interest is not a measure of interest expense as determined by GAAP.

Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt 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 measure of 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, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 (1)

Year Ended December 31, 2019

Interest expense $ 67,751 $ 3,168 $ 181,484 $ 176,223

Interest expense attributable to discontinued operations 36,945 1,148 39,648 16,936

Interest expense attributable to continuing operations 30,806 2,020 141,836 159,287

Capitalized interest 2,077 128 6,106 11,270

Amortization of deferred financing costs (2)

(13,727) (152) (6,865) (7,886)

Amortization of debt discount — — (8,317) (12,164)

Cash Interest $ 19,156 $ 1,996 $ 132,760 $ 150,507

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

(1) For the period from January 1, 2020 through November 19, 2020 (Predecessor), interest expense and cash interest include a specified default interest charge of $30.3 million attributable to continuing operations.

In addition, for the period from January 1, 2020 through November 19, 2020 (Predecessor), interest expense includes a specified default interest charge of $28.0 million attributable to discontinued operations.

These specified default interest charges were waived on the Emergence Date.

(2) For the year ended December 31, 2021 (Successor), we incurred a $7.8 million fee to enter into a commitment letter for a senior secured second lien facility.

The senior secured second lien facility was terminated prior to being drawn.

Adjusted EBITDA and Adjusted Free Cash Flow

We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or non-recurring charges.

Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP.

Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and analysts for assessing our results of operations, financial performance and ability to generate cash from our business operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our debt covenants.

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

We define Adjusted EBITDA from continuing operations as Adjusted EBITDA less Adjusted EBITDA attributable to discontinued operations, plus distributions from OMP.

We define Adjusted Free Cash Flow as Adjusted EBITDA from continuing operations less Cash Interest and E&P and other capital expenditures (excluding capitalized interest and acquisition capital).

Adjusted EBITDA and Adjusted Free Cash Flow are not measures of net income (loss) or cash flows as determined by GAAP.

Management believes that the presentation of Adjusted EBITDA and Adjusted Free Cash Flow provides useful additional information to investors and analysts for assessing our results of operations, financial performance, ability to generate cash from our business operations without regard to our financing methods or capital structure and our ability to maintain compliance with our debt covenants.

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 measures of Adjusted EBITDA and Adjusted Free Cash Flow 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,

Net loss including non-controlling interests $ (45,962) $ (3,724,611) $ (90,647) $ (19,500)

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

Net income (loss) including non-controlling interests $ 355,298 $ (45,962) $ (3,724,611) $ (90,647)

(Gain) loss on sale of properties (222,806) (11) (10,396) 4,455

(Gain) loss on extinguishment of debt — (83,867) (4,312) 13,848

Gain on extinguishment of debt — — (83,867) (4,312)

Net (gain) loss on derivative instruments 589,641 84,615 (233,565) 106,314

5 unchanged sentences

Exploration expenses 2,760 — 2,748 6,658

Successor Predecessor

Year Ended December 31, 2021 Period from November 20, 2020 through December 31, 2020 Period from January 1, 2020 through November 19, 2020 Year Ended December 31, 2019

Equity-based compensation expenses 15,476 270 31,315 33,607

4 unchanged sentences

Adjusted EBITDA 695,478 55,119 592,342 1,039,549

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

Adjusted EBITDA attributable to discontinued operations (216,540) (22,309) (173,457) (241,226)

Cash distributions from OMP and DevCo Interests 71,781 7,734 123,057 150,388

Adjusted EBITDA from continuing operations 550,719 40,544 541,942 948,711

Cash Interest (19,156) (1,996) (132,760) (150,507)

E&P and other capital expenditures (170,466) (15,018) (201,075) (609,977)

Midstream capital expenditures attributable to DevCo Interests — (1,173) (6,147) (14,353)

Capitalized interest 2,077 128 6,106 11,270

Adjusted Free Cash Flow $ 363,174 $ 22,485 $ 208,066 $ 185,144

Net cash provided by operating activities $ 914,136 $ 95,255 $ 202,936 $ 892,853

10 unchanged sentences

Adjusted EBITDA 695,478 55,119 592,342 1,039,549

Adjusted EBITDA attributable to non-controlling interests 5,430 41,716 51,525 21,703

Adjusted EBITDA attributable to Oasis $ 49,689 $ 550,626 $ 988,024 $ 936,979

Segment Adjusted EBITDA and E&P Free Cash Flow

We define E&P Free Cash Flow as Adjusted EBITDA for our E&P segment plus distributions to Oasis for our ownership of (i) OMP limited partner units, (ii) a controlling interest in OMP’s general partner, OMP GP, and (iii) retained interests in Bobcat DevCo LLC and Beartooth DevCo LLC (together, the “DevCo Interests”);

less E&P Cash Interest, capital expenditures for E&P and other (excluding capitalized interest) and midstream capital expenditures attributable to our DevCo Interests.

E&P Free Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP.

Management believes that the presentation of E&P Free Cash Flow provides useful additional information to investors and analysts for assessing the financial performance of our E&P business as compared to our peers and our ability to generate cash from our E&P operations and

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midstream ownership interests after interest and capital spending.

In addition, E&P Free Cash Flow excludes changes in operating assets and liabilities that relate to the timing of cash receipts and disbursements, which we may not control, and changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

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

Exploration and Production (1)

Successor Predecessor

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

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)

Adjusted EBITDA attributable to discontinued operations (216,540) (22,309) (173,457) (241,226)

Cash distributions from OMP and DevCo Interests 71,781 7,734 123,057 150,388

Adjusted EBITDA from continuing operations 550,719 40,544 541,942 948,711

Cash Interest (19,156) (1,996) (132,760) (150,507)

E&P and other capital expenditures (170,466) (15,018) (201,075) (609,977)

1 unchanged sentence

Capitalized interest 2,077 128 6,106 11,270

E&P Free Cash Flow (3)

$ 22,098 $ 203,466 $ 159,359 $ (1,246,444)

____________________

(1) As a result of our Well Services Exit in the first quarter of 2020, the well services business is no longer a separate reportable segment, and the remaining services performed by OWS are included in the E&P segment.

Prior period amounts have been restated to reflect the change in reportable segments.

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

(3) For the 2020 Predecessor Period, E&P Cash Interest includes the impact of Specified Default Interest charges of $30.3 million related to the Predecessor Credit Facility, which was waived pursuant to the Plan on the Emergence Date.

The offsetting discharge of the Specified Default Interest was recorded in reorganization items, net for the 2020 Predecessor Period, and as a result, there is no net impact on E&P Free Cash Flow related to these charges.

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Successor Predecessor

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

(In thousands)

Income before income taxes including non-controlling interests $ 19,678 $ 136,616 $ 224,096 $ 141,001

Loss on sale of properties — — — 9,622

Interest expense, net of capitalized interest 1,023 39,648 16,936 2,343

Depreciation, depletion and amortization 4,199 36,670 37,152 29,282

Impairment — 111,613 — —

Equity-based compensation expenses 270 1,930 1,744 1,547

Reorganization items, net — (76,463) — —

Other non-cash adjustments 9 (884) — —

Adjusted EBITDA $ 25,179 $ 249,130 $ 279,928 $ 183,795

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

We define Adjusted Net Income (Loss) Attributable to Oasis as net income (loss) after adjusting for (i) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash charges or non-recurring items, (ii) the impact of net income (loss) attributable to non-controlling interests and (iii) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items, excluding net income (loss) attributable to non-controlling interests, in the same period.

Adjusted Net Income (Loss) Attributable to Oasis is not a measure of net income (loss) as determined by GAAP.

We define Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share as Adjusted Net Income (Loss) Attributable to Oasis divided by diluted weighted average shares outstanding.

Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share is not a measure of diluted earnings (loss) per share as determined by GAAP.

Management believes that the presentation of Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share provides useful additional information to investors and analysts for evaluating our operational trends and performance in comparison to our peers.

This measure is more comparable to earnings estimates provided by securities analysts, and charges or amounts excluded cannot be reasonably estimated and are excluded from guidance provided by us.

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

Successor Predecessor

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

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)

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)

(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)

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)

Litigation settlement — 0.07 0.06 —

Other non-cash adjustments 0.02 0.01 0.01 0.01

Tax impact (4)

(1.00) (3.06) (0.13) (0.11)

Other tax adjustments (5)

0.46 2.01 — —

Adjusted Diluted Earnings Attributable to Oasis Per Share $ 1.22 $ 0.40 $ 0.03 $ 0.26

Diluted weighted average shares outstanding (6)

19,991 318,253 315,324 310,860

Effective tax rate applicable to adjustment items (4)

23.7 % 23.7 % 23.7 % 23.7 %

____________________

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(1) For the 2020 Predecessor Period, OMP recorded an impairment expense of $103.4 million which is included in our Consolidated Statements of Operations.

The portion of OMP impairment expense attributable to non-controlling interests of $26.7 million is excluded from impairment expense in the table above for the 2020 Predecessor Period.

(2) For the 2020 Predecessor Period, we recorded Specified Default Interest charges of $30.3 million related to the Predecessor Credit Facility and OMP Specified Default Interest charges of $28.0 million related to the OMP Credit Facility.

The Specified Default Interest and OMP Specified Default Interest were waived upon our emergence from the Chapter 11 Cases.

The offsetting discharge of the Specified Default Interest and OMP Specified Default Interest was recorded in non-cash reorganization items, net for the 2020 Predecessor Period, and as a result, there is no net impact on Adjusted Net Income (Loss) Attributable to Oasis related to these charges.

The portion of OMP Specified Default Interest attributable to non-controlling interests of $9.1 million is excluded from additional interest charges and non-cash reorganization items, net in the table for the 2020 Predecessor Period.

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

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

(5) Other tax adjustments include the deferred tax asset valuation allowance and tax impact of non-deductible restructuring fees in the 2020 Predecessor Period.

These items are adjusted to reflect the tax impact of the other adjustments using an assumed effective tax rate that excludes their impact.

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

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Adjusted Free Cash Flow $ 363,174 $ 22,485 $ 208,066 $ 185,144

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis