What changed in this filing

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Item 1. Business

2022-02-25 compared with 2021-03-08 · 304 added, 365 removed, 487 unchanged (58% of the section changed)

Oasis Petroleum Inc.

(together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”), a Delaware corporation, is an independent exploration and production (“E&P”) company formed in 2007 focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States.

Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct our E&P activities and own our oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Permian Basin, respectively.

In addition to our E&P segment, we also operate a midstream business segment primarily through Oasis Midstream Partners LP (“OMP”).

OMP is a premier gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets in North America.

We own a substantial majority of the general partner and a majority of the outstanding units of OMP.

We derive significant cash flows from the midstream segment through distributions from our ownership of OMP limited partner units, distributions from the general partner and our retained ownership of equity interests in certain OMP subsidiaries.

As of December 31, 2020, we have 401,766 net leasehold acres in the Williston Basin, of which approximately 98% is held by production, and 24,396 net leasehold acres in the Permian Basin, of which approximately 74% is held by production.

In the Williston Basin, we are currently exploiting significant resource potential from the Middle Bakken and Three Forks formations, which are present across a substantial portion of our acreage.

In the Permian Basin, our development activities are focused on the Bone Spring and Wolfcamp formations, and our advanced geologic position supports strong inventory across multiple pay zones.

We believe the locations, size and concentration of our acreage in the Williston and Permian Basins create an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory.

Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs and has substantial Williston Basin and Permian Basin experience.

As of December 31, 2020, we had 1,127 gross (827.9 net) operated producing horizontal wells in the Williston Basin and 57 gross (53.4 net) operated producing horizontal wells in the Permian Basin, and our total average daily production in 2020 was 64,717 barrels of oil equivalent per day (“Boepd”).

As of December 31, 2020, DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 152.2 million barrels of oil equivalent (“MMBoe”) in the Williston Basin, of which 74% were classified as proved developed and 63% were crude oil, and net proved reserves to be 30.3 MMBoe in the Permian Basin, of which 55% were classified as proved developed and 80% were crude oil.

Voluntary Reorganization under Chapter 11 and Emergence from Bankruptcy

On September 30, 2020 (the “Petition Date”), Oasis Petroleum Inc.

and certain of our direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions (the “Chapter 11 Cases”) for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).

On November 10, 2020, the Bankruptcy Court confirmed the Joint Prepackaged Chapter 11 Plan of Reorganization of Oasis Petroleum Inc.

and its Debtor Affiliates (the “Plan”), and the Debtors emerged from bankruptcy on November 19, 2020 (the “Emergence Date”).

OMP and its subsidiaries were not included in the Chapter 11 Cases.

As a result of the restructuring, we strengthened our balance sheet, reducing our total indebtedness by $1.8 billion by issuing equity in a reorganized entity to the holders of our senior unsecured notes.

For more information on our emergence from the Chapter 11 Cases and related matters, see “Part II, Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” and “Part II, Item 8.

Financial Statements and Supplementary Data—Note 2—Emergence from Voluntary Reorganization under Chapter 11.”

Fresh start accounting

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

Accordingly, the consolidated financial statements on or after November 19, 2020 are not comparable to the consolidated financial statements prior to that date.

References to “Successor” relate to our financial position and results of operations as of and subsequent to the Emergence Date.

References to “Predecessor” relate to our financial position prior to, and our results of operations through and including, the Emergence Date.

For more information related to fresh start accounting, see “Part II.

Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting.”

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(together with our consolidated subsidiaries, the “Company,” “Oasis,” “we,” “us,” or “our”), a Delaware corporation, is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets in 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 unconventional onshore oil-rich resources in the continental United States.

As of December 31, 2021, we have 492,355 net leasehold acres in the Williston Basin, of which approximately 99% is held by production.

We are currently exploiting significant resource potential from the Middle Bakken and Three Forks formations, which are present across a substantial portion of our acreage.

We believe the locations, size and concentration of our acreage in the Williston Basin creates an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory.

Our management team has a proven track record in identifying, acquiring and executing large, repeatable development drilling programs and has substantial experience in the Williston Basin.

As of December 31, 2021, we had 1,499 gross (1,150.1 net) operated producing horizontal wells, and our total average daily production in 2021 was 58,032 barrels of oil equivalent per day (“Boepd”).

As of December 31, 2021, DeGolyer and MacNaughton, our independent reserve engineers, estimated our net proved reserves to be 250.8 million barrels of oil equivalent (“MMBoe”), of which 70% were classified as proved developed and 69% were crude oil.

Business Strategy

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

• Returns-focused business model.

We intend to generate significant free cash flow and sustainable full cycle returns by efficiently developing our acreage positions in the Williston and Permian Basins while maintaining rigorous capital discipline.

Our Board of Directors established a capital allocation committee that developed a framework focused on systematic evaluation and screening of capital investments to ensure strong returns, which forms the foundation of the Company’s budgeting process.

We intend to reinvest capital well within cash flow and return capital to shareholders.

We declared a dividend of $0.375 per share of common stock payable on March 22, 2021 to shareholders of record as of March 8, 2021.

Additionally, our management team is focused on maintaining our strong balance sheet and financial flexibility.

As of December 31, 2020, we had $449.0 million of liquidity available, including $15.9 million of cash and cash equivalents and $433.2 million in the aggregate of unused borrowing capacity available under the Oasis Credit Facility and the OMP Credit Facility (both as defined in “Part II, Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments”).

Our liquidity position, along with expected cash flows from operations, will provide continued financial flexibility as we actively manage the pace of development on our acreage positions.

• Operational excellence.

Our management team is focused on continuous improvement of our operations and overall cost structure and has significant experience in successfully operating cost-efficient development programs.

We have initiated an extensive third-party review of our cost structure and organizational efficiency and are targeting new material cost and capital efficiencies.

The magnitude and concentration of our acreage within the Williston and Permian Basins, particularly in the core of the plays, allows us to capture economies of scale, including the ability to drill multiple wells from a single drilling pad into multiple formations, utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.

Our team is focused on employing leading drilling and completion techniques to optimize overall project economics.

We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices.

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

• Maximize returns.

We intend to maximize returns through efficiently executing our development program and optimizing our capital allocation.

We have developed a systematic approach of responsibly executing our development program to enhance financial returns while evaluating our performance and focusing on continuous improvement.

As part of our efforts to maximize returns, we have established a rigorous capital allocation framework with the objective of balancing shareholder returns and reinvestment of capital.

We are focused on conservative capital allocation, delivering low reinvestment rates and returning significant capital to shareholders.

We have streamlined our portfolio through exiting the Permian Basin and the midstream business, while building scale in the Williston Basin.

This portfolio shift was fundamentally based on aligning company resources with our core competitive strengths and our strategic focus of building a sustainable enterprise which generates significant and sustainable free cash flow for the benefit of the Company and its shareholders.

We will continue to evaluate and pursue accretive industry consolidation opportunities that enhance shareholder value and build scale.

As opportunities arise, we intend to identify and acquire additional acreage and producing assets to supplement our existing operations.

During 2021, we paid cash dividends of $5.625 per share of common stock and repurchased $100.0 million of common stock.

On February 9, 2022, we announced a plan to return $280 million of capital to shareholders over the next year 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.

On February 9, 2022, we 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.

Our Board of Directors also authorized a new $150.0 million share repurchase program, which replaces the $100.0 million share repurchase program that was fully utilized during 2021.

• Financial strength.

Our management team is focused on maintaining a solid risk management process to preserve our strong balance sheet and protect our cash generation capabilities.

Recognizing the oil and gas industry is cyclical, our business is designed to navigate challenging environments while preserving sufficient liquidity to be opportunistic in low commodity price cycles.

As of December 31, 2021, we had $619.7 million of liquidity available, including $172.1 million of cash and cash equivalents and $447.6 million of unused borrowing capacity available under the Oasis Credit Facility (defined in “Part II, Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

• Built to last.

We are focused on creating a durable organization that generates strong financial returns and sustainable free cash flow through commodity cycles.

We believe we have an attractive inventory that is resilient to commodity price fluctuations, which supports the sustainable generation of free cash flow.

Our management team is focused on the continuous improvement of our operations and overall cost structure and has significant experience in successfully operating cost-efficient development programs.

The magnitude and concentration of our acreage within the Williston Basin allows us to capture economies of scale, including the ability to drill multiple wells from a single drilling pad into multiple formations, utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.

Our team is focused on employing leading drilling and completions techniques to optimize overall project economics.

We continuously evaluate our internal drilling and completions results and monitor the results of other operators to improve our operating practices.

We continue to optimize our completion designs based on geology and well spacing.

• Environmental, social and governance leadership.

We are committed to environmental, social and governance (“ESG”) initiatives and continue to implement new ESG best practices.

We work to provide safe, reliable energy in a responsible manner while meeting the expectations of a carbon-constrained world.

We are focused on identifying opportunities to minimize our environmental impact, improve safety, invest in our employees and support the communities in which we live and work.

We are a recognized industry leader in the capture of the natural gas that we produce due to the proactive and significant investments we have made in our midstream business.

As of December 31, 2020, we were capturing approximately 96% of our natural gas production in North Dakota, and our flared gas percentage is two-thirds less than the average for North Dakota operators.

In addition, we capture gas for other operators, reducing industry-wide emissions.

We foster a culture of innovation and continuous improvement, constantly looking for ways to strengthen our organizational agility and adaptability.

In addition, management, with oversight from our Board of Directors, created an enterprise risk management (“ERM”) committee, which seeks to improve our knowledge and awareness of emerging and strategic risks.

Formalizing our ERM process has allowed us to have a better enterprise-view of risks, improve our risk response and preparedness, and better incorporate risk mitigation around existing and emerging risks into our strategic plans.

• Responsible stewards.

We are committed to ESG initiatives and seek a culture of improvement in ESG practices.

We work to provide safe, reliable and affordable energy in a responsible manner while being cognizant of the broader energy transition.

The key tenets of our ESG philosophy are to identify opportunities to reduce our environmental impact, improve safety, invest in our employees and support the communities in which we live and work while improving transparency and accountability.

We are proficient in capturing the natural gas that we produce.

As of December 31, 2021, we were capturing approximately 92% of our natural gas production in North Dakota, and our flared gas percentage for the year ended December 31, 2021 was well below the average for North Dakota operators.

We are working to further improve gas capture as we integrate the recently acquired assets in the Williston Basin, while also identifying areas for improvement on our legacy assets.

We provide leadership training and educational and professional development programs for employees at every level of the organization.

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We are deeply involved in the areas in which we work and deploy our financial resources, time and talent to support a number of charitable organizations and our local communities.

Our refreshed Board of Directors is comprised of experienced energy industry professionals and 83% independent.

The Board of Directors established the Nominating, Environmental, Social and Governance Committee to oversee our ESG policies.

We have implemented compensation practices focused on value creation and aligned with shareholder interests.

For more information about our ESG and corporate responsibility efforts, please see the “Sustainability” page of our website and the Proxy Statement that we will file for our 2021 Annual Meeting of Shareholders.

• Portfolio review.

We are reviewing our E&P portfolio of quality assets in the Williston and Permian Basins for fit with our new business model focused on generating free cash flow and sustainable returns.

In addition, we are evaluating our midstream position for optimal structure and value creation options.

• Consolidation.

We will evaluate and pursue strategic acquisition opportunities that enhance shareholder value and build scale.

As opportunities arise, we intend to identify and acquire additional acreage and producing assets to

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supplement our existing operations.

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

Our Board of Directors is 87.5% independent and comprised of diverse and experienced energy industry professionals.

As part of our ongoing effort to enhance our ESG practices, the Board of Directors has established the Nominating, Environmental, Social and Governance Committee, which is charged with overseeing our ESG policies.

To help strengthen our ESG performance, we have implemented compensation practices focused on value creation and aligned with shareholder interests.

For more information about our ESG and corporate responsibility efforts, please see our inaugural Sustainability Report that was published in August 2021 and can be found on our website.

In addition, more information on our ESG practices can be found on the “Sustainability” page of our website and in the Proxy Statement that we will file for our 2022 Annual Meeting of Shareholders.

Competitive Strengths

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

• Best-in-class balance sheet.

We believe our strong balance sheet will allow us to generate significant free cash flow and corporate-level returns.

We have no near-term debt maturities.

We are focused on rigorous capital discipline and have a robust hedging program to minimize downside risk.

• Incentivized management team with proven operating and acquisition skills.

Our senior management team has extensive expertise in the oil and gas industry with an average of more than 25 years of industry experience.

We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven track record in identification, acquisition and execution of large, repeatable development drilling programs.

In addition, a substantial majority of our executive officers’ overall compensation has been in long-term equity-based incentive awards, and we have implemented best-in-class management compensation practices aligned with shareholders, which we believe provides them with significant incentives to grow the value of our business and return capital to shareholders.

• Substantial leasehold position in two of North America’s leading unconventional crude oil resource plays.

We believe our Williston Basin acreage is one of the largest concentrated leasehold positions that is prospective in the Bakken and Three Forks formations and will continue to provide significant free cash flow generation.

• Substantial leasehold position in one of North America’s leading unconventional crude oil resource plays.

We believe our Williston Basin acreage is one of the largest concentrated leasehold positions and will continue to provide significant free cash flow generation.

As of December 31, 2021, we had 492,355 net leasehold acres in the Williston Basin, of which 487,254 net acres were held by production, and 69% of our 250.8 MMBoe estimated net proved reserves in this area were comprised of crude oil.

We believe our Permian Basin leasehold position provides attractive rates of return in the deepest part of one of the most prolific crude oil plays in North America across the highly contiguous blocks of acreage.

As of December 31, 2020, we had 24,396 net leasehold acres in the Permian Basin, of which 17,933 net acres were held by production, and 80% of our 30.3 MMBoe estimated net proved reserves in this area were comprised of crude oil.

We believe we have a large project inventory of potential drilling locations that we have not yet drilled, a majority of which are operated by us.

In 2021, we will continue our drilling and completion activities in both the Williston and Permian Basins.

In 2022, we will continue our drilling and completion activities in the Williston Basin.

• Operating control over the majority of our portfolio.

In order to maintain better control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate.

As of December 31, 2020, 97% of our estimated net proved reserves were attributable to properties that we expect to operate.

In 2021, we plan to complete approximately 23 to 25 gross operated wells with an average working interest of approximately 86% in the Williston Basin and approximately 6 to 8 gross operated wells with an average working interest of approximately 100% in the Permian Basin.

In addition to our E&P position, we have a robust midstream infrastructure platform that we control that provides attractive cost and certainty of service.

Controlling operations enables us to optimize capital allocation and control the pace of development of our assets to manage our reinvestment rates in line with our broader strategic objectives.

Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio, including both our E&P and midstream segments.

As of December 31, 2021, 94% of our estimated net proved reserves were attributable to properties that we operate.

In 2022, we plan to complete approximately 40 to 42 gross operated wells with an average working interest of approximately 72%.

Controlling operations enables us to optimize capital allocation and control the pace of

development of our assets to manage our reinvestment rates in line with our broader strategic objectives.

Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio.

We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational and cost efficiencies and capital efficiency.

We are also better able to manage infrastructure investment to drive down operating costs and optimize crude oil, natural gas and NGL price realizations.

• Vertical integration.

Our investment in and operational control of our midstream business provides us with additional operational efficiencies and cost savings compared to our peers.

This vertical integration helps us control capital dollars being spent in advance of production to ensure volumes flow, improve uptime performance of our producing wells, protect against rising service costs and increase transparency in the planning process.

In addition, our midstream business generates free cash flow, provides optionality and further diversifies our customer base through midstream services we provide to other companies.

• Best-in-class balance sheet.

We believe our strong balance sheet will allow us to generate significant, sustainable free cash flow and corporate-level returns.

We have no near-term debt maturities, are focused on rigorous capital discipline and have a robust hedging program to minimize downside risk.

• Incentivized management team with proven operating and acquisition skills.

Our senior management team has extensive expertise in the oil and gas industry with an average of more than 25 years of industry experience.

Exploration and Production Operations

Proved reserves

Estimated net proved reserves

Our estimated net proved reserves and related PV-10 at December 31, 2021, 2020 and 2019 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers.

In preparing its reports, DeGolyer and MacNaughton evaluated 100% of the reserves and discounted values at December 31, 2020, 2019 and 2018 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in crude oil and natural gas

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producing activities.

In preparing its reports, DeGolyer and MacNaughton evaluated 100% of the reserves and discounted values at December 31, 2021, 2020 and 2019 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in crude oil and natural gas producing activities.

Our estimated net proved reserves and related future net revenues, PV-10 and standardized measure of discounted future net cash flows (“Standardized Measure”) do not include probable or possible reserves and were determined using the preceding 12 months’ unweighted arithmetic average of the first-day-of-the-month index prices for crude oil and natural gas, which were held constant throughout the life of the properties.

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See “Reconciliation of Standardized Measure to PV-10” below.

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

Proved Developed Proved Undeveloped

Crude oil (MMBbls) Natural gas (Bcf) Total

(MMBoe) Crude oil (MMBbls) Natural gas (Bcf) Total

Williston Basin 72.3 241.9 112.6 23.3 97.2 39.6

Permian Basin 13.2 20.8 16.6 11.0 16.3 13.7

Total 85.5 262.7 129.2 34.3 113.5 53.3

Estimated net proved reserves at December 31, 2020 were 182.5 MMBoe, a 36% decrease from estimated net proved reserves of 286.4 MMBoe at December 31, 2019, primarily due to decreases of 86.3 MMBoe for net negative revisions and 23.7 MMBoe for production, partially offset by an increase of 6.0 MMBoe for additions.

The net negative revisions were attributable to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 31.9 MMBoe due to lower realized prices, offset by positive revisions of 1.1 MMBoe due to lower operating expenses.

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

Proved developed revisions were primarily due to negative revisions of 29.3 MMBoe due to lower realized prices, partially offset by positive revisions of 1.5 MMBoe due to lower operating expenses.

Our proved undeveloped reserves decreased 67.4 MMBoe, or 56%, to 53.3 MMBoe for the year ended December 31, 2020 from 120.6 MMBoe for the year ended December 31, 2019 primarily due to net negative revisions of 58.4 MMBoe and the conversion of wells to proved developed of 11.7 MMBoe, offset by additions of 2.8 MMBoe.

The proved undeveloped revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the anticipated five-year development plan and 2.6 MMBoe due to lower realized prices.

See Note 27 to our consolidated financial statements for more information on our proved reserves for the years ended December 31, 2019 and 2018.

Estimated net proved reserves at December 31, 2021 were 250.9 MMBoe, a 37% increase from estimated net proved reserves of 182.5 MMBoe at December 31, 2020, primarily due to increases of 57.0 MMBoe for the acquisition of assets in the Williston Basin, 53.9 MMBoe for net positive revisions and 10.2 MMBoe for additions, partially offset by a decrease of 31.5 MMBoe for the divestiture of assets in the Permian Basin and 21.2 MMBoe for production.

The net positive revisions of 53.9 MMBoe were attributable to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, 37.2 MMBoe associated with higher realized prices and 6.2 MMBoe due to lower operating expenses, partially offset by negative revisions of 22.9 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 5.2 MMBoe due to the impact of removing the benefits of our midstream operations from operating expenses.

Our proved developed reserves increased 45.1 MMBoe, or 35%, to 174.3 MMBoe for the year ended December 31, 2021 from 129.2 MMBoe for the year ended December 31, 2020, primarily due to increases of 47.3 MMBoe for the acquisition of producing assets in the Williston Basin, 20.3 MMBoe for net positive revisions, 16.6 MMBoe for the conversions of proved undeveloped reserves and 2.6 MMBoe for additions.

These increases were partially offset by decreases of 21.2 MMBoe for production and 20.5 MMBoe for the divestiture of producing assets in the Permian Basin.

The proved developed net positive revisions of 20.3 MMBoe were attributable to positive revisions of 36.5 MMBoe associated with higher realized prices and 6.0 MMBoe due to lower operating expenses, partially offset by negative revisions of 17.6 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 4.6 MMBoe due to the impact of removing the benefits of our midstream operations from operating expenses.

Our proved undeveloped reserves increased 23.3 MMBoe, or 44%, to 76.5 MMBoe for the year ended December 31, 2021 from 53.3 MMBoe for the year ended December 31, 2020, primarily due to increases of 33.5 MMBoe for net positive revisions, 9.8 MMBoe for the acquisition of undrilled acreage in the Williston Basin and 7.6 MMBoe for additions, offset by decreases of 16.6 MMBoe for the conversion of wells to proved developed and 11.0 MMBoe for the divestiture of undrilled acreage in the Permian Basin.

The proved undeveloped net positive revisions of 33.5 MMBoe were attributable to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, offset by negative revisions of 5.1 MMBoe attributable to reservoir analysis and well performance across our Bakken asset.

See Note 25 to our consolidated financial statements for more information on our estimated proved reserves for the years ended December 31, 2020 and 2019.

For the comparison of the years ended December 31, 2020 and 2019, refer to “Item 1.

Business—Our operations - exploration and production activities” in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020.

Business—Our operations - exploration and production activities” in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on March 8, 2021.

Reconciliation of Standardized Measure to PV-10

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PV-10 $ 3,115.4 $ 1,115.0 $ 2,934.4

The PV-10 of our estimated net proved reserves at December 31, 2020 was $1,115.0 million, a 62% decrease from PV-10 of $2,934.4 million at December 31, 2019.

This decrease was primarily due to lower commodity price assumptions and a decrease in reserves year over year.

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The PV-10 of our estimated net proved reserves at December 31, 2021 was $3.1 billion, a 179% increase from PV-10 of $1.1 billion at December 31, 2020.

This increase was primarily due to higher commodity price assumptions and an increase in reserves year over year.

Proved undeveloped reserves

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Extensions, discoveries and other additions 7,587

Purchases of minerals in place 9,758

Sales of minerals in place (10,952)

Revisions of previous estimates 33,513

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The remaining $98.6 million resulted in the conversion of 16.6 MMBoe of proved undeveloped reserves, or 31% of our proved undeveloped reserves balance at the beginning of 2021, to proved developed reserves.

We added 2.8 MMBoe of proved undeveloped reserves as a result of our five-year development plan.

The 2020 proved undeveloped revisions of 58.4 MMBoe were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the anticipated five-year development plan and 2.6 MMBoe due to lower realized prices.

We expect to develop all of our proved undeveloped reserves, including all wells drilled but not yet completed, as of December 31, 2020 within five years.

The future development of such proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, the Oasis Credit Facility and our derivative contracts.

All proved undeveloped locations are located on properties where the leases are held by existing production or continuous drilling operations.

Approximately 21% of our proved undeveloped reserves at December 31, 2020 are attributable to wells that have been drilled but not yet completed, and 100% of our undrilled reserves are within our core acreage in the Williston and Permian Basins.

We added 9.8 MMBoe of proved undeveloped reserves for the acquisition of undrilled acreage in the Williston Basin and 7.6 MMBoe of proved undeveloped reserves as a result of our five-year development plan, offset by a decrease of 11.0 MMBoe for the divestiture of undrilled acreage in the Permian Basin.

The 2021 proved undeveloped revisions of 33.5 MMBoe were attributable to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, partially offset by negative revisions of 5.1 MMBoe attributable to reservoir analysis and well performance across our Bakken asset.

We expect to develop all of our proved undeveloped reserves, including all wells drilled but not yet completed, as of December 31, 2021 within five years after the initial year booked.

The future development of such proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as cash flows from operations, capital markets, the Oasis Credit Facility and our derivative contracts.

Substantially all proved undeveloped locations are located on properties where the leases are held by existing production or continuous drilling operations.

Approximately 5% of our proved undeveloped reserves at December 31, 2021 are attributable to wells that have been drilled but not yet completed, and 100% of our undrilled reserves are within our core acreage in the Williston Basin.

Independent petroleum engineers

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The firm’s more than 180 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry.

DeGolyer and MacNaughton has provided such services for 85 years.

DeGolyer and MacNaughton has provided such services for over 85 years.

The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Professional Engineer in the State of Texas, is a member of the Society of Petroleum Engineers and has over 10 years of experience in crude oil and natural gas reservoir studies and reserve evaluations.

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The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate.

Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in

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the same reservoir or an analogous reservoir or by using reliable technology.

Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology.

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

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Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history and appropriate reserves definitions.

The methodology used for the analysis

was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history and appropriate reserves definitions.

Internal controls over reserves estimation process

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

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

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

Production, price and cost history

We produce and market crude oil, natural gas and NGLs, which are commodities.

The price that we receive for the crude oil and natural gas we produce is largely a function of market supply and demand.

The price that we receive for the crude oil, natural gas and NGLs we produce is largely a function of market supply and demand.

Demand is impacted by general economic conditions, access to markets, weather and other seasonal conditions, including hurricanes and tropical storms.

Over or under

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supply of crude oil or natural gas can result in substantial price volatility.

Over or under supply of crude oil, natural gas or NGLs can result in substantial price volatility.

Historically, commodity prices have been volatile, and we expect that volatility to continue in the future.

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

The following table sets forth information regarding our crude oil and natural gas production by basin, realized prices and production costs for the periods presented.

The following table sets forth information regarding our crude oil and natural gas production, realized prices and production costs for the periods presented.

Prior periods have been recast to reflect the impacts of discontinued operations due to the OMP Merger (defined below).

For additional information on price calculations, please see information set forth in “Part II, Item 7.

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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,

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 production volumes:

Williston Basin

Crude oil (MBbls) 13,489 1,593 14,226 22,825

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Average daily production (Boepd) 58,032 57,809 65,612 88,061

Permian Basin

Crude oil (MBbls) 257 2,368 2,102 1,264

Natural gas (MMcf) 364 3,355 3,093 1,880

Oil equivalents (MBoe) 317 2,927 2,618 1,578

Average daily production (Boepd) 7,553 9,033 7,172 4,322

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

Average sales prices:

Crude oil (per Bbl)

Williston Basin $ 42.98 $ 37.04 $ 55.30 $ 62.21

Permian Basin 45.30 35.30 54.96 55.52

Total average sales price 43.36 36.75 55.27 61.84

Total average realized price after the effect of derivative settlements (1)

Crude oil, without derivative settlements (per Bbl) $ 67.49 $ 43.36 $ 36.75 $ 55.27

Crude oil, with derivative settlements (1) (per Bbl)

48.55 43.36 48.13 55.89

Natural gas (per Mcf)

Williston Basin 3.54 2.00 2.70 3.91

Permian Basin 2.56 0.94 1.48 3.29

Total average sales price (2)

Natural gas, without derivative settlements (2) (per Mcf)

6.28 3.41 1.86 2.62

Total average realized price after the effect of derivative settlements (1)(2)

Natural gas, with derivative settlements (1)(2) (per Mcf)

5.96 3.40 1.86 2.70

Average costs (per Boe):

Production costs (3)

Williston Basin $ 11.81 $ 9.96 $ 11.04 $ 10.08

Permian Basin 6.44 7.39 10.10 8.31

Lease operating expenses 9.63 9.27 7.55 8.98

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Production taxes 3.63 2.45 2.14 3.50

E&P general and administrative expenses 5.04 5.92 3.39 3.63

E&P Cash G&A (4)

General and administrative expenses 3.81 6.10 6.81 4.00

2.18 5.04 4.52 2.37

__________________

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

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derivative liquidations.

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

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

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

(4) E&P Cash G&A, a non-GAAP financial measure, represents general and administrative (“G&A”) expenses less non-cash equity-based compensation expenses and other non-cash charges included in our E&P segment.

(3) Cash G&A is a non-GAAP financial measure.

See “Part II, Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for a reconciliation of G&A expenses to E&P Cash G&A.

The following table sets forth certain information regarding the developed and undeveloped acreage by basin in which we own a working interest as of December 31, 2020.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for a reconciliation of G&A expenses to Cash G&A.

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2021.

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

Developed acres Undeveloped acres Total

Gross Net Gross Net Gross Net

Williston Basin 466,649 355,203 78,459 46,563 545,108 401,766

Permian Basin 27,431 16,162 12,748 8,234 40,179 24,396

Total 494,080 371,365 91,207 54,797 585,287 426,162

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

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

Developed acres 549,517 422,750

Undeveloped acres 99,214 69,605

Total acres 648,731 492,355

Our total acreage that is held by production increased to 487,254 net acres at December 31, 2021 from 411,652 net acres at December 31, 2020 .

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2021 that will expire over the next three years unless production is established on the acreage prior to the expiration dates:

Undeveloped acres expiring

Year ending December 31,

2022 3,914 1,115

Gross Net Gross Net Gross Net

Williston Basin 6,030 5,769 3,599 1,108 262 161

Permian Basin 1,794 879 110 13 40 6

Total 7,824 6,648 3,709 1,121 302 167

2024 1,018 864

Productive wells

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

Total wells Operated wells

Gross Net Gross Net

Williston Basin - horizontal wells 1,491 870.6 1,127 827.9

Williston Basin - other — — — —

Permian Basin - horizontal wells 172 54.1 57 53.4

Permian Basin - other 17 6.4 4 3.2

Total wells 1,680 931.1 1,188 884.5

All of our productive wells are crude oil wells.

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

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As of December 31, 2021, we had 2,226 (1,218.1 net) total gross productive wells, of which 1,499 gross (1,150.1 net) productive wells were operated by us.

All of our productive wells as of December 31, 2021 were horizontal wells.

Drilling and completion activity

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As of December 31, 2021, we had 26 gross (10.8 net) wells in the process of being drilled or completed, which includes 10 gross operated wells waiting on completion and 15 gross non-operated wells drilling or completing.

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

As of December 31, 2021, we had two operated rigs running, and we expect to run two operated rigs during 2022.

Description of properties

Williston Basin

Our position in the North Dakota and Montana areas of the Williston Basin is our cornerstone asset.

As of December 31, 2021, our operations were focused in the North Dakota and Montana areas of the Williston Basin.

We are one of the top producers in the Williston Basin and have been active in the area since our formation.

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Our development activity is currently focused on our top-tier operated acreage in the deepest part of the Williston Basin in McKenzie, Mountrail and Williams counties in North Dakota.

As of December 31, 2020, our total leasehold position in the Williston Basin consisted of 401,766 net acres, and we had a total of 870.6 net producing wells and 827.9 net operated producing wells in the Williston Basin.

During the year ended December 31, 2020, we had average daily production of 55,853 net Boepd in the Williston Basin, 100% of which was produced from horizontal wells.

As of December 31, 2020, our working interest for producing horizontal wells averaged 58% in total and 73% in the wells we operate.

Permian Basin

We entered the Permian Basin in February 2018 when we closed on an acquisition of approximately 22,000 net acres primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across Ward, Winkler, Loving and Reeves counties in West Texas (the “2018 Permian Acquisition”).

Our advanced geologic position in the Permian Basin results in an over 80% oil mix and has multi-stacked pay zones, with four primary stacked zones counted in our core inventory and potential upside from four additional zones.

As of December 31, 2020, our total leasehold position in the Permian Basin consisted of 24,396 net acres, and we had a total of 60.5 net producing wells and 56.6 net operated producing wells in the Permian Basin.

During the year ended December 31, 2020, we had average daily production of 8,864 net Boepd in the Permian Basin, of which 99%, or 8,818 net Boepd, was produced from horizontal wells.

As of December 31, 2020, we had 53.4 net operated producing horizontal wells in the Permian Basin, and our working interest for producing horizontal wells in the Permian Basin averaged 31% in total and 94% in the wells we operate.

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Continuous development agreement.

In connection with the closing of the 2018 Permian Acquisition, Forge Energy, LLC (“Forge Energy”) entered into and assigned to OP Permian a continuous development agreement (the “CDA”) with the Commissioner of the General Land Office, on behalf of the State of Texas (collectively, the “State”), as approved by the Board for Lease of University Lands (together with the State, “University Lands”).

The CDA concerns certain leases covering a substantial portion of the acreage that we indirectly acquired from Forge Energy in the 2018 Permian Acquisition and under which University Lands is the lessor.

Pursuant to the CDA, the tracts covered by these leases are pooled into a single development area for which we indirectly hold an eight-year initial term ending on December 31, 2025, with an additional five-year term for certain retained acreage at certain depths in the Delaware, Bone Spring and Wolfcamp formations.

If OP Permian fails to meet certain drilling and development obligations, the CDA may be subject to early termination, in which case, we may be obligated to pay non-performance fees of up to approximately $100 million.

See “Item 1A.

Risk Factors—Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.

Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.” Due to the extraordinary market conditions during 2020, we agreed with University Lands to pause operations, and on December 31, 2020, we executed an amendment to the CDA reflecting that agreement.

The amendment reduced or postponed certain drilling and development obligations for the year ended December 31, 2020 and did not result in the payment of any penalty.

Our current budget contemplates drilling activity which does not meet certain obligations under the CDA.

We are currently in discussions with University Lands, similar to those held in 2020, in which we will seek an amendment for the reduction of our drilling obligations for 2021 similar to that previously received.

We can provide no assurance that we will be successful in obtaining this amendment.

Given the early stages of our discussions with University Lands on our drilling obligations for 2021 and the continuous flexibility we have with our drilling program to adjust as market and business conditions warrant, we cannot predict whether we will incur losses or estimate the amount of any potential loss.

As of December 31, 2021, our total leasehold position in the Williston Basin consisted of 492,355 net acres, and we had a total of 1,218.1 net producing wells and 1,150.1 net operated producing wells.

During the year ended December 31, 2021, we had average daily production of 58,032 net Boepd.

As of December 31, 2021, our working interest for producing wells averaged 55% in total and 77% in the wells we operate.

On June 29, 2021, we completed our exit from the Permian Basin to build size and scale in the Williston Basin.

For additional information on the sale of our upstream assets in the Permian Basin, see “Part II, Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments.”

Marketing and major customers

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These gathering systems, which typically originate at the wellhead and are connected to multiple pipeline and rail facilities, reduce the need to transport barrels by truck from the wellhead.

As of December 31, 2020, we were flowing approximately 92% of our gross operated crude oil production through crude oil gathering systems, including 93% of our gross operated crude oil production in the Williston Basin and 81% of our gross operated crude oil production in the Permian Basin.

As of December 31, 2021, we were flowing approximately 95% of our gross operated crude oil production through crude oil gathering systems.

In addition, from time to time we may enter into third-party purchase and sales transactions that allow us to optimize our advantageous gathering and transportation positions and increase the value of our crude oil price realizations.

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For a description of some of these factors, please see “Item 1A.

Risk Factors—Risks related to the oil and gas industry and our business—The marketability of our production is dependent upon crude oil, natural gas and NGL gathering, processing and transportation facilities, some of which are owned by third parties.

Market conditions or operational impediments could hinder our access to crude oil, natural gas or NGL markets, delay our production or reduce the realized prices we receive.”

For the Successor period of November 20, 2020 through December 31, 2020, sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of our total product sales.

For the Predecessor period of January 1, 2020 through November 19, 2020, Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of our total product sales.

For the year ended December 31, 2019, sales to Phillips 66 Company accounted for approximately 14% of our hydrocarbon product sales.

Risk Factors—Risks related to the oil and

gas industry and our business—We depend upon Crestwood, a third party midstream provider, for a large portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure from Crestwood and other midstream providers to successfully deliver crude oil, natural gas and NGLs to market may adversely affect our earnings, cash flows and results of operations.”

For the year ended December 31, 2021 (Successor), sales to Phillips 66 Company accounted for approximately 13% of our total product sales.

For the period of November 20, 2020 through December 31, 2020 (Successor), sales to ExxonMobil Oil Corporation and Phillips 66 Company accounted for approximately 22% and 15%, respectively, of our total product sales.

For the period of January 1, 2020 through November 19, 2020 (Predecessor), Phillips 66 Company and Gunvor USA LLC accounted for approximately 11% and 10%, respectively, of our total product sales.

For the year ended December 31, 2019 (Predecessor), sales to Phillips 66 Company accounted for approximately 14% of our total product sales.

No other purchasers accounted for more than 10% of our total sales in 2021, 2020 or 2019.

For the year ended December 31, 2018, no purchaser accounted for more than 10% of our total sales.

We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as there are a number of alternative crude oil, natural gas and NGL purchasers and markets in the Williston and Permian Basins.

Delivery commitments

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

We are required to make periodic deficiency payments for any shortfalls in delivering the minimum

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volume commitments under certain agreements.

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

Midstream Operations

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

Our midstream operations are primarily conducted through OMP, a consolidated subsidiary and master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets.

OMP conducts its operations through its four development companies:

As of December 31, 2021, we had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 45.8 MMBbl of crude oil, 603.3 Bcf of natural gas and 22.5 MMBbl of NGLs, prior to any applicable volume credits, within specified timeframes, the majority of which are ten years or less.

We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements.

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

We acquired certain unfavorable contracts in connection with the Williston Basin Acquisition where we determined it was probable we would not meet the minimum volume commitment in the agreement and have recorded a liability of $11.9 million as of December 31, 2021.

Midstream Transactions

As of December 31, 2021, we operated a midstream business that provided midstream services for natural gas (gathering, compression, processing and gas lift supply), crude oil (gathering, terminaling and transportation) and water services (gathering and disposal of produced and flowback water and freshwater distribution).

These midstream operations were primarily conducted through Oasis Midstream Partners LP (“OMP”), a consolidated subsidiary and master limited partnership that operates midstream assets through its four wholly-owned development companies:

Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”), Beartooth DevCo LLC (“Beartooth DevCo”) and Panther DevCo LLC.

At December 31, 2020, our ownership interest in OMP consisted of a 67.5% limited partner interest, a 92% controlling interest in OMP GP LLC (“OMP GP”), which owns all of OMP’s incentive distribution rights and its non-economic general partner interest, and our retained interests in Bobcat DevCo and Beartooth DevCo of 64.7% and 30%, respectively.

Our midstream assets are strategically located with our exploration and development activities in the Williston and Permian Basins and support our upstream operations.

We have several long-term contractual arrangements with OMP, pursuant to which we have dedicated significant acreage to OMP for midstream services.

We have approved an expansion of our acreage dedication to OMP in South Nesson, one of our top operating areas in the Williston Basin, to now include crude oil and produced water services.

We previously dedicated our South Nesson acreage to OMP for natural gas services in 2019.

OMP expects volumes under each service offering to flow in 2022.

As part of the arrangement, we agreed to assign to Bighorn DevCo, which is 100% owned by OMP, certain assets in Bobcat DevCo specifically built to support both existing third-party customers in South Nesson and our future development.

All future midstream infrastructure in South Nesson will be built by Bighorn DevCo, which will perform, and earn the revenue for, all of OMP’s future midstream services in the area.

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

At December 31, 2021, we owned approximately 70% of OMP’s outstanding common units representing limited partner interests, as well as 100% of OMP’s general partner, OMP GP LLC (“OMP GP”).

On October 25, 2021, OMP and OMP GP entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”).

Pursuant to the Merger Agreement, Oasis agreed to sell to Crestwood its 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”).

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 Company had provided OMP acreage dedications pursuant to several long-term, fee-based contractual arrangements for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services;

(ii) crude oil gathering, terminaling and transportation services;

(iii) produced and flowback water gathering and disposal services;

and (iv) freshwater distribution services.

These contracts were assigned to Crestwood upon completion of the OMP Merger, and we now depend on Crestwood for a large portion of our midstream services.

See “Item 1A.

Risk Factors—Risks related to the oil and gas industry and our business” for more information.

In addition, the Company and Crestwood executed a director nomination agreement pursuant to which Oasis designated two directors to the Board of Directors of Crestwood GP Equity LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”).

Pursuant to the director nomination agreement, for so long as Oasis and its affiliates own at least 15% of Crestwood’s issued and outstanding common units, Oasis may designate two directors to the Board of Directors of Crestwood GP.

Oasis may designate one director if Oasis and its affiliates hold at least 10% (but less than 15%) of Crestwood’s issued and outstanding common units.

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

See “Part II.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” for additional information.

The oil and gas industry is worldwide and highly competitive in all phases.

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Title to Properties

As is customary in the crude oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves.

As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves.

Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects.

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Risk Factors—Risks related to the oil and gas industry and our business—We may incur losses as a result of title defects in the properties in which we invest.”

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Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other crude oil and natural gas operations.

These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs.

Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Our E&P and midstream operations are substantially affected by federal, tribal, regional, state and local laws and regulations.

In particular, crude oil and natural gas production, crude oil gathering and transportation, natural gas processing and related operations are, or have been, subject to price controls, taxes and numerous laws and regulations.

All of the jurisdictions in which we own or operate properties for crude oil and natural gas production or otherwise provide midstream services have statutory provisions regulating the exploration for and production of crude oil and natural gas or the gathering, transportation and processing of those commodities, including provisions related to permits for the drilling of wells or processing of natural gas, bonding requirements to drill or operate producing or injection wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled or processing plants are constructed, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells.

Such seasonal anomalies can also pose challenges for meeting our drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Our E&P operations are substantially affected by federal, tribal, regional, state and local laws and regulations.

In particular, crude oil and natural gas production is, or has been, subject to price controls, taxes and numerous laws and regulations.

All of the jurisdictions in which we own or operate properties for crude oil and natural gas production have statutory provisions regulating the exploration for and production of crude oil and natural gas or the gathering, transportation and processing of those commodities, including provisions related to permits for the drilling of wells or processing of natural gas, bonding requirements to drill or operate producing or injection wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled or processing plants are constructed, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells.

Our operations are also subject to various conservation laws and regulations.

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Therefore, we are unable to predict the future costs or impact of compliance.

Additional proposals and proceedings that affect the oil and gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts.

Additional proposals and proceedings that affect the oil and gas industry are regularly considered by Congress, the states, the Federal

Energy Regulatory Commission (“FERC”) and the courts.

We cannot predict when or whether any such proposals may be finalized and become effective.

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Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for crude oil pipelines that allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index, without making a cost of service filing.

Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1, and our Bighorn DevCo Johnson’s Corner line will utilize the FERC crude oil index beginning on July 1, 2022.

Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1.

Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs.

Most recently, on December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index plus 0.78%.

FERC has received requests for rehearing of its December 17, 2020 order, which remain pending in FERC Docket No.

On December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates were permitted to adjust their indexed ceiling annually by Producer Price Index plus 0.78%.

The Commission received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index (“January 2022 Order”).

Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index minus 0.21%.

FERC directed oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 based on the new index level.

Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022.

Bighorn DevCo owns a FERC regulated crude oil transportation pipeline to Johnson’s’ Corner.

Bighorn DevCo historically has not filed to increase its rates pursuant to the index;

therefore its existing rates remain under the ceiling level.

On February 1, 2022, we completed the OMP Merger and no longer have any ownership interest in Bighorn DevCo.

Intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions.

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Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis.

Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same

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terms and under the same rates.

Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates.

When crude oil pipelines operate at full capacity, access is generally governed by prorationing provisions set forth in the pipelines’ published tariffs.

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Since 2011, all new railroad tank cars that have been built to transport crude oil or other petroleum type fluids, including ethanol, have been built to more stringent safety standards.

In 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, new operational protocols for trains transporting large volumes of flammable liquids and a requirement that older DOT-111 tank cars be phased out beginning in October 2017 if they are not already retrofitted to comply with new tank car design standards.

In 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029, and more recently in February 2019, PHMSA published a final rule requiring railroads to develop and submit comprehensive oil spill response plans for specific route segments traveled by a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train.

Additionally, the February 2019 final rule requires railroads to establish geographic response zones along various rail routes, ensure that both personnel and equipment are staged and prepared to respond in the event of an accident, and share information about high-hazard flammable train operations with state and tribal emergency response commissions.

In addition, a number of states proposed or enacted laws in recent years that encourage safer rail operations, urge the federal government to strengthen requirements for these operations or otherwise seek to impose more stringent standards on rail transport of crude oil.

In 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, new operational protocols for trains transporting large volumes of flammable liquids and a requirement that older DOT-111 tank cars be phased out beginning in late 2017 if they are not already retrofitted to comply with new tank car design standards.

In 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029, and in early 2019, PHMSA published a final rule requiring railroads to develop and submit comprehensive oil spill response plans for specific route segments traveled by a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train.

Additionally, the 2019 final rule requires railroads to establish geographic response zones along various rail routes, ensure that both personnel and equipment are staged and prepared to respond in the event of an accident, and share information about high-hazard flammable train operations with state and tribal emergency response commissions.

transport of crude oil.

For example, in the absence of a current federal standard on the vapor pressure of crude oil transported by rail, the State of Washington passed a law that became effective in July 2019, prohibiting the loading or unloading of crude oil from a rail car in the state unless the crude oil vapor pressure is lower than 9 pounds per square inch.

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We cannot assure that costs incurred to comply with PHMSA and Transport Canada standards and regulations emerging from these existing and any future rulemakings will not be material to our business, financial condition or results of operations.

In addition, any derailment of crude oil from the Williston or Permian Basins involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.

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believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event.

In addition, any derailment of crude oil from the Williston Basin involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.

Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event.

Nonetheless, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

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Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

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Regulation of production

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Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations.

We own and operate properties in North Dakota, Montana and Texas, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells.

We own and operate properties in North Dakota and Montana, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells.

The effect of these regulations is to limit the amount of crude oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing.

Moreover, all three states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and NGLs within their jurisdictions.

Moreover, both states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and NGLs within their jurisdictions.

The failure to comply with these rules and regulations can result in substantial penalties.

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Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority.

EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,307,164 per day, adjusted annually for inflation, for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,307,164 per violation per day, adjusted annually for inflation.

EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,388,496 per day, adjusted annually for inflation, for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation

per day to $1,388,496 per violation per day, adjusted annually for inflation.

The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce.

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A violation of this rule may result in civil penalties of up to $1,246,249 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.

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Texas Railroad Commission crude oil and natural gas rules

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Flaring may provide crude oil and natural gas producers with an approved means for continuing crude oil production under certain scenarios, such as, for example, when there may be insufficient pipeline infrastructure in place to transport natural gas to market or to prevent resource waste.

The imposition of more stringent requirements by the RRC or as a result of litigation contesting such flare permit practice that lessen producers’ opportunities to flare under RRC permitted exceptions could result in reduced production, which development could have an adverse effect on our and similarly situated producers’ business and results of operations.

We no longer operate any assets in Texas following the completion of the Permian Basin Sale (defined in “Part II, Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments”) and the OMP Merger.

North Dakota Industrial Commission crude oil and natural gas rules

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however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results.

New pipeline safety laws or regulations, amendment of existing

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

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

Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators.

In particular, the HLPSA and NGPSA were amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2016.

Each of these laws imposed increased pipeline safety obligations on pipeline operators.

The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines.

The PIPES Act of 2016 extended PHMSA’s statutory mandate and, among other things, required PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities.

The PIPES Act of 2016 also empowers PHMSA to address unsafe conditions or practices constituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or gas pipeline facilities without prior notice or an opportunity for a hearing.

More recently, Congress passed the Fiscal Year 2021 Omnibus Appropriations Bill, made effective on December 27, 2020, pursuant to which Congress adopted the PIPES Act of 2020.

The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions that, among other things, will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.

New regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational restrictions, delays or cancellations.

In October 2019, PHMSA published a final rule, made effective July 2020, that significantly extends and expands the reach of certain PHMSA hazardous liquid integrity management requirements, such as, for example, performance of periodic assessments and expanded use of leak detection systems, regardless of the pipeline’s proximity to a HCA (for example, integrity assessments at least once every 10 years for onshore, piggable, hazardous liquid pipeline segments located outside of HCAs, and expanded use of leak detection systems outside of HCAs on all regulated hazardous liquid pipelines other than offshore gathering and regulated rural gathering pipelines).

Additionally, this final rule requires all hazardous liquid pipelines in or affecting a HCA to be capable of accommodating in-line inspection tools within the next 20 years unless the basic construction of a pipeline cannot be modified to permit that accommodation.

Moreover, this final rule extends annual, accident, and safety-related conditional reporting requirements to hazardous liquid gravity lines and certain gathering lines and also imposes inspection requirements on hazardous liquid pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.

Also, in October 2019, PHMSA published the first of three expected regulations relating to new or more stringent requirements for certain natural gas pipelines, that had originally been proposed in 2016 as part of PHMSA’s “gas Mega Rule,” which first final rule became effective on July 1, 2020, and imposed numerous requirements, including maximum allowable operating pressure (“MAOP”) reconfirmation through re-verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (including all MCAs and those Class 3 and Class 4 areas found not to be in HCAs) within 14 years of publication date and at least once every 10 years thereafter, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management.

We are currently evaluating the operational and financial impact related to this final rule.

The remaining rulemakings comprising the gas Mega Rule have not yet been published, and we cannot predict when they will be finalized;

however, they are expected to include revised pipeline repair criteria as well as more stringent corrosion control requirements.

New legislation or any new regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory initiatives, including obligating operators of nonrural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.

With adoption of the 2011 Act, the 2016 Act and the PIPES Act of 2020, there exist more stringent mandates for PHMSA to make pipeline safety requirements more stringent.

As a result, PHMSA has issued a series of significant rulemakings.

In October 2019, PHMSA published a final rule imposing numerous requirements on onshore gas transmission pipelines relating to maximum allowable operating pressure (“MAOP”) reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs and non-HCA Class 3 and Class 4 areas by 2033, and the consideration of seismicity as a risk factor in integrity management.

PHMSA published a second final rule in October 2019 for hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity management requirements, requires accommodation of in-line inspection tools by 2039 unless the pipeline cannot be modified to permit such accommodation, increased annual, accident and safety-related conditional reporting requirements, and expanded the use of leak detection systems beyond HCAs.

PHMSA also published final rules during February and July 2020 that amended the minimum

safety issues related to natural gas storage facilities, including wells, wellbore tubing and casing, as well as added applicable reporting requirements.

More recently, in November 2021, PHMSA issued a final rule that will impose safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures.

Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities.

PHMSA, together with state regulators, are expected to commence inspection of these plans in 2022.

These new legislation or any future regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.

In the absence of the PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.

Environmental and occupational health and safety regulation

Our exploration, development and production operations, crude oil gathering and transportation activities, natural gas processing services and related operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection.

These laws and regulations may, among other things, require the acquisition of permits to conduct drilling or provide midstream services;

Our exploration, development and production operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection.

These laws and regulations may, among other things, require the acquisition of permits to conduct drilling;

govern the amounts and types of substances that may be released into the environment;

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require investigatory and remedial actions to mitigate pollution conditions;

impose obligations

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to reclaim and abandon well sites, pits, processing plants and pipelines;

impose obligations to reclaim and abandon well sites and pits;

and impose specific criteria addressing worker protection.

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CERCLA also authorizes the U.S.

Environmental Protection Agency (the “EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur.

Environmental Protection Agency (the “EPA”) and, in some instances, third parties to act in response to threats to the public

health or the environment and to seek to recover from the responsible classes of persons the costs they incur.

It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.

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There have been efforts from time to time to remove this exclusion, which removal could significantly increase our and our customers operating costs, and it is possible that certain crude oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce crude oil and natural gas or for conducting midstream services.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce crude oil and natural gas.

Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal.

In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control.

These properties and the substances disposed or released thereon may be subject to CERCLA,

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RCRA and analogous state laws.

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

These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws.

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

Air emissions

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For example, in 2015, the EPA under the Obama Administration issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent.

Since that time, the EPA has issued area designations with respect to ground-level ozone, and, on December 31, 2020, published a notice of final action to retain the 2015 ozone NAAQS without revision on a going-forward basis, but this December 2020 final action is subject to legal challenge, and the NAAQS may be subject to further revision under the Biden Administration.

However, several groups have filed litigation over this December 2020 decision, and the Biden Administration has announced plans to reconsider the December 2020 final action in favor of a more stringent ground-level ozone requirements.

States are expected to implement more stringent regulations that could apply to our operations.

Compliance with this final rule or any other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, significantly increase our capital expenditures and operating costs and reduce demand for the crude oil and natural gas that we produce, which one or more developments could adversely impact our E&P and midstream businesses.

Environmental protection and natural gas flaring initiatives

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We have allocated significant resources to connect our wells to natural gas infrastructure.

In both the Williston and Permian Basins, the substantial majority of our operated wells are connected to gas gathering systems, which minimizes our flared volumes of natural gas.

The NDIC has issued orders and pursued other regulatory initiatives to implement legally enforceable “gas capture percentage goals” targeting the capture of natural gas produced in the state, commencing in October 2014.

The substantial majority of our operated wells are connected to gas gathering systems, which minimizes our flared volumes of natural gas.

As of November 1, 2020, the enforceable gas capture percentage goal is 91%.

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Most recently, in September 2020, the NDIC revised the gas capture policy to allow several additional exceptions for companies that flare natural gas under certain circumstances, such as gas plant outages or delays in securing a right-of-way for pipeline construction, but did not change the gas capture targets.

While we were satisfying the applicable gas capture percentage goals as of December 31, 2021, there is no assurance that we will remain in compliance in the future or that such future satisfaction of such goals will not have a material adverse effect on our business and results of operations.

Climate change

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

Moreover, because the U.S.

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

Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States.

In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA under the Obama Administration published final regulations under the CAA establishing new performance standards for methane in 2016, but since that time the EPA under the Trump Administration undertook several measures, including publishing in September 2020 final rule policy and technical amendments to the NSPS, for stationary sources of air emissions.

The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile organic compound (“VOC”) requirements for the remaining sources that were established by the Obama Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more.

Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s September 2020 final rules, and on January 20, 2021, President Biden issued an executive order, that among other things, directed the EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no later than September 2021.

A reconsideration of the September 2020 policy amendments is expected to follow.

The January 20, 2021 executive order also directed the establishment of new methane and VOC standards applicable to existing crude oil and natural gas operations, including the production, transmission, processing and storage segments.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions.

At the international level, the non-binding Paris Agreement requests that nations limit their GHG emissions through individually-determined reduction goals every five years after 2020.

Although the U.S.

had withdrawn from the Paris Agreement, President Biden has issued executive orders recommitting the U.S.

to the Paris Agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement.

With the U.S.

recommitting to the Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the Paris Agreement’s goals.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States.

On January 20, 2021, the Acting Secretary of the U.S.

Department of the Interior issued an order, effective immediately, that suspends new crude oil and natural gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days.

Building on this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for crude oil and natural gas E&P on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal crude oil and natural gas permitting and leasing practices.

The January 20, 2021 and January 27, 2021 orders do not apply to existing leases but the January 27, 2021 order further directs applicable agencies to take measures to eliminate subsidies provided to the fossil fuel industry.

These suspensions are subject to legal challenge, with at least one industry group filing a lawsuit in January 2021, in Wyoming federal district court and seeking to have the moratorium declared invalid.

Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against the largest crude oil and natural gas E&P companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as well as other companies handling fossil fuels, including owners of terminals, pipelines and refineries, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors.

Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies.

Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies, as President Biden signed an executive order in January 2021 calling for, among other things, the development of a climate finance plan and, separately, the Federal Reserve announced in December 2020 that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

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

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The threat of climate change continues to attract considerable attention in the United States and around the world.

Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions.

No comprehensive climate change legislation has been implemented at the federal level, but President Biden has made the combat of climate change arising from GHG emissions a priority under his Administration and has issued, and may continue to issue, executive orders or other regulatory initiatives in pursuit of his regulatory agenda.

The EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources, and impose new standards reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements.

In recent years, there has been considerable uncertainty surrounding regulation of methane emissions.

During 2020, the former Trump Administration revised performance standards for methane established in 2016 to lessen the impact of those standards and remove the transmission and storage segments from the source category for certain regulations.

However, shortly after taking office in 2021, President Biden issued an executive order calling on the EPA to revisit federal regulations regarding methane and establish new or more stringent standards for existing or new sources in the oil and gas sector, including the transmission and storage segments.

Congress also passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards.

In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would establish Quad Ob new source and Quad Oc first-time existing source standards of performance for methane and volatile organic compound (“VOC”) emissions in the crude oil and natural gas source category.

This proposed rule would apply to upstream and midstream facilities at oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities.

Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called green well completion requirements.

The EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements that were not included in the November 2021 proposed rule.

The EPA anticipates issuing a final rule before end-of-year 2022.

Additionally, the House of Representatives version of the Build Back Better Act included a fee on methane emissions targeting industries that produce, transport, and store natural gas throughout the United States at $900 per ton in 2023, $1,200 per ton in 2024 and $1,500 per ton in 2025 and beyond.

Congress could seek to include this fee in future legislation.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, GHG reporting and tracking programs, and restriction of GHG emissions.

At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020.

President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50% – 52% reduction from 2005 levels in economy-wide net GHG emissions by 2030.

Moreover, the international community gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”), during which multiple announcements (not having the effect of law) were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs.

Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 countries joined, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030,

including “all feasible reductions” in the energy sector.

The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in federal political risks in the United States.

President Biden has issued several executive orders calling for more expansive action to address climate change and suspend new oil and gas operations on federal lands and waters.

The suspension of the federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension.

The federal government is appealing the district court decision.

Other actions adversely affecting the oil and gas industry that may be pursued by the Biden Administration include limiting hydraulic fracturing by banning new oil and gas permitting on federal lands and waters, potentially eliminating certain tax rules (referred to as subsidies) that benefit the oil and gas industry, and imposing restrictions on pipeline infrastructure.

Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against oil and gas exploration and production companies in state or federal court, alleging, among other things, that such energy companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore, are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

The Company is not currently a defendant in any of these lawsuits but it could be named in actions making similar allegations.

An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Additionally, our access to capital may be impacted by climate change policies.

Shareholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors.

Institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending and investment practices that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies.

Many of the largest U.S.

banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions.

At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals.

The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050.

These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions.

Additionally, there is the possibility that financial institutions may be pressured or required to adopt policies that limit funding for fossil fuel energy companies.

In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities.

While we cannot predict what policies may result from these announcements, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations.

Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.

These climatic developments have the potential to cause physical damage to our assets and thus could have an adverse effect on our exploration and production operations.

Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or its production.

While our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Water discharges

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In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit.

In 2015, the EPA and U.S.

Army Corps of Engineers (the “Corps”) under the Obama Administration published a final rule that would significantly expand the scope of the Clean Water Act over waters of the United States, including wetlands.

However, the EPA and the Corps under the Trump Administration issued a final rule, made effective in December 2019, that repealed the 2015 rule and they also published a final rule in April 2020 re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation.

The April 2020 final rule is subject to various pending legal challenges;

moreover, there is an expectation with the Biden Administration taking office in January 2021, there is a possibility that the new administration will review and may reconsider this April 2020 final rule.

If the EPA and the Corps under the Biden Administration revise the April 2020 final rule in a manner similar to or more stringent than the 2015 final rule, or if any challenge to the April 2020 final rule is successful, the scope of the Clean Water Act’s jurisdiction in areas where we conduct operations could again be expanded and result in increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Any such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increase compliance expenditures or mitigation costs for our operations.

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit, and there continues to be uncertainty on the federal government’s applicable jurisdictional reach over waters of the United States, including wetlands.

The EPA and U.S.

Army Corps of Engineers (the “Corps”) under the Obama, Trump and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach.

While the EPA and Corps under the Trump Administration issued a final rule in January 2021 narrowing federal jurisdictional reach over waters of the United States, President Biden issued an executive order to further review and assess these regulations consistent with the new administration’s policy objectives, following which the EPA and Corps announced plans in June 2021 to initiate a new rulemaking process that would repeal the 2020 rule and restore protections that were in place prior to 2015.

Although the EPA and Corps did not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico have vacated the 2020 rule in decisions announced during the third quarter of 2021.

While these district court decisions may be appealed, it is clear that the EPA and Corps intend to adopt a more expansive definition for waters of the United States.

As an initial step, the agencies published on December 7, 2021 a proposed rulemaking that would put back into place the pre-2015 definition of “waters of the United States” in effect prior to the 2015 rule issued under the Obama Administration and updated to reflect consideration of Supreme Court decisions.

The proposed rule, if adopted, would serve as an interim approach to “waters of the United States” and provide the agency with time to develop a subsequent rule that builds upon the currently proposed rule based, in part, on additional stakeholder involvement.

Additionally, in January 2022, the U.S.

Supreme Court agreed to hear a case on the scope and authority of the Clean Water Act and the definitions of “waters of the United States”.

If the EPA and the Corps under the Biden Administration or any court expand the scope of the Clean Water Act’s jurisdiction in areas where we conduct operations, such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increase compliance expenditures or mitigation costs for our operations, which may reduce our rate of production of crude oil or natural gas.

The Oil Pollution Act of 1990 (the “OPA”) amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of crude oil spills.

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In response to seismic events near underground injection wells used for the disposal of produced water from crude oil and natural gas activities, federal and some state agencies have investigated, and continue to investigate, whether such wells have caused increased seismic activity.

In 2016, the United States Geological Survey identified Texas as being among six states with areas of increased rates of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction.

Since that time, the United States Geological Survey indicates that these rates have decreased in these states, although concern continues to exist over quakes arising from induced seismic activities.

In 2016, the United States Geological Survey identified six states, though not North Dakota or Montana, with areas of increased rates of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction.

In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells.

For example, in Texas, the RRC has adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of crude oil and natural gas in order to address these seismic activity concerns within the state.

Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.

Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal.

These developments could result in additional regulation and restrictions on the use of injection wells by us or our customers.

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Hydraulic fracturing activities

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However, in late 2018, the BLM under the Trump Administration published a final rule rescinding the 2016 final rule.

Litigation challenging the BLM's 2016 final rule as well as its 2018 final rule rescinding the 2016 rule has been pursued by various states and industry and environmental groups.

While a California federal court vacated the 2018 final rule in July 2020, a Wyoming federal court subsequently vacated the 2016 final rule in October 2020 and, accordingly, the 2016 final rule is no longer in effect but the Wyoming decision may be appealed.

Since that time, litigation challenging the BLM's 2016 final rule and the 2018 final rule has resulted in rescission in federal courts of both the 2016 and 2018 rules but appeals to those decisions are on-going.

Additionally, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.

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From time to time Congress has considered, but has not adopted, legislation to provide for federal regulation of hydraulic fracturing.

However, with President Biden taking office and the shift in party control of the Congressional Senate in January 2021, there is a possibility that a Biden Administration will pursue such legislation.

In addition to pursuing the revision of existing laws and regulations, President Biden has issued, and may continue to issue, additional executive orders in pursuit of his regulatory agenda with regards to limiting hydraulic fracturing.

In addition, some states, including North Dakota and Texas where we primarily operate, have adopted, and other states may adopt, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities.

The Biden Administration has issued executive orders, could issue additional executive orders and could pursue other legislative and regulatory initiatives that restrict hydraulic fracturing activities on federal lands.

For example, the Biden Administration issued an order in January 2021 suspending the issuance of new leases on federal lands and waters pending review and reconsideration of federal oil and gas leasing and permitting practices.

The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension but the federal government is appealing the district court decision.

Also, further constraints may be adopted by the Biden Administration in the future.

In addition, some states, including North Dakota where we primarily operate, have adopted, and other states may adopt, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities.

States could elect to adopt certain prohibitions on hydraulic fracturing, following the approach already taken by several states.

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The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States and prohibits the taking of endangered species.

Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”).

Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”) and to bald and golden eagles under the Bald and Golden Eagle Protection Act.

Fish and Wildlife Service (the “FWS”) under the Trump Administration issued a final rule on January 7, 2021, which notably clarifies that criminal liability under the MBTA will apply only to actions “directed at” migratory birds, their nests or their eggs;

however, in 2020, the U.S.

District Court for the Southern District of New York vacated a Department of Interior memorandum articulating a similar interpretation.

With the new Presidential Administration taking office in January 2021, it is possible that the January 2021 rule will be subject to reconsideration by the Biden Administration or be subject to legal challenges.

Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed or endangered species or modify their critical habitats.

Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species.

If endangered or threatened species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment

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

however, the FWS under the Biden Administration has since published a final rule in October 2021 revoking the January 2021 rule and affirmatively stating that the MBTA prohibits incidental takes of migratory birds.

Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed or endangered species or modify their

critical habitats.

Some of our operations are located in areas that are designated as habitat for endangered or threatened species, and our development plans have been impacted on occasion by certain endangered or threatened species, including the Dakota skipper and the golden eagle.

If endangered or threatened species are located in areas of the underlying properties where we want to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed by seasonal or permanent restrictions or require the performance of extensive studies or implementation of costly mitigation practices.

Moreover, the FWS may make determinations on the listing of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in more fulsome protections for non-protected or lesser-protected species pursuant to specific timelines.

The issuance of more stringent conservation measures or land, water, or resource use restrictions could result in operational delays and decreased production and revenue for us and have an indirect adverse impact on the demand for our midstream services.

The issuance of more stringent conservation measures or land, water, or resource use restrictions could result in operational delays and decreased production and revenue for us.

Operations on federal lands

Performance of crude oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“NEPA”).

NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs, to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment.

NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs (“BIA”), to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment.

In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment.

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The modified rule also eliminates the responsibility to consider cumulative effects of a project.

With the change in Presidential Administrations in January 2021, it is possible that the final rule will be delayed or not implemented as President Biden may have the CEQ under his administration reconsider or withdraw the rule and also because the final rule is being challenged in court.

However, the CEQ under the Biden Administration announced in October 2021 a proposed rule that will require agencies to consider direct, indirect and cumulative effects of major federal actions, as well as less-harmful alternatives, and to allow federal agencies to implement more stringent requirements that are required by the CEQ.

Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be substantial, and be subject to delays, limitations or prohibitions in the scope of crude oil and natural gas projects or performance of midstream services.

Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt our or our customers’ E&P activities.

President Biden has pledged to ban new leases for production of minerals on federal properties, including onshore lands and offshore waters, and recently issued a 60-day suspension of such new leases and drilling permits on federal properties.

President Biden issued an order in January 2021 suspending the issuance of new leases on federal lands and waters pending review and reconsideration of federal oil and gas leasing and permitting practices.

The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension, but the federal government is appealing the district court decision.

Approximately 2% of our net acreage position in the Williston Basin is federal mineral acreage, which is spread across our acreage position, and any portion of a well on federal land requires a permit.

However, we believe that the vast majority of our future drilling locations are not affected by the need to obtain a federal permit.

However, we believe that the vast majority of our future drilling locations would not be affected by any subsequent need to obtain a federal permit.

Employee health and safety

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Human Capital Resources

As of December 31, 2020, we employed 432 people.

As of February 1, 2022, we employed 255 people.

Our future success will depend partially on our ability to attract, retain and motivate qualified personnel.

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From time to time we utilize the services of independent contractors to perform various field and other services.

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

We, as a company and as individuals, believe in “doing the right thing” and being passionate about our work with the goal that we all succeed together, including our employees, contractors, shareholders and the communities in which we operate.

We also believe that great people and great assets create great opportunity, and these core values inform how we think about our business.

Health and safety

We are committed to protecting the safety of our employees, our contractors, and the communities in which we operate.

We continually seek to develop best-in-class procedures to maintain our safety culture.

We seek to improve our procedures to maintain our safety culture.

We operate our worksites under a stop work authority program, under which every person on our worksites is empowered to halt operations to address a potential safety issue.

In addition, we have developed and implemented a comprehensive environment, health and safety management system and regularly conduct internal and external audits of our environmental and safety programs, including contractor safety audits.

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

During 2020, we launched a proactive response to the COVID-19 pandemic to protect the health and safety of our employees, contractors and the communities in which we operate.

We took actions to adhere to recommendations by the Centers for Disease Control and Prevention regarding social distancing and limited public exposure in connection with the COVID-19 pandemic.

Even though our operations were not required to close, we adopted a work-from-home system for all office-based employees and deployed additional safety protocols at our operating sites in order to keep the field-based employees and contractors supporting our operations safe while continuing operations running without material disruption.

We believe regular and consistent communication with employees is important to establish new procedures and mitigate the spread of COVID-19.

In light of the recent resurgence of COVID-19 and evolving data concerning the pandemic, we continue to review the guidelines from federal, state and local officials to promote the safety of our stakeholders.

Safety training is provided to all employees, and safety performance is integrated into our annual compensation program.

Our core values include “doing the right thing,” and our response to the COVID-19 pandemic demonstrates this principle in action.

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.

Compensation and benefits

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Our principal office is located in Houston, Texas at 1001 Fannin Street.

We also own field offices in the North Dakota communities of Williston, Powers Lake, Alexander and Watford City.

We also own field offices in the North Dakota communities of Williston, Powers Lake, Watford City and Parshall.

Available Information

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

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Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including the Chief Executive Officer and Chief Financial Officer.

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

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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 1. Business