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Item 1. Business

2023-02-28 compared with 2022-02-25 · 438 added, 355 removed, 436 unchanged (65% of the section changed)

Oasis Petroleum Inc.

(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.

Chord Energy Corporation (together with our consolidated subsidiaries, the “Company,” “Chord,” “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.

Chord, formerly known as Oasis Petroleum Inc.

(“Oasis”), was established on July 1, 2022 upon completion of the combination of Oasis and Whiting Petroleum Corporation (“Whiting”) in a merger of equals transaction (the “Merger”).

Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees.

We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

As of December 31, 2022, we had 963,009 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.

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

As of December 31, 2022, we had 3,583 gross (2,742.8 net) operated producing wells, including 2,558.6 net operated producing wells in the Williston Basin.

Our working interest for producing wells averaged 46% in total and 77% in the wells we operate.

During the year ended December 31, 2022, we had average daily production of 119,785 net Boepd, including average daily production of 171,880 net Boepd for the period subsequent to the Merger (with crude oil production of 95,992 Bopd).

As of December 31, 2022, Netherland, Sewell & Associates, Inc.

(“NSAI”), our independent reserve engineers, estimated our net proved reserves to be 655.6 MMBoe, of which 77% were classified as proved developed and 58% were crude oil.

Effective July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis.

Accordingly, our reported production volumes and reserve estimates as of and subsequent to July 1, 2022 are reported on a three-stream basis, while periods prior to July 1, 2022 were reported on a two-stream basis with NGLs combined with the natural gas stream.

Business Strategy

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• 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.

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

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

Since our inaugural dividend in February 2021, we have declared cash dividends to our stockholders of $37.46 per share of common stock.

We materially enhanced our scale in the Williston Basin as a result of the Merger and have high-quality assets that generate significant, sustainable cash flow to support the priority we place on stockholder returns.

We expect that our business strategy will continue to provide sizable cash flow generation which will enable us to return capital to our stockholders and continue to pursue acquisitions that add to our inventory, while maintaining a strong balance sheet.

In August 2022, we introduced a return of capital program designed to provide peer-leading, sustainable stockholder returns.

The return of capital plan includes a base dividend of $1.25 per share per quarter ($5.00 per share annualized) and a $300 million share-repurchase program.

As of December 31, 2022, we had $272.9 million remaining under this share-repurchase program.

We plan to return capital through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases.

We expect to return a certain percentage of adjusted free cash flow (“Adjusted FCF”) each quarter, with the targeted percentage based on free cash flow generated during the previous quarter and leverage under the following framework:

• Below 0.5x leverage:

75%+ of Adjusted FCF

• Below 1.0x leverage:

50%+ of Adjusted FCF

• >1.0x leverage:

Base dividend+ ($5.00 per share annualized)

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The variable dividend will be calculated using the framework noted above to establish the minimum percentage of free cash flow to be returned less share repurchases completed during the quarter and the base dividend.

• 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.

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

As of December 31, 2022, we had $1.6 billion of liquidity available, including $593.2 million of cash and cash equivalents and $993.6 million of unused borrowing capacity available under the Credit Facility (defined in “Part II, Item 7.

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

• Built to last.

• Commitment to excellence.

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

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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.

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, the ability to drill longer lateral lengths for developmental wells, the ability to utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.

We have extensive engineering, operational, geologic and subsurface technical knowledge.

Our technical team has access to an abundance of digital well log, seismic, completion, production and other subsurface information, which is analyzed in order to accurately and efficiently characterize the anticipated performance of our oil and gas reservoirs.

We leverage many technologies in support of data gathering, information analysis and production optimization.

Data management and reporting practices improve the availability, accuracy and analysis of our information in a cycle of continuous improvement.

Emerging technologies are evaluated on a regular basis, ensuring we are implementing the best technologies for our business needs.

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

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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.

Management, with oversight from the Board of Directors, is focused on enterprise risk management (“ERM”), which seeks to establish guidelines and policies for appropriate risk assessment and risk management, including exposure to safety risk, financial risk, commodity price risk and cybersecurity risk.

The Audit and Reserves Committee of our Board of Directors reviews our cybersecurity guidelines and policies and receives updates on cybersecurity matters at least annually.

In addition, we have established cybersecurity best practices aligned with the National Institute of Standards and Technology, require quarterly cybersecurity training of our employees and receive an annual audit and penetration assessment by a third party.

Our ERM program allows 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 are committed to our established ESG initiatives and seek to maintain a culture of continuous improvement in ESG practices.

We strive to provide safe, reliable and affordable energy in a responsible manner against the backdrop of an evolving energy landscape.

The key tenets of our ESG philosophy are to always put safety first, minimize our environmental impact, reduce our emissions intensity, promote a diverse and inclusive culture, align executive compensation with long-term value creation and stockholder interests, and support programs that benefit the communities in which we operate.

From a safety standpoint, our corporate, field and environmental, health and safety teams are enhancing best practices and training to minimize the likelihood of safety incidents among employees and contractors.

We owe it to our employees, our service providers and stakeholders to do all we can to create an environment where everyone on a Chord location is safe.

We hold ourselves to always put safety first, to be diligent and never complacent.

We expect the same of any service provider or partner that works with us.

We remain focused on reducing Scope 1 GHG emissions, and in particular methane emissions.

We are establishing a carbon management program that includes a team focused on gas capture, flare management and replacement or retrofit of gas pneumatics.

In addition, we plan to increase transparency by reporting full Scope 1 and Scope 2 operated emissions while continuing to align our disclosures towards the Sustainability Accounting Standards Board (“SASB”) and Task Force on Climate-Related Financial Disclosures (“TCFD”) frameworks.

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also are proficient in capturing the natural gas that we produce, and, as of December 31, 2022, we were capturing substantially all of our natural gas production in North Dakota.

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

We have also made meaningful investments in safety training programs that benefit our employees as well as employees of other operators and contractors.

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

Our 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.

We have also made meaningful investments in safety training programs that benefit our employees and contractors.

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

We have a short tenured and highly capable Board of Directors that is comprised of diverse and experienced energy industry professionals.

Our Board of Directors is 80% independent and 63% of our independent directors are women.

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

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 2023 Annual Meeting of Stockholders.

Competitive Strengths

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

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

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

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

We believe that our Williston Basin acreage represents a premier position in a top oil basin in the United States that will continue to provide significant free cash flow generation.

As of December 31, 2022, we had 963,009 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin.

Of our 963,009 net leasehold acres, 954,566 net acres were held by production and 58% of our 655.6 MMBoe estimated net proved reserves were comprised of crude oil.

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

• 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.

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

As of December 31, 2022, 96% of our estimated net proved reserves were attributable to properties that we operate.

In 2023, we plan to complete approximately 90 to 94 gross operated wells with an average working interest of approximately 73%.

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.

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.

We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational, cost and capital efficiencies, and allows us to better manage infrastructure investment to drive down operating costs and optimize price realizations.

• 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.

We have no near-term debt maturities, are focused on rigorous capital discipline and have a 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.

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 record of accomplishment in identification, acquisition and execution of large, repeatable development drilling programs.

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

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Exploration and Production Operations

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, 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.

The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $66.55 per Bbl for crude oil and $3.64 per MMBtu for natural gas, $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas and $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas for the years ended December 31, 2021, 2020 and 2019, respectively.

These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The information in the following table does not give any effect to or reflect our commodity derivatives.

Future operating costs, production taxes and capital costs were based on current costs as of each year-end.

For a definition of proved reserves under the SEC rules, please see the “Glossary of Terms” included at the end of this report.

For more information regarding our independent reserve engineers, please see “Independent petroleum engineers” below.

Future net revenues represent projected revenues from the sale of our estimated net proved reserves (excluding derivative contracts) net of production and development costs (including operating expenses and production taxes).

PV-10 and Standardized Measure represent the present value of the future net revenues discounted at 10%, before and after income taxes, respectively.

There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties.

There can be no assurance that our estimated net proved reserves will be produced within the periods indicated or that prices and costs will remain constant.

A substantial or extended decline in crude oil prices could result in a significant decrease in our estimated net proved reserves and related future net revenues, Standardized Measure and PV-10 in the future.

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

Our estimated net proved reserves and related PV-10 at December 31, 2022 are based on reports independently prepared by NSAI, our independent reserve engineers.

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

Our current and previous independent reserve engineers evaluated 100% of the reserves and discounted values at December 31, 2022, 2021 and 2020 in accordance with the rules and regulations of the SEC applicable to companies involved in crude oil, NGL and natural gas producing activities.

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

Financial Statements and Supplementary Data—Note 26.—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated net proved reserves.

The following table summarizes our estimated net proved reserves based upon the SEC Price:

At December 31,

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Crude oil (MMBbls) 381.3 174.3 119.8

NGLs (MMBbls) (1)

Natural gas (Bcf) 814.9 459.3 376.2

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Crude oil (MMBbls) 272.5 114.0 85.4

NGLs (MMBbls) (1)

Natural gas (Bcf) 689.7 361.8 262.7

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Crude oil (MMBbls) 108.8 60.3 34.3

NGLs (MMBbls) (1)

Natural gas (Bcf) 125.3 97.4 113.5

Total estimated proved undeveloped reserves (MMBoe) 152.9 76.5 53.3

Future net revenues (in millions) $ 5,495.1 $ 1,793.6 $ 5,385.4

Standardized Measure (in millions) (1)

$ 2,696.9 $ 948.9 $ 2,844.4

PV-10 (in millions) (2)

Standardized Measure (GAAP) (in millions) (2)

$ 11,494.5 $ 2,696.9 $ 948.9

PV-10 (Non-GAAP) (in millions) (3) :

Proved developed PV-10 $ 11,460.3 $ 2,474.5 $ 936.9

Proved undeveloped PV-10 2,991.9 640.9 178.1

Total PV-10 (Non-GAAP) $ 14,452.2 $ 3,115.4 $ 1,115.0

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(1) At December 31, 2021 and 2020, we reported crude oil and natural gas reserves on a two-stream basis, with NGLs combined with the natural gas stream.

At December 31, 2022, NGL reserves are reported separately from the natural gas stream on a three-stream basis.

This change impacts the comparability of the periods presented.

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

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

(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under GAAP, because it does not include the effect of income taxes on discounted future net cash flows.

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

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

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Reconciliation of Standardized Measure to PV-10

PV-10 is derived from Standardized Measure, which is the most directly comparable GAAP financial measure.

PV-10 is a computation of Standardized Measure on a pre-tax basis.

PV-10 is derived from Standardized Measure, which is the most directly comparable financial measure under GAAP.

PV-10 is equal to Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%.

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PV-10 $ 14,452.2 $ 3,115.4 $ 1,115.0

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

At December 31, 2021, we had approximately 76.5 MMBoe of proved undeveloped reserves as compared to 53.3 MMBoe at December 31, 2020.

The following table summarizes the changes in our proved undeveloped reserves during 2021:

Year Ended December 31, 2021

Proved undeveloped reserves, beginning of period 53,253

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

Conversion to proved developed reserves (16,646)

Proved undeveloped reserves, end of period 76,513

During 2021, we spent a total of $127.9 million related to the development of proved undeveloped reserves, $29.3 million of which was spent on proved undeveloped reserves that represent wells in progress at year-end.

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 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

Our estimated net proved reserves and related future net revenues and PV-10 at December 31, 2021, 2020 and 2019 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revised June 2019) and definitions and current guidelines established by the SEC.

Our estimated net proved reserves and PV-10 at December 31, 2022 are based on reports independently prepared by NSAI, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revised June 2019) (the “Estimating and Auditing Standards”) and definitions and current guidelines established by the SEC.

NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr.

Talley, a Licensed Professional Engineer in the State of Texas (No.

102425), has been practicing as a petroleum engineering consultant at NSAI since 2004 and has over 5 years of prior industry experience.

He graduated from University of Oklahoma in 1998 with a Bachelor of Science degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration degree.

Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No.

2364), has been practicing as a petroleum geoscience consultant at NSAI since 2008 and has over 11 years of prior industry experience.

He graduated from Texas Christian University in 1992 with a Bachelor of Science degree in Geology and from Texas A&M University in 1998 with a Master of Science degree in geology.

Both technical principals meet or exceed the education, training and experience requirements set forth in the Estimating and Auditing Standards.

In addition, both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines.

Our estimated net proved reserves and PV-10 at December 31, 2021 and 2020 were based on reports independently prepared by DeGolyer and MacNaughton, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimated and Auditing Standards and definitions and current guidelines established by the SEC.

DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Moscow, Astana, Buenos Aires, Baku and Algiers.

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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.

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

He graduated with a Bachelor of Science degree in Petroleum Engineering from Istanbul Technical University in 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010.

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The firm is a Texas Registered Engineering Firm.

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Technology used to establish proved reserves

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

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007) .

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards.

The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

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

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

A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories.

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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

We employ DeGolyer and MacNaughton as the independent reserves evaluator for 100% of our reserves base.

We employ NSAI as the independent preparer for 100% of our reserves.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process.

Brett Newton, Senior Vice President and Chief Engineer, is the technical person primarily responsible for overseeing our reserves evaluation process.

He has over 30 years of industry experience with positions of increasing responsibility in engineering and management.

He holds both a Bachelor of Science degree and Master of Science degree in petroleum engineering.

Newton reports directly to our President and Chief Operating Officer.

Our Managing Director, Corporate Planning & Reserves is responsible for overseeing the preparation of the reserves estimates under the supervision of our Senior Vice President, Planning & Investor Relations.

Our Managing Director, Corporate Planning & Reserves has more than 12 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional and unconventional evaluation and development projects, including corporate reserves estimations.

He holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.

Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures.

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

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

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

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

• Discussion of material reserve variances among our internal reservoir engineers;

• Review of the reserves report by members of our senior management team, including our President & Chief Executive Officer;

Executive Vice President & Chief Operating Officer;

Executive Vice President & Chief

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Financial Officer;

Senior Vice President, Planning & Investor Relations and Managing Director, Corporate Planning & Reserves;

• Review of our reserves estimation process and the reserves report by our Audit and Reserves Committee and NSAI 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, natural gas and NGLs we produce is largely a function of market supply and demand.

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

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

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

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

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

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

Please see “Item 1A.

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

The following table sets forth information regarding our crude oil and natural gas production, 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).

Risk Factors—Risks related to the oil and gas industry and our business” for additional information on risks associated with commodity prices.

Please also see “Part II, Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions” for additional information on market demand.

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

References to “Successor” relate to our results of operations subsequent to our emergence from bankruptcy on November 19, 2020.

References to “Predecessor” relate to our results of operations through and including our emergence from bankruptcy on November 19, 2020.

In addition, the Merger was accounted for as of July 1, 2022.

Accordingly, the results of operations presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022 and the results of Chord (including legacy Whiting) from July 1, 2022 through December 31, 2022.

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

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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

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

Net production volumes:

Crude oil (MBbls) 25,457 13,489 1,593 14,226

NGLs (MBbls) (1)

Natural gas (MMcf) (1)

67,428 46,157 5,008 42,199

Oil equivalents (MBoe) 43,722 21,182 2,428 21,258

Average daily production (Boepd) 119,785 58,032 57,809 65,612

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:

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73.50 48.55 43.36 48.13

NGL, without derivative settlements (1) (per Bbl)

NGL, with derivative settlements (1)(2) (per Bbl)

Natural gas, without derivative settlements (1) (per Mcf)

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Production taxes 5.25 3.63 2.45 2.14

General and administrative expenses 3.81 6.10 6.81 4.00

__________________

(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 derivative liquidations.

(1) For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when presenting our production data and average sales prices.

As of July 1, 2022, NGLs were reported separately from the natural gas stream on a three-stream basis.

This prospective change impacts the comparability of the periods presented.

(2) 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) 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 Cash G&A.

The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending within the periods presented.

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The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2022.

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Total acres 1,458,289 1,011,836

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 .

Our total net leasehold position shown in the table above includes 963,009 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin.

At December 31, 2022, our total acreage that is held by production increased to 996,187 net acres from 487,254 net acres at December 31, 2021.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2022 that will expire over the next three years unless production is established on the acreage prior to the expiration dates:

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2024 2,353 1,934

We have not assigned any PUD reserves to locations scheduled to be drilled after lease expiration.

Productive wells

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.

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.

The following table presents the total and operated gross and net productive wells as of December 31, 2022:

Total wells Operated wells

Gross Net Gross Net

Horizontal wells 6,534 3,025.2 3,579 2,740.1

Other 40 9.0 4 2.7

Total wells 6,574 3,034.2 3,583 2,742.8

Our total producing wells shown in the table above includes 2,758.7 total net producing wells and 2,558.6 operated net producing wells in the Williston Basin.

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Drilling and completion activity

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As of December 31, 2022, we had 45 gross (27.4 net) wells in the process of being drilled or completed, which includes 36 gross operated wells waiting on completion and 7 gross non-operated wells drilling or completing.

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

As of December 31, 2022, we had three operated rigs running, and we expect to run four operated rigs for the majority of 2023.

Description of properties

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.

Our management team originally targeted the Williston Basin because of its oil-prone nature, multiple producing horizons, substantial resource potential and management’s previous professional history in the basin.

As of December 31, 2022, our operations were focused in the North Dakota and Montana areas of the Williston Basin targeting the Middle Bakken and Three Forks formations.

We are one of the top producers in the Williston Basin, and we have the largest acreage position of any operator in the Williston Basin.

As a result of the Merger, we significantly enhanced our scale in our acreage position, reserves and production.

We focus our operations in the Williston Basin because of its high oil content, multiple producing horizons, substantial resource potential and management’s previous professional history in the basin.

The Williston Basin also generally has established infrastructure and access to materials and services.

Production in the Williston Basin primarily comes from two zones:

the Middle Bakken and the Three Forks.

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

As of December 31, 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

We principally sell our crude oil, natural gas and NGL production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities.

In an effort to improve price realizations from the sale of our crude oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil and natural gas to a broad array of potential purchasers.

We principally sell our crude oil, NGL and natural gas production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities.

In an effort to improve price realizations, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL and natural gas to a broad array of potential purchasers.

We sell a significant amount of our crude oil production through bulk sales at delivery points on crude oil gathering systems to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but are not limited to, transportation costs.

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

As of December 31, 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.

We also enter into various short-term sales contracts for a portion of our portfolio at fixed differentials.

Our marketing of crude oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

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, helping remove trucks from local highways and reduce greenhouse gas emissions.

As of December 31, 2022, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems.

In addition, from time to time we may enter into third-party purchase and sales transactions to, among other things, improve price realizations, optimize transportation costs, blend to meet pipeline specifications or to cover production shortfalls.

We also enter into various sales contracts for a portion of our portfolio at fixed differentials.

We believe that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.

Our marketing of crude oil, NGL and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

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

Risk Factors—Risks related to the oil and

gas industry and our business—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.

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 Basin.

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

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Delivery commitments

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.

As of December 31, 2022, we had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 44.7 MMBbl of crude oil, 17.0 MMBbl of NGLs, 494.2 Bcf of natural gas and 1.6 MMBbl of water, 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.

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, NGLs and natural gas from third parties to satisfy our minimum volume commitments.

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, 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.

On February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP LLC, OMP’s general partner (“OMP GP”) with and into a subsidiary of Crestwood Equity Partners LP (“Crestwood”) and, in exchange, received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood (the “OMP Merger”).

Prior to the completion of the OMP Merger, OMP was a consolidated subsidiary and we owned approximately 70% of OMP’s issued and outstanding common units.

We 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.

There is a high degree of competition in the oil and gas industry for acquiring properties, obtaining investment capital, securing oil field goods and services, marketing oil, NGLs and natural gas products and attracting and retaining qualified personnel.

Certain of our competitors possess and employ financial, technical and personnel resources greater than ours, which can be particularly important in the areas in which we operate.

Those companies may be able to pay more for productive oil and gas properties and exploratory prospects, better sustain production in periods of low commodity prices and evaluate, bid for and purchase a greater number of properties and prospects than our resources permit.

Furthermore, competitive conditions may be substantially affected by various forms of energy legislation or regulation enacted by state, local and U.S.

government bodies and their associated agencies, especially with regard to environmental protection and climate-related policies.

It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or the resultant effects on our future operations.

Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil, NGLs and natural gas and our larger competitors may be able to better absorb the burden of such legislation and regulation, which would also adversely affect our competitive position.

See “Regulation” below as well as Item 1A.

within this Annual Report on Form 10-K for more information on and the potential associated risks resulting from existing and future legislation and regulation of our industry.

Additionally, the unavailability or high cost of drilling rigs, completion crews or other equipment and services could delay or adversely affect our development and exploration operations.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to obtain necessary capital as well as evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

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.

We encounter competition from other crude oil and natural gas companies in all areas of operation, including the acquisition of leasing options on oil and gas properties to the exploration and development of those properties.

Our competitors include major integrated crude oil and natural gas companies, numerous independent crude oil and natural gas companies, individuals and drilling and income programs.

Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do.

Such companies may be able to pay more for lease options on oil and gas properties and exploratory locations and to define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit.

Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Please see “Item 1A.

Risk Factors—Risks related to the oil and gas industry and our business—Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.”

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

The price and availability of alternative energy sources, such as wind, solar, nuclear, coal, hydrogen and biofuels as well as the emerging impact of climate change activism, fuel conservation measures and governmental requirements for renewable energy sources, could adversely affect our revenues.

See “Item 1A.

Risk Factors—Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.”

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Title to Properties

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Prior to completing an acquisition of producing crude oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions.

Our oil and gas properties are subject to customary royalty and other interests, liens to secure borrowings under the Oasis Credit Facility, liens for current taxes and other burdens, which we believe do not materially interfere with the use or affect our carrying value of the properties.

Our oil and gas properties are subject to customary royalty and other interests, liens to secure borrowings under the Credit Facility, liens for current taxes and other burdens, which we believe do not materially interfere with the use or affect our carrying value of the properties.

Please see “Item 1A.

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

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.

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

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

These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally discourage the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties.

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however, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may occur and, thus, there can be no assurance that such costs will not be material in the future.

Additionally, environmental incidents such as spills or other releases may occur or past non-compliance with environmental laws or regulations may be discovered.

Additionally, environmental incidents such as spills or other releases may occur or past non-compliance with environmental laws or regulations may be discovered, any of which may require us to install new or modified controls on equipment or processes, incur longer permitting timelines, and incur increased capital or operating expenditures, the costs of which may be material.

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”), the U.S.

Environmental Protection Agency (“EPA”) and the courts.

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

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Regulation of transportation and sales of crude oil

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices.

Sales of crude oil and NGLs are not currently regulated and are made at negotiated prices.

Nevertheless, Congress could reenact price controls in the future.

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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”).

The Commission received requests for rehearing of its December 17, 2020 order and on January 20, 2022, in Docket No.

RM20-14, 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%.

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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.

On February 22, 2022, several shippers filed for a Request for Clarification, or in the alternative, Rehearing of the January 2022 Order (“Request for Rehearing”).

Additionally, during February and March 2022, shippers filed timely petitions for review of the January 2022 Order with the D.C.

Circuit and the 5th Circuit.

The petitions for review filed with the D.C.

Circuit were transferred to the 5th Circuit.

On May 6, 2022, the FERC issued an order on rehearing in which it denied the Request for Rehearing.

On May 11, 2022, the 5th Circuit transferred the challenge to the D.C.

Additional petitions for review were timely filed with the D.C.

Circuit in June 2022.

The appeal remains pending before the D.C.

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

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Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that Bakken crude oil tends to be more volatile and flammable than certain other crude oils, and thus poses an increased risk for a significant accident.

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

Since 2011, all new railroad tank cars 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 late 2017 if they are not already retrofitted to comply with new tank car design standards.

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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.

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.

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

In response, the States of North Dakota and Montana filed a preemption application with PHMSA in July 2019 and in May 2020, PHMSA published a Notice of Administrative Determination of Preemption, finding that the federal Hazardous Material Transportation Law preempts Washington State’s vapor pressure limit was preempted under applicable federal law.

One or more of these federal or state safety improvements or updates relating to rail tank cars and rail crude oil-related operational practices imposed by PHMSA since 2015 could drive up the cost of transport and lead to shortages in availability of tank cars.

One or more of these federal or state safety improvements or updates relating to rail tank cars and rail crude oil-related operational practices imposed by PHMSA since 2015 could drive up the cost of transportation and lead to shortages in availability of tank cars.

We do not currently own or operate rail transportation facilities or rail cars.

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Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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In 2000, FERC issued Order No.

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Regulation of production

The production of crude oil, natural gas and NGLs is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.

The production of crude oil, NGLs and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.

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

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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, 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.

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

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

Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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Other federal laws and regulations affecting our industry

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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 $1,388,496 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.

EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,496,035 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 $1,496,035 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 $1,426,319 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.

Texas Railroad Commission crude oil and natural gas rules

The Texas Railroad Commission (the “RRC”), through its Oil and Gas Division, regulates the exploration, production and transportation of crude oil and natural gas in Texas.

Among other duties, the RRC develops and adopts regulations to prevent waste of the state’s crude oil and natural resources, protects the correlative rights of different interest owners, prevents pollution and provides safety with respect to operations including, for example, hydrogen sulfide emissions.

The RRC grants drilling permits based on established spacing, density and special field rules.

Additionally, each month, the RRC assigns production allowables on crude oil and natural gas wells based on factors such as tested well capability, reservoir mechanics, market demand for production and past production, as well as receives operators’ production reports on crude oil leases and gas wells and audits the crude oil disposition path to ensure production did not exceed allowables.

The RRC also regulates crude oil field injection and disposal wells under a federally-approved program that includes permitting, annual reporting and periodic testing activities.

Through this program, fluids are injected into either productive reservoirs under enhanced recovery projects to increase production or into productive or non-productive reservoirs for disposal.

In other pollution prevention activities, the RRC assures waste management is carried out by permitting pits and landfarming, discharges, waste haulers, waste minimization and hazardous waste management tasks.

To prevent pollution of the state’s surface and ground water resources, the RRC has an abandoned well plugging and abandoned site remediation program that uses funds provided by industry through fees and taxes.

Wells and sites are remediated with funds from this program when responsible operators cannot be found.

Moreover, flaring of natural gas is subject to regulation by the RRC under its rules, but those rules allow for permitted exceptions through the use of flare permits.

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

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

The North Dakota Industrial Commission (the “NDIC”) regulates the drilling and production of crude oil and natural gas in North Dakota.

The North Dakota Industrial Commission (“NDIC”) regulates the drilling and production of crude oil and natural gas in North Dakota.

Beginning in 2012 and continuing thereafter, the NDIC has adopted more stringent rules relating to production activities, including with respect to financial assurance for wells and underground gathering pipelines, waste discharges and storage, hydraulic fracturing and associated public disclosure on the FracFocus chemical disclosure registry, site construction, underground gathering pipelines and spill containment, which new requirements are now in effect.

These requirements have increased or will increase the well costs incurred by us and similarly situated crude oil and natural gas E&P operators, and we expect to continue to incur these increased costs as well as any added costs arising from new NDIC legal requirements laws and regulations applicable to the drilling and production of crude oil and natural gas that may be issued in the future.

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Furthermore, the NDIC regulates natural gas flaring and over the past decade has issued orders limiting flaring emissions.

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Please see below the discussion of “Environmental protection and natural gas flaring initiatives” for more information on the natural gas flaring program.

In addition, the NDIC has adopted rules that improve the safety of Bakken crude oil for transport by establishing operating standards for conditioning equipment to properly separate production fluids, limits to the vapor pressure of produced crude oil, and parameters for temperatures and pressures associated with the production equipment.

In addition, the NDIC has adopted rules that improve the safety of transporting Bakken crude oil by establishing operating standards for conditioning equipment to properly separate production fluids, limits to the vapor pressure of produced crude oil, and parameters for temperatures and pressures associated with the production equipment.

Pipeline safety regulation

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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.

Following the adoption of the 2011 Pipeline Safety Act, the PIPES Act of 2016 and the PIPES Act of 2020, PHMSA issued a series of significant rulemakings imposing more stringent regulations on certain types of pipelines.

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.

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.

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

More recently, in August 2022, PHMSA issued a final rule that established more stringent standards for management of change, integrity management, corrosion control, and inspection criteria to help identify and mitigate potential failures and worst-case scenarios.

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.

PHMSA, together with state regulators, inspected these plans throughout 2022.

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These new regulatory actions or any future regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs or 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 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

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and impose specific criteria addressing worker protection.

Certain environmental laws impose joint and several strict liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released.

Certain environmental laws impose strict, joint and several liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released.

Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas.

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The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly well construction, drilling, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations and financial position.

The trend in environmental regulation is to place more restrictions and limitations on, and enhanced disclosures of, activities that may affect the environment, and thus, any new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly well construction, drilling, operating conditions, monitoring and reporting obligations, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations and financial position.

We may be unable to pass on such increased compliance costs to our customers.

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These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances released at the site.

Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.

CERCLA also authorizes the U.S.

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

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

Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.

CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur.

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

We generate materials in the course of our operations that may be regulated as hazardous substances.

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We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes.

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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.

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 business.

However, several groups have filed litigation over this December 2020 decision, and in October 2021 the EPA announced plans to reconsider the December 2020 decision.

The EPA has indicated that it expects to complete its reconsideration efforts by the end of 2023.

If the EPA were to adopt more stringent NAAQS for ground-level ozone as a result of its reconsideration of the December 2020 decision, state implementation of the revised standard 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 business.

Environmental protection and natural gas flaring initiatives

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We recognize the environmental and financial risks associated with air emissions, particularly with respect to flaring of natural gas from our operated well sites and are focused on reducing these emissions, consistent with applicable requirements.

We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is a historical lack of natural gas gathering infrastructure in the Williston Basin, which translates into the inability of operators to promptly connect their wells to natural gas processing and gathering infrastructure.

We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is a historical lack of sufficient natural gas gathering infrastructure in the Williston Basin, which translates into the inability of operators to promptly connect their wells to natural gas processing and gathering infrastructure.

External factors impacting such inability that are out of the control of the operator include, for example, the granting of right-of-way access by land owners, investment from third parties in the development of gas gathering systems and processing facilities, and the development and adoption of regulations.

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

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

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

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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 2014.

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Failure of an operator to comply with the applicable goal at maximum efficiency rate may result in the imposition of monetary penalties and restrictions on production from subject wells.

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

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.

As of December 31, 2022, we were capturing substantially all of our natural gas production in North Dakota.

While we were satisfying the applicable gas capture percentage goals as of December 31, 2022, 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.

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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.

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 emissions of GHGs.

These efforts have included consideration of cap-and-trade programs, carbon taxes, climate-related disclosure obligations, and regulations that directly limit GHG emissions from certain sources.

Moreover, President Biden highlighted addressing climate change as a priority of his administration, issued several Executive Orders related to climate change, and recommitted the United States to long-term international goals to reduce emissions.

In recent years the U.S.

Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas.

While it presently appears unlikely that comprehensive climate change legislation will be passed by Congress in the near future, energy legislation and other regulatory initiatives are expected to be proposed that may be relevant to GHG emissions issues.

For example, the IRA, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities, was signed into law in August 2022.

The excess methane emissions fee provision of the IRA takes effect in 2024.

The provision applies to methane leaks from certain oil and gas facilities and begins at $900 per metric ton of leaked methane in 2024 and rises to $1,200 in 2025, and $1,500 for 2026 and thereafter.

The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.

In addition, following the U.S.

Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules and regulations 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.

The EPA also works together with the Department of Transportation (“DOT”) to 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.

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.

During 2020, the former Trump Administration finalized two sets of amendments to the 2016 Subpart OOOO performance standards for methane, volatile organic compound (“VOC”) and sulfur dioxide emissions to lessen the impact of those standards and remove the transmission and storage segments from the source category for certain regulations.

The first, known as the “2020 Technical Rule,” reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes.

The second, known as the “2020 Policy Rule,” rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments.

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.

Congress also passed, and President Biden signed into law, a resolution under the Congressional Review Act (“CRA”) that revoked the 2020 Policy Rule.

The CRA resolution did not address the 2020 Technical Rule.

In response to President Biden’s executive order, in November 2021, the EPA issued a proposed rule that, if finalized, would make the existing regulations in Subpart OOOOa more stringent and establish Subpart OOOOb to expand emissions reduction requirements for new, modified and reconstructed oil and gas sources, including certain source types not previously regulated under Subpart OOOOa.

In addition, the proposed rule would create a new Subpart OOOOc which would require states to develop plans to reduce methane and VOC emissions from existing sources that must be at least as effective as presumptive standards set by the EPA.

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.

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emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called green well completion requirements.

The EPA issued a supplemental proposed rule in November 2022, which updated, strengthened, and expanded the standards provided in the November 2021 proposed rule.

The supplemental proposed rule requires states to develop their compliance plan for existing sources under Subpart OOOOc within eighteen months of final publication.

The EPA is currently seeking comments on the supplemental proposed rule, and like each of EPA’s previous methane emission regulations, any adopted final rule is likely to face immediate legal challenges.

Separately, the Bureau of Land Management (“BLM”) has also proposed rules to limit venting, flaring, and methane leaks for oil and gas operations on federal lands.

While we cannot predict the final scope or compliance costs of these proposed regulatory requirements, any such requirements have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows.

At the international level, the United Nations (“UN”) -sponsored Paris agreement (“Paris Agreement”) requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020.

President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030.

Additionally, at the UN Climate Change Conference of Parties (“COP26”), held in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector.

COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions.

These goals were reaffirmed at the November 2022 Conference of Parties (“COP27”).

At COP27, the US also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.

Moreover, various state and local governments have also publicly committed to furthering the goals of the Paris Agreement.

The full impact of these actions, and any legislation or regulation promulgated to fulfill the United States’ commitments thereunder, is uncertain at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects on our operations.

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.

President Biden has issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas.

Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States:

Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency, decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels eliminating subsidies provided to the fossil fuel industry, reducing non-CO2 GHG emissions, and increasing the emphasis on climate-related risks across government agencies and economic sectors.

The Biden Administration has also called for revisions and restrictions to the leasing and permitting programs for oil and gas development on federal lands and, for a time, suspended federal oil and gas leasing activities.

The Department of Interior’s (“DOI’s”) comprehensive review of the federal leasing program resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate.

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 deductions and relief available to the oil and gas industry, and imposing restrictions on pipeline infrastructure and LNG export facilities.

Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against various oil and gas companies in state or federal court, alleging, among other things, that such energy companies created public nuisances by producing fuels that contributed to climate change and its 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 in the future making similar allegations.

Should the Company be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors.

Involvement in such a case could have adverse reputational impacts and 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.

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 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.

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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.

At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”), a coalition of over 550 firms

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around the world, announced it had 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.

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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.

Then, 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.

More recently, in January 2023, the Federal Reserve published instructions for its pilot climate scenario analysis exercise, which the six largest U.S.

banks are required to complete by July 31, 2023.

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.

Additionally, in March 2022, the SEC issued a proposed rule that would mandate extensive disclosure of climate risks, including financial impacts, physical and transition risks, related climate-related governance and strategy, and GHG emissions, for all U.S.-listed public companies.

Although the final form and substance of this rule and its requirements are not yet known and its ultimate impact on our business is uncertain, compliance with the proposed rule, if finalized, will result in additional legal, accounting and financial compliance costs which may be significant.

In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.

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.

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, as well as chronic shifts in temperature and precipitation patterns.

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.

Finally, increasing concentrations of GHGs 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, as well as chronic shifts in temperature and precipitation patterns.

These climatic developments have the potential to cause physical damage to our assets or disrupt our supply chains and thus could have an adverse effect on our exploration and production operations through, for example, water use curtailments in response to extended drought conditions.

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

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Water discharges

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States.

The Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States.

The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.

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

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

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

The CWA 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 (“WOTUS”), 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.

The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect waters of the United States.

While the EPA and Corps under the Trump Administration issued a final rule in April 2020 narrowing federal jurisdictional reach over WOTUS, the rule was later vacated by two federal district court decisions, resulting in a return to protections that were in place prior to the 2015 rulemaking revisions under the Obama Administration.

President Biden had also previously issued an executive order to further review and assess these regulations consistent with the new administration’s policy objectives.

The EPA and the Corps have since published a final rule, which will take effect on March 20, 2023, defining WOTUS according to the broader pre-2015 standards with additional updates to incorporate existing U.S.

Supreme Court decisions and agency guidance regarding regional and geographic differences.

However, the new rule has already been challenged, with the State of Texas and industry groups filing separate suits in federal court in Texas on January 18, 2023.

Moreover, the EPA and the Corps have announced an intent to develop a subsequent rule further revising the definition of WOTUS.

Supreme Court is also expected to rule in mid-2023 on certain aspects of the definition.

Therefore, the future substance of the WOTUS definition and its impacts on the scope of the CWA remain

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uncertain at this time.

In addition, in an April 2020 decision, the U.S.

Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

The Court rejected the EPA’s and Corps’ assertion that groundwater should be totally excluded from the CWA.

To the extent any new rule or judicial determination expands the scope of the CWA’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 CWA and sets minimum standards for prevention, containment and cleanup of crude oil spills.

The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect WOTUS.

Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for crude oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from crude oil spills.

The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of crude oil into waters of the United States.

The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of crude oil into WOTUS.

Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations.

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Any leakage from the subsurface portions of the injection wells may cause degradation of fresh water, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages and personal injuries.

Moreover, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be significant.

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

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The hydraulic fracturing process is typically regulated by state crude oil and natural gas commissions or similar agencies, but federal agencies have asserted regulatory authority over certain aspects of the process.

For example, the EPA has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities, as well as published an advance notice of proposed rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing.

In addition, the EPA has published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional crude oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

Moreover, in 2016, the federal Bureau of Land Management (the “BLM”) under the Obama Administration published a final rule imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water.

While hydraulic fracturing is generally exempt from regulation under the SDWA’s UIC program, the EPA has published permitting guidance for certain hydraulic fracturing activities involving the use of diesel fuel and issued a final regulation under the CWA prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities.

In late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances.

These reports or any future studies could spur initiatives to further regulate hydraulic fracturing and ultimately make it more difficult or costly for the Company to perform fracturing activities.

Moreover, in 2016, the BLM under the Obama Administration published a final rule imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback water.

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

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.

The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances.

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

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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.

The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in the issuance of an injunction by a federal district judge in Louisiana, effectively halting implementation of the leasing suspension within the thirteen plantiff states, including Montana.

Further constraints may be adopted by the Biden Administration in the future.

In addition, some states, including North Dakota and Montana 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.

For example, both North Dakota and Montana require operators to disclose chemical ingredients and water volumes used in hydraulic fracturing activities, subject to certain trade-secret exceptions.

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

Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

Nevertheless, if new or more stringent federal, state or local legal restrictions or bans relating to the hydraulic fracturing process are adopted in areas where we operate, or in the future plan to operate, we could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be limited or precluded from drilling wells or in the volume that we are ultimately able to produce from our reserves.

Nevertheless, if new or more stringent federal, state or local legal restrictions or bans relating to the hydraulic fracturing process are adopted in areas where we operate, or in the future plan to operate, we could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be limited or precluded from drilling wells or limited in the volume that we are ultimately able to produce from our reserves.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, crude oil and natural gas production activities using hydraulic fracturing techniques.

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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.

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.

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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”).

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 detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government.

For example, these regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, including corporate successors of former operators.

These requirements may result in significant costs associated with the removal of tangible equipment and other restorative actions.

Additionally, under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated.

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Oil, NGL, and natural gas operations on federal lands are subject to increasing regulatory attention.

The Biden Administration has explored various means to curtail oil and natural gas activities on federal lands.

For example, in January 2021, President Biden issued an executive order that instructed the Secretary of the DOI to pause new oil and natural gas leases on public lands, but not existing operations under valid leases or on tribal lands which the federal government merely holds in trust, pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices.

A federal district court issued a preliminary injunction against the order in June 2021 that was subsequently vacated and remanded back to the district court by Fifth U.S.

Circuit Court of Appeals in August 2022.

The district court then issued a permanent injunction against the order, though limited in scope to the thirteen plaintiff states, including Montana.

Meanwhile, the DOI released a report on the federal oil and natural gas leasing program in November 2021 which included several recommendations for how to reform the program.

Some of the report’s recommendations, including an increased royalty rate and a significant reduction in total available acreage, have been incorporated in recent lease sales.

While most of the Biden Administration’s changes to federal lands regulations have focused on new leases, future regulatory efforts could shift focus to existing lease operations.

For example, the BLM issued a proposed rule in November 2022 to reduce natural gas waste from venting, flaring, and leaks associated with exploration and production activities on federal and tribal lands.

The outcome of litigation surrounding the Biden Administration’s Social Cost of Carbon (“SCC”) metric may also impact future regulatory decision-making.

In February 2022, a district court blocked the Biden Administration’s use of its interim SCC value in agency decision-making.

In March 2022, the Fifth Circuit stayed the order while the government’s appeal remains in progress.

The ultimate result of this litigation may impact the character of new regulations on certain federal oil and gas leases or oil and gas infrastructure on federal lands, which in turn could impact our future operations.

Additionally, oil and natural gas operations and related infrastructure projects on federal lands may be impacted by recent changes to the National Environmental Policy Act (“NEPA”) implementing regulations.

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.

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On July 16, 2020, the Council on Environmental Quality (the “CEQ”) under the Trump Administration published a final rule modifying NEPA.

The modified final rule establishes a time limit of two years for preparation of environmental impact statements and one year for the preparation of environmental assessments.

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

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.

The 2020 rule established a time limit of two years for preparation of environmental impact statements and one year for the preparation of environmental assessments.

The 2020 rule also limited the scope of review to the direct effects of a proposed project on the environment.

However, in April 2022 the CEQ under the Biden Administration introduced a new ‘Final Rule’ that reversed several parts of the 2020 rule, including the scope limitations.

The 2022 Final Rule requires NEPA reviews to incorporate consideration of indirect and cumulative impacts of the proposed project, including effects on climate change and GHGs, consistent with pre-2020 requirements.

The new rule also allows agencies to create stricter NEPA rules as they see fit but left in place the 2020 rule two-year time limit to complete environmental impact statements.

More recently, in January 2023 the CEQ released updated guidance for agency consideration of GHG emissions and climate change impacts in environmental reviews, which includes, among other recommendations, best practices for analyzing and communicating climate change effects.

In addition to administrative and policy risks, operations on federal lands also face litigation risks.

For example, in January 2022, a federal district court in Washington, DC, vacated the results of the federal government’s Lease Sale 257, effectively canceling the sale, on the grounds that the federal government failed to consider foreign consumption of oil and natural gas in its GHG emissions analysis.

Lease Sale 257 was reinstated as part of the IRA, but litigation remains ongoing as to whether the lease sale was properly vacated.

More recently, a June 2022 settlement approved by a federal district court in Washington, DC, obligates BLM to repeat its environmental reports under NEPA for all oil and gas leases sold between 2015 and 2020.

The settlement stems from a 2016 lawsuit alleging that BLM was not properly accounting for the cumulative climate impacts of its federal leasing program.

However, the settlement does not require the BLM to rescind affected leases nor does it prohibit the agency from approving applications for permits to drill.

Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be material, 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 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 8% 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 would not be affected by any subsequent need to obtain a federal permit.

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Employee health and safety

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Human Capital Resources

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.

We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees.

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

To execute our strategy in the highly competitive oil and gas industry we need to attract, develop and retain a highly effective and diverse workforce.

Our ability to do so depends on a number of factors, including an available pool of qualified talent, compelling compensation and benefits plans and an energizing environment committed to helping employees develop and grow.

As of February 22, 2023, we employed 531 full-time employees and we utilize independent contractors to perform various field and corporate services as needed.

As part of the Merger, an organizational review was completed to identify synergies across the legacy organizations.

Staff reductions in connection with the Merger have occurred, and corporate functions are expected to transfer to our corporate headquarters in Houston, Texas by June 30, 2023.

Our current hiring plans focus on advancing talent attraction in our primary operating locations of Houston, Texas and Williston, North Dakota.

We believe that the knowledge transfer plans we have in place are appropriate, and that we will continue to have the human capital necessary to operate our business safely while executing on our strategic priorities.

Additionally, we are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

We consider our relations with our employees to be satisfactory.

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

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.

Health and safety

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

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

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.

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.

For example, our environmental, health and safety teams regularly monitor and update our recommended safety practices with feedback and input from our field personnel under a management of change process framework.

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

We have developed a comprehensive safety management system that includes recurring risk assessment, hazard recognition and mitigation and emergency response preparedness training, protective measures including adequate personal protective equipment, life-saving rules, onboarding processes, contractor safety management, partner surveys, comprehensive audits, semi-ann ual safety summits, exec utive-level reviews of incidents and ad-hoc safety stand-downs.

In addition, safety training is provided to all employees, and, in order to reinforce accountability, safety performance is integrated into our annual compensation program.

We seek to partner only with contractors and vendors who share our commitment to safety.

Compensation and benefits

We seek to provide fair, competitive compensation and comprehensive benefits to our employees.

To ensure alignment with our short- and long-term objectives, our compensation programs consist of base pay, short-term incentives and long-term incentives, including stock grants.

Our wide array of benefits include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, flexible work schedules and wellness resources, including emotional well-being services through an employee Life Assistance Program as well as financial wellness tools and resources.

We invest in leadership training and professional development programs that will enable our employees to reach their potential and perform at their best.

Oasis Academy for Success is our on-demand learning system, which supports job-specific training as well as soft skill and leadership development training.

Diversity and inclusion

We recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to providing a diverse and inclusive workplace to attract and retain talented employees.

We maintain a work culture that treats all employees fairly and with respect, promotes inclusivity, and provides equal opportunities for the professional growth and advancement based on merit.

Our Code of Business Conduct and Ethics prohibits discrimination or harassment against any employee or applicant on the basis of race, color, gender, religion, age, national origin, citizenship status, military service or veteran status, sexual orientation or disability.

In addition, we seek business partners who do not engage in prohibited discrimination in hiring or in their employment practices and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria.

To sustain and promote a diverse and inclusive workforce, we maintain a robust compliance program supported by annual certification by all employees to our Code of Business Conduct and Ethics, as well as training programs on affirmative action and equal employment opportunity.

We evaluate ways to enhance awareness of and promote diversity and inclusion on an ongoing basis.

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, Watford City and Parshall.

The goal of our total rewards program is to provide a transparent, thoughtful framework for decisions on employee compensation and benefits.

Our total rewards program considers goals in addition to financial benefits and aims to increase employee focus on key performance goals, improve overall happiness and well-being and deepen commitment to our collective success.

We do this by ensuring employees at Chord are fairly compensated and feel valued, which enables us to attract, motivate and retain high level talent while delivering strong performance to achieve our business strategy.

Our intent is to ensure the compensation and benefits provided as part of our total rewards program are fair and equitable across positions and locations, market competitive, based on merit, consistent with our values and transparent to our employees.

The core elements of our compensation program include base pay, short-term incentives and long-term incentive opportunity for employees at all levels of the Company.

In addition, we provide benefits that include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, flexible work schedules, financial wellness tools and resources and emotional well-being services, such as an employee Life Assistance Program.

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Training, development and career opportunities

Our team of talented employees possess a broad set of skills including engineering, geology, production, marketing, land, supply chain, health and human safety, human resources, finance, accounting, information technology and legal.

Many of our employees work in disciplines that require highly specialized skills and subject-matter expertise, underpinning our ability to deliver on our strategic priorities.

We are committed to the personal and professional development of our employees, with the belief that a greater level of knowledge, skill and ability benefits the employee and fosters a more creative, innovative, efficient and therefore competitive organization.

We empower our employees to develop the skills they need to perform in their current jobs while also developing skills and experiences to support their longer-term growth.

We provide our employees with programs that support their learning and development, which are designed to build and strengthen employees’ abilities, including leadership trainings, development of professional competencies, safety trainings and information and technology trainings.

We are also proud to sponsor training and scholarships to support growth in our communities, such as:

serving as corporate sponsor to the Bakken Area Skills Center, which provides high school students hands on training in various technical trades;

sponsoring engineering college scholarships in North Dakota and Montana;

volunteering at Habitat for Humanity to build homes for families in need of safe and affordable housing;

and supporting and promoting OneGoal and Junior Achievement in Houston, which provide access to college scholarships and classroom mentorship opportunities for students across our community.

Finally, we have in place a robust approach to succession planning for key personnel by assessing the competencies, experience, leadership capabilities and development opportunities of identified succession candidates.

We will continue to build a pipeline of talent for the future through our new graduate and intern hiring programs, which brings fresh perspectives and new ideas to the organization to help us continually challenge the status-quo.

Diversity, equity and inclusion

We believe a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to creating an environment where every employee is valued and heard.

We regularly seek ways to increase the diversity of our workforce, and we embrace an approach to talent attraction and promotion that enables each and every individual to be evaluated based on merit.

Our Compensation and Human Resources Committee reviews the Company’s development, implementation and effectiveness of our human resources and human capital management practices, policies, strategies and goals, including those related to the recruitment, development and retention of personnel, talent management, diversity, equity and inclusion and other employment practices.

Similarly, our Environmental Social and Governance Committee provides oversight, guidance and perspective to management and the Board of Directors regarding the Company’s policies, programs and initiatives related to the promotion of diversity.

As of February 22, 2023, approximately 25% of our employees are either women or members of a minority group.

In addition, the Board of Directors believes it is important for directors to possess a diverse array of backgrounds, skills and achievements.

When considering new candidates, the Nominating and Governance Committee, with input from the Board of Directors, takes these factors into account as set forth in its charter.

As of February 22, 2023, 63% of our independent directors are women.

We are an equal opportunity employer and do not discriminate on the basis of race, religion, color, national origin, sex, gender, gender expression, sex (including pregnancy, sexual orientation and gender identity), age, marital status, socioeconomic background, veteran status or disability status.

We engage with individuals with disabilities to provide reasonable accommodations that may allow them to participate in the job application or interview process, to perform essential job functions and to receive other benefits and privileges of employment.

In addition, we seek to work with business partners who do not engage in prohibited discrimination in hiring or in their employment practices, and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria.

To sustain and promote a diverse, equitable and inclusive workforce, we maintain a robust compliance program supported by annual certification by all employees to our Code of Business Conduct and Ethics Policy, as well as training programs on equal employment opportunity.

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

We also have a corporate office in Denver, Colorado at 1700 Lincoln Street.

We also own field offices in the North Dakota communities of Williston, Ray, New Town and Watford City.

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Available Information

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Our filings with the SEC are available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

We make available on our website at http://www.oasispetroleum.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC.

We make available on our website at http://www.chordenergy.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC.

Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.

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

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.

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

Our Code of Business Conduct and Ethics Policy 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, as applicable, we will post on our website any modification to the Code of Business Conduct and Ethics Policy 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.

We also make available Sustainability Reports and other sustainability documents on our website, which contain various performance highlights relating to ESG and human capital measures.

Information contained in our Sustainability Reports, and other documents, are not incorporated by reference into, and do not constitute a part of, this Annual Report on Form 10-K.

References to the Company’s website in this Form 10-K are provided as a convenience and do not constitute, and should not be deemed, an incorporation by reference of the information contained on, or available through, the website, and such information should not be considered part of this Form 10-K.

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Item 1. Business