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What changed in Chord Energy Corp's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of Chord Energy Corp's 2023 and 2024 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2024 report.

+532 added−528 removedSource: 10-K (2025-02-27) vs 10-K (2024-02-26)

Top changes in Chord Energy Corp's 2024 10-K

532 paragraphs added · 528 removed · 412 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

161 edited+29 added−39 removed257 unchanged
Biggest changeYear ended December 31, 2023 2022 2021 Gross Net Gross Net Gross Net Development wells: Oil 111 66.9 67 41.3 49 23.3 Gas — — — — — — Dry — — — — — — Total development wells 111 66.9 67 41.3 49 23.3 Exploratory wells: Oil — — — — — — Gas — — — — — — Dry — — — — — — Total exploratory wells — — — — — — Total wells 111 66.9 67 41.3 49 23.3 As of December 31, 2023, we had 64 gross (33.9 net) wells in the process of being drilled or completed, which included 44 gross operated wells waiting on completion and 19 gross non-operated wells drilling or completing. 17 Table of Contents As of December 31, 2023, we had four operated rigs running, and we expect to run four operated rigs during the majority of 2024.
Biggest changeAs of December 31, 2024, we had 98 gross (74.5 net) wells in the process of being drilled or completed, which included 86 gross operated wells waiting on completion and 5 gross non-operated wells drilling or completing.
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.
We have developed a comprehensive safety management system that includes recurring risk assessment, hazard recognition and mitigation training, 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.
The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, as described below.
The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, as described below.
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.
While most of the former 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.
We continue to align our Scope 1 and Scope 2 disclosures towards various frameworks, including the Task Force on Climate-related Financial Disclosures (TCFD), the Sustainability Accounting Standards Board's (SASB) Extractives & Minerals Processing Sector: Oil & Gas - Exploration and Production Standard, the Global Reporting Initiative (GRI) Standard for Oil and Gas, and the American Exploration and Production Council (AXPC) ESG Metrics Framework.
We continue to work to align our Scope 1 and Scope 2 disclosures towards various frameworks, including the Task Force on Climate-related Financial Disclosures (TCFD), the Sustainability Accounting Standards Board's (SASB) Extractives & Minerals Processing Sector: Oil & Gas - Exploration and Production Standard, the Global Reporting Initiative (GRI) Standard for Oil and Gas, and the American Exploration and Production Council (AXPC) ESG Metrics Framework.
Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for crude oil pipelines that allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index, without making a cost of service filing.
Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for crude oil pipelines that allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index (“PPI”), without making a cost of service filing.
The outcome of litigation surrounding the Biden Administration’s SC-GHGs metric may also impact future regulatory decision-making. While the Fifth Circuit dismissed initial challenges to the Biden Administration’s interim calculations of (then named) SCC values on standing grounds in February 2023, future litigation opposing federal agency applications of the current SC-GHGs metric appears likely.
The outcome of litigation surrounding the former Biden Administration’s SC-GHGs metric may also impact future regulatory decision-making. While the Fifth Circuit dismissed initial challenges to the Biden Administration’s interim calculations of (then named) SCC values on standing grounds in February 2023, future litigation opposing federal agency applications of the current SC-GHGs metric appears likely.
In addition, we offer 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.
In addition, we offer 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 Assistance Program.
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.
Within the time period required by the SEC and The Nasdaq Stock Market LLC (the “Nasdaq”), 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.
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.
These 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.
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. Various U.S. states and local governments have also publicly committed to furthering the goals of the Paris Agreement.
President Biden 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. Various U.S. states and local governments have also publicly committed to furthering the goals of the Paris Agreement.
In 2015 and 2020, respectively, the Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over waters of the United States (“WOTUS”). However, both of these rulemakings were subject to legal challenge. In January 2023, the EPA and the U.S.
In 2015 and 2020, respectively, the former Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over waters of the United States (“WOTUS”). However, both of these rulemakings were subject to legal challenge. In January 2023, the EPA and the U.S.
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.
The price and availability of alternative energy sources, such as wind, solar, nuclear, coal, hydrogen and biofuels as well as the impact of climate change activism, fuel conservation measures and governmental requirements for renewable energy sources, could adversely affect our revenues. See “Item 1A.
Additionally, under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated. 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.
Additionally, under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated. Oil, NGL, and natural gas operations on federal lands are subject to increasing regulatory attention. The former Biden Administration has explored various means to curtail oil and natural gas activities on federal lands.
Additionally, in September 2023, the Biden Administration directed federal agencies to consider the Social Cost of GHGs (“SC-GHGs”) (formerly known as the Social Cost of Carbon (“SCC”)) metric in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate.
Additionally, in September 2023, the previous Biden Administration directed federal agencies to consider the Social Cost of GHGs (“SC-GHGs”) (formerly known as the Social Cost of Carbon (“SCC”)) metric in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate.
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 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 former Biden Administration introduced a new ‘Final Rule’ that reversed several parts of the 2020 rule, including the scope limitations.
On July 16, 2020, the Council on Environmental Quality (the “CEQ”) under the Trump Administration published a final rule modifying NEPA. 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.
On July 16, 2020, the Council on Environmental Quality (the “CEQ”) under the first Trump Administration published a final rule modifying NEPA. 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.
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.
Our Compensation and Human Resources Committee reviews the Company’s development and implementation of our 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.
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 projected 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) 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.
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 projected 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+ ($5.20 per share annualized) 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.
In September 2023, the Biden Administration announced it would be directing federal agencies to incorporate SC-GHGs values in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate.
In September 2023, the former Biden Administration announced it would be directing federal agencies to incorporate SC-GHGs values in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate.
Exploration and Production Operations Estimated net proved reserves Our estimated net proved reserves and related PV-10 at December 31, 2023 and 2022 are based on reports independently prepared by NSAI, our independent reserve engineers.
Exploration and Production Operations Estimated net proved reserves Our estimated net proved reserves and related PV-10 at December 31, 2024, 2023 and 2022 are based on reports independently prepared by NSAI, our independent reserve engineers.
As of December 31, 2023, substantially all of our gross operated crude oil and natural gas production was 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.
As of December 31, 2024, substantially all of our gross operated crude oil and natural gas production was 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.
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, 2023, we were capturing substantially all of our natural gas production in North Dakota.
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, 2024, we were capturing substantially all of our natural gas production in North Dakota.
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. 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.
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. Approximately 6% 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.
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.
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, terminal and transportation services, (iii) produced and flowback water gathering and disposal services and (iv) freshwater distribution services.
When crude oil pipelines operate at full capacity, access is generally governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
When crude oil pipelines operate at full capacity, access is generally governed by proration provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
We 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 control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate.
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 control over our asset portfolio, we have established a leasehold position comprised largely of properties that we expect to operate.
The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending within the periods presented. Acreage The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2023.
The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending within the periods presented. Acreage The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2024.
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”), the U.S. Environmental Protection Agency (“EPA”) and the courts.
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”), the U.S. Environmental Protection Agency (“EPA”), other federal agencies and the courts.
While we were satisfying the applicable gas capture percentage goals as of December 31, 2023, 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.
While we were satisfying the applicable gas capture percentage goals as of December 31, 2024, 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.
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.
Moreover, in 2016, the BLM under the former 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 first Trump Administration published a final rule rescinding the 2016 final rule.
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.
During 2020, the first 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.
We also are proficient in capturing the natural gas that we produce, and, as of December 31, 2023, 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 also are proficient in capturing the natural gas that we produce, and, as of December 31, 2024, 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.
If the EPA were to adopt more stringent NAAQS for ground-level ozone as a result of its new review and ongoing 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 business.
If the EPA were to adopt more stringent NAAQS for ground-level ozone as a result of its new review and ongoing reconsideration of the December 2020 decision, state implementation of the 25 Table of Conten ts 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 business.
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 19 Table of Contents 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.
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.
Additionally, in November 2021, the previous 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-carbon dioxide GHG emissions and increasing the emphasis on climate-related risks across government agencies and economic sectors.
To sustain and promote a diverse, equitable and inclusive workforce, we maintain a robust compliance program supported by an annual certification by all employees to our Code of Business Conduct and Ethics Policy, as well as training programs on equal employment opportunity. Offices Our principal corporate office is located in Houston, Texas at 1001 Fannin Street.
To maintain a diverse and inclusive workforce, we maintain a robust compliance program supported by an annual certification by all employees to our Code of Business Conduct and Ethics Policy, as well as training programs on equal employment opportunity. Offices Our principal corporate office is located in Houston, Texas at 1001 Fannin Street.
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.
In addition, a substantial majority of our executive officers’ overall compensation is in long-term equity-based incentive awards, and we have implemented leading 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.
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 2024 Annual Meeting of Stockholders.
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 2025 Annual Meeting of Stockholders.
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. 16 Table of Contents (2) Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.
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.
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”).
The Commission received requests for rehearing of the December 2020 Order and on January 20, 2022, in Docket No. RM20-14, granted rehearing and modified the oil index (“January 2022 Order”).
As of November 1, 2020, the enforceable gas capture percentage goal is 91%. The NDIC requires operators to develop and implement Gas Capture Plans to maintain 26 Table of Contents consistency with the agency’s gas capture percentage goals, but it maintains the flexibility to exclude certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals.
As of November 1, 2020, the enforceable gas capture percentage goal is 91%. The NDIC requires operators to develop and implement Gas Capture Plans to maintain consistency with the agency’s gas capture percentage goals, but it maintains the flexibility to exclude certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals.
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. 34 Table of Contents
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. 34 Table of Conten ts
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 22 Table of Contents exceptions to such regulations or to have reductions in well spacing.
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.
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. 20 Table of Contents 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.
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 built to transport crude oil or other petroleum type fluids, including ethanol, have been built to more stringent safety standards.
Some of the report’s recommendations, including an increased royalty rate, minimum bid limits and a significant reduction in total available acreage, were required to be 31 Table of Contents implemented as part of the IRA and have been subsequently incorporated in recent lease sales.
Some of the report’s recommendations, including an increased royalty rate, minimum bid limits and a significant reduction in total available acreage, were required to be implemented as part of the IRA and have been subsequently incorporated in recent lease sales.
Furthermore, competitive conditions may be 18 Table of Contents 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.
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.
Due to several crude oil train derailments in the past decade, transportation safety regulators in the United States and Canada have examined the adequacy of transporting crude oil by rail, with an emphasis on the safe transport of Bakken crude oil by rail, following findings by the U.S.
Due to several crude oil train derailments in the past 15 years, transportation safety regulators in the United States and Canada have examined the adequacy of transporting crude oil by rail, with an emphasis on the safe transport of Bakken crude oil by rail, following findings by the U.S.
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 former Biden Administration 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.
Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following: • Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database; • Review of working interests and net revenue interests in our reserves database against our well ownership system; • Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database; 15 Table of Contents • Review of updated capital costs prepared by our operations team; • Review of internal reserve estimates by well and by area by our internal reservoir engineers; • Discussion of material reserve variances among our internal reservoir engineers; • 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 Financial Officer; Senior Vice President, Planning & Investor Relations and Managing Director, Corporate Planning & Reserves; and • Review of our reserves estimation process and the reserves report by our Audit and Reserves Committee and NSAI on an annual basis.
Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following: • Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database; • Review of working interests and net revenue interests in our reserves database against our well ownership system; • Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database; • Review of updated capital costs prepared by our operations team; • Review of internal reserve estimates by well and by area by our internal reservoir engineers; • Discussion of material reserve variances among our internal reservoir engineers; • 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 Strategy Officer & Chief Commercial Officer; Executive Vice President & Chief Financial Officer and Senior Director, Corporate Planning & Reserves; and • Review of our reserves estimation process and the reserves report by our Audit and Reserves Committee and NSAI on an annual basis.
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, 12 Table of Contents repeatable development drilling programs.
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, 12 Table of Conten ts repeatable development drilling programs.
While, historically, our compliance costs with environmental laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no assurance that such costs will not be material in the future as a result of such existing laws and regulations or any new laws and regulations, or that such future compliance will not have a material adverse effect on our business and operating results.
While, historically, our compliance costs with environmental laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no assurance that such costs will not be material in the future as a result of such 24 Table of Conten ts existing laws and regulations or any new laws and regulations, or that such future compliance will not have a material adverse effect on our business and operating results.
The final rules expand the scope of regulated oil and gas sources beyond those currently regulated under the existing NSPS Subpart OOOOa. Under the final rules, states have two years to prepare and submit plans to impose methane and VOC emissions 27 Table of Contents controls for existing sources.
The final rules expand the scope of regulated oil and gas sources beyond those currently regulated under the existing NSPS Subpart OOOOa. Under the final rules, states have two years to prepare and submit plans to impose methane and VOC emissions controls for existing sources.
The following table provides a reconciliation of Standardized Measure to PV-10: At December 31, 2023 2022 2021 (In millions) Standardized Measure of discounted future net cash flows $ 6,990.6 $ 11,494.5 $ 2,696.9 Add: present value of future income taxes discounted at 10% 1,537.9 2,957.7 418.5 PV-10 $ 8,528.5 $ 14,452.2 $ 3,115.4 Independent petroleum engineers Our estimated net proved reserves and PV-10 at December 31, 2023 and 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.
The following table provides a reconciliation of Standardized Measure to PV-10: At December 31, 2024 2023 2022 (In millions) Standardized Measure of discounted future net cash flows $ 8,354.2 $ 6,990.6 $ 11,494.5 Add: present value of future income taxes discounted at 10% 1,908.4 1,537.9 2,957.7 PV-10 $ 10,262.6 $ 8,528.5 $ 14,452.2 Independent petroleum engineers Our estimated net proved reserves and PV-10 at December 31, 2024, 2023 and 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.
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.
Other information, such as presentations, the charters of the Audit and Reserves Committee, Compensation and Human Resources Committee, Nominating and Governance Committee, and Safety and Sustainability 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.
Enhanced climate disclosure requirements could result in additional legal and accounting costs and accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. States may also pass laws imposing more expansive disclosure requirements for climate-related risks.
Court of Appeals for the Eighth Circuit. Enhanced climate disclosure requirements could result in additional legal and accounting costs and accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. States may also pass laws imposing more expansive disclosure requirements for climate-related risks.
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%.
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 PPI plus 0.78% (“December 2020 Order”).
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.
For example, in the absence of a current federal standard on the vapor pressure of crude oil transported by 20 Table of Conten ts 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.
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.
We believe that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results 17 Table of Conten ts of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.
Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense.
Prior to the commencement of drilling operations on those properties, we conduct a thorough title 18 Table of Conten ts examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense.
We 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 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. • Strong balance sheet.
Since our inaugural dividend in February 2021, we have declared cash dividends to our stockholders of $47.79 per share of common stock. Our scale and high-quality assets in the Williston Basin allow us to generate significant, sustainable cash flow to support maximizing returns.
Since our inaugural dividend in February 2021, we have declared cash dividends to our stockholders of $55.99 per share of common stock. Our scale and high-quality assets in the Williston Basin allow us to generate significant, sustainable cash flow to support maximizing returns.
The key tenets of our ESG philosophy are to always put safety first, minimize our environmental impact, reduce our emissions intensity, promote an 11 Table of Contents inclusive culture, align executive compensation with long-term value creation and stockholder interests, and support programs that benefit the communities in which we operate.
The key tenets 11 Table of Conten ts of our ESG philosophy are to always put safety first, minimize our environmental impact, reduce our emissions intensity, promote an inclusive, merit-based culture, align executive compensation with long-term value creation and stockholder interests, and support programs that benefit the communities in which we operate.
Deregulation of 21 Table of Contents wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index minus 0.21%. FERC directed oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 based on the new index level.
Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates were permitted to adjust their indexed ceilings annually by PPI minus 0.21%. FERC directed oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 based on the new index level.
In the remaining 23 states, the agencies are implementing the September 2023 rule, which did not define the term “continuous surface connection.” Therefore, some uncertainty remains 29 Table of Contents as to how broadly the September 2023 rule and the Sackett decision will be interpreted by the agencies.
In the remaining 23 states, the agencies are implementing the September 2023 rule, which did not define the term “continuous surface connection.” Therefore, some uncertainty remains as to how broadly the September 2023 rule and the Sackett decision will be interpreted by the agencies.
Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.” Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters.
Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.” 21 Table of Conten ts Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters.
Should the Company be targeted by any such litigation, we may incur liability, which, to the extent that societal 28 Table of Contents 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.
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.
EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,544,521 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 $1,544,521 per violation per day, adjusted annually for inflation.
EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,584,648 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 $1,584,648 per violation per day, adjusted annually for inflation.
The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice or course of business that operates as a fraud or deceit upon any person.
FERC’s regulations implementing EPAct 2005 make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice or course of business that operates as a fraud or deceit upon any person.
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.
These climatic developments have the potential to 28 Table of Conten ts 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.
Our Managing Director, Corporate Planning & Reserves has more than 13 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.
Our Senior Director, Corporate Planning & Reserves has more than 14 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.
A violation of this rule may result in civil penalties of up to $1,544,521 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.
A violation of this rule may result in civil penalties of up to $1,584,648 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.
Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs.
Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1. Every five years, FERC reviews the 19 Table of Conten ts appropriateness of the index level in relation to changes in industry costs.
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, 2023, we had 1,029,263 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin.
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, 2024, we had 1,254,860 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin.
Our senior management team has extensive expertise in the oil and gas industry with an average of more than 25 years of industry experience.
Our senior management team has extensive expertise in the oil and gas industry with an average of nearly 25 years of industry experience.
For example, the IRA, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on methane emissions from certain facilities, was signed into law in August 2022. The methane emissions fee provision of the IRA takes effect in 2024.
For example, the IRA, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on methane emissions from certain facilities, was signed into law in August 2022.
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. This change impacts comparability with prior periods.
Accordingly, our reported production volumes 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. This change impacts comparability with prior periods.
From time to time, legal challenges have been filed relating to federal leasing decisions, such as for failure to adequately assess the impact of any increase in GHG emissions resulting from increased production on federal lands.
Operations on federal lands also face litigation risks. From time to time, legal challenges have been filed relating to federal leasing decisions, such as for failure to adequately assess the impact of any increase in GHG emissions resulting from increased production on federal lands.
Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices.
FERC market transparency rules Under FERC’s regulations, Order No. 704 and related subsequent orders, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeIn addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including: • advance notice provisions for stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of stockholders; and • limitations on the ability of our stockholders to call special meetings. 55 Table of Contents Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.
Biggest changeDelaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.
Such legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations such as us.
Such legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. and Canadian federal income tax rate applicable to corporations such as us.
We may not be able to utilize all or a portion of our net operating loss carryforwards or other tax benefits to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our financial position, results of operations and cash flows.
We may not be able to utilize all or a portion of our net operating loss carryforwards or other tax benefits to offset future taxable income for U.S. federal or state or Canadian federal tax purposes, which could adversely affect our financial position, results of operations and cash flows.
We may be limited in the portion of our net operating loss carryforwards (“NOLs”) that we can use in the future to offset taxable income for U.S. federal and state income tax purposes. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured.
We may be limited in the portion of our net operating loss carryforwards (“NOLs”) that we can use in the future to offset taxable income for U.S. federal and state and Canadian federal income tax purposes. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured.
Our risk is not concentrated at DAPL as we have alternative outlets to sell our crude oil production using multiple modes of transportation. In the event DAPL were to cease operating, we would anticipate Williston Basin crude oil prices to weaken materially before improving as the market adapts to rail transportation.
Our risk is not concentrated at DAPL as we have alternative outlets to sell our crude oil production using multiple modes of transportation; however, in the event DAPL were to cease operating, we would anticipate Williston Basin crude oil prices to weaken materially before improving as the market adapts to rail transportation.
Additionally, we may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our NOLs and other Tax Benefits.
We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our NOLs and other Tax Benefits.
Significant acquisitions and other strategic transactions, including the Merger, may involve other risks, including: • diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions; • the challenge and cost of integrating acquired and expanded operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business; • difficulty associated with coordinating geographically separate organizations; • an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and • the challenge of attracting and retaining personnel associated with acquired operations.
Significant acquisitions and other strategic transactions, including the Arrangement, may involve other risks, including: • diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions; • the challenge and cost of integrating acquired and expanded operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business; • difficulty associated with coordinating geographically separate organizations; • an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and • the challenge of attracting and retaining personnel associated with acquired operations.
To the lesser extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate capacity.
To the lesser extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate pipeline capacity.
Financial Statements and Supplementary Data—Note 24—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated crude oil and natural gas reserves and the PV-10 and Standardized Measure as of December 31, 2023, 2022 and 2021. In order to prepare our estimates, we must project production rates and the timing of development expenditures.
Financial Statements and Supplementary Data—Note 24—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated crude oil and natural gas reserves and the PV-10 and Standardized Measure as of December 31, 2024, 2023 and 2022. In order to prepare our estimates, we must project production rates and the timing of development expenditures.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following: • shortages of or delays in obtaining equipment and qualified personnel; • facility or equipment malfunctions and/or failure; • unexpected operational events, including accidents; • pressure or irregularities in geological formations; • adverse weather or climatic conditions, such as blizzards, ice storms, wildfires, floods and prolonged drought conditions; • reductions in crude oil, NGL and natural gas prices; • inflation in exploration and drilling costs; • disruptions in our supply chain for raw materials, chemicals and equipment; • delays imposed by or resulting from compliance with regulatory requirements, including permits; • proximity to and capacity of transportation facilities; • contractual disputes; • title problems; and • limitations in the market for crude oil, NGLs and natural gas.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following: • shortages of or delays in obtaining equipment and qualified personnel; • facility or equipment malfunctions and/or failure; • unexpected operational events, including accidents; • pressure or irregularities in geological formations; • adverse weather or climatic conditions, such as blizzards, ice storms, wildfires, floods and prolonged drought conditions; • reductions in crude oil, NGL and natural gas prices; 37 Table of Conten ts • inflation in exploration and drilling costs; • disruptions in our supply chain for raw materials, chemicals and equipment; • delays imposed by or resulting from compliance with regulatory requirements, including permits; • proximity to and capacity of transportation facilities; • contractual disputes; • title problems; and • limitations in the market for crude oil, NGLs and natural gas.
Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities . As of December 31, 2023, approximately all of our total net acreage in the Williston Basin was held by production.
Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities . As of December 31, 2024, approximately all of our total net acreage in the Williston Basin was held by production.
It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in 2024; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities.
It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in 2025; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities.
These potential impacts, while uncertain and difficult to predict, may negatively affect our business, including, without limitation, our operating results, financial position and liquidity, the duration of any potential disruption of our business, how and the degree to which the pandemic may impact our customers, supply chain and distribution network, the health of our employees, the productivity and sustainability of our workforce, our insurance premiums, costs attributable to our emergency measures, payments from customers and uncollectible accounts, limitations on travel, the availability of industry experts and qualified personnel and the market for our securities. 47 Table of Contents Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect our production.
These potential impacts, while uncertain and difficult to predict, may negatively affect our business, including, without limitation, our operating results, financial position and liquidity, the duration of any potential disruption of our business, how and the degree to which the pandemic may impact our customers, supply chain and distribution network, the health of our employees, the productivity and sustainability of our workforce, our insurance premiums, costs attributable to our emergency measures, payments from customers and uncollectible accounts, limitations on travel, the availability of industry experts and qualified personnel and the market for our securities. 46 Table of Conten ts Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect our production.
The process of integrating assets, including those obtained in the Merger, could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business.
The process of integrating assets, including those obtained in the Arrangement, could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information about our realized crude oil prices and average price differentials relative to NYMEX WTI for the years ended December 31, 2023, 2022 and 2021. Additionally, the refining capacity in the U.S.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information about our realized crude oil prices and average price differentials relative to NYMEX WTI for the years ended December 31, 2024, 2023 and 2022. Additionally, the refining capacity in the U.S.
We may be subject to risks in connection with acquisitions, including the Merger, because of integration difficulties, uncertainties in evaluating recoverable reserves, well performance and potential liabilities and uncertainties in forecasting crude oil, NGL and natural gas prices and future development, production and marketing costs.
We may be subject to risks in connection with acquisitions, including the Arrangement, because of integration difficulties, uncertainties in evaluating recoverable reserves, well performance and potential liabilities and uncertainties in forecasting crude oil, NGL and natural gas prices and future development, production and marketing costs.
From time to time, U.S. federal and state level legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies.
From time to time, U.S. federal and state level and Canadian federal and provincial legislation has been proposed that would, if enacted into law, make significant changes to U.S. and Canadian tax laws, including to certain key U.S. federal and state and Canadian federal income tax provisions currently available to oil and natural gas exploration and development companies.
Compliance with current and future environmental laws, executive orders, regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing activities, the injection of waste streams into disposal wells or any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted but that could be materially adverse to our business and results of operations. 48 Table of Contents Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGLs and natural gas and secure and retain trained personnel.
Compliance with current and future environmental laws, executive orders, regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing activities, the injection of waste streams into disposal wells or any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted but that could be materially adverse to our business and results of operations. 47 Table of Conten ts Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGLs and natural gas and secure and retain trained personnel.
As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. We did not record any impairment charges on unproved properties during the years ended December 31, 2023, 2022 and 2021.
As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. We did not record any impairment charges on unproved properties during the years ended December 31, 2024, 2023 and 2022.
Our operations are subject to federal, state and local laws and regulations related to environmental and natural resources protection and occupational health and safety which may expose us to significant costs and liabilities and may result in increased costs and additional operating restrictions or delays.
Our operations are subject to federal, state (provincial in Canada) and local laws and regulations related to environmental and natural resources protection and occupational health and safety, which may expose us to significant costs and liabilities and may result in increased costs and additional operating restrictions or delays.
If we fail to realize the benefits we anticipate from an acquisition, including the Merger, our results of operations and stock price may be adversely affected. We may incur losses as a result of title defects in the properties in which we invest.
If we fail to realize the benefits we anticipate from an acquisition, including the Arrangement, our results of operations and stock price may be adversely affected. We may incur losses as a result of title defects in the properties in which we invest.
For the year ended December 31, 2023, changes in our estimate of expected credit losses was not material. In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.
For the year ended December 31, 2024, changes in our estimate of expected credit losses was not material. In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.
On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and the sustained conflict and disruption in the region that has occurred since this date is expected to continue. Additionally, on October 7, 2023, Hamas, a 36 Table of Contents U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel.
On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and the sustained conflict and disruption in the region that has occurred since this date is expected to continue. Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel.
Our ability to drill and develop these locations depends on a number 44 Table of Contents of uncertainties, including crude oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.
Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.
Former Enerplus shareholders may decide not to hold the shares of our common stock that they receive in the Arrangement, and our historic stockholders may decide to reduce their investment in Chord as a result of the changes to our investment profile as a result of the Arrangement.
Former Enerplus shareholders may decide not to hold the shares of our common stock that they received in the Arrangement, and our historic stockholders may decide to reduce their investment in Chord as a result of the changes to our investment profile as a result of the Arrangement.
Risks that we face while completing our wells include, but are not limited to, the following: • the ability to fracture stimulate the planned number of stages; • the ability to run tools the entire length of the wellbore during completion operations; 39 Table of Contents • the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage; and • protecting nearby producing wells from the impact of fracture stimulation.
Risks that we face while completing our wells include, but are not limited to, the following: • the ability to fracture stimulate the planned number of stages; • the ability to run tools the entire length of the wellbore during completion operations; • the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage; and • protecting nearby producing wells from the impact of fracture stimulation.
Moreover, failure or a perception (whether or not valid) of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us and negatively impact our operations.
Moreover, failure or a perception (whether or not valid) of failure to implement ESG strategies related to corporate responsibility or achieve ESG goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us and negatively impact our operations.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including: • our estimated net proved reserves; • the level of crude oil, NGLs and natural gas we are able to produce from existing wells and new projected wells; • the prices at which our crude oil, NGLs and natural gas are sold; • the costs of developing and producing our crude oil and natural gas production; • our ability to acquire, locate and produce new reserves; • the ability and willingness of our banks to lend; and • our ability to access the equity and debt capital markets.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including: • our estimated net proved reserves; • the level of crude oil, NGLs and natural gas we are able to produce from existing wells and new projected wells; • the prices at which our crude oil, NGLs and natural gas are sold; • regulatory and third-party approvals; • the costs of developing and producing our crude oil and natural gas production; • our ability to acquire, locate and produce new reserves; • the ability and willingness of our banks to lend; and • our ability to access the equity and debt capital markets.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of: • injury or loss of life; • damage to and destruction of property, natural resources and equipment; • pollution and other environmental damage; 43 Table of Contents • regulatory investigations and penalties; • suspension of our operations; and • repair and remediation costs.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of: • injury or loss of life; • damage to and destruction of property, natural resources and equipment; • pollution and other environmental damage; • regulatory investigations and penalties; • suspension of our operations; and • repair and remediation costs.
Judgments and estimates to determine accruals related to legal, governmental and regulatory proceedings could change from period to period, and such changes could be material. Our profitability may be negatively impacted by inflation in the cost of labor, materials and services and general economic, business or industry conditions.
Judgments and estimates to determine accruals related to legal, governmental and regulatory proceedings could change from period to period, and such changes could be material. Our profitability may be negatively impacted by inflationary pressures in the cost of labor, materials and services and general economic, business or industry conditions.
Our operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations and services.
Our operations are subject to stringent federal, tribal, regional, state (provincial in Canada) and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations and services.
Moreover, as the sophistication and volume of cyber-attacks continue to increase, we may be required to expend significant additional resources to further enhance our digital security and IT infrastructure or to remediate vulnerabilities, including through the use of artificial intelligence, and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.
Moreover, as the sophistication and volume of cyber-attacks continue to increase, we may be required to expend significant additional resources to further enhance our digital security and IT infrastructure or to remediate vulnerabilities, including 56 Table of Conten ts through the use of artificial intelligence, and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.
In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities.
In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities, unless otherwise waived.
In the past, there have been periods when this discount has substantially increased due to the production of crude oil in the area increasing to a point that it temporarily 42 Table of Contents surpasses the available pipeline transportation, rail transportation and refining capacity in the area.
In the past, there have been periods when this discount has substantially increased due to the production of crude oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area.
Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG related disclosures, increasing mandatory ESG disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, reputational damage and negative impacts on our access to capital markets.
Attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary disclosures related to ESG or corporate responsibility, mandatory disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, reputational damage and negative impacts on our access to capital markets.
This growth and the anticipated benefits of the transaction may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, 35 Table of Contents strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated.
This growth and the anticipated benefits of the transaction may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated.
One or more of these factors may increase our costs of doing business 41 Table of Contents on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.
One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.
We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements 56 Table of Contents with our service providers to manage costs and availability of certain services that are utilized in our operations.
We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations.
If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our 52 Table of Contents operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
If cash generated by operations or cash available under our revolving credit facility 51 Table of Conten ts is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of crude oil, NGL and natural gas reserves. Based upon our anticipated five-year development plan and current costs, we project that we will incur capital costs of approximately $2.7 billion to develop our PUD reserves.
We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of crude oil, NGL and natural gas reserves. Based upon our anticipated five-year development plan and current costs, we project that we will incur capital costs of approximately $3.4 billion to develop our PUD reserves.
Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows.
Further, to the extent our revenues are unhedged, they could be adversely 53 Table of Conten ts affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows.
These factors include the following: • worldwide and regional economic and political conditions impacting the global supply and demand for crude oil, NGLs and natural gas; • the actions by the members of OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations; • the price and quantity of imports of foreign crude oil, NGLs and natural gas; 37 Table of Contents • political conditions in or affecting other crude oil, NGL and natural gas producing countries, including the current conflicts in and among the Middle East and conditions in South America, China, India and Russia; • the level of global exploration and production; • the level of global crude oil, NGL and natural gas inventories; • events that impact global market demand, including impacts from wars, such as the ongoing conflicts between Russia and Ukraine and between Hamas and Israel and global health epidemics and concerns such as the COVID-19 pandemic; • localized supply and demand fundamentals and regional, domestic and international transportation availability; • weather conditions and natural disasters; • domestic and foreign governmental laws, regulations and policies, including, among others, the IRA, environmental requirements and the discouragement of the use of fuels that emit GHGs and encouragement of the use of alternative energy sources; • speculation as to future commodity prices and the speculative trading of crude oil, NGL and natural gas futures contracts; • changing consumer or market preferences, stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil, NGLs and natural gas and related infrastructure; • price and availability of competitors’ supplies of crude oil, NGLs and natural gas; • technological advances affecting energy consumption; and • the price and availability of alternative fuels.
These factors include the following: • worldwide and regional economic and political conditions impacting the global supply and demand for crude oil, NGLs and natural gas; • the actions by the members of OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations; • the price and quantity of imports of foreign crude oil, NGLs and natural gas; • political conditions in or affecting other crude oil, NGL and natural gas producing countries, including the current conflicts in and among the Middle East and conditions in South America, China, India and Russia; • the level of global exploration and production; • the level of global crude oil, NGL and natural gas inventories; • events that impact global market demand, including impacts from wars, such as the ongoing conflicts between Russia and Ukraine and between Hamas and Israel and global health epidemics and concerns such as the COVID-19 pandemic; • localized supply and demand fundamentals and regional, domestic and international transportation availability; • the ability to continue to access critical transportation infrastructure such as DAPL, rail, and other regional outlets; • the ability for the United States to continue to export oil, natural gas, and NGLs; • weather conditions and natural disasters; 36 Table of Conten ts • domestic and foreign governmental laws, regulations and policies, including, among others, the IRA, environmental requirements and the discouragement of the use of fuels that emit GHGs and encouragement of the use of alternative energy sources; • speculation as to future commodity prices and the speculative trading of crude oil, NGL and natural gas futures contracts; • changing consumer or market preferences, stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil, NGLs and natural gas and related infrastructure; • price and availability of competitors’ supplies of crude oil, NGLs and natural gas; • technological advances affecting energy consumption; and • the price and availability of alternative fuels.
The Arrangement Agreement contains no restrictions on the ability of former Enerplus shareholders to sell or otherwise dispose of such shares following completion of the Arrangement.
The Arrangement Agreement contains no restrictions on the ability of former Enerplus shareholders to sell or otherwise dispose of such shares.
On February 4, 2022, the Department of the Interior issued an official opinion stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the state of North Dakota, overturning a 2020 Trump-agency decision that gave the state of North Dakota ownership.
The Department of the Interior previously issued an official opinion stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the State of North Dakota, overturning a 2020 Trump-agency decision that gave the State of North Dakota ownership.
In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations. See also “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures.
In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations. See also “Risks related to our financial position—Our exploration, development and 42 Table of Conten ts exploitation projects require substantial capital expenditures.
The development of our PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 29% of our estimated net proved reserves were classified as PUD as of December 31, 2023.
The development of our PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 30% of our estimated net proved reserves were classified as PUD as of December 31, 2024.
Such changes in interpretation 50 Table of Contents could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, such changes in interpretation could result in legal or other proceedings.
Such changes in interpretation could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, such changes in interpretation could result in legal or other proceedings.
Our obligations under our revolving credit facility are collateralized by perfected first priority liens and security interests on substantially all of our oil and gas assets, including mortgage liens on oil and gas properties having at least 85% of the reserve value as determined by reserve reports.
Our obligations under our revolving credit facility are collateralized by perfected first priority liens and security interests on substantially all of our oil and gas assets, including mortgage liens on oil and gas properties having at least 85% of the 50 Table of Conten ts reserve value as determined by reserve reports.
The synergies attributable to the Arrangement may vary from expectations. The combined company may fail to realize the anticipated benefits and synergies expected from the Arrangement, which could adversely affect the combined company’s business, financial condition and operating results.
The combined company may fail to realize the anticipated benefits and synergies expected from the Arrangement, which could adversely affect the combined company’s business, financial condition and operating results.
Please see “Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities” for a discussion of risks related to such proceedings. Risks related to our financial position Increased costs of capital could adversely affect our business.
Please see “Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities” for a discussion of risks related to such proceedings. 49 Table of Conten ts Risks related to our financial position Increased costs of capital could adversely affect our business.
If the indebtedness under our senior unsecured notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in 51 Table of Contents full.
If the indebtedness under our senior unsecured notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation and the availability and cost of credit in the European, Asian and U.S. markets contribute to economic uncertainty and diminished expectations for the global economy.
Concerns over global economic conditions, changes in tariffs and trade agreements, energy costs, geopolitical issues, inflation and the availability and cost of credit in the European, Asian and U.S. markets contribute to economic uncertainty and diminished expectations for the global economy.
Chord and Enerplus believe that the combination of the companies will provide operational and financial scale, increasing free cash flow, and enhancing the combined company’s corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the Arrangement.
Chord believes that the combination of the companies will provide operational and financial scale, increasing free cash flow, and will enhance the combined company’s corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the Arrangement.
If our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash flows in that year, but provide an offsetting credit against our regular U.S. federal income tax liability in future tax years.
If our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash flows in that year, but 52 Table of Conten ts provide an offsetting credit against our regular U.S. federal income tax liability in future tax years.
In addition, the resurgence of COVID-19 or other public health events may adversely affect our operations or the health of our workforce and the workforces of our customers and service providers by rendering employees or contractors unable to work or access the appropriate facilities for an indefinite period of time.
In addition, future public health events may adversely affect our operations or the health of our workforce and the workforces of our customers and service providers by rendering employees or contractors unable to work or access the appropriate facilities for an indefinite period of time.
The re-emergence of high levels of inflation would further raise our costs for labor, materials and services, due to a combination of factors, including: (i) global supply chain disruptions resulting in limited availability of certain materials and equipment (including drill pipe, casing and tubing), (ii) increased demand for fuel and steel, (iii) increased demand for services coupled with a limited availability of service providers and (iv) labor shortages, which would negatively impact our profitability and cash flows.
High levels of inflation could further raise our costs for labor, materials and services, due to a combination of factors, including: (i) global supply chain disruptions resulting in limited availability of certain materials and equipment (including drill pipe, casing and tubing), (ii) increased demand for fuel and steel, (iii) increased demand for services coupled with a limited availability of service providers 55 Table of Conten ts and (iv) labor shortages, which would negatively impact our profitability and cash flows.
The successful acquisition of producing properties requires an assessment of several factors, including: • recoverable reserves; • future crude oil, NGL and natural gas prices and their appropriate differentials; • development and operating costs; • potential for future drilling and production; • validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and • potential environmental and other liabilities, together with associated litigation of such matters. 49 Table of Contents The accuracy of these assessments is inherently uncertain.
The successful acquisition of producing properties requires an assessment of several factors, including: • recoverable reserves; • future crude oil, NGL and natural gas prices and their appropriate differentials; • development and operating costs; • potential for future drilling and production; • validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and • potential environmental and other liabilities, together with associated litigation of such matters.
Businesses that do not adapt to or comply with investor or stakeholder expectations and standards, which are continuing to evolve, or businesses that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition and/or stock price of such business entity could be materially and adversely affected.
Businesses that do not adapt to or comply with evolving investor or stakeholder expectations and standards, which are continuing to evolve, or businesses that are perceived to have not responded appropriately to the growing concern for issues related to ESG, corporate responsibility or in some instances anti-ESG sentiment, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition and/or stock price of such business entity could be materially and adversely affected.
A final EIS and formal decision by the Corps is expected in spring or summer 2024; however, we cannot guarantee when the Corps may ultimately complete these actions. We regularly use DAPL in addition to other outlets to market our crude oil to end markets.
A final EIS and formal decision by the Corps is expected by the end of 2025; however, we cannot guarantee when the Corps may ultimately complete these actions. We regularly use DAPL in addition to other outlets to market our crude oil to end markets.
The crude oil business environment has historically been characterized by periods when crude oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for NYMEX West Texas Intermediate (“NYMEX WTI”) crude oil.
The crude oil business environment has historically been characterized by periods when crude oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for NYMEX WTI crude oil.
Further, any such strategic alternative may not ultimately lead to increased stockholder value. We do not undertake to provide updates or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law. Increasing stakeholder and market attention to ESG matters may impact our business and ability to secure financing.
Further, any such strategic alternative may not ultimately lead to increased stockholder value. We do not undertake to provide updates or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law. 44 Table of Conten ts Stakeholder and market attention to matters related to corporate responsibility may impact our business and ability to secure financing.
As a result, if such markets become oversupplied with crude oil, NGLs and/or natural gas, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations. Variances in quality may also cause differences in the value received for our products.
As a result, if such markets become oversupplied with crude oil, NGLs and/or natural gas, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations.
As of December 31, 2023, we had an aggregate of 1,296 net acres expiring in 2024, 632 net acres expiring in 2025 and 2,087 net acres expiring in 2026 in the Williston Basin. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all.
As of December 31, 2024, we had an aggregate of 568 net acres expiring in 2025, 1,086 net acres expiring in 2026 and 186 net acres expiring in 2027 in the Williston Basin. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all.
As part of our ongoing effort to enhance our ESG practices, our Board of Directors has established the Environmental, Social and Governance Committee, which is charged with overseeing our ESG policies. Committee members are expected to review the implementation and effectiveness of our ESG programs and policies.
As part of our ongoing effort to enhance our ESG practices related to corporate responsibility, our Board of Directors has established the Safety and Sustainability Committee, which is charged with overseeing our ESG policies related to corporate responsibility. Committee members are expected to review the implementation and effectiveness of our ESG programs and policies.
The market price of our common stock may fluctuate significantly following completion of the Arrangement and holders of our common stock could lose some or all of the value of their investment. If the Arrangement is consummated, we will issue shares of our common stock to former Enerplus shareholders.
The market price of our common stock may fluctuate significantly following completion of the Arrangement and holders of our common stock could lose some or all of the value of their investment. Upon closing of the Arrangement, we issued shares of our common stock to former Enerplus shareholders.
Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. At December 31, 2023, we had commodity derivatives in place with nine counterparties and a total net commodity derivative liability of $3.6 million.
Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. At December 31, 2024, we had commodity derivatives in place with 15 counterparties and a total net commodity derivative asset of $16.5 million.
There can be no assurance that our personnel will not be impacted by these pandemic diseases or ultimately lead to a reduction in our workforce productivity or increased medical costs or insurance premiums as a result of these health risks.
Our personnel could be impacted by these pandemic diseases or ultimately lead to a reduction in our workforce productivity or increased medical costs or insurance premiums as a result of these health risks.
Disruptions to the broader economy and financial markets, including the Federal Reserve’s actions with respect to interest rates and the timing of any anticipated decrease in rates, as well as the potential for a U.S. government shutdown relating to budget deadlines, may also reduce our ability to access capital or result in such capital being available on less favorable terms.
Disruptions to the broader economy and financial markets, including the Federal Reserve’s actions with respect to interest rates and the timing of any anticipated decrease in rates following the September 2024 rate reduction, as well as the potential for a U.S. government shutdown (such as the near shutdown in December 2024 related to debt ceiling legislation), may also reduce our ability to access capital or result in such capital being available on less favorable terms.
Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these environmental and occupational health and safety matters.
Business—Regulation—Environmental and occupational health and safety 43 Table of Conten ts regulation” for more discussion on these environmental and occupational health and safety matters.
The U.S. economy experienced significant increases in inflation rates beginning in 2021 from, among other things, supply chain disruptions and governmental stimulus or fiscal policies adopted in response to the COVID-19 pandemic. Although U.S. inflation rates have shown signs of moderating, we cannot predict any future trends in the rate of inflation.
The U.S. economy has experienced significant inflation since 2021 stemming from, among other things, supply chain disruptions, wage increases associated with a low U.S. unemployment rate and governmental stimulus or fiscal policies adopted in response to the COVID-19 pandemic. Although U.S. inflation rates have moderated slightly, we cannot predict any future trends in the rate of inflation.
The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock. As of December 31, 2023, we had 3,232,654 outstanding warrants to purchase shares of our common stock and 839,039 outstanding stock–based awards.
The exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock. As of December 31, 2024, we had 888,742 outstanding warrants to purchase shares of our common stock and 594,520 outstanding stock–based awards.
Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
Variances in quality may also cause differences in the value received for our products. 39 Table of Conten ts Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
In addition, as of December 31, 2023, a total of 2,201,501 shares of common stock were available for future issuance under our equity incentive plans, including 1,002,681 shares of common stock reserved for future issuance under the Oasis 2020 Long Term Incentive Plan (the “2020 LTIP”) and 1,198,820 shares of common stock reserved for future issuance under the Whiting 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which we assumed in connection with the Merger.
In addition, as of December 31, 2024, a total of 2,801,654 shares of common stock were available for future issuance under our equity incentive plans, including 1,613,057 shares of common stock reserved for future issuance under the Chord Energy Corporation Long Term Incentive Plan (the “2020 LTIP”) and 1,188,597 shares of common stock reserved for future issuance under the Whiting 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which we assumed in connection with the Merger.
Should we fail to comply with all applicable statutes, rules, regulations and orders of FERC, the CFTC or the FTC, we could be subject to substantial penalties and fines. 45 Table of Contents We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships and other strategic alternatives that may enhance stockholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.
We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships and other strategic alternatives that may enhance stockholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.
To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our operations.
To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
Supreme Court in September 2021; however, the appeal was rejected on February 22, 2022. The Corps released its draft EIS on September 8, 2023, which it made available for public comments. The Corps initially established a deadline of November 13, 2023 for public comments and, on October 31, 2023, the deadline for public comments was extended to December 13, 2023.
Supreme Court in September 2021; however, the appeal was rejected on February 22, 2022. The Corps released its draft EIS on September 8, 2023, which it made available for public comments.
Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us. Risks related to the Arrangement The synergies attributable to the Arrangement may vary from expectations.
If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed, and we could fail to meet our financial reporting obligations. Item 1B. Unresolved Staff Comments None.
If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed, and we could fail to meet our financial reporting obligations. We face risks associated with disruptive technologies, innovation and competition, including artificial intelligence.
We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.
Moreover, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

16 edited+2 added−1 removed12 unchanged
Biggest changeWe have integrated the above cybersecurity risk management processes into our overall ERM program. Cybersecurity risks are understood to be significant business risks, and as such, are considered an important component of our enterprise-wide risk management approach.
Biggest changeCybersecurity risks are understood to be significant business risks, and as such, are considered an important component of our enterprise-wide risk management approach. 58 Table of Conten ts As of the date of this report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect us.
We have endeavored to implement policies, standards and technical controls based on the National Institute of Standards and Technology (NIST) framework with the aim of protecting our networks and applications.
We have endeavored to implement policies, standards and technical controls based on the National Institute of Standards and Technology framework with the aim of protecting our networks and applications.
We have implemented a requirement that all employees and contractors participate in information security training at least quarterly and have deployed internal phishing campaigns to measure the effectiveness of the training program. 58 Table of Contents • Access Controls: We provide users with access consistent with the principle of least privilege, which requires that users be given no more access than necessary to complete their job functions.
We have implemented a requirement that all employees and contractors participate in information security training at least quarterly and have deployed internal phishing campaigns to measure the effectiveness of the training program. • Access Controls: We provide users with access consistent with the principle of least privilege, which requires that users be given no more access than necessary to complete their job functions.
The Cybersecurity Council also engages periodically with external and internal auditors, as well as the Cybersecurity and Infrastructure Security Agency, 59 Table of Contents the American Exploration and Production Council and the Federal Bureau of Investigation to stay informed on cybersecurity risk management. Item 2. Properties The information required by Item 2. is contained in Item 1. Business. Item 3.
The Cybersecurity Council also engages periodically with external and internal auditors, as well as the Cybersecurity and Infrastructure Security Agency, the American Exploration and Production Council and the Federal Bureau of Investigation to stay informed on cybersecurity risk management. Item 2. Properties The information required by Item 2. is contained in Item 1. Business. Item 3.
Our cybersecurity incident response plan provides processes for escalation if there is an emerging cybersecurity incident, including timely notice to our Board of Directors if the incident is deemed material or as otherwise appropriate. We have developed a Cybersecurity Council that reports directly to our Chief Financial Officer.
Our cybersecurity incident response plan provides processes for escalation if there is an emerging cybersecurity incident, including timely notice to our Board of Directors if the incident is deemed material or as otherwise appropriate. We have developed a Cybersecurity Council that reports directly to our Chief Strategy Officer & Chief Commercial Officer.
Additionally, on an annual basis, the Managing Director, Information Technology, reviews with the Audit and Reserves Committee the results from tests of key cybersecurity risks and the subsequent steps taken to mitigate such risks. Management is responsible for assessing and managing cybersecurity risk.
Additionally, on an annual basis, the Vice President, Information Technology, reviews with the Audit and Reserves Committee the results from tests of key cybersecurity risks and the subsequent steps taken to mitigate such risks. Management is responsible for assessing and managing cybersecurity risk.
Item 1C. Cybersecurity Cybersecurity Risk Management and Strategy We maintain a cybersecurity program overseen by the Managing Director, Information Technology that uses a risk-based methodology to support the security, confidentiality, integrity and availability of our information. The security of our field infrastructure and corporate network is a priority for our business.
Item 1C. Cybersecurity Cybersecurity Risk Management and Strategy We maintain a cybersecurity program overseen by the Vice President, Information Technology that uses a risk-based methodology to support the security, confidentiality, integrity and availability of our information. The security of our field infrastructure and corporate network is a priority for our business.
The Managing Director, Information Technology, works closely with other management positions, including our Chief Financial Officer and our General Counsel, to help us maintain an effective incident response communication plan and understanding of our cybersecurity risk management processes.
The Vice President, Information Technology, works closely with other management positions, including our Chief Financial Officer and our General Counsel, to help us maintain an effective incident response communication plan and understanding of our cybersecurity risk management processes.
Legal Proceedings See “Part II, Item 8. Financial Statements and Supplementary Data—Note 21—Commitments and Contingencies,” which is incorporated herein by reference, for a discussion of material legal proceedings. Item 4. Mine Safety Disclosures Not applicable. 60 Table of Contents PART II
Legal Proceedings See “Part II, Item 8. Financial Statements and Supplementary Data—Note 21—Commitments and Contingencies,” which is incorporated herein by reference, for a discussion of material legal proceedings. Item 4. Mine Safety Disclosures Not applicable. 59 Table of Conten ts PART II
Specifically, the Managing Director, Information Technology, is responsible for overseeing the prevention, mitigation, detection and remediation of cybersecurity incidents. Our Managing Director, Information Technology, has over 16 years of experience, including prior industry experience consulting on various IT matters and developing and testing IT general controls and cybersecurity risk management programs.
Specifically, the Vice President, Information Technology, is responsible for overseeing the prevention, mitigation, detection and remediation of cybersecurity incidents. Our Vice President, Information Technology, has over 17 years of experience, including prior industry experience consulting on various IT matters and developing and testing IT general controls and cybersecurity risk management programs.
The Cybersecurity Council is led by the Managing Director, Information Technology, and is comprised of select members of the IT team. The Cybersecurity Council meets monthly to review current cybersecurity threats as well as our potential exposure.
The Cybersecurity Council is led by the Vice President, Information Technology, and is comprised of select members of the IT team with an average of nearly 20 years of cybersecurity experience. The Cybersecurity Council meets monthly to review current cybersecurity threats as well as our potential exposure.
The Board of Directors delegates oversight of risk, including reviews of cybersecurity and data protection and compliance with cybersecurity policies, to the Audit and Reserves Committee. The Managing Director, Information Technology, provides updates to the Audit and Reserves Committee on data protection and cybersecurity matters on at least a semi-annual basis, or as requested or deemed necessary.
The Vice President, Information Technology, provides updates to the Audit and Reserves Committee on data protection and cybersecurity matters on at least a semi-annual basis, or as requested or deemed necessary.
These risks may include, among other things, operational risks, intellectual property theft, fraud, extortion, harm to employees, customers or business partners, violation of privacy or security laws and other litigation and legal risk and reputational risks.
Our cybersecurity program utilizes a combination of automated tools, manual processes and third-party assessments with the goal of identifying and assessing potential cybersecurity risks. 57 Table of Conten ts These risks may include, among other things, operational risks, intellectual property theft, fraud, extortion, harm to employees, customers or business partners, violation of privacy or security laws and other litigation and legal risk and reputational risks.
Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our information technology (“IT”) systems could have significant consequences for the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible.
However, we acknowledge that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our IT systems could have significant consequences for the business.
We recognize the importance of assessing, identifying and managing material risks associated with cybersecurity threats. Our cybersecurity program utilizes a combination of automated tools, manual processes and third-party assessments with the goal of identifying and assessing potential cybersecurity risks.
We recognize the importance of assessing, identifying and managing material risks associated with cybersecurity threats.
See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our IT systems. Cybersecurity Governance and Oversight The Board of Directors has primary oversight of risks from cybersecurity threats.
While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our IT systems.
Removed
As of the date of this report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect us. However, we acknowledge that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents remains.
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We have integrated the above cybersecurity risk management processes into our overall ERM program.
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Cybersecurity Governance and Oversight The Board of Directors has primary oversight of risks from cybersecurity threats. The Board of Directors delegates oversight of risk, including reviews of cybersecurity and data protection and compliance with cybersecurity policies, to the Audit and Reserves Committee.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

10 edited+2 added−0 removed2 unchanged
Biggest changeAs of February 16, 2024, the number of record holders of our common stock was 285. Based on inquiry, management believes that the number of beneficial owners of our common stock as of February 16, 2024 was approximately 109,816. On February 16, 2024, the last sale price of our common stock, as reported on the Nasdaq, was $163.71 per share.
Biggest changeManagement’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends” for more information. Holders. As of February 14, 2025, the number of record holders of our common stock was 299. Based on inquiry, management believes that the number of beneficial owners of our common stock as of February 14, 2025 was approximately 162,227.
The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) for the period of November 20, 2020 (the date we emerged from bankruptcy and our common stock commenced trading) through December 31, 2023.
The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) for the period of November 20, 2020 (the date we emerged from bankruptcy and our common stock commenced trading) through December 31, 2024.
The comparison was prepared based upon the following assumptions: 1. $100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on November 20, 2020 at the closing price on such date; and 2. Dividends were reinvested. Item 6. [Reserved] 62 Table of Contents
The comparison was prepared based upon the following assumptions: 1. $100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on November 20, 2020 at the closing price on such date; and 2. Dividends were reinvested.
Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. See “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends” for more information. Holders.
Business—Business Strategy—Maximize returns” for additional information on the return of capital plan. Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. See “Part II. Item 7.
In 2023, we paid an aggregate amount of cash dividends of $11.88 per share of common stock, including base dividends of $5.00 per share of common stock and variable dividends of $6.88 per share of common stock. On February 21, 2024, we declared a base-plus-variable dividend of $3.25 per share of common stock.
In 2024, we paid an aggregate amount of cash dividends of $10.15 per share of common stock, including base dividends of $5.00 per share of common stock and variable dividends of $5.15 per share of common stock. On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock.
(2) During the fourth quarter of 2023, we repurchased 510,471 shares of common stock at a weighted average price of $162.20 per common share for a total cost of $82.8 million, excluding accrued excise tax of $0.2 million, under our publicly announced share repurchase program.
(2) During the fourth quarter of 2024, we repurchased 1,604,011 shares of common stock at a weighted average price of $127.82 per common share for a total cost of $205.0 million, under our publicly announced share repurchase program.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2023. Securities Authorized for Issuance Under Equity Compensation Plans. Information concerning securities authorized for issuance under our equity compensation plans will be disclosed in our definitive proxy statement for our 2024 Annual Meeting of Stockholders. Issuer Purchases of Equity Securities.
Information concerning securities authorized for issuance under our equity compensation plans will be disclosed in our definitive proxy statement for our 2025 Annual Meeting of Stockholders. Issuer Purchases of Equity Securities.
The following table contains information about our acquisition of equity securities during the three months ended December 31, 2023: Period Total Number of Shares Exchanged (1)(2) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)(3) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2) October 1 – October 31, 2023 117,632 $ 164.17 117,632 $ 746,489,046 November 1 – November 30, 2023 237,162 161.94 232,359 708,864,811 December 1 – December 31, 2023 160,480 161.15 160,480 683,003,178 ___________________ (1) During the fourth quarter of 2023, we withheld 4,803 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.
The following table contains information about our acquisition of equity securities during the three months ended December 31, 2024: Period Total Number of Shares Exchanged (1)(2) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)(3) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2) October 1 – October 31, 2024 366,961 $ 129.90 366,961 $ 397,561,163 November 1 – November 30, 2024 811,848 129.81 810,456 644,792,257 December 1 – December 31, 2024 472,518 121.45 426,594 592,635,902 ___________________ (1) During the fourth quarter of 2024, we withheld 47,316 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.
(3) On October 25, 2023, our Board of Directors authorized a new share repurchase program of up to $750 million of our common stock, which resulted in the expiration of the $300 million share repurchase program authorized in August 2022. 61 Table of Contents Stock Performance Graph.
(3) In October 2023, our Board of Directors had previously authorized a share repurchase program of up to $750 million of our common stock. In October 2024, our Board of Directors authorized a new share repurchase program covering up to $750 million of common stock, which replaced the existing $750 million share repurchase program.
These dividends will be payable on March 19, 2024 to stockholders of record as of March 5, 2024. In October 2023, we introduced a new $750 million share repurchase program. See “Part I. Item 1. Business—Business Strategy—Maximize returns” for additional information on the return of capital plan.
The dividend will be payable on March 26, 2025 to stockholders of record as of March 11, 2025. In October 2024, the Board of Directors authorized a new $750 million share repurchase program, which replaced the $750 million share repurchase program the Board of Directors had previously authorized in October 2023. See “Part I. Item 1.
Added
On February 14, 2025, the last sale price of our common stock, as reported on the Nasdaq, was $110.93 per share. Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2024. Securities Authorized for Issuance Under Equity Compensation Plans.
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The amount presented for the period ending October 31, 2024 was calculated using the remaining authorization under the previously authorized share repurchase program, and the amounts presented for the periods ending November 30, 2024 and December 31, 2024 were calculated using the authorization under the new share repurchase program. 60 Table of Conten ts Stock Performance Graph.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

103 edited+54 added−38 removed36 unchanged
Biggest changeFor the year ended December 31, 2022, net cash used in financing activities of $823.1 million was primarily attributable to dividends paid to stockholders of $654.7 million, payments made to repurchase common stock of $152.0 million and payments for income tax withholdings on vested equity-based compensation awards of $41.8 million, partially offset by proceeds from the exercise of outstanding warrants of $19.8 million.
Biggest changeNet cash used in investing activities for the year ended December 31, 2023 of $1.4 billion was primarily attributable to $905.7 million of capital expenditures, $361.6 million paid for the 2023 acquisition of acreage in the Williston Basin and $268.9 million associated with the settlement of derivative contracts, partially offset by $54.4 million of proceeds from divestitures and $40.6 million of proceeds from the sale of Energy Transfer units. 71 Table of Conten ts Cash flows used in financing activities For the year ended December 31, 2024, net cash used in financing activities of $624.5 million was primarily attributable to dividends paid to stockholders of $529.9 million, payments made to repurchase common stock of $444.2 million, payments for income tax withholdings on vested equity-based compensation awards of $63.4 million and repayments on the Enerplus Senior Notes of $63.0 million.
While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.
While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties or goodwill is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties and goodwill as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.
Revenues and expenses from crude oil and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty.
Revenues and expenses from crude oil, NGL and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty.
Overview Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, natural gas liquids (“NGL”) and natural gas in the Williston Basin.
Overview Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, natural gas liquids (“NGL”) and natural gas primarily in the Williston Basin.
The fair value of the oil and gas properties was calculated by a third party valuation expert using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgement and assumptions, including future production volumes based upon estimates of reserves prepared by our reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate.
The fair value of the oil and gas properties was calculated by a third party valuation expert using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by our reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate.
Our Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.
The Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter.
We were in compliance with the financial covenants in the Credit Facility at December 31, 2023. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information. Senior unsecured notes. As of December 31, 2023, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026.
We were in compliance with the financial covenants in the Credit Facility at December 31, 2024. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information. Senior unsecured notes. As of December 31, 2024, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026.
Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, changes to the Company’s anticipated five-year development plan, changes to commodity prices, cost changes, technological advances, new geological or geophysical data or other economic factors.
Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, changes to our anticipated five-year development plan, changes to commodity prices, cost changes, technological advances, new geological or geophysical data or other economic factors.
These gathering systems, which originate at the wellhead, 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, 2023, substantially all of our gross operated crude oil production was connected to gathering systems.
These gathering systems, which originate at the wellhead, 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, 2024, substantially all of our gross operated crude oil production was connected to gathering systems.
Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which could result in lower commodity prices due to reduced demand for crude oil, NGLs and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information).
Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGLs and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information).
See “Part I, Item 1A. Risk Factors—If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties” for additional information.
See “Part I, Item 1A. Risk Factors—If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties and goodwill” for additional information.
For the year ended December 31, 2023, we recorded a $21.3 million gain related to our investment in Energy Transfer primarily related to a realized gain of $10.8 million for cash distributions received and an unrealized gain of $8.4 million as a result of an increase in the fair value of the investment during the year. Other income, net.
During the year ended December 31, 2023, we recorded a $21.3 million gain related to our investment in Energy Transfer, primarily related to a realized gain of $10.8 million for cash distributions received and an unrealized gain of $8.4 million as a result of an increase in the fair value of the investment during the year.
The following are the accounting policies, estimates and judgments used in preparation of our consolidated financial statements which we consider most critical: 73 Table of Contents Method of accounting for oil and gas properties GAAP provides two alternative methods to account for oil and gas properties known as the successful efforts method and the full cost method.
The following are the accounting policies, estimates and judgments used in preparation of our consolidated financial statements which we consider most critical: Method of accounting for oil and gas properties GAAP provides two alternative methods to account for oil and gas properties known as the successful efforts method and the full cost method.
Prices for 63 Table of Contents crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas.
Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas.
During the year ended December 31, 2023, we repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise tax of $0.4 million, under both the August 2022 and October 2023 share repurchase programs.
During the year ended December 31, 2023, the Company repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise taxes of $0.4 million under both the October 2023 and August 2022 share repurchase programs.
We account for oil and gas properties under the successful efforts method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 2—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information. Estimated quantities of reserves Our independent reserve engineers prepare our estimates of crude oil, NGL and natural gas reserves.
We account for oil and gas properties under the successful efforts method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 2—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information. 73 Table of Conten ts Estimated quantities of reserves Our independent reserve engineers prepare our estimates of crude oil, NGL and natural gas reserves.
Deferred taxes are recorded for any differences between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Our capital plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control.
The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Our capital plan may further be adjusted as business conditions warrant. 72 Table of Conten ts The amount, timing and allocation of capital expenditures is largely discretionary and within our control.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 28, 2023.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 26, 2024.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 28, 2023.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 26, 2024.
Share Repurchase Program In October 2023, our Board of Directors authorized a new share repurchase program covering up to $750 million of our common stock, which replaced the existing $300 million share repurchase program that was authorized in August 2022.
Share Repurchase Program In October 2024, our Board of Directors authorized a new share repurchase program covering up to $750 million of our common stock, which replaced the existing $750 million share repurchase program that was authorized in October 2023.
We cannot reasonably predict future commodity prices; however, assuming all other factors are held constant, a 10% decrease in the SEC Price for crude oil and natural gas would decrease our estimated net proved reserves by 21.7 MMBoe and decrease the PV-10 by $1.7 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 17.6 MMBoe and increase the PV-10 by $1.7 billion.
We cannot reasonably predict future commodity prices; however, assuming all other factors are held constant, a 10% decrease in the SEC Price for crude oil and natural gas would decrease our estimated net proved reserves by 26.7 MMBoe and decrease the PV-10 by $2.0 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 21.4 MMBoe and increase the PV-10 by $2.0 billion.
Commodity prices decreased during 2023 due to a combination of factors, including slowing demand growth as a result of decreased global economic activity levels and higher levels of production from domestic oil and gas producers in the United States and other non-OPEC+ countries.
Commodity prices remained low throughout 2024 due to a combination of factors, including slowing demand growth as a result of decreased global economic activity levels and higher levels of production from domestic oil and gas producers in the United States and other non-OPEC+ countries.
For discussion related to changes in financial condition and results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to “Part II, Item 7.
For a discussion of the changes related to the financial condition and results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II, Item 7.
See “Item 1. Business—Exploration and Production Operations—Estimated net proved reserves” for additional information on the revisions to our estimated net proved reserves. Our estimated net proved reserves and PV-10 were determined using the SEC Price. The SEC Price was $78.22 per Bbl for crude oil and $2.64 per MMBtu for natural gas for the year ended December 31, 2023.
See “Item 1. Business—Exploration and Production Operations—Estimated net proved reserves” for additional information on the revisions to our estimated net proved reserves. Our estimated net proved reserves and PV-10 were determined using the SEC Price. The SEC Price was $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas for the year ended December 31, 2024.
Changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $91.9 million and $46.6 million during the year ended December 31, 2023 and 2022, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.
During the years ended December 31, 2024 and 2023, changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $34.1 million and $91.9 million, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.
The net gain of $56.4 million on commodity derivative contracts included an unrealized gain of $313.1 million related to the change in fair value of our commodity derivative contracts, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts.
The net gain of $56.4 million on commodity derivative contracts included an unrealized gain of $313.1 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts.
At December 31, 2023, we had dividends payable of $37.6 million related to dividend equivalent rights accrued on equity-based compensation awards, including $23.8 million that was recorded under accrued liabilities and $13.8 million that was recorded under other liabilities on the Consolidated Balance Sheet.
At December 31, 2024, we had dividends payable of $16.7 million related to dividend equivalent rights accrued on equity-based compensation awards, including $16.1 million that was recorded under accrued liabilities and $0.6 million that was recorded under other liabilities on the Consolidated Balance Sheet.
Under the terms of the Arrangement Agreement, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at closing.
Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock, par value $0.01 per share, and $1.84 per share in cash in exchange for each share of Enerplus they owned at closing.
For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $991.1 million as of December 31, 2023, and excludes current hedge assets, which were $37.4 million as of December 31, 2023.
For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $1.0 billion as of December 31, 2024, and excludes current hedge assets, which were $35.9 million as of December 31, 2024.
The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. See “Item 8.
Critical accounting policies and estimates Our consolidated financial statements have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. See “Item 8.
Dividends During the year ended December 31, 2023, we declared base-plus-variable cash dividends of $11.88 per share of common stock, or $508.6 million in aggregate. On February 21, 2024, we declared a base-plus-variable dividend of $3.25 per share of common stock. The dividends will be payable on March 19, 2024 to shareholders of record as of March 5, 2024.
Dividends During the year ended December 31, 2024, we declared base-plus-variable cash dividends of $10.15 per share of common stock, or $507.6 million in aggregate. On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to shareholders of record as of March 11, 2025.
Business—Exploration and Production Operations—Marketing.” Our average net realized crude oil prices and average price differentials are shown in the tables below for the periods presented: 2023 Year ended December 31, 2023 Q1 Q2 Q3 Q4 Average Realized Crude Oil Prices ($/Bbl) (1) $ 76.04 $ 73.89 $ 83.22 $ 77.88 $ 77.85 Average Price Differential ($/Bbl) (2) $ — $ 0.14 $ 0.69 $ (0.52) $ 0.07 Average Price Differential Percentage (2) — % 0.2 % 0.8 % (0.7) % 0.1 % 2022 Year ended December 31, 2022 Q1 Q2 Q3 Q4 Average Realized Crude Oil Prices ($/Bbl) (1) $ 95.34 $ 111.79 $ 93.13 $ 83.74 $ 92.98 Average Price Differential ($/Bbl) (2) $ 1.22 $ 2.82 $ 1.63 $ 0.99 $ 1.52 Average Price Differential Percentage (2) 1.3 % 2.5 % 1.8 % 1.2 % 1.6 % __________________ (1) Realized crude oil prices do not include the effect of derivative contract settlements.
Business—Exploration and Production Operations—Marketing.” Our average net realized crude oil prices and average price differentials are shown in the tables below for the periods presented: 2024 Year Ended December 31, 2024 Q1 Q2 Q3 Q4 Average realized crude oil prices ($/Bbl) (1) $ 75.32 $ 78.89 $ 73.51 $ 68.79 $ 73.67 Average price differential ($/Bbl) (2) $ (1.71) $ (1.41) $ (1.51) $ (1.49) $ (1.52) Average price differential percentage (2) (2.3) % (1.8) % (2.1) % (2.2) % (2.1) % 2023 Year Ended December 31, 2023 Q1 Q2 Q3 Q4 Average realized crude oil prices ($/Bbl) (1) $ 76.04 $ 73.89 $ 83.22 $ 77.88 $ 77.85 Average price differential ($/Bbl) (2) $ — $ 0.14 $ 0.69 $ (0.52) $ 0.07 Average price differential percentage (2) — % 0.2 % 0.8 % (0.7) % 0.1 % __________________ (1) Realized crude oil prices do not include the effect of derivative contract settlements.
Impairment expenses for the year ended December 31, 2023 included $17.5 million associated with the write-down of the right-of-use asset for our Denver office lease, $5.8 million associated with a lower of average cost or net realizable value write down of oil-in-tank inventory and $5.6 million to adjust the carrying value of certain non-core properties held for sale to their estimated fair value less costs to sell.
During the year ended December 31, 2023, exploration and impairment expenses totaled $35.3 million, which was primarily due to impairment expenses of $29.0 million, including $17.5 million associated with the write-down of our Denver office lease acquired in 2022, $5.8 million associated with a lower of cost or net realizable value write-down of oil-in-tank inventory and $5.6 million to adjust the carrying value of certain non-core properties held for sale to their estimated fair value less costs to sell.
The factors used to determine the undiscounted future cash flows and fair value require significant judgment and assumptions, including future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis 74 Table of Contents differentials) and estimates of future operating and development costs.
The factors used to determine the undiscounted future cash flows and fair value require significant judgment and assumptions, including future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials) and estimates of future operating and development costs. These factors are generally consistent with those used in the planning and budgeting processes.
Cash flows used in financing activities For the year ended December 31, 2023, net cash used in financing activities of $664.7 million was primarily attributable to dividends paid to stockholders of $500.3 million and payments made to repurchase common stock of $239.3 million, partially offset by proceeds from the exercise of outstanding warrants of $91.3 million.
Net cash used in financing activities for the year ended December 31, 2023 of $664.7 million was primarily attributable to dividends paid to shareholders of $500.3 million, payments to repurchase our common stock of $239.3 million and payments for income tax withholdings on vested equity-based compensation awards of $14.6 million, partially offset by proceeds from the exercise of outstanding warrants of $91.3 million.
For the year ended December 31, 2023, we recognized $10.0 million of other income, net as compared to $2.9 million for the year ended December 31, 2022. The $7.1 million increase was primarily due to an increase in interest income year-over-year associated with higher balances in our money market accounts. Income tax (expense) benefit.
For the year ended December 31, 2024, we recognized $5.0 million of other income, net as compared to $10.0 million for the year ended December 31, 2023. The $5.0 million decrease was primarily due to a decrease in interest income year-over-year associated with lower balances in our money market accounts. Income tax expense.
Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract.
Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements were $579.2 million as of December 31, 2024.
Although we do not currently have a business relationship with the failed banking institutions and are unable to predict future interest rates, these disruptions to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity.
Although we are unable to predict future interest rates, this disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity.
For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Merger The Merger was accounted for as a business combination under the acquisition method of accounting.
For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. 76 Table of Conten ts
Recent Developments Pending Acquisition On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), pursuant to which, among other things, we have agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”), subject to satisfaction of certain closing conditions.
Recent Developments Enerplus Arrangement On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement ”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, we agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”).
In an effort to reduce inflationary pressures that emerged in the broader economy, central banks began to aggressively raise interest rates in 2022 and continued to raise interest rates during a portion of 2023.
In an effort to reduce inflationary pressures that emerged in the broader economy, central banks began to aggressively raise interest rates in 2022. After peaking in 2023, interest rates began to trend downward during 2024.
Senior secured revolving line of credit. We have a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.5 billion and elected commitments of $1.0 billion that is due July 1, 2027.
As of December 31, 2024, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $3.0 billion and an aggregate amount of elected commitments of $1.5 billion that is due July 1, 2027.
See “Results of Operations” above for additional information on the impact of volumes and prices on revenues and for additional information on increases and decreases in operating expenses between periods. Working capital. Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements.
See “Results of Operations” above for additional information. Working capital. Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements.
Purchased oil and gas expenses increased $89.4 million to $761.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022 primarily due to an increase in crude oil volumes purchased, offset by lower crude oil prices year-over-year. Production taxes.
Purchased oil and gas expenses. Purchased oil and gas expenses increased $651.0 million to $1.4 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023 primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year. Production taxes.
The uncertainties resulting from the potential economic outcomes of monetary policy decisions of central banks, coupled with the geopolitical risks associated with the continued military conflicts between Russia and Ukraine and between Hamas and Israel, make it difficult to predict future impacts to commodity prices.
The uncertainties 62 Table of Conten ts resulting from the potential economic outcomes of monetary policy decisions of central banks as well as tariff and trade policy decisions of the U.S. or other governments, coupled with the geopolitical risks associated with the continued military conflicts in the Red Sea Region and the wars between Russia and Ukraine and Hamas and Israel, make it difficult to predict future impacts to commodity prices.
There were no borrowings outstanding under the Credit Facility (defined below) as of December 31, 2023; however, on a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
On a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
Our planned 2024 E&P capital expenditures are expected to be approximately $905 million to $945 million. We expect to run four operated rigs during the majority of 2024 and plan to TIL approximately 103 to 113 gross operated wells with an average working interest of approximately 75%.
Our planned 2025 E&P capital expenditures are expected to be approximately $1.3 billion to $1.5 billion. We expect to run four to five operated rigs during the majority of 2025 and plan to TIL approximately 130 to 150 gross operated wells with an average working interest of approximately 78%.
Any excess of the purchase price consideration over the estimated acquisition date fair value of assets acquired and liabilities assumed is recorded as goodwill, while any deficit of the purchase price consideration under the estimated acquisition date fair value of assets acquired and liabilities assumed is recorded in current earnings as a gain on bargain purchase.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase.
These factors are generally consistent with those used in the planning and budgeting processes. Future production is based upon a combination of inputs and assumptions, including the timing and pace of our development plans, as well as estimates of reserve quantities.
Future production is based upon a combination of inputs and assumptions, including the timing and pace of our development plans, as well as estimates of reserve quantities.
These dividends will be payable on March 19, 2024 to stockholders of record as of March 5, 2024. 65 Table of Contents Revenues Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production.
The dividend will be payable on March 26, 2025 to stockholders of record as of March 11, 2025. 64 Table of Conten ts Revenues Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production.
Volumes (Bbl) Weighted Average Prices Commodity Settlement Period Derivative Instrument Total Daily Sub-Floor Floor Ceiling Crude oil 2024 Two-way collars 825,000 3,000 $ 66.65 $ 81.94 Crude oil 2025 Three-way collars 1,095,000 3,000 $ 55.00 $ 70.00 $ 81.62 Crude oil 2026 Three-way collars 270,000 3,000 $ 50.00 $ 65.00 $ 83.70 Material cash requirements Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases.
The following table summarizes these commodity derivative contracts: Volumes Weighted Average Prices Commodity Settlement Period Derivative Instrument Total Units Fixed-price swaps Sub-floor Floor Ceiling Crude oil 2025 Fixed-price swaps 2,015,000 Bbls $ 70.45 Crude oil 2025 Two-way collars 91,000 Bbls $ 65.00 $ 77.35 Crude oil 2026 Three-way collars 730,000 Bbls $ 50.00 $ 65.00 $ 73.93 Crude oil 2026 Fixed-price swaps 180,000 Bbls $ 68.67 Crude oil 2027 Three-way collars 182,000 Bbls $ 50.00 $ 65.00 $ 74.15 Natural gas 2025 Fixed-price swaps 15,640,000 MMBtu $ 4.12 Natural gas 2026 Fixed-price swaps 8,220,000 MMBtu $ 3.94 Natural gas 2026 Two-way collars 5,430,000 MMBtu $ 3.83 $ 4.26 Material cash requirements Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases.
These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. Our revenues for the year ended December 31, 2024 increased due to the Arrangement, which expanded our operations primarily in the Williston Basin.
In addition, the Federal Reserve’s increases in interest rates and the potential for such rates to increase further or to remain elevated for an extended period of time have created additional economic uncertainty.
Federal Reserve recently decreased interest rates, however the potential for such rates to decrease further or to increase or remain elevated for an extended period of time creates additional economic uncertainty.
As of December 31, 2023, we completed these Non-core Asset Sales and received total net cash proceeds (including purchase price adjustments) of $39.1 million, subject to customary post-closing adjustments. In addition, during the year ended December 31, 2023, we completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.1 million.
In addition, during the year ended December 31, 2024, we completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds (subject to purchase price adjustments) of $25.0 million.
We recorded a $63.2 million net gain on derivative instruments for the year ended December 31, 2023, which was primarily comprised of a net gain of $56.4 million associated with our contracts to manage commodity price risk and a net gain of $6.8 million associated with an embedded derivative related to the contingent consideration included within the 2021 agreement to sell our upstream assets in the Permian Basin.
During the year ended December 31, 2023, we recorded a $63.2 million net gain on derivative instruments, which was primarily comprised of a net gain of $56.4 million associated with our commodity derivative contracts and a net gain of $6.8 million associated with a contract that includes contingent consideration.
Our income tax expense was recorded at 23.5% of pre-tax income from continuing operations for the year ended December 31, 2023, and our income tax benefit was recorded at (3.4)% of pre-tax income from continuing operations for the year ended December 31, 2022.
Our effective tax rate for the year ended December 31, 2024 was materially unchanged from our effective tax rate for the year ended December 31, 2023. Our income tax expense was recorded at 23.7% and 23.5% of pre-tax income for the year ended December 31, 2024 and December 31, 2023, respectively.
There were no discontinued operations for the year ended December 31, 2023. 69 Table of Contents Liquidity and Capital Resources As of December 31, 2023, we had $1.3 billion of liquidity available, including $318.0 million in cash and cash equivalents and $991.1 million of aggregate unused borrowing capacity available under our Credit Facility (defined below).
Liquidity and Capital Resources As of December 31, 2024, we had $1.1 billion of liquidity available, including $37.0 million in cash and cash equivalents and $1.0 billion of aggregate unused borrowing base capacity available under our Credit Facility (defined below).
Interest on the senior unsecured notes is payable semi-annually on June 1 and December 1 of each year. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.
Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. See “Item 8.
We completed 69 net operated wells in 2023, compared to 54 net operated wells in 2022. Additionally, on June 30, 2023, we completed the 2023 Williston Basin Acquisition for total cash consideration of $361.6 million. Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.
Non-operated drilling and completion activities accounted for $135.9 million of our total E&P and other capital expenditures for the year ended December 31, 2024. Additionally, on June 30, 2023, we completed the Williston Basin Acquisition for total cash consideration of $361.6 million. Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.
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. 70 Table of Contents Long-term debt Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements and $400.0 million of 6.375% senior unsecured notes.
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.
Operational and Financial Highlights • Production volumes averaged 173,425 Boepd (58% oil). • Lease operating expenses (“LOE”) were $10.41 per Boe. • E&P and other capital expenditures were $922.3 million. • Estimated net proved reserves were 636.2 MMBoe as of December 31, 2023, with a Standardized Measure of $7.0 billion and PV-10 of $8.5 billion. • TIL’d 94 gross (69 net) operated wells.
Operational and Financial Highlights • Production volumes averaged 232,737 Boepd (57% oil) for the year ended December 31, 2024. • Lease operating expenses (“LOE”) were $9.68 per Boe for the year ended December 31, 2024. • E&P and other capital expenditures were $1.2 billion for the year ended December 31, 2024. • Net cash provided by operating activities was $2.1 billion and net income was $848.6 million for the year ended December 31, 2024. • Estimated net proved reserves were 883.0 MMBoe as of December 31, 2024, with a Standardized Measure of $8.4 billion and PV-10 of $10.3 billion. • TIL’d 142 gross (93 net) operated wells for the year ended December 31, 2024.
The increase in net cash used in investing activities of $747.7 million from the year ended December 31, 2022 was primarily attributable to an increase of $374.3 million in capital expenditures incurred to develop our oil and gas properties and an increase in acquisitions of $213.5 million.
Cash flows used in investing activities For the year ended December 31, 2024, net cash used in investing activities of $1.8 billion was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1.2 billion and net cash paid for acquisitions of $655.0 million.
Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Expansions of both rail and pipeline facilities in the Williston Basin has reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.
Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations.
This increase was primarily due to an increase in crude oil volumes purchased and then subsequently sold, partially offset by lower crude oil prices year-over-year. 67 Table of Contents Expenses and other income (expense) The following table summarizes our operating expenses and other income (expense) for the periods presented: Year Ended December 31, 2023 2022 (In thousands, except per Boe of production) Operating expenses Lease operating expenses $ 658,938 $ 443,560 Gathering, processing and transportation expenses 180,219 141,644 Purchased oil and gas expenses 761,325 671,935 Production taxes 260,002 229,571 Depreciation, depletion and amortization 598,562 369,659 Exploration and impairment 35,330 2,204 General and administrative expenses 126,319 209,299 Total operating expenses 2,620,695 2,067,872 Gain (loss) on sale of assets, net (2,764) 4,867 Operating income 1,273,182 1,583,789 Other income (expense) Net gain (loss) on derivative instruments 63,182 (208,128) Net gain from investment in unconsolidated affiliate 21,330 34,366 Interest expense, net of capitalized interest (28,630) (29,349) Other income 9,964 2,901 Total other expense, net 65,846 (200,210) Income from continuing operations 1,339,028 1,383,579 Income tax (expense) benefit (315,249) 46,884 Net income from continuing operations 1,023,779 1,430,463 Income from discontinued operations attributable to Chord, net of income tax — 425,696 Net income attributable to Chord $ 1,023,779 $ 1,856,159 Costs and expenses (per Boe of production) Lease operating expenses $ 10.41 $ 10.14 Gathering, processing and transportation expenses 2.85 3.24 Production taxes 4.11 5.25 Lease operating expenses.
This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year. 66 Table of Conten ts Expenses and other income (expense) The following table summarizes our operating expenses and other income (expense) for the periods presented: Year Ended December 31, 2024 2023 (In thousands, except per Boe of production) Operating expenses Lease operating expenses $ 824,408 $ 658,938 Gathering, processing and transportation expenses 267,559 180,219 Purchased oil and gas expenses 1,412,357 761,325 Production taxes 333,397 260,002 Depreciation, depletion and amortization 1,107,776 598,562 General and administrative expenses 205,585 126,319 Exploration and impairment 17,021 35,330 Total operating expenses 4,168,103 2,620,695 Gain (loss) on sale of assets, net 17,088 (2,764) Operating income 1,100,067 1,273,182 Other income (expense) Net gain on derivative instruments 12,563 63,182 Net gain from investment in unconsolidated affiliate 51,284 21,330 Interest expense, net of capitalized interest (56,523) (28,630) Other income, net 5,047 9,964 Total other income, net 12,371 65,846 Income before income taxes 1,112,438 1,339,028 Income tax expense (263,811) (315,249) Net income $ 848,627 $ 1,023,779 Costs and expenses (per Boe of production) Lease operating expenses $ 9.68 $ 10.41 Gathering, processing and transportation expenses 3.14 2.85 Production taxes 3.91 4.11 Lease operating expenses.
Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.
During the year ended December 31, 2023, we declared base-plus-variable cash dividends of $11.88 per share of common stock, or $508.6 million in aggregate. Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.
During the year ended December 31, 2022, we recorded a $208.1 million net loss on derivative instruments, which included a net loss of $224.2 million associated with our commodity derivatives contracts, partially offset by an unrealized gain of $16.1 million associated with our contract that includes contingent consideration.
During the year ended December 31, 2024, we recorded a $12.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $7.5 million associated with our commodity derivative contracts and a net gain of $5.1 million associated with a contract that includes contingent consideration.
Business combinations We account for business combinations under the acquisition method of accounting. Under the acquisition method of accounting, we recognize amounts for identifiable assets acquired and liabilities assumed measured at their estimated acquisition date fair values.
Business combinations We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed.
Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes. 66 Table of Contents Crude oil revenues. Our crude oil revenues increased $469.0 million to $2.8 billion for the year ended December 31, 2023 due to the Merger, which significantly expanded our operations in the Williston Basin.
Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes. 65 Table of Conten ts Crude oil revenues. Our crude oil revenues increased $735.4 million to $3.6 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023.
(5) Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. 72 Table of Contents For the year ended December 31, 2023, our total E&P and other capital expenditures increased $418.7 million to $926.5 million as a result of the Merger, which significantly expanded our operations in the Williston Basin.
(6) Total capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.
Our primary sources of liquidity are from cash on hand, cash flows from operations and available borrowing capacity under our Credit Facility. Our primary liquidity requirements are for capital expenditures for the development of oil and gas properties, dividend payments, share repurchases and working capital requirements.
Our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, debt repayments under our Credit Facility, share repurchases, cash consideration and transaction costs associated with the Arrangement, and working capital requirements.
Our capital expenditures are summarized in the following table: Year Ended December 31, 2023 2022 2021 (In thousands) Capital expenditures E&P $ 920,841 $ 495,947 $ 168,189 Other capital expenditures (1) 5,626 11,771 2,277 Total E&P and other capital expenditures (2) 926,467 507,718 170,466 Acquisitions (3) 361,609 (2,275) 586,030 Total capital expenditures from continuing operations 1,288,076 505,443 756,496 Discontinued operations (4) — 3,396 49,123 Total capital expenditures (5) $ 1,288,076 $ 508,839 $ 805,619 __________________ (1) Other capital expenditures includes items such as infrastructure capital, administrative capital and capitalized interest.
Our capital expenditures are summarized in the following table: Year Ended December 31, 2024 2023 2022 (In thousands) E&P (1) $ 1,229,263 $ 920,841 $ 495,947 Other capital expenditures (2) 7,191 5,626 11,771 Total E&P and other capital expenditures (3) 1,236,454 926,467 507,718 Acquisitions (4) 15,951 361,609 (2,275) Total capital expenditures from continuing operations (3)(6) 1,252,405 1,288,076 505,443 Discontinued operations (5) — — 3,396 Total capital expenditures (6) $ 1,252,405 $ 1,288,076 $ 508,839 __________________ (1) For the year ended December 31, 2024, capital expenditures related to the Marcellus Shale were $8.9 million.
We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future. Our cash flows depend on many factors, including the price of crude oil, NGL and natural gas and the success of our development and exploration activities as well as future acquisitions.
Our cash flows depend on many factors, including the price of crude oil, NGLs and natural gas and the success of our development and exploration activities as well as future acquisitions.
For purposes of the Current Ratio, the Credit 71 Table of Contents Facility’s definition of total current liabilities excludes current hedge liabilities, which were $14.2 million as of December 31, 2023. Cash flows used in investing activities Net cash used in investing activities was $1,430.3 million for the year ended December 31, 2023.
For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $1.2 million as of December 31, 2024.
The following table summarizes our revenues, production data and average realized prices for the periods presented: Year Ended December 31, 2023 2022 (In thousands) Revenues Crude oil revenues $ 2,835,962 $ 2,366,995 NGL revenues (1) 177,715 184,288 Natural gas revenues (1) 118,734 425,013 Purchased oil and gas sales 764,230 670,174 Other services revenues — 324 Total revenues $ 3,896,641 $ 3,646,794 Production data Crude oil (MBbls) 36,427 25,457 NGLs (MBbls) (1) 13,047 7,026 Natural gas (MMcf) (1) 82,953 67,428 Oil equivalents (MBoe) 63,300 43,722 Average daily production (Boepd) 173,425 119,785 Average daily crude oil production (Bopd) 99,801 69,746 Average sales prices Crude oil (per Bbl) Average sales price $ 77.85 $ 92.98 Effect of derivative settlements (2) (6.93) (19.48) Average realized price after the effect of derivative settlements (2) $ 70.92 $ 73.50 NGLs (per Bbl) (1) Average sales price $ 13.62 $ 26.23 Effect of derivative settlements (2) 0.22 0.71 Average realized price after the effect of derivative settlements (2) $ 13.84 $ 26.94 Natural gas (per Mcf) (1) Average sales price $ 1.43 $ 6.30 Effect of derivative settlements (2) (0.08) (1.04) Average realized price after the effect of derivative settlements (2) $ 1.35 $ 5.26 __________________ (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 reporting revenues, production data and average sales prices.
The following table summarizes our revenues, production and average realized prices for the periods presented: Year Ended December 31, 2024 2023 (In thousands, except price per unit data) Revenues Crude oil revenues $ 3,571,336 $ 2,835,962 NGL revenues 162,052 177,715 Natural gas revenues 102,750 118,734 Purchased oil and gas sales 1,414,944 764,230 Total revenues $ 5,251,082 $ 3,896,641 Production data Crude oil (MBbls) 48,479 36,427 NGLs (MBbls) 16,338 13,047 Natural gas (MMcf) (1) 122,193 82,953 Oil equivalents (MBoe) 85,182 63,300 Average daily production (Boepd) 232,737 173,425 Average daily crude oil production (Bopd) 132,455 99,801 Average sales prices Crude oil (per Bbl) Average sales price $ 73.67 $ 77.85 Effect of derivative settlements (2) 0.02 (6.93) Average realized price after the effect of derivative settlements (2) $ 73.69 $ 70.92 NGLs (per Bbl) Average sales price $ 9.92 $ 13.62 Effect of derivative settlements (2) — 0.22 Average realized price after the effect of derivative settlements (2) $ 9.92 $ 13.84 Natural gas (per Mcf) Average sales price (1) $ 0.84 $ 1.43 Effect of derivative settlements (2) — (0.08) Average realized price after the effect of derivative settlements (1)(2) $ 0.84 $ 1.35 __________________ (1) For the year ended December 31, 2024, natural gas production volume from the Marcellus Shale was 24,727 MMcf.
Our NGL and natural gas sales decreased primarily due to lower natural gas and NGL prices year-over-year of $407.8 million, partially offset by an increase of $95.0 million due to higher natural gas and NGL sales volumes year-over-year due to our expanded operations in the Williston Basin as a result of the Merger.
The decrease was primarily due to lower natural gas realized prices year-over-year resulting in a $49.0 million decrease, offset by an increase in total natural gas production volumes sold of $33.0 million, primarily due to our expanded operations as a result of the Arrangement.
Financial Statements and Supplementary Data—Note 11—Discontinued Operations” for additional information. For discussion related to changes in financial condition and results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to “Part II, Item 7.
See “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this report for an explanation of these types of statements. For discussion related to changes in financial condition and results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II, Item 7.
Average crude oil sales prices, without derivative settlements, decreased by $15.13 per barrel year-over-year to an average of $77.85 per barrel for the year ended December 31, 2023. NGL and natural gas revenues . Our NGL and natural gas revenues decreased $312.9 million to $296.4 million for the year ended December 31, 2023.
Average crude oil sales prices, without derivative settlements, decreased by $4.18 per barrel year-over-year to an average of $73.67 per barrel for the year ended December 31, 2024 due to decreases in NYMEX WTI and widening in-basin differentials. NGL revenues .
The production tax rate as a percentage of crude oil, NGL and natural gas sales was 8.3% for the year ended December 31, 2023 as compared to 7.7% for the year ended December 31, 2022. This increase was primarily due to an increase in natural gas production volumes, coupled with lower average natural gas sales prices. Depreciation, depletion and amortization.
This rate increase year-over-year was primarily due to an increase in new wells with a higher associated oil production tax rate, coupled with decreased natural gas and NGL revenues as a result of lower realized prices. Depreciation, depletion and amortization.
The decrease in net cash provided by operating activities of $104.2 million from the year ended December 31, 2022 was primarily due to an increase in operating expenses, partially offset by an increase in revenues from crude oil, NGL and natural gas sales.
The increase in net cash provided by operating activities of $277.4 million from the year ended December 31, 2023 was primarily due to an increase in oil revenues, offset by increases in LOE, merger-related costs, GPT costs and production taxes, as well as lower NGL and natural gas revenues and changes in our working capital.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

16 edited+2 added−2 removed12 unchanged
Biggest changeIn January 2024, we received $25.0 million related to the 2023 earn-out payment. See “Item 8. Financial Statements and Supplementary Data—Note 7—Derivative Instruments” for additional information. Interest rate risk. At December 31, 2023, we had $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.375% per annum.
Biggest changeAs of December 31, 2024, the fair value of this contingent consideration was $22.8 million. We received $25.0 million related to the 2023 and 2024 earn-out payments in January 2024 and 2025, respectively. See “Item 8. Financial Statements and Supplementary Data—Note 7— Derivative Instruments” and “Note 6—Fair Value Measurements” for additional information regarding our commodity derivative contracts and other derivatives.
Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial. In addition, our crude oil, NGL and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.
Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial. In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.
Costs of certain materials and services remained elevated in 2023, and inflationary pressures could continue or increase in 2024. We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations.
Costs of certain materials and services remained elevated in 2023 and 2024, and inflationary pressures could continue or increase in 2025. We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations.
The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading. Commodity price exposure risk.
The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk derivative instruments were entered into for hedging purposes, rather than for speculative trading. Commodity price exposure risk.
It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in 2024; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities.
It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in 2025; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities.
These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2023, our credit losses on joint interest receivables were immaterial.
These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2024, our credit losses on joint interest receivables were immaterial.
Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. 76 Table of Contents Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate.
Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. 77 Table of Conten ts Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate.
A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative asset position by approximately $0.2 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative asset position by approximately $0.2 million. See “Item 7.
A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative liability position by approximately $6.3 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative liability position by approximately $6.3 million. See “Item 7.
See “Part I, Item 1A.—Risk Factors—Our profitability may be negatively impacted by inflation in the cost of labor, materials and services and general economic, business or industry conditions” for additional information. 77 Table of Contents
See “Part I, Item 1A.—Risk Factors—Our profitability may be negatively impacted by inflationary pressures in the cost of labor, materials and services and general economic, business or industry conditions” for additional information. 78 Table of Conten ts
In addition, in connection with the sale of our upstream assets in the Permian Basin in June 2021, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year.
In addition, in connection with the 2021 divestiture of certain oil and gas properties, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year.
At December 31, 2023, we had no borrowings and $8.9 million of outstanding letters of credit issued under the Credit Facility, which were subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the amended and restated credit agreement).
Borrowings under the Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the amended and restated credit agreement).
A 10% increase in crude oil prices would decrease the fair value of this unrealized derivative asset position by approximately $31.0 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $30.8 million.
A 10% increase in crude oil prices would decrease the fair value of this unrealized derivative asset position by approximately $55.9 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $54.3 million.
The fair value of our unrealized natural gas derivative positions at December 31, 2023 was a net asset of $0.3 million.
The fair value of our unrealized natural gas derivative positions at December 31, 2024 was a net liability of $1.6 million.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 8. Financial Statements and Supplementary Data—Note 7—Derivative Instruments” for additional information regarding our derivative instruments.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment.
See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information on the interest incurred on the Credit Facility. We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility.
We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility.
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 8. Financial Statements and Supplementary Data—Note 7— Derivative Instruments” and “Note 6—Fair Value Measurements” for additional information regarding our commodity derivative contracts.
Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. The fair value of our unrealized crude oil derivative positions at December 31, 2024 was a net asset of $16.2 million.
Removed
The fair value of our unrealized crude oil derivative positions at December 31, 2023 was a net asset of $7.6 million.
Added
Interest rate risk. At December 31, 2024, we had $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.375% per annum. At December 31, 2024, we had $445.0 million net borrowings outstanding and $30.8 million of outstanding letters of credit issued under the Credit Facility.
Removed
If the NYMEX WTI crude oil price for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter our right to receive any remaining earn-out payments is terminated. As of December 31, 2023, the fair value of this contingent consideration was $42.7 million.
Added
As of December 31, 2024, if interest rates were to increase by 100 basis points on the Credit Facility, the impact on our annual interest expense would not be material. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.

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