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What changed in NORTHERN OIL & GAS, INC.'s 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of NORTHERN OIL & GAS, INC.'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.

+422 added−395 removedSource: 10-K (2025-02-20) vs 10-K (2024-02-23)

Top changes in NORTHERN OIL & GAS, INC.'s 2024 10-K

422 paragraphs added · 395 removed · 334 edited across 7 sections

Item 1. Business

Business — how the company describes what it does

69 edited+32 added−12 removed99 unchanged
Biggest changeWe offer many additional programs to support the wellness of our workforce, including an onsite fitness center at our executive offices and a flexible paid time off and vacation policy. We recognize the importance of investing in our employees’ professional development, and are committed to ensuring that all employees are prepared for every aspect of their day-to-day roles.
Biggest changeThe Company also provides a generous match for employee donations to qualifying charitable organizations, and organizes employee volunteer days from time to time. We offer many additional programs to support the wellness of our workforce, including an onsite fitness center within our executive offices, company-provided lunches, and a flexible paid time off and vacation policy.
Insofar as such regulation within a particular state will generally affect all intrastate natural gas 6 Table of Contents shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.
Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas 6 Table of Contents transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.
The EPA has also finalized rules in December 2023 intended to reduce methane emissions from new and existing oil and gas sources and in January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of liquified natural gas to non-free trade agreement countries until the Department of Energy can update the underlying analyses for authorizations, including an assessment of the impact of GHG emissions.
The EPA also finalized rules in December 2023 intended to reduce methane emissions from new and existing oil and gas sources and in January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of liquified natural gas to non-free trade agreement countries until the Department of Energy can update the underlying analyses for authorizations, including an assessment of the impact of GHG emissions.
The EPA, however, has issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the Underground Injection Control (“UIC”) program, specifically as “Class II” UIC wells, and prohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. Scrutiny of hydraulic fracturing activities continues in other ways.
The EPA has issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the Underground Injection Control (“UIC”) program, specifically as “Class II” UIC wells, and prohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. Scrutiny of hydraulic fracturing activities continues in other ways.
While lower commodity prices may reduce our future net cash flow from operations, we expect to have sufficient liquidity to continue development of our oil and gas properties. In addition, we undertake an active commodity hedging program that is designed to help stabilize the volatile commodity pricing environment and protect cash flows in a potential downturn.
While lower commodity prices may reduce our future net cash flow from operations, we expect to have sufficient liquidity to continue development of our oil and natural gas properties. In addition, we undertake an active commodity hedging program that is designed to help stabilize the volatile commodity pricing environment and protect cash flows in a potential downturn.
We intend to continue these activities, while at the same time evaluating and pursuing larger non-operated asset packages that we believe can responsibly add significant production, cash flow and scale to existing operations. • Build and Maintain a Strong Balance Sheet and Proactively Manage to Limit Downside.
We intend to continue these activities, while at the same time evaluating and pursuing larger non-operated asset packages that we believe can responsibly add significant production, cash flow and scale to existing operations. • Build and Maintain a Strong Balance Sheet and Proactively Manage to Limit Downside Risk.
We may also use the services of independent consultants and contractors to perform various professional services. We strive to attract, develop and retain the best talent and spend considerable time and resources to advance the professional development and security of our workforce.
We may also use the services of independent consultants and contractors to perform various professional services from time to time. We strive to attract, develop and retain the best talent and spend considerable time and resources to advance the professional development and security of our workforce.
We operate on the fundamental philosophy that people are our most valuable asset, as every person who works for us has the potential to impact our success. We believe employees choose working at the Company in part due to our engaging culture, competitive compensation and benefits, and professional development opportunities.
We operate on the fundamental philosophy that people are our most valuable asset, as every person who works for us has the potential to impact our success. We believe employees choose to work at the Company in part due to our engaging culture, competitive compensation and benefits, and professional development opportunities.
Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring system to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations.
Among other things, the November 2022 supplemental proposed rule sought to remove an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring system to flag large emissions events, referred to in the proposed rule as “super emitters.” In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations.
Furthermore, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to considering or enacting laws requiring the disclosure of climate-related information and developing programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes or encouraging the use of renewable energy or alternative low-carbon fuels.
At the same time, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to considering or enacting laws requiring the disclosure of climate-related information and developing programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes or encouraging the use of renewable energy or alternative low-carbon fuels.
The Phase 1 Final Rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule, affecting the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.
The Phase I Final Rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule, affecting the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.
The following table provides a summary of certain information regarding our assets as of December 31, 2023, including reserves information audited by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“Cawley”).
The following table provides a summary of certain information regarding our assets as of December 31, 2024, including reserves information audited by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“Cawley”).
Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and 8 Table of Contents require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed but not passed in recent sessions of Congress.
Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed but not passed in recent sessions of Congress.
Our ability to discover reserves and acquire additional properties in the future is dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Our ability to add reserves and acquire additional properties in the future is dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.
Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties.
Moreover, many states impose a production or severance tax 5 Table of Contents with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties.
The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate a transition away from fossil fuels, which could in turn adversely affect our business and results of operations. The U.S.
The Waste Emissions Charge and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate a transition away from fossil fuels, which could in turn adversely affect our business and results of operations. The U.S.
Development We primarily engage in oil and natural gas exploration and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage.
Development As a non-operator, we primarily engage in oil and natural gas exploration and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage.
Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of certain operations altogether.
Although we believe that our operations are in substantial compliance with such statutes, future amendments are uncertain, and any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of certain operations altogether.
In addition, under Subpart OOOOc, the EPA’s proposed rule would require states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
Under Subpart OOOOc, the EPA’s proposed rule sought to require states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.
Across these operators, no single operator represented more than 20% of our fourth quarter 2023 oil and natural gas sales. Prior to 2020, we focused our operations exclusively on oil-weighted properties in the Williston Basin.
Across these operators, no single operator represented more than 14% of our fourth quarter 2024 oil and natural gas sales. Prior to 2020, we focused our operations exclusively on oil-weighted properties in the Williston Basin.
Given our large acreage footprint and substantial number of well participations, we believe we can make accurate economic drilling decisions. Historically, we have not managed our commodities marketing activities internally. Instead, our operating partners generally market and sell oil and natural gas produced from wells in which we have an interest.
Given our large acreage footprint and substantial number of well participations, we believe we can make accurate economic decisions with respect to our participation in well proposals. Historically, we have not managed our commodities marketing activities internally. Instead, our operating partners generally market and sell oil and natural gas produced from wells in which we have an interest.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.
At the same time, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.
See “Financial Statements” and the notes to our consolidated financial statements for financial information about this reportable segment. Our primary focus is investing in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in three premier basins within the United States.
See “Financial Statements” and the notes to our financial statements for financial information about this reportable segment. Our primary strategy is to invest in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in the premier basins within the United States.
Item 1. Business Overview We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties in the United States, primarily in the Williston Basin, the Permian Basin and the Appalachian Basin.
Item 1. Business Overview We are an independent energy company engaged as a non-operator in the acquisition, exploration, development and production of oil and natural gas properties in the United States, primarily in the Williston Basin, the Permian Basin, the Appalachian Basin and the Uinta Basin.
In furtherance of this EO, in November 2021, EPA proposed rules to regulate methane emissions from the oil and natural gas industry, including, for the first time, reductions from certain upstream and midstream existing oil and gas sources under Subparts OOOOa and OOOOb.
In 2021, the EPA proposed rules to regulate methane emissions from the oil and natural gas industry, including, for the first time, reductions from certain upstream and midstream existing oil and gas sources under Subparts OOOOa and OOOOb.
Further, we are able to avoid exploratory and infrastructure costs incurred by many oil and gas producers. We seek to create value through strategic acquisitions and partnering with operators who have significant experience in developing and producing hydrocarbons in our core areas. We have more than 105 experienced operating partners that provide technical insights and opportunities for acquisitions.
Further, we are able to avoid exploratory and infrastructure costs incurred by many oil and natural gas producers. We seek to create value through strategic acquisitions and financially participating alongside operators who have significant experience in developing and producing hydrocarbons in our core areas. We have more than 90 experienced operating partners that provide technical insights and opportunities for acquisitions.
Governmental Regulation and Environmental Matters Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole.
Governmental Regulation and Environmental Matters Our business is subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole.
The proposed rule would formally reinstate methane (a greenhouse gas (“GHG”)) emission limitations for existing and modified facilities in the oil and gas sector under Subpart OOOOa and would also regulate, for the first time under Subpart OOOOb, existing oil and gas facilities.
The proposed rule sought to formally reinstate methane (a greenhouse gas (“GHG”)) emission limitations for existing and modified facilities in the oil and gas sector under Subparts OOOOa and OOOOb and sought to also regulate existing oil and gas facilities for the first time.
The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or 5 Table of Contents the locations at which we can drill.
The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which our operating partners can drill.
While the United States withdrew from the Paris Agreement during the Trump Administration in 2020, President Biden recommitted the United States to the Paris Agreement in January 2021 and established a goal of reducing economy-wide net GHG emissions by at least thirty percent from 2020 levels by 2030.
While the United States withdrew from the Paris Agreement during the Trump Administration in 2020, the Biden Administration recommitted the United States to the Paris Agreement in January 2021 and established a goal of reducing GHG emissions by at least fifty percent from 2005 levels by 2030.
Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. On January 20, 2022, the FERC established a new price index for the five-year period which commenced on July 1, 2021. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.
Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. The current price index covers the five-year period which commenced on July 1, 2021. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.
The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026.
The Waste Emissions Charge imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 in 2025 and $1,500 in 2026.
Climate Change In the United States, no comprehensive federal climate change legislation regulating GHG emissions or directly imposing a price on carbon has been implemented to date; however, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, and the Biden Administration has indicated willingness to pursue new climate change legislation, executive actions or other regulatory initiatives to limit GHG emissions.
Climate Change In the United States, no comprehensive federal climate change legislation regulating GHG emissions or directly imposing a price on carbon has been implemented to date; however, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues.
The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply.
The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply.
Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us. Human Capital Resources As of December 31, 2023, we had 38 full time employees. We may hire additional personnel as appropriate.
There thus remains some litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us. Human Capital Resources As of December 31, 2024, we had 49 full time employees. We may hire additional personnel as appropriate.
Further, legislative and regulatory initiatives are underway to that purpose. The Inflation Reduction Act of 2022 (“IRA”), signed into law in August 2022, appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain oil and gas sources and facilities.
The Inflation Reduction Act of 2022 (“IRA”), signed into law in August 2022, appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a Waste Emission Charge on GHG emissions from certain oil and gas sources and facilities.
We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.
Our office space consists of 24,641 square feet of leased space. We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.
To attract and retain the best talent, we provide our employees a comprehensive total rewards program. In addition to competitive salaries, we offer both short and long-term incentive compensation; company-matched 401(k) contributions; company-paid premiums for health, dental and vision insurance, short and long-term disability insurance, and life insurance; and company-supported health savings accounts and flexible spending accounts.
In addition to competitive salaries, we offer both short and long-term incentive compensation; company-matched 401(k) contributions; company-paid premiums for health, dental and vision insurance, short and long-term disability insurance, and life insurance; and company-supported health savings accounts and flexible spending accounts.
For the three months ended December 31, 2023, 46% of our production was from the Williston Basin, 44% was from the Permian Basin and 10% was from the Appalachian Basin. • Accelerate Growth by Pursuing Value-Enhancing Acquisitions.
For the three months ended December 31, 2024, 48% of our production was from the Permian Basin, 34% was from the Williston Basin, 12% was from the Appalachian Basin and 6% was from the Uinta Basin. • Accelerate Growth by Pursuing Value-Enhancing Acquisitions.
Regulation of Oil and Natural Gas Production Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies.
Regulation of Oil and Natural Gas Production The oil and natural gas exploration, production and related operations that we participate in as a non-operator are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies.
Our policies and practices are designed to support diversity of thought, perspective, sexual orientation, gender, gender identity and expression, race, ethnicity, culture and professional experience, among others. Office Locations Our executive offices are located at 4350 Baker Road, Suite 400, Minnetonka, Minnesota 55343. Our office space consists of 24,641 square feet of leased space.
Our policies and practices are designed to promote diversity of thought, perspective, and professional experience, and to support all employees fairly without regard to disability, sexual orientation, gender, gender identity and expression, religion, race, ethnicity, culture, and nationality, among others. Office Locations Our executive offices are located at 4350 Baker Road, Suite 400, Minnetonka, Minnesota 55343.
At the 27th COP, President Biden announced the EPA’s supplemental proposed rule to reduce methane emissions from existing oil and gas sources and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.
At the 27th COP, the United States agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.
Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. In 2021, the United States Supreme Court held that the CWA requires a discharge permit if the addition of pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters.
In 2021, the United States Supreme Court held that the CWA requires a discharge permit if the addition of pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters.
These regulations also expanded controls to reduce methane emissions, such as enhancement of leak detection and repair provisions. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rules, removing an emissions monitoring exemption for small wellhead-only sites and creating a new third-party monitoring program to flag large emissions events.
In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rules, removing an emissions monitoring exemption for small wellhead-only sites and creating a new third-party monitoring program to flag large emissions events.
The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water.
The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water.
CAA regulations include New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. 7 Table of Contents In November 2021, the Environmental Protection Agency (“EPA”) issued a proposed rule intended to revise and add to the NSPS program rules, known as Subpart OOOOa.
CAA regulations include New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of 7 Table of Contents emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.
Since then we have significantly grown and diversified our properties via acquisitions in the Permian Basin and the Appalachian Basin, while also adding to our legacy position in the Williston Basin. See Note 3 to our financial statements for details regarding our recent acquisitions.
Since then we have significantly grown and diversified our properties via acquisitions of oil and natural gas properties in the Permian Basin, Appalachian Basin and Uinta Basin. See Note 3 to our financial statements for information regarding our recent acquisition activities.
The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply.
The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply. The final rule is subject to ongoing litigation but remains in effect.
As of December 31, 2023, we have participated in 9,765 gross (951.6 net) producing wells with an average working interest of 9.7% in each gross well, with more than 105 experienced operating partners.
As of December 31, 2024, we have participated in 10,868 gross (1,108 net) producing wells with an average working interest of 10.2% in each gross well, with more than 90 experienced operating partners.
Our acquisition activity was a significant driver of our 45% production growth from 78,854 Boe per day in the fourth quarter of 2022 to 114,363 Boe per day in the fourth quarter of 2023.
Our acquisition activities were a significant driver of our 15% production growth from 114,363 Boe per day in the fourth quarter of 2023 to 131,777 Boe per day in the fourth quarter of 2024.
We value and strive to treat all employees, consultants, vendors, contractors, service providers, and business partners equally. We prohibit discrimination or harassment on the basis of any grounds prohibited by law. We are committed to maintaining employment practices based on equal opportunity for all employees and providing a safe and productive working environment for all employees.
We are committed to providing a workplace environment free of discrimination and harassment, where all individuals are treated with respect and dignity, can contribute fully, and have equal opportunities. We value and strive to treat all employees, consultants, vendors, contractors, service providers, and business partners equally. We prohibit discrimination or harassment on the basis of any grounds prohibited by law.
Connecticut that, with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the CAA, the Court left open the question of whether tort claims against sources of 10 Table of Contents GHG emissions alleging property damage may proceed under state common law. There thus remains some litigation risk for such claims.
Supreme Court held in its 2011 decision American Electric Power Co. v. Connecticut that, with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the CAA, the Court left open the question of whether tort claims against sources of GHG emissions alleging property damage may proceed under state common law.
To the extent that these regulations or initiatives remain in place and to the extent that our third-party operating partners are required to further control methane emissions, such controls could impact our business. In addition, our third-party operating partners are required to report their GHG emissions under CAA rules.
PHMSA and the Department of Interior continue to focus on regulatory initiatives to control methane emissions from upstream and midstream equipment. To the extent that these regulations or initiatives remain in place and to the extent that our third-party operating partners are required to further control methane emissions, such controls could impact our business.
Because regulation of GHG emissions continues to evolve, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the U.S. Supreme Court held in its 2011 decision American Electric Power Co. v.
In addition, our third-party operating partners are required to report their GHG emissions under CAA rules. Because regulation of GHG emissions continues to evolve, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the U.S.
Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans.
Accordingly, future implementation and enforcement of these rules and policies is uncertain at this time. Additionally, costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans.
Electronic filings with the SEC are also available on the SEC internet website at www.sec.gov. 11 Table of Contents We have also posted to our website our Bylaws, Audit Committee Charter, Compensation Committee Charter, Governance, Nominating and ESG Committee Charter, Executive Committee Charter, Acquisition Committee Charter, Corporate Governance Guidelines, Code of Business Conduct and Ethics, Insider Trading Policy and Clawback Policy, in addition to all pertinent company contact information.
We have also posted to our website our Bylaws, Acquisition Committee Charter, Audit Committee Charter, Compensation Committee Charter, Executive Committee Charter, Governance, Nominating and ESG Committee Charter, Corporate Governance Guidelines, Stock Ownership Guidelines, Code of Business Conduct and Ethics, Insider Trading Policy, Clawback Policy, Human Rights Statement, Political Contributions and Trade Associations Policy and our Compliance Hotline, in addition to all pertinent company contact information.
The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into waters of the United States (“WOTUS”). Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands.
However, many related initiatives are expected to continue at the local, state and international levels. The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into waters of the United States (“WOTUS”).
Federal Reserve to increase the federal funds interest rate by 5.25% between March 2022 and December 2023 in an effort to curb inflationary pressure on the costs of goods and services.
Federal Reserve to increase the federal funds interest rate by 5.25% to a high of 5.375% between March 2022 and July 2023 in an effort to curb inflationary pressure on the costs of goods and services. While inflationary pressures in the United States’ economy have begun to subside, inflation is still holding above the U.S. Federal Reserve’s target level.
Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors.
To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. Among other things, the new rule expands the emissions events that are subject to reporting requirements to include “other large release events” and applies reporting requirements to certain new sources and sectors.
These regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.
Any regulations or proposals requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition. At the international level, the United Nations-sponsored Paris Agreement requires signatory countries to set voluntary targets to reduce domestic GHG emissions.
While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth.
Further, despite the U.S. Federal Reserve decreasing the federal funds interest rate to 4.375% between September 2024 and December 2024, we continue to be impacted by the elevated federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth.
In October 2021, the Biden Administration proposed a Phase 1 rule to undo 2020 changes to NEPA enacted under the Trump Administration. The Phase 1 rule is the first of two planned rules to roll back the 2020 rule and was finalized in April, 2022.
In April 2022, the White House Council on Environmental Quality (“CEQ”) finalized the first of two planned rules to undo changes to NEPA enacted in 2020 under the Trump Administration.
In certain circumstances, we may post information, such as presentation materials and press releases, to our corporate website, www.noginc.com, or our investor relations website to expedite public access to information regarding the Company in lieu of making a filing with the SEC for first disclosure of the information.
We use our website as a channel of distribution for important Company information. We routinely post important information, including presentation materials and press releases, to our corporate website, www.noginc.com, including the investor relations section thereof.
When permissible, we expect to continue to do so without also providing disclosure of this information through filings with the SEC. Where we have included internet addresses in this Annual Report on Form 10-K, we have included those internet addresses as inactive textual references only.
Therefore, investors should look to our website for important and time-critical information. Where we have included Internet addresses in this Annual Report on Form 10-K, we have included those Internet addresses as inactive textual references only.
Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial 9 Table of Contents compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.
Compliance with any enhanced climate disclosure obligations, including the Climate Disclosure Rule to the extent it becomes effective as finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, place strain on our personnel, systems and resources.
As of December 31, 2023 Net Acres Productive Wells Average Daily Production (1) (Boe per day) Proved Reserves (MBoe) % Oil % Proved Developed Gross Net Williston Basin 180,642 7,981 643.7 52,413 142,700 70 % 79 % Permian Basin 36,576 1,387 207.6 50,601 119,069 59 66 Appalachian Basin 55,034 397 100.3 11,349 77,926 — 57 Total 272,251 9,765 951.6 114,363 339,695 50 % 69 % __________________ (1) Represents the average daily production over the three months ended December 31, 2023. 2 Table of Contents Business Strategy Our business strategy is focused on growing our reserves, production and free cash flow to create long-term value for our stakeholders while maintaining a strong balance sheet.
As of December 31, 2024 Net Acres Productive Wells Average Daily Production (1) (MBoe per day) Proved Reserves (MBoe) % Oil % Proved Developed Gross Net Williston Basin 179,209 8,278 664.0 45 118,158 68 % 85 % Permian Basin 44,241 1,895 302.3 63 154,749 59 65 Appalachian Basin 53,142 424 104.3 15 79,285 — 82 Uinta Basin 15,908 271 37.4 8 26,293 87 48 Total 292,500 10,868 1,108.0 132 378,484 52 % 74 % __________________ (1) Represents the average daily production over the three months ended December 31, 2024. 2 Table of Contents Business Strategy Our business strategy is focused on growing our reserves, production and free cash flow to create long-term value for our stakeholders while maintaining a strong balance sheet.
We have a multi-year rotational analyst development program, to ensure that we are hiring and developing new talent and offering cross-functional exposure and learning experience. This program was designed with the intent of developing an internally trained pool of future leaders that have a wholistic view of our systems, processes and operations.
This program was designed with the intent of developing an internally trained pool of future leaders that have a holistic view of our systems, processes and operations. We also support employees who seek to further their professional development through appropriate external educational programs and offer tuition reimbursement benefits for various extended educational learning opportunities.
Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA provides for criminal penalties for willful violations of the ESA.
Under the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat. Accordingly, restrictions may be imposed on exploration and production operations, as well as actions by federal agencies, to avoid significantly impairing or jeopardizing the species or its habitat.
However, litigation opposing the September 2023 final rule remains ongoing and substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally. Any expansion to CWA jurisdiction could impact areas where oil and gas operations are conducted.
However, roughly half of the states and other plaintiffs are challenging the September 2023 rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues. As a result, substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally.
Removed
Moreover, the Biden Administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands.
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The ESA provides for criminal penalties for willful violations of the ESA. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species.
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At the international level, the United Nations-sponsored Paris Agreement requires signatory countries to set voluntary targets to reduce domestic GHG emissions.
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A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development.
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These include rejoining the Paris Agreement treaty on climate change in 2021, issuing several executive orders to address climate change, the U.S.
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In November 2021, the Environmental Protection Agency (“EPA”) issued a proposed rule intended to revise and add to the NSPS program rules, known as Subpart OOOOa.
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Methane Emissions Reduction Action Plan, a commitment to cut greenhouse gas emissions 50-52 percent of 2005 levels by 2030, and participation in the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030.
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However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of these rules remains uncertain at this time.
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Since its formal launch at the 26 th United Nations Conference of the Parties (“COP”), over 150 countries have joined the pledge.
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However, in January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The full impact of these actions remains unclear at this time.
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Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeIn either case, and in other cases, our obligations under the notes and the indenture could increase the cost of acquiring us or otherwise discourage a third party from acquiring us or removing incumbent management, including in a transaction that noteholders or holders of our common stock may view as favorable . 27 Table of Contents Risks Related to Legal and Regulatory Matters The current presidential administration, acting through the executive branch and/or in coordination with Congress, already has ordered or proposed, and could enact additional rules and regulations that restrict our ability to acquire federal leases in the future and/or impose more onerous permitting and other costly environmental, health and safety requirements.
Biggest changeIn either case, and in other cases, our obligations under the notes and the indenture could increase the cost of acquiring us or otherwise discourage a third party from acquiring us or removing incumbent management, including in a transaction that noteholders or holders of our common stock may view as favorable .
To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products may become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Climate change-related developments in particular may result in negative perceptions of the traditional oil and gas industry and, in turn, reputational risks associated with exploration and production activities.
Additionally, certain segments of the investor community have expressed negative sentiment towards investing in the oil and natural gas industry. Climate change-related developments in particular may result in negative perceptions of the traditional oil and gas industry and, in turn, reputational risks associated with exploration and production activities.
Any acquisition involves other potential risks, including, among other things: • the validity of our assumptions about reserves, future production, revenues and costs; • a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; • the ultimate value of any contingent consideration agreed to be paid in an acquisition; • dilution to stockholders if we use equity as consideration for, or to finance, acquisitions; • the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; • an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and • an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
Any acquisition involves other potential risks, including, among other things: • the validity of our assumptions about reserves, future production, revenues and costs; • a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; 18 Table of Contents • the ultimate value of any contingent consideration agreed to be paid in an acquisition; • dilution to stockholders if we use equity as consideration for, or to finance, acquisitions; • the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; • an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and • an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including: • declines in oil or natural gas prices; 14 Table of Contents • infrastructure limitations, such as the gas gathering and processing constraints experienced in the Williston Basin in 2019; • the high cost, shortages or delays of equipment, materials and services; • unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems; • compliance with environmental and other governmental requirements; • regulations, restrictions, moratoria and bans on hydraulic fracturing; • unusual or unexpected geological formations; • environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas; • fires, blowouts, craterings and explosions; • uncontrollable flows of oil, natural gas or well fluids; and • pipeline capacity curtailments.
In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including: • declines in oil or natural gas prices; • infrastructure limitations, such as the gas gathering and processing constraints experienced in the Williston Basin in 2019; • the high cost, shortages or delays of equipment, materials and services; • unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems; • compliance with environmental and other governmental requirements; • regulations, restrictions, moratoria and bans on hydraulic fracturing; • unusual or unexpected geological formations; • environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas; • fires, blowouts, craterings and explosions; • uncontrollable flows of oil, natural gas or well fluids; and • pipeline capacity curtailments.
This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, petroleum products and the use of products manufactured with, or powered by, petroleum products, may in the long-term result in (i) the enactment of climate change-related regulations, policies and initiatives (at the government, regulator, corporate and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures and responsible energy development, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy ( e.g. , wind, solar and hydrogen power, smart grid technology and battery technology, increasing efficiency) and (iii) increased availability of, and increased consumer and industrial/commercial demand for, alternative energy sources and products manufactured with, or powered by, alternative energy sources ( e.g. , electric vehicles and renewable residential and commercial power supplies).
This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, petroleum products and the use of products manufactured with, or powered by, petroleum products, may in the long-term result in (i) the enactment of climate change-related regulations, policies and initiatives (at the government, regulator, corporate and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation, enhanced disclosure obligations and emissions reductions measures and responsible energy development, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy ( e.g. , wind, solar and hydrogen power, smart grid technology and battery technology, increasing efficiency) and (iii) increased availability of, and increased consumer and industrial/commercial demand for, alternative energy sources and products manufactured with, or powered by, alternative energy sources ( e.g. , electric vehicles and renewable residential and commercial power supplies).
Further, our business and growth opportunities require us to have strong relationships with various key stakeholders, including our stockholders, employees, suppliers, customers, local communities and others.
Further, our business and growth opportunities require us to have strong relationships with various key stakeholders, including our stockholders, lenders, employees, suppliers, customers, local communities and others.
On January 14, 2021, the CFTC published a final rule imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents, though certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC’s requirements for certain enumerated “bona fide” derivative transactions.
On January 14, 2021, the CFTC published a final rule imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents, though certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC’s requirements for certain enumerated “bona fide” hedging transactions and positions.
See further discussion in the risk factor further below entitled “ The adoption of climate change legislation or regulations restricting or relating to emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce. ” Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas.
See further discussion in the risk factor further below entitled “ The adoption of climate change legislation or regulations restricting or relating to emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce. ” 21 Table of Contents Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could 28 Table of Contents eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational 20 Table of Contents purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by our operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.
The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by our operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.
The option counterparties and/or their respective affiliates may modify their hedge positions by entering into or unwinding various derivatives with respect to our common stock and/or purchasing or selling our common stock or other securities of ours in secondary market transactions prior to the maturity of the Convertible Notes (and are likely to do so during any observation period related to a conversion of such notes).
The option counterparties and/or their respective affiliates may modify their hedge positions by entering into or unwinding various derivatives with respect to our common stock and/or purchasing or selling our common stock or other 25 Table of Contents securities of ours in secondary market transactions prior to the maturity of the Convertible Notes (and are likely to do so during any observation period related to a conversion of such notes).
To the extent the nature of our business or assets change in the future and we do not qualify for another 32 Table of Contents exemption or exception under the ICA at such time, we may be required to register as an “investment company” and become subject to regulations thereunder, which would limit our business operations and require us to spend significant resources in order to comply with such regulations.
To the extent the nature of our business or assets change in the future and we do not qualify for another exemption or exception under the ICA at such time, we may be required to register as an “investment company” and become subject to regulations thereunder, which would limit our business operations and require us to spend significant resources in order to comply with such regulations.
Failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals we have set could damage our reputation, causing our investors or other stakeholders to lose confidence in our company, and negatively impact our operations.
Failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals we may set could damage our reputation, causing our investors or other stakeholders to lose confidence in our company, and negatively impact our operations.
The option counterparties to the capped call transactions are financial institutions, and we will be subject to the risk that one or more of the option counterparties may default or otherwise fail to perform, or may exercise certain rights to terminate their obligations, under the capped call transactions.
The option counterparties to the capped call transactions are financial institutions, and we are subject to the risk that one or more of the option counterparties may default or otherwise fail to perform, or may exercise certain rights to terminate their obligations, under the capped call transactions.
States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield fluids.
States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield 31 Table of Contents fluids.
In addition, upon a default or other failure to perform, or a termination of obligations, by an option counterparty, we may 26 Table of Contents suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of any option counterparty.
In addition, upon a default or other failure to perform, or a termination of obligations, by an option counterparty, we may suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of any option counterparty.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. 31 Table of Contents Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is used extensively by our third-party operating partners.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is used extensively by our third-party operating partners.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and derive production from additional oil and natural gas reserves.
Any significant variance could 15 Table of Contents materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other company materials. Our future success depends on our ability to replace reserves that our operators produce.
Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other company materials. Our future success depends on our ability to replace reserves that our operators produce.
To the extent the frequency of extreme weather events increases, this could impact our business in various ways, including damage to operators’ facilities at our properties or increased insurance premiums. Potential adverse effects on our third party operators could also include disruption of their production activities and supply chain.
To the extent the frequency of extreme weather events increases, this could impact our business in various ways, including damage to operators’ facilities at our properties or increased insurance premiums. Potential adverse effects on our third party operators could also 16 Table of Contents include disruption of their production activities and supply chain.
Covenants contained in the instruments governing our indebtedness restrict the payment of dividends. Investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. 33 Table of Contents Item 1B. Unresolved Staff Comments None.
Covenants contained in the instruments governing our indebtedness restrict the payment of dividends. Investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Item 1B. Unresolved Staff Comments None.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or 22 Table of Contents actual risks or events or forecasts of expected risks or events, including the costs associated therewith.
Restrictions on GHG emissions that may be imposed, or the adoption and implementation of regulations that require reporting of GHG emissions or other climate-related information or otherwise seek to limit GHG emissions (including carbon pricing schemes) from our operating partners, could adversely affect our business and the oil and gas industry, including by restricting our ability to execute on our business strategy, requiring additional capital, compliance, operating costs, increasing the cost of oil and natural gas products and services, reducing demand for oil and natural gas products and services, reducing our access to financial markets, or creating greater potential for governmental investigations or litigation.
Restrictions on GHG emissions that may be imposed, or the adoption and implementation of regulations by governmental entities in the U.S. or other countries that require reporting of GHG emissions or other climate-related information or otherwise seek to limit GHG emissions (including carbon pricing schemes) from our operating partners, could adversely affect our business and the oil and gas industry, including by restricting our ability to execute on our business strategy, requiring additional capital, compliance, operating costs, increasing the cost of oil and natural gas products and services, reducing demand for oil and natural gas products and services, reducing our access to financial markets, or creating greater potential for governmental investigations or litigation.
We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors, including in some cases estimates prepared by our internal reserve engineers and professionals that are not reviewed or audited by an independent reserve engineering firm.
We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors, including in some cases estimates prepared by our internal reserve engineers and 14 Table of Contents professionals that are not reviewed or audited by an independent reserve engineering firm.
To the extent elevated inflation remains, we may experience further cost increases for our operations. We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.
To the extent elevated inflation remains, we may experience further cost increases for our operations. 17 Table of Contents We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.
Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to 19 Table of Contents provide effective contractual protection against all or a portion of the underlying deficiencies.
Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies.
Any change in the level of our dividends or the suspension of the payment thereof could have a material adverse effect on the market price of our common stock. Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Any change in the level of our dividends or the suspension of the payment thereof could have a material adverse effect on the market price of our common stock. 24 Table of Contents Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal, state and local taxing authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal, 28 Table of Contents state and local taxing authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
If we are unable to use the if-converted method in accounting for the shares issuable upon conversion of the Convertible Notes, our diluted earnings per share could be adversely affected. The conditional conversion feature of the Convertible Notes, if triggered, could adversely affect our financial position and liquidity.
If we are unable to use the if-converted method in accounting for the shares issuable upon conversion of the Convertible Notes, our diluted earnings per share could be adversely affected. 26 Table of Contents The conditional conversion feature of the Convertible Notes, if triggered, could adversely affect our financial position and liquidity.
In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area.
In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to 15 Table of Contents transport production from all of the wells in the area.
To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry and will use our management team’s relationships with industry participants to enter into strategic relationships. The members of our management team may terminate their employment with our company at any time.
To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry and 19 Table of Contents will use our management team’s relationships with industry participants to enter into strategic relationships. The members of our management team may terminate their employment with our company at any time.
To the extent that our products are competing with higher GHG emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions.
To the extent that our products are competing with higher GHG emitting energy sources, our products may become more desirable in the market with more stringent limitations on GHG emissions.
Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced.
Except to the extent that we acquire additional properties containing proved reserves, participate in successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced.
The occurrence of any of these events or any issuance of common stock upon conversion of our Convertible Notes or upon exercise of our outstanding warrants may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock.
The occurrence of any of these events or any issuance of common stock upon conversion of our Convertible Notes may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock.
Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial 24 Table of Contents performance, and, as a result, our ability to generate cash flow from operations and to pay our debt.
Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt.
Our exposure to the credit risk of the option counterparties will not be secured by any collateral. Global economic conditions have from time to time resulted in the actual or perceived failure or financial difficulties of many financial institutions.
Our exposure to the credit risk of the option counterparties is not secured by any collateral. Global economic conditions have from time to time resulted in the actual or perceived failure or financial difficulties of many financial institutions.
In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our business and limit the quantity of natural gas we may produce and sell.
In addition, our activities are subject to the regulations regarding conservation practices and protection of 30 Table of Contents correlative rights. These regulations affect our business and limit the quantity of natural gas we may produce and sell.
Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered.
Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heir ship or causing an estate to be administered.
In July 2020, a federal district court ordered DAPL to be shut down pending the completion of an environmental impact statement (“EIS”) to determine whether the 16 Table of Contents DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. The temporary shutdown order was overturned by the U.S.
In July 2020, a federal district court ordered DAPL to be shut down pending the completion of an environmental impact statement (“EIS”) to determine whether the DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. The temporary shutdown order was overturned by the U.S. Court of Appeals in August 2020.
We maintain an active hedging program related to commodity price risks. 30 Table of Contents Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties.
We maintain an active hedging program related to commodity price risks. Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties.
Whether and to what extent we could be subject to the excise tax in connection with repurchases of our shares will depend on a number of factors, including (i) the fair market value of the repurchase, (ii) the nature and amount of any equity issuances within the same taxable year of the repurchase, and (iii) the content of any future regulations and other guidance issued from the Treasury.
Whether and to what extent we are subject to the excise tax in connection with repurchases of our shares depends on a number of factors, including (i) the fair market value of the repurchase, (ii) the nature and amount of any equity issuances within the same taxable year of the repurchase, and (iii) the content of any future regulations and other guidance issued from the Treasury.
Although we utilize various procedures and controls to monitor these 21 Table of Contents threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.
Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.
If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. We may be able to incur substantially more debt.
If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
We are affected by the adoption of laws, regulations and policy directives that, for economic, environmental protection or other policy reasons, could curtail exploration and development drilling for oil and gas. For example, in January 2021, President Biden signed an Executive Order directing the U.S.
We are affected by the adoption of laws, regulations and policy directives that, for economic, environmental protection or other policy reasons, could curtail exploration and development drilling for oil and gas. For example, in January 2021, the Biden Administration directed the U.S.
A portion of our crude oil production is transported to market centers by rail. Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids.
Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids.
If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected. Our derivatives activities could adversely affect our cash flow, results of operations and financial condition.
If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected.
If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed. Deficiencies of title to our leased interests could significantly affect our financial condition.
If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.
Additionally, in July 2023, DOI announced a proposed rule to revise outdated fiscal terms of the onshore federal oil and gas leasing program, including for bonding requirements, royalty rates and minimum bids, with a final rule expected in April 2024.
Additionally, in April 2024, DOI finalized a rule to revise outdated fiscal terms of the onshore federal oil and gas leasing program, including for bonding requirements, royalty rates and minimum bids.
Our Revolving Credit Facility, the indenture the “2028 Notes Indenture” governing our 8.125% senior notes due 2028 (the “Senior Notes due 2028”), and the indenture the “2031 Notes Indenture” and, together with the 2028 Notes Indenture, the “Senior Notes Indentures”) governing our 8.750% senior notes due 2031 (the “Senior Notes due 2031” and, together with the Senior Notes due 2028, the “Senior Notes”), and any future indebtedness we incur may contain a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things: declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem certain debt; make loans or certain investments; make certain acquisitions and investments; incur or guarantee additional indebtedness or issue certain types of equity securities; incur liens; transfer or sell assets; create subsidiaries; consolidate, merge or transfer all or substantially all of our assets; and engage in transactions with our affiliates.
Our Revolving Credit Facility, and the Senior Notes Indentures (as defined herein), and any future indebtedness we incur may contain a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things: declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests or purchase or redeem certain debt; make loans or certain investments; make certain acquisitions and investments; incur or guarantee additional indebtedness or issue certain types of equity securities; incur liens; transfer or sell assets; create subsidiaries; consolidate, merge or transfer all or substantially all of our assets; and engage in transactions with our affiliates.
A new 1% U.S. federal excise tax could be imposed on us in connection with repurchases of our shares by us. On August 16, 2022, the IRA was signed into federal law.
We are subject to a 1% U.S. federal excise tax in connection with repurchases of our shares by us. On August 16, 2022, the IRA was signed into federal law.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contracts for a portion of our expected production, which may include swaps, collars, puts and other structures.
Our derivatives activities could adversely affect our cash flow, results of operations and financial condition. 20 Table of Contents To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contracts for a portion of our expected production, which may include swaps, collars, puts and other structures.
The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital.
These risks are heightened in a low commodity price environment, which may present significant challenges to our operators. The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital.
Approximately 31% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2023. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.
Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 27% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2024. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.
If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline.
If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could suffer and the trading price of our common stock could decline. Risks Related to Our Business and the Oil, Natural Gas and NGL Industry Oil and natural gas prices are volatile.
In recent years, companies across all industries are facing increasing scrutiny from stakeholders related to their ESG and sustainability practices.
Companies across all industries continue to face increasing scrutiny from stakeholders related to their ESG and sustainability practices.
With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. 22 Table of Contents This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers.
We may face pressures from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating public company.
We may face pressures from stakeholders to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability, or with respect to other ESG matters, while at the same time remaining a successfully operating public company.
Lower oil and natural gas prices may limit our ability to comply with the covenants under our Revolving Credit Facility (or other debt instruments) and/or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves.
Lower oil and natural gas prices may limit our ability to comply with the covenants under our Revolving Credit Facility (or other debt instruments) and/or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves. 13 Table of Contents Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.
Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.
Our operators’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.
In situations where cost inflation exceeds commodity price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted.
In situations where cost inflation exceeds commodity price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash flows.
While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.
Federal Reserve decreasing the federal funds interest rate to 4.375% between September 2024 and December 2024, we continue to be impacted by the elevated federal funds interest rate, which could additionally have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.
At December 31, 2023, we had an estimated NOL carryforward of approximately $573.0 million for U.S. federal income tax purposes. In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “IRC”), a corporation that undergoes an “ownership change” can be subject to limitations on the use of its NOLs to offset future taxable income.
In general, under Section 382 of the Internal Revenue Code of 1986, as amended (the “IRC”), a corporation that undergoes an “ownership change” can be subject to limitations on the use of its NOLs to offset future taxable income.
Legislative and regulatory developments could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business .
Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition. 29 Table of Contents Legislative and regulatory developments could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business .
Our ability to comply with some of the covenants and restrictions may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.
If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.
As of December 31, 2023, we estimate that we had leases that were not developed that represented 8,442 net acres potentially expiring in 2024, 5,896 net acres potentially expiring in 2025, 1,595 net acres potentially expiring in 2026, 1,746 net acres potentially expiring in 2027, and 7,571 net acres potentially expiring in 2028 and beyond.
As of December 31, 2024, we estimate that we had leases that were not developed that represented 5,743 net acres potentially expiring in 2025, 1,902 net acres potentially expiring in 2026, 3,074 net acres potentially expiring in 2027, 2,138 net acres potentially expiring in 2028, and 2,670 net acres potentially expiring in 2029 and beyond.
Further, in September 2021, President Biden publicly announced the Global Methane Pledge, an international pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030. These efforts, among others, are intended to support the Biden Administration’s stated goal of addressing climate change.
Further, in September 2021, the Biden Administration publicly announced the Global Methane Pledge, an international pact that aims to reduce global methane emissions by at least 30% below 2020 levels by 2030.
In addition, the Revolving Credit Facility requires us to maintain compliance with certain financial covenants and other covenants. As a result of these covenants, we could be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
As a result of the financial covenants and other covenants, we could be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs. Our ability to comply with some of the covenants and restrictions may be affected by events beyond our control.
Risks Related to Our Common Stock There may be future sales or issuances of our common stock, including issuances in connection with our incentive plans, acquisitions or otherwise, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.
Risks Related to Our Common Stock There may be future sales or issuances of our common stock, including issuances in connection with our incentive plans, acquisitions or otherwise, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock. 32 Table of Contents Our certificate of incorporation authorizes us to issue 270,000,000 shares of common stock, of which 99,113,645 shares were issued and outstanding as of December 31, 2024.
Department of the Interior (“DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed subject to certain limitations.
Department of the Interior (“DOI”) to temporarily pause new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. Litigation over the leasing pause remains ongoing.
The excise tax would cause a reduction in our cash available on hand, which could have a negative impact on our business and operations. 29 Table of Contents Our business involves the selling and shipping by rail of crude oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
Our business involves the selling and shipping by rail of crude oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations. A portion of our crude oil production is transported to market centers by rail.
Court of Appeals in August 2020. DAPL currently remains in operation while the U.S. Army Corps of Engineers (“USACE”) conducts the EIS, which was released in draft form in September 2023 and was open for public comment until mid-December 2023. The date that the final EIS will be published is not yet known.
DAPL currently remains in operation while the U.S. Army Corps of Engineers (“USACE”) conducts the EIS, which was released in draft form in September 2023 and was open for public comment until mid-December 2023. The USACE received over 200,000 public comments.
Increasing attention to climate change may also result in additional governmental investigations, private litigation against us, operational delays or restrictions, increased operating costs, and additional regulatory burdens.
This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Increasing attention to climate change may also result in additional governmental investigations, private litigation against us, operational delays or restrictions, increased operating costs, and additional regulatory burdens.
To our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer material losses in the future.
To our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer material losses in the future. The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations.
This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.
With regard to derivative activities that we undertake with respect to oil, natural gas, NGLs, or other energy commodities, we are required to observe the market-related regulations enforced by these agencies. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.
With regard to derivative activities that we undertake with respect to oil, natural gas, NGLs, or other energy commodities, we are required to observe the market-related regulations enforced by these agencies.
Any of these executive, administrative or Congressional actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements.
To the extent that future legislative or regulatory impose more restrictive requirements pertaining to permitting, GHG emissions, financial assurance and bonding for decommissioning liabilities, or carbon taxes, such actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements.
The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business. We depend on computer and telecommunications systems, and failures in our systems or cyber security attacks could significantly disrupt our business operations.
The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.
It is possible that we, or these third parties, could incur interruptions from cyber security attacks, computer viruses or malware, or that third-party service providers could cause a breach of our data.
In addition, we have developed or may develop proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible that we, or these third parties, could incur interruptions from cybersecurity attacks, computer viruses or malware, or that third-party service providers could cause a breach of our data.
If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected. 17 Table of Contents These risks are heightened in a low commodity price environment, which may present significant challenges to our operators.
The success of our business operations depends on the timing of drilling activities and success of our third-party operators. If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeIn addition to continuous cyber monitoring, the IT Steering Committee participates in quarterly updates with cybersecurity experts which include reports from these experts on identification of new cyber risks and threats, reported vulnerabilities, trend analysis on attack vectors, and monitoring of risk mitigation activities.
Biggest changeIn addition to continuous cyber monitoring, 33 Table of Contents the IT Steering Committee participates in quarterly cyber updates with our cybersecurity vendor, which includes identification of new cyber risks and threats, reported vulnerabilities, trend analysis on attack vectors, and monitoring of risk mitigation activities. The Audit Committee has ultimate oversight of cybersecurity risks and our cybersecurity risk management program.
In addition, employees participate in mandatory annual cyber training and management conducts routine social engineering tests to monitor employees’ awareness of cyber risks and to train employees on how to identify potential cybersecurity risks. In the last fiscal two years, we have not experienced any material cybersecurity breach incidents. For additional information about our cybersecurity risks, please see “Item 1A.
In addition, employees participate in mandatory annual cybersecurity training and management conducts routine social engineering tests to monitor employees’ awareness of cyber risks and to train employees on how to identify potential cybersecurity risks. In the last two fiscal years, we have not experienced any material cybersecurity breach incidents. For additional information about our cybersecurity risks, please see “Item 1A.
Item 1C. Cybersecurity We have a cybersecurity program to identify, monitor, and mitigate cybersecurity risks. The security program consists of formal roles and responsibilities for information security and incident response, and is overseen by our IT Steering Committee, which consists of key executives and employees, with guidance from our third-party cybersecurity vendor.
Item 1C. Cybersecurity We have a cybersecurity risk management program to identify, monitor, and mitigate cybersecurity risks. The program consists of formal roles and responsibilities for information security and incident response, and is overseen by our IT Steering Committee, which consists of key executives and employees with guidance from our third-party cybersecurity vendor.
Management provides cybersecurity program briefings to the Audit Committee on at least an annual basis, and more frequently if circumstances warrant. These briefings include assessments of cyber risks, the threat landscape, updates on any incidents, and reports on NOG’s investments in cybersecurity risk mitigation and governance.
Management provides cybersecurity program briefings to the Audit Committee on at least an annual basis, and more frequently if circumstances warrant. These briefings include assessments of cyber risks, the threat landscape, updates on any incidents, and reports on our investments in cybersecurity risk mitigation and governance.
Our enterprise risk management program considers cybersecurity risks alongside other company risks, and we consult with subject matter experts to gather information necessary to identify cybersecurity risks, evaluate their nature and severity, as well as identify mitigations and assess the impact of those mitigations on residual risk.
Our enterprise risk management program considers cybersecurity risks alongside other company risks, and we consult with our cybersecurity vendor to gather information necessary to identify cybersecurity risks, evaluate their nature and severity, as well as identify mitigations and assess the impact of those mitigations on residual risk.
We have a formal IT Security Policy to provide appropriate governance over information security including control requirements for change management and patching, multifactor authentication, data backup, security monitoring, mobile device management and asset management. Management performs annual testing of security controls and results are reported to the Audit Committee.
We have a formal IT Security Policy to provide appropriate governance over information security including control requirements for change management and patching, multi-factor authentication, data backup, security monitoring, mobile device management and asset management.
In addition, management has a formal incident response plan and has contracted with a cybersecurity operations vendor to provide 24x7 monitoring/management of our infrastructure and systems. The incident response plan addresses the lifecycle of incidents including identification, response and recovery, and the plan is tested at least annually.
In addition, management has a formal incident response plan and our cybersecurity vendor provides 24x7 monitoring/management of our infrastructure and systems. The incident response plan addresses the lifecycle of incidents including identification, response and recovery, and the plan is tested at least annually. In addition, we carry insurance that provides protection against the potential losses arising from cybersecurity incidents.
In addition, we carry insurance that provides protection against the potential losses arising from a cybersecurity incident. Management maintains an inventory of third parties and completes an annual third-party cyber risk assessment.
Management maintains an inventory of third parties (e.g., vendors, consultants, etc., from whom we may face cybersecurity risk in connection with our relationship) and completes an annual third-party cyber risk assessment.
Added
Management utilizes the National Institute of Standards and Technology (NIST) Cybersecurity Framework as a guideline to manage our cybersecurity risks and inform the Audit Committee on the overall progress of our information security program.
Added
Management performs annual testing of security controls, including penetration testing from a different cybersecurity vendor that is independent of both our Company and the cybersecurity vendor that provides guidance on our overall cybersecurity program, and results are reported to the Audit Committee.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeManagement’s Discussion and Analysis of Financial Condition and Results of Operations.” 40 Table of Contents Year Ended December 31, 2023 2022 2021 Net Production: Oil (Bbl) 22,012,986 16,090,072 12,288,358 Natural Gas and NGLs (Mcf) 84,341,858 68,829,142 44,073,941 Total (Boe) 36,069,962 27,561,596 19,634,015 Oil (Bbl) per day 60,310 44,082 33,667 Mcf per day 231,074 188,573 120,751 Total (Boe) per day 98,822 75,511 53,792 Average Sales Prices: Oil (per Bbl) $ 74.78 $ 91.65 $ 62.94 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) (0.90) (21.48) (10.19) Oil Net of Settled Oil Derivatives (per Bbl) 73.88 70.17 52.75 Natural Gas and NGLs (per Mcf) 2.98 7.43 4.57 Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.92 (1.60) (0.92) Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 3.90 5.83 3.65 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 52.61 72.05 49.66 Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 1.61 (16.52) (6.37) Realized Price on a Boe Basis Including Settled Commodity Derivatives 54.22 55.53 43.29 Average Costs: Production Expenses (per Boe) $ 9.62 $ 9.46 $ 8.70 41 Table of Contents The following table sets forth our production results for the years ended December 31, 2023, 2022 and 2021 in total and for each of our basins of operations.
Biggest changeManagement’s Discussion and Analysis of Financial Condition and Results of Operations.” 40 Table of Contents Year Ended December 31, 2024 2023 2022 Net Production: Oil (MBbl) 26,511 22,013 16,090 Natural Gas (MMcf) 113,476 84,342 68,829 Total (MBoe) 45,423 36,070 27,562 Oil (MBbl) per day 72 60 44 Natural Gas (MMcf) per day 310 231 189 Total (MBoe) per day 124 99 76 Average Sales Prices: Oil (per Bbl) $ 71.59 $ 74.78 $ 91.65 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) (0.11) (0.90) (21.48) Oil, Net of Settled Oil Derivatives (per Bbl) 71.48 73.88 70.17 Natural Gas and NGLs (per Mcf) 2.24 2.98 7.43 Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.76 0.92 (1.60) Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) 3.00 3.90 5.83 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 47.38 52.61 72.05 Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) 1.83 1.61 (16.52) Realized Price on a Boe Basis Including Settled Commodity Derivatives 49.21 54.22 55.53 Average Costs: Production Expenses (per Boe) $ 9.46 $ 9.62 $ 9.46 41 Table of Contents The following table sets forth our production results for the years ended December 31, 2024, 2023 and 2022 in total and for each of our basins of operations.
Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, after adjustment to reflect applicable transportation and quality differentials.
Delivery Commitments For our properties in the Appalachian Basin, we have contractually agreed to deliver firm quantities of natural gas to certain third parties, which we seek to fulfill with production from existing reserves. In the event we are not able to meet these firm commitments, we are subject to deficiency payments.
Delivery Commitments For our properties in the Appalachian Basin, we have contractually agreed to deliver firm quantities of natural gas to certain unaffiliated third parties, which we seek to fulfill with production from existing reserves. In the event we are not able to meet these firm commitments, we are subject to deficiency payments.
All of our wells in the Williston and Permian Basins are classified as oil wells, although they also produce natural gas and condensate. All of our wells in the Appalachian Basin are classified as natural gas wells.
All of our wells in the Williston, Permian, and Uinta Basins are classified as oil wells, although they also produce natural gas and condensate. All of our wells in the Appalachian Basin are classified as natural gas wells.
Our executive internal reserve engineer has a B.S. in petroleum engineering from Montana Tech, has over eighteen years of oil and gas experience on the reservoir side, and has experience working for large independents on projects and acquisitions. In addition, we utilize a third-party reservoir engineering firm as our independent reserves auditor for 100% of our reserves base.
Our executive internal reserve engineer has a B.S. in petroleum engineering from Montana Tech, has over nineteen years of oil and gas experience on the reservoir side, and has experience working for large independents on projects and acquisitions. In addition, we utilize a third-party reservoir engineering firm as our independent reserves auditor for 100% of our reserves base.
As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2023, our future income taxes were significantly reduced. Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.
As a result of available net operating loss carryforwards and the remaining tax basis of our assets at December 31, 2024, our future income taxes were significantly reduced. Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.
Depletion of Oil and Natural Gas Properties Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses during 2023, 2022 and 2021.
Depletion of Oil and Natural Gas Properties Our depletion expense is driven by many factors including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. The following table presents our depletion expenses during 2024, 2023 and 2022.
Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. 36 Table of Contents The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2023 to the Standardized Measure of discounted future net cash flows.
Our PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. 36 Table of Contents The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2024 to the Standardized Measure of discounted future net cash flows.
All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan. At December 31, 2023, the PV-10 value of our proved undeveloped reserves amounted to 20% of the PV-10 value of our total proved reserves.
All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan. At December 31, 2024, the PV-10 value of our proved undeveloped reserves amounted to 20% of the PV-10 value of our total proved reserves.
The following table summarizes our cumulative gross and net productive oil and natural gas wells by geographic area within the United States at each of December 31, 2023, 2022 and 2021. Wells are classified as oil or natural gas wells according to the predominant production stream.
The following table summarizes our cumulative gross and net productive oil and natural gas wells by geographic area within the United States at each of December 31, 2024, 2023 and 2022. Wells are classified as oil or natural gas wells according to the predominant production stream.
In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 3 to our financial statements regarding our recent acquisition activity.
In those instances, we still review each lease on a lease-by-lease basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 3 to our financial statements regarding our recent acquisition activities.
Item 2. Properties Estimated Net Proved Reserves The table below summarizes our estimated net proved reserves at December 31, 2023 based on reports prepared by the Company for the year ended December 31, 2023 and audited by Cawley, our third-party independent reserve engineers.
Item 2. Properties Estimated Net Proved Reserves The table below summarizes our estimated net proved reserves at December 31, 2024 based on reports prepared by the Company for the year ended December 31, 2024 and audited by Cawley, our third-party independent reserve engineers.
In preparing its reports, the Company evaluated properties representing all of our proved reserves at December 31, 2023 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
In preparing its reports, the Company evaluated properties representing all of our proved reserves at December 31, 2024 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
(3) Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure. See “Reconciliation of PV-10 to Standardized Measure” above for a reconciliation of the PV-10 of our 2023 SEC Case proved reserves to the Standardized Measure. GAAP does not prescribe a corresponding measure for PV-10 of proved reserves based on other than SEC prices.
(4) Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure. See “Reconciliation of PV-10 to Standardized Measure” above for a reconciliation of the PV-10 of our 2024 SEC Case proved reserves to the Standardized Measure. GAAP does not prescribe a corresponding measure for PV-10 of proved reserves based on other than SEC prices.
As a non-operator, we have limited control over the drilling of new wells and primarily rely on our third-party operating partners in this regard. The following table summarizes our total net commitments as of December 31, 2023. (in Bcf) Commitment Volumes 2024 18.4 2025 3.2 Total 21.6
As a non-operator, we have limited control over the drilling of new wells and primarily rely on our third-party operating partners in this regard. The following table summarizes our total net commitments as of December 31, 2024. (in Bcf) Commitment Volumes 2025 3.2 Total 3.2
Although our 2023 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties.
Although our 2024 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties.
Our proved undeveloped locations were increased from 138.2 net wells at December 31, 2022 to 146.0 net wells at December 31, 2023 due to our 2023 acquisitions and increased development activity. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled under our acreage.
Our proved undeveloped locations were increased from 146.0 net wells at December 31, 2023 to 146.4 net wells at December 31, 2024 due to our 2024 acquisitions and increased development activity. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled under our acreage.
We also removed 24.9 MMBoe of proved undeveloped reserves due to the SEC-prescribed 5-year rule. Proved Reserves Sensitivity by Price Scenario The SEC disclosure rules allow for optional reserves sensitivity analysis, such as the sensitivity that oil and natural gas reserves have to price fluctuations.
We also removed 11.7 MMBoe of proved undeveloped reserves primarily due to the SEC-prescribed 5-year rule. Proved Reserves Sensitivity by Price Scenario The SEC disclosure rules allow for optional reserves sensitivity analysis, such as the sensitivity that oil and natural gas reserves have to price fluctuations.
Additional discussion of our proved reserves is set forth under the heading “Supplemental Oil and Gas Information - Unaudited” to our financial statements included later in this report. Proved Undeveloped Reserves At December 31, 2023, we had approximately 104.8 MMBoe of proved undeveloped reserves as compared to 116.2 MMBoe at December 31, 2022.
Additional discussion of our proved reserves is set forth under the heading “Supplemental Oil and Gas Information - Unaudited” to our financial statements included later in this report. Proved Undeveloped Reserves At December 31, 2024, we had approximately 100.3 MMBoe of proved undeveloped reserves as compared to 104.8 MMBoe at December 31, 2023.
During 2023, we increased our capital spending by 31% compared to 2022. With 78% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.
During 2024, we increased our capital spending by 2% compared to 2023. With 75% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.
The 2023 lease expirations carried a cost of $5.2 million. We believe that the expired acreage was not material to our capital deployed. As of December 31, 2023, we estimate that less than 1% of our proved undeveloped reserves were attributable to locations scheduled to be drilled after lease expiration.
The 2024 lease expirations carried a cost of $3.8 million. We believe that the expired acreage was not material to our capital deployed. As of December 31, 2024, we estimate that less th an 1% of our proved undeveloped reserves were attributable to locations scheduled to be drilled after lease expiration.
Year Ended December 31, (In thousands, except per Boe data) 2023 2022 2021 Depletion of Oil and Natural Gas Properties $ 482,306 $ 248,252 $ 138,759 Depletion Expense (per Boe) 13.37 9.01 7.07 Research and Development We do not anticipate performing any significant research and development under our plan of operation.
Year Ended December 31, (In thousands, except per Boe data) 2024 2023 2022 Depletion of Oil and Natural Gas Properties $ 736,600 $ 482,306 $ 248,252 Depletion Expense (per Boe) 16.22 13.37 9.01 Research and Development We do not anticipate performing any significant research and development under our plan of operation.
SEC Pricing Proved Reserves (In thousands) Standardized Measure Reconciliation Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $ 5,004,082 Future Income Taxes, Discounted at 10% (1) (847,845) Standardized Measure of Discounted Future Net Cash Flows $ 4,156,237 ____________ (1) The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows.
SEC Pricing Proved Reserves (In thousands) Standardized Measure Reconciliation Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $ 5,069,851 Future Income Taxes, Discounted at 10% (1) (838,931) Standardized Measure of Discounted Future Net Cash Flows $ 4,230,920 ____________ (1) The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows.
December 31, 2023 2022 2021 Gross Net (1) Gross Net (1) Gross Net (1) Exploratory Wells: Oil — — — — — — Natural Gas — — — — — — Non-Productive — — — — — — Development Wells: Oil 803 76.1 550 55.9 354 33.6 Natural Gas 16 0.5 7 0.9 8 2.2 Non-Productive — — — — — — Total Productive Exploratory and Development Wells 819 76.6 557 56.8 362 35.8 ______________ (1) Net Well totals in 2023, 2022 and 2021 do not include an additional 80.4, 66.4 and 169.4 net wells, respectively, from acquisitions which were already producing when acquired.
December 31, 2024 2023 2022 Gross Net (1) Gross Net (1) Gross Net (1) Development Wells: Oil 790 86.9 803 76.1 550 55.9 Natural Gas 29 3.8 16 0.5 7 0.9 Non-Productive — — — — — — Total Development Wells 819 90.7 819 76.6 557 56.8 ______________ (1) Net Well totals in 2024, 2023 and 2022 do not include an additional 69.4, 80.4 and 66.4 net wells, respectively, from acquisitions which were already producing when acquired.
At December 31, 2023, we had spent a total of $327.8 million related to the development of proved undeveloped reserves, which resulted in the conversion of 27.9 MMBoe of proved undeveloped reserves as of December 31, 2022 to proved developed reserves as of December 31, 2023.
At December 31, 2024, we had spent a total of $398.5 million related to the development of proved undeveloped reserves, which resulted in the conversion of 51.9 MMBoe of proved undeveloped reserves as of December 31, 2023 to proved developed reserves as of December 31, 2024.
A reconciliation of the change in proved undeveloped reserves during 2023 is as follows: MMBoe Estimated Proved Undeveloped Reserves at 12/31/2022 116.2 Converted to Proved Developed Through Drilling (27.9) Added from Extensions and Discoveries 24.6 Purchases of Minerals in Place 23.4 Removed for 5-Year Rule (24.9) Revisions (6.6) Estimated Proved Undeveloped Reserves at 12/31/2023 104.8 Our future development drilling program includes the drilling of approximately 146.0 proved undeveloped net wells before the end of 2028 at an estimated cost of $1.2 billion.
A reconciliation of the change in proved undeveloped reserves during 2024 is as follows: MMBoe Estimated Proved Undeveloped Reserves at 12/31/2023 104.8 Converted to Proved Developed Through Drilling (51.9) Added from Extensions and Discoveries 22.7 Purchases of Minerals in Place 21.0 Removed for 5-Year Rule (11.7) Revisions 15.4 Estimated Proved Undeveloped Reserves at 12/31/2024 100.3 Our future development drilling program includes the drilling of approximately 146.4 proved undeveloped net wells before the end of 2029 at an estimated cost of $1.3 billion.
Proved developed property additions in 2023 also included 12.4 MMBoe from the conversion of previously undeveloped locations that were not booked in our December 31, 2022 proved undeveloped reserves (the related development costs incurred at December 31, 2023 were $242.8 million).
Proved developed property additions in 2024 also included 13.1 MMBoe from the conversion of previously undeveloped locations that were not booked in our December 31, 2023 proved undeveloped reserves (the related development costs incurred at December 31, 2024 were $175.7 million).
Leasehold Properties As of December 31, 2023, our principal assets included approximately 272,251 net acres located in the United States.
Leasehold Properties As of December 31, 2024, our principal assets included approximately 292,500 net acres located in the United States.
Our development plan for drilling proved undeveloped wells calls for the drilling of 90.9 net wells during 2024 (includes 55.8 net wells spud at December 31, 2023, but classified as proved undeveloped due to Cawley’s internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 19.4 net wells during 2025, 18.7 net wells during 2026, 11.6 net wells during 2027, and 5.4 net wells during 2028 for a total of 146.0 net wells.
Our development plan for drilling proved undeveloped wells calls for the drilling of 71.7 net wells during 2025 (includes 30.1 net wells spud at December 31, 2024, but classified as proved undeveloped due to internal guidelines which require greater than 50% of total costs to be incurred to be classified as developed), 32.2 net wells during 2026, 23.9 net wells during 2027, 12.9 net wells during 2028, and 5.7 net wells during 2029 for a total of 146.4 net wells.
The average resulting price used as of December 31, 2023, after adjustment to reflect applicable transportation and quality differentials, was $75.51 per barrel of oil and $3.10 per Mcf of natural gas.
The average resulting price used as of December 31, 2024, after adjustment to reflect applicable transportation and quality differentials, was $70.60 per barrel of oil and $2.02 per Mcf of natural gas.
(2) The table above values oil and natural gas reserve quantities as of December 31, 2022, assuming constant realized prices of $91.95 per barrel of oil and $7.43 per Mcf of natural gas.
(2) The table above values oil and natural gas reserve quantities as of December 31, 2023, assuming constant realized prices of $75.51 per barrel of oil and $3.10 per Mcf of natural gas.
The table below shows our proved reserves utilizing the 2023 SEC Case compared with the $70 Flat Case.
The table below shows our proved reserves utilizing the 2024 SEC Case compared with the $80 Flat Case and the $60 Flat Case.
December 31, 2023 2022 2021 Gross Net Gross Net Gross Net Williston Basin 7,981 643.7 7,487 608.0 6,996 571.7 Permian Basin 1,387 207.6 818 92.8 83 11.6 Appalachian Basin 397 100.3 367 98.5 357 97.5 Total 9,765 951.6 8,672 799.3 7,436 680.8 As of December 31, 2023, we had an additional 512 gross (66.5 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.
December 31, 2024 2023 2022 Gross Net Gross Net Gross Net Williston Basin 8,278 664.0 7,981 643.7 7,487 608.0 Permian Basin 1,895 302.3 1387 207.6 818 92.8 Appalachian Basin 424 104.3 397 100.3 367 98.5 Uinta Basin 271 37.4 — — — — Total 10,868 1,108.0 9,765 951.6 8,672 799.3 As of December 31, 2024, we had an additional 485 gross (50.4 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.
The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $75.51 per Bbl for oil and $3.10 per Mcf for natural gas.
The unescalated twelve month arithmetic average of the first day of the month posted prices were adjusted for transportation and quality differentials to arrive at prices of $70.60 per Bbl for oil and $2.02 per Mcf for natural gas. Production costs were held constant for the life of the wells.
In 2023, we also added 24.6 MMBoe of proved undeveloped reserves as a result of our development activity. We added an additional 23.4 MMBoe from our acquisitions.
In 2024, we also added 22.7 MMBoe of proved undeveloped reserves as a result of our development activity. We added an additional 21.0 MMBoe from our acquisitions.
The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $16.44 lower per barrel of oil and $4.33 lower per Mcf of natural gas at year-end 2023 as compared to year-end 2022. Additionally, we had negative revisions of 6.6 MMBoe primarily due to the aforementioned lower pricing.
The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $4.91 lower per barrel of oil and $1.08 lower per Mcf of natural gas at year-end 2024 as compared to year-end 2023. Additionally, we had positive revisions of 15.4 MMBoe primarily due to continued development in already proven areas.
We have chosen to compare our proved reserves calculated using SEC Pricing (the “2023 SEC Case”) to one alternate pricing case, which uses a flat pricing deck of $70.00 per Bbl for oil and $3.00 per MMbtu for natural gas (the “$70 Flat Case”). The sensitivity scenario was not audited by a third-party.
We have chosen to compare our proved reserves calculated using SEC Pricing (the “2024 SEC Case”) to two alternate pricing cases. The first case scenario uses a flat pricing deck of $80.00 per Bbl for oil and $4.00 per MMbtu for natural gas (the “$80 Flat Case”).
December 31, 2023 December 31, 2022 Proved Reserves (MBoe)(1) % of Total Proved Reserves (MBoe)(2) % of Total SEC Proved Reserves: Developed 234,861 69 % 214,602 65 % Undeveloped 104,833 31 % 116,207 35 % Total Proved Properties 339,694 100 % 330,809 100 % ___________________ (1) The table above values oil and natural gas reserve quantities as of December 31, 2023, assuming constant realized prices of $75.51 per barrel of oil and $3.10 per Mcf of natural gas.
December 31, 2024 December 31, 2023 Proved Reserves (MBoe)(1) % of Total Proved Reserves (MBoe)(2) % of Total SEC Proved Reserves: Developed 278,151 73 % 234,861 69 % Undeveloped 100,333 27 % 104,833 31 % Total Proved Properties 378,484 100 % 339,694 100 % ___________________ (1) The table above values oil and natural gas reserve quantities as of December 31, 2024, assuming constant realized prices of $70.60 per barrel of oil and $2.02 per Mcf of natural gas.
Estimated net proved reserves at December 31, 2023 were 339,694 MBoe, a 3% increase from estimated net proved reserves of 330,809 MBoe at December 31, 2022. The increase was primarily due to the impact of our 2023 acquisitions, as well as higher activity levels in 2023 as compared to 2022.
Estimated net proved reserves at December 31, 2024 were 378,484 MBoe, an 11% increase from estimated net proved reserves of 339,694 MBoe at December 31, 2023. The increase was primarily due to the impact of our 2024 acquisitions, as well as organic drilling activities in 2024.
Production costs were held constant for the life of the wells. 38 Table of Contents (2) Prices based on $70.00 per Bbl for oil and $3.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $67.38 per Bbl for oil and $3.42 per Mcf for natural gas.
(2) Prices based on $80.00 per Bbl for oil and $4.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $75.10 per Bbl for oil and $3.88 per Mcf for natural gas. 38 Table of Contents (3) Prices based on $60.00 per Bbl for oil and $3.00 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $55.22 per Bbl for oil and $2.85 per Mcf for natural gas.
Additionally, our proved undeveloped reserves at December 31, 2023 included 58.6 MMBoe for net wells that had commenced drilling activities but remained classified as undeveloped reserves due to Cawley’s internal guidelines which require greater than 50% of the total costs to have been incurred in order to be classified as proved developed (the related development costs incurred at December 31, 2023 were $175.7 million).
Additionally, our proved undeveloped reserves at December 31, 2024 included 29.7 MMBoe for net wells that had commenced drilling activities but remained classified as undeveloped reserves due to more than half of the capital expenditures that remain to be incurred for completion of the wells (the related development costs incurred at December 31, 2024 were $101.7 million).
As a result, the $70 Flat Case included 7.9 fewer proved undeveloped net wells compared to the 146.0 proved undeveloped net wells included in the 2023 SEC Case. This sensitivity is only meant to demonstrate the impact that changing commodity prices may have on estimated proved reserves and PV-10 and there is no assurance this outcome will be realized.
The change in pricing in the $60 Flat Case resulted in fewer future drilling locations that were considered economic compared to the 2024 SEC Case. This sensitivity analysis is only meant to demonstrate the impact that changing commodity prices may have on estimated proved reserves and PV-10 values. There is no assurance that any particular outcome will be realized.
The approximate expiration of our net acres which are subject to expire between 2024 and 2028 and thereafter, are set forth below: Acreage Subject to Expiration Year Ended Gross Net December 31, 2024 42,286 8,442 December 31, 2025 23,876 5,896 December 31, 2026 9,178 1,595 December 31, 2027 20,784 1,746 December 31, 2028 and thereafter 19,162 7,571 Total 115,286 25,250 During 2023, we had leases expire covering approximately 5,173 net acres.
The approximate expiration of our net acres which are subject to expire between 2025 and 2029 and thereafter, are set forth below: Acreage Subject to Expiration Year Ended Gross Net December 31, 2025 25,763 5,743 December 31, 2026 7,886 1,902 December 31, 2027 11,907 3,074 December 31, 2028 7,457 2,138 December 31, 2029 and thereafter 4,183 2,670 Total 57,196 15,527 During 2024, we had leases expire covering approximately 4,510 net acres.
As a result of the higher activity levels and our 2023 acquisitions, the number of proved undeveloped wells included in the reserves was increased from 138.2 net wells in 2022 to 146.0 net wells in 2023. 35 Table of Contents The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2023: SEC Pricing Proved Reserves (1) Reserve Volumes PV-10 (3) Reserve Category Oil (MBbls) Natural Gas (MMcf) Total (MBoe) (2) % Amount (In thousands) % PDP Properties 118,634 662,079 228,981 67 % $ 3,899,733 78 % PDNP Properties 3,230 15,899 5,880 2 % 113,577 2 % PUD Properties 48,477 338,138 104,833 31 % 990,772 20 % Total 170,341 1,016,116 339,694 100 % $ 5,004,082 100 % _____ ___________ (1) The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2023, based on average prices of $78.22 per barrel of oil and $2.64 per MMbtu of natural gas.
As of December 31, 2024 and 2023, we had 146.4 and 146.0 net proved developed wells, respectively, included in our reserves. 35 Table of Contents The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2024: SEC Pricing Proved Reserves (1) Reserve Volumes PV-10 (3) Reserve Category Oil (MBbls) Natural Gas (MMcf) Total (MBoe) (2) % Amount (In thousands) % PDP Properties 128,508 728,333 249,897 66 % $ 3,791,530 75 % PDNP Properties 7,049 127,227 28,254 7 % 259,341 5 % PUD Properties 59,554 244,677 100,333 27 % 1,018,980 20 % Total 195,111 1,100,237 378,484 100 % $ 5,069,851 100 % _____ ___________ (1) The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2024, based on average prices of $75.48 per barrel of oil and $2.13 per MMbtu of natural gas.
Year Ended December 31, 2023 2022 2021 Net Production: Oil (Bbl) Williston Basin 12,746,957 11,651,938 11,683,218 Permian Basin 9,266,029 4,438,134 605,140 Appalachian Basin — — — Total 22,012,986 16,090,072 12,288,358 Natural Gas and NGLs (Mcf) Williston Basin 31,102,642 27,027,761 23,186,806 Permian Basin 28,594,041 14,255,738 1,111,673 Appalachian Basin 24,645,175 27,545,643 19,775,462 Total 84,341,858 68,829,142 44,073,941 Crude Oil Equivalents (Boe) Williston Basin 17,930,730 16,156,565 15,547,686 Permian Basin 14,031,702 6,814,090 790,419 Appalachian Basin 4,107,529 4,590,941 3,295,910 Total 36,069,961 27,561,596 19,634,015 42 Table of Contents Drilling and Development Activity The following table sets forth the number of gross and net productive and non-productive wells drilled in the years ended December 31, 2023, 2022 and 2021.
Year Ended December 31, 2024 2023 2022 Net Production: Oil (MBbl) Williston Basin 12,241 12,747 11,652 Permian Basin 13,529 9,266 4,438 Appalachian Basin 56 — — Uinta Basin 685 — — Total 26,511 22,013 16,090 Natural Gas and NGLs (MMcf) Williston Basin 31,518 31,103 27,028 Permian Basin 44,621 28,594 14,256 Appalachian Basin 36,785 24,645 27,546 Uinta Basin 552 — — Total 113,476 84,342 68,829 Crude Oil Equivalents (MBoe) Williston Basin 17,494 17,931 16,157 Permian Basin 20,966 14,032 6,814 Appalachian Basin 6,186 4,108 4,591 Uinta Basin 777 — — Total 45,423 36,070 27,562 42 Table of Contents Drilling and Development Activity The following table sets forth the number of gross and net productive and non-productive wells drilled in the years ended December 31, 2024, 2023 and 2022.
In this sensitivity scenario, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the 2023 SEC Case. However, the change in pricing in the sensitivity scenario did result in fewer future drilling locations that were economic at the $70 Flat Case compared to the 2023 SEC Case.
The second scenario uses a flat pricing deck of $60.00 per Bbl for oil and $3.00 per MMbtu for natural gas (the “$60 Flat Case”). The sensitivity scenarios were not audited by a third-party. In these sensitivity scenarios, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the 2024 SEC Case.
Removed
Increased development activity in 2023 led to an increase in our capital spending as well as an increase in the number of undeveloped drilling locations reflected in our 2023 proved reserve estimates.
Added
Price Cases 2024 SEC Case (1) $80 Flat Case (2) $60 Flat Case (3) Net Proved Reserves (December 31, 2024) Oil (MBbl) Developed 135,558 140,719 127,434 Undeveloped 59,554 61,044 53,303 Total 195,112 201,763 180,737 Natural Gas (MMcf) Developed 855,561 918,639 864,266 Undeveloped 244,677 249,674 234,286 Total 1,100,238 1,168,313 1,098,552 Total Proved Reserves (MBOE) 378,484 396,482 363,829 Pre-tax PV10% (in thousands) (4) $ 5,069,851 $ 6,625,185 $ 3,920,353 _________________ (1) Represents reserves based on pricing prescribed by the SEC.
Removed
Price Cases 2023 SEC Case (1) $70 Flat Case (2) Net Proved Reserves (December 31, 2023) Oil (MBbl) Developed 121,865 118,877 Undeveloped 48,477 45,874 Total 170,342 164,751 Natural Gas (MMcf) Developed 677,978 686,780 Undeveloped 338,138 333,651 Total 1,016,116 1,020,431 Total Proved Reserves (MBOE) 339,694 334,823 Pre-tax PV10% (in thousands) (3) $ 5,004,082 $ 4,438,111 _________________ (1) Represents reserves based on pricing prescribed by the SEC.
Added
The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2024. 43 Table of Contents Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Williston Basin 895,223 168,906 43,545 10,303 938,768 179,209 Permian Basin 173,353 36,348 35,154 7,893 208,507 44,241 Appalachian Basin 129,077 27,333 96,088 25,810 225,165 53,143 Uinta Basin 248,354 14,525 51,876 1,382 300,230 15,907 Total: 1,446,007 247,112 226,663 45,388 1,672,670 292,500 As of December 31, 2024, approximately 84% of our total acreage was developed.
Removed
The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2023. 43 Table of Contents Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Williston Basin 889,133 166,567 72,862 14,074 961,995 180,641 Permian Basin 169,788 30,513 25,599 6,063 195,387 36,576 Appalachian Basin 195,910 46,473 45,986 8,561 241,896 55,034 Total: 1,254,831 243,553 144,447 28,698 1,399,278 272,251 As of December 31, 2023, approximately 89% of our total acreage was developed.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

10 edited+1 added−2 removed5 unchanged
Biggest changeSubsequently, our board of directors declared and paid incrementally higher quarterly cash dividends through the $0.40 per share cash dividend declared on October 30, 2023 and paid on January 31, 2024 to stockholders of record as of the close of business on December 28, 2023.
Biggest changeSubsequently, our board of directors declared and paid incrementally higher quarterly cash dividends through the $0.42 per share cash dividend declared on August 6, 2024 and paid on October 31, 2024 to stockholders of record as of the close of business on September 27, 2024 and the $0.42 per share cash dividend declared on November 26, 2024 and paid on January 31, 2025 to stockholders of record as of the close of business on December 30, 2024.
Issuer Purchases of Equity Securities The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act), of our common stock during the quarter ended December 31, 2023.
Issuer Purchases of Equity Securities The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act), of our common stock during the quarter ended December 31, 2024.
Most recently, on February 5, 2024, our board of directors declared a cash dividend on our common stock in the amount of $0.40 per share, payable on April 30, 2024 to stockholders of record as of the close of business on March 28, 2024.
Most recently, on January 28, 2025, our board of directors declared a cash dividend on our common stock in the amount of $0.45 per share, payable on April 30, 2025 to stockholders of record as of the close of business on March 28, 2025.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common stock trades on the New York Stock Exchange under the symbol “NOG.” The closing price for our common stock on February 21, 2024 was $34.89 per share.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common stock trades on the New York Stock Exchange under the symbol “NOG.” The closing price for our common stock on February 18, 2025 was $35.19 per share.
Period Total Number of Shares Purchased(1) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(2) October 1, 2023 to October 31, 2023 — $ — — $ 87.5 million November 1, 2023 to November 30, 2023 — — — 87.5 million December 1, 2023 to December 31, 2023 — — — 87.5 million Total — $ — — $ 87.5 million __________________________________ (1) Any shares purchased outside of publicly announced plans or programs represent shares surrendered in satisfaction of tax withholding obligations in connection with the vesting of restricted stock awards.
Period Total Number of Shares Purchased(1) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(2) October 1, 2024 to October 31, 2024 — $ — — $ 135.5 million November 1, 2024 to November 30, 2024 — — — 135.5 million December 1, 2024 to December 31, 2024 723,525 36.27 693,658 110.3 million Total 723,525 $ 36.28 693,658 $ 110.3 million __________________________________ (1) Any shares purchased outside of publicly announced plans or programs represent shares surrendered in satisfaction of tax withholding obligations in connection with the vesting of restricted stock awards.
(2) In May 2022, our board of directors approved and the Company promptly announced a stock repurchase program to acquire up to $150 million of shares of our outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
(2) On July 23, 2024, the Company’s board of directors approved and promptly announced a stock repurchase program to acquire up to $150 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
The following graph compares the 60-month cumulative total stockholder return on our common stock since December 31, 2018, and the cumulative total returns of the Standard & Poor’s 500 Index, the XOP and the Arca Index for the same period.
The following graph compares the 60-month cumulative total stockholder return on our common stock since December 31, 2019, and the cumulative total returns of the Standard & Poor’s 500 Index and the SPDR S&P Oil & Gas Exploration & Production ETF for the same period.
Holders As of February 21, 2024, we had 100,873,127 shares of our common stock outstanding, held by approximately 183 stockholders of record.
Holders As of February 18, 2025, we had 99,113,645 shares of our common stock outstanding, held by approximately 130 stockholders of record.
This graph tracks the performance of a $100 investment in our common stock and in each index (including reinvestment of all dividends) from December 31, 2018 to December 31, 2023. 46 Table of Contents The following table sets forth the total returns utilized to generate the foregoing graph. 12/31/2018 12/31/2019 12/31/2020 12/31/2021 12/31/2022 12/31/2023 Northern Oil & Gas, Inc. 100.00 103.54 38.76 91.75 141.67 177.68 S&P 500 100.00 131.49 155.68 200.37 164.08 207.21 SPDR S&P Oil & Gas Exploration & Production ETF 100.00 90.56 57.59 96.03 139.60 144.57 NYSE Arca Oil Index 100.00 119.15 82.22 106.64 150.11 164.57 The stock price performance included in this graph is not necessarily indicative of future stock price performance.
This graph tracks the performance of a $100 investment in our common stock and in each index (including reinvestment of all dividends) from December 31, 2019 to December 31, 2024. 46 Table of Contents The following table sets forth the total returns utilized to generate the foregoing graph. 12/31/2019 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024 Northern Oil & Gas, Inc. 100.00 37.44 88.61 136.82 171.61 179.77 S&P 500 100.00 118.40 152.39 124.79 157.59 197.02 SPDR S&P Oil & Gas Exploration & Production ETF 100.00 63.6 106.04 154.15 159.64 158.04 The stock price performance included in this graph is not necessarily indicative of future stock price performance.
In connection with the announcement of the latest dividend declaration, we affirmed our intention to set our dividend policy once per year, and currently anticipate maintaining a $0.40 per share quarterly dividend throughout 2024. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors.
The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors.
Removed
Because we believe the new index is a more appropriate index for comparison, in 2023 we chose to compare our cumulative total stockholder return against the SPDR S&P Oil & Gas Exploration & Production ETF (the “XOP”), instead of the NYSE Arca Oil Index (the “Arca Index”).
Added
We have announced our intention to set our dividend policy once per year, with the potential for interim modifications driven by material changes in realized commodity prices, significant corporate actions or other events, and currently anticipate maintaining a $0.45 per share quarterly dividend throughout 2025.
Removed
If a company selects a different index for comparison from that used in the immediately preceding fiscal year, the company’s stock performance must be compared with both the newly-selected index and the index used in the immediately preceding year.

Item 7. Management's Discussion & Analysis

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

103 edited+14 added−21 removed54 unchanged
Biggest changeYear Ended December 31, 2023 2022 Net Production: Oil (Bbl) 22,012,986 16,090,072 Natural Gas and NGLs (Mcf) 84,341,858 68,829,142 Total (Boe) 36,069,962 27,561,596 Net Sales (in thousands): Oil Sales $ 1,646,096 $ 1,474,610 Natural Gas and NGL Sales 251,683 511,188 Gain (Loss) on Settled Commodity Derivatives 57,919 (455,450) Gain on Unsettled Commodity Derivatives 201,331 40,187 Other Revenue 9,230 — Total Revenues 2,166,259 1,570,535 Average Sales Prices: Oil (per Bbl) $ 74.78 $ 91.65 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) (0.90) (21.48) Oil Net of Settled Oil Derivatives (per Bbl) 73.88 70.17 Natural Gas and NGLs (per Mcf) 2.98 7.43 Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.92 (1.60) Natural Gas and NGLs Net of Settled Natural Gas Derivatives (per Mcf) 3.90 5.83 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 52.61 72.05 Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe) 1.61 (16.52) Realized Price on a Boe Basis Including Settled Commodity Derivatives 54.22 55.53 Operating Expenses (in thousands): Production Expenses $ 347,006 $ 260,676 Production Taxes 160,118 158,194 General and Administrative Expenses 46,801 47,201 Depletion, Depreciation, Amortization and Accretion 486,024 251,272 Other Expenses 4,448 — Costs and Expenses (per Boe): Production Expenses $ 9.62 $ 9.46 Production Taxes 4.44 5.74 General and Administrative Expenses 1.30 1.71 Depletion, Depreciation, Amortization and Accretion 13.47 9.12 Net Producing Wells at Period-End 951.6 799.3 53 Table of Contents Oil and Natural Gas Sales Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.
Biggest changeYear Ended December 31, 2024 2023 Net Production: Oil (MBbl) 26,511 22,013 Natural Gas (MMcf) 113,476 84,342 Total (MBoe) 45,423 36,070 Net Sales (in thousands): Oil Sales $ 1,897,857 $ 1,646,096 Natural Gas and NGL Sales 254,222 251,683 Gain on Settled Commodity Derivatives 83,225 57,919 Gain (Loss) on Unsettled Commodity Derivatives (21,258) 201,331 Other Revenue 11,683 9,230 Total Revenues 2,225,729 2,166,259 Average Sales Prices: Oil (per Bbl) $ 71.59 $ 74.78 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) (0.11) (0.90) Oil, Net of Settled Oil Derivatives (per Bbl) 71.48 73.88 Natural Gas and NGLs (per Mcf) 2.24 2.98 Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.76 0.92 Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) 3.00 3.90 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives 47.38 52.61 Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) 1.83 1.61 Realized Price on a Boe Basis Including Settled Commodity Derivatives 49.21 54.22 Operating Expenses (in thousands): Production Expenses $ 429,792 $ 347,006 Production Taxes 157,091 160,118 General and Administrative Expenses 50,463 46,801 Depletion, Depreciation, Amortization and Accretion 740,901 486,024 Other Expense 9,650 4,448 Costs and Expenses (per Boe): Production Expenses $ 9.46 $ 9.62 Production Taxes 3.46 4.44 General and Administrative Expenses 1.11 1.30 Depletion, Depreciation, Amortization and Accretion 16.31 13.47 Net Producing Wells at Period-End 1,108.0 951.6 53 Table of Contents Oil and Natural Gas Sales Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes.
If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow.
If oil, natural gas and NGL prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow.
To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a capitalized ceiling impairment.
To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount rate and based on 12-month/SEC oil and natural gas prices) of the estimated future net cash flows from our proved oil and natural gas reserves and the capitalized cost associated with our unproved properties, we would have a non-cash ceiling impairment.
Such costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary.
Such impairment costs would be charged to operations as a reduction of the carrying value of oil and natural gas properties. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian and Appalachian Basins subjects our operating results to factors specific to these regions.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Permian, Appalachian, and Uinta Basins subjects our operating results to factors specific to these operating regions.
The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and gas properties.
The Revolving Credit Facility is subject to a borrowing base with maximum loan value to be assigned to the proved reserves attributable to our oil and natural gas properties.
Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Based on current conditions and expectations, we are not budgeting for any significant change in per well drilling and completion and other associated costs in 2024 compared to 2023.
Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Based on current conditions and expectations, we are not budgeting for any significant change in per well drilling and completion and other associated costs in 2025 compared to 2024.
Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: • the timing and success of drilling and production activities by our operating partners; • the prices and the supply and demand for oil, natural gas and NGLs; • the quantity of oil and natural gas production from the wells in which we participate; • changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices; • our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and • the level of our operating expenses.
Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: • the timing and success of drilling and production activities by our operating partners; • the prices and the supply and demand for oil, natural gas and NGLs; • the quantity of oil and natural gas production from the wells in which we participate; • changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in commodity prices; 50 Table of Contents • our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and • the level of our operating expenses.
See also Note 12 to our financial statements. 52 Table of Contents Results of Operations for 2023 and 2022 The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
See also Note 12 to our financial statements. 52 Table of Contents Results of Operations for 2024 and 2023 The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, 59 Table of Contents fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, fluctuations in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 31% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves.
In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 27% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves.
We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. See “Item 7A.
We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 36 months. See “Item 7A.
See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022 for discussion and analysis of results of operations for the year ended December 31, 2021.
See Item 7., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2023 for discussion and analysis of results of operations for the year ended December 31, 2022.
For a summary as of December 31, 2023, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below.
For a summary as of December 31, 2024, of our open commodity price derivative contracts for future periods, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in Item 7A below.
In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if 61 Table of Contents estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity.
In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or if estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity.
Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and 60 Table of Contents engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions.
Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions.
Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end. • Production expenses.
Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end. 49 Table of Contents • Production expenses.
Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized 54 Table of Contents immediately into earnings.
Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings.
The increase in depletion rate per Boe for 2023 as compared to 2022 was primarily due to a significant increase to our depletable base, due to the closing of several larger acquisitions in 2022 and 2023 (see Note 3 to our financial statements).
The increase in depletion rate per Boe for 2024 as compared to 2023 was primarily due to a significant increase to our depletable cost base, due to the closing of several larger acquisitions in 2023 and 2024 (see Note 3 to our financial statements).
These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly 50 Table of Contents during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.
These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these operating regions.
During 2023 and 2022, we added 76.6 and 56.8 net wells to production, respectively, excluding already producing wells from acquisitions. Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity.
During 2024 and 2023, we added 90.7 and 76.6 net wells to production, respectively, excluding already producing wells from acquisitions. Our cash flows used in investing activities reflects actual cash spending, which can lag several months from when the related costs were incurred. As a result, our actual cash spending is not always reflective of current levels of development activity.
We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.
Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.
The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price.
The price at which our oil production is sold typically reflects a discount to the NYMEX WTI benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX Henry Hub benchmark price.
Our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc., audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2023. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC.
Our third-party independent reserve engineers, Cawley, audited 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2024. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC.
The decrease in the net liability at December 31, 2023 as compared to December 31, 2022 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2022. Our open commodity derivative contracts are summarized in “Item 7A.
The increase in the net liability at December 31, 2024 as compared to December 31, 2023 was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2023. Our open commodity derivative contracts are summarized in “Item 7A.
Oil accounted for 87% and 74% of our total oil and gas sales in 2023 and 2022, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices.
Oil accounted for 88% and 87% of our total oil and gas sales in 2024 and 2023, respectively. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas and NGL prices.
In addition, the number of net wells we added to production (excluding acquisitions) increased by 35% in 2023 as compared to 2022, due to our growing organic acreage footprint and increased development on our properties.
In addition, the number of net wells we added to production (excluding acquisitions) increased by 18% in 2024 as compared to 2023, due to our growing organic acreage footprint and increased development on our properties.
For instance, during the year ended December 31, 2023, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g. drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1,925.9 million, while the actual cash spend in this regard amounted to $1,861.1 million. Development and acquisition activities are discretionary.
For instance, during the year ended December 31, 2024, our capitalized costs incurred, excluding non-cash consideration, for oil and natural gas properties (e.g., drilling and completion costs, acquisitions, and other capital expenditures) amounted to $1.9 billion, while the actual cash spend in this regard amounted to $1.7 billion. Development and acquisition activities are discretionary.
Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods. For the year ended December 31, 2023, our average depletion expense per unit of production w as $13.37 per Boe.
Subsequent reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting periods. For the year ended December 31, 2024, our average depletion expense per unit of production w as $16.22 per Boe.
Our substantial acquisition activities in 2022 and 2023 (see Note 3 to our financial statements) helped drive the 31% increase in production levels in 2023 as compared to 2022.
Our substantial acquisition activities in 2024 and 2023 (see Note 3 to our financial statements) helped drive the 26% increase in production levels in 2024 as compared to 2023.
Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark and the sales prices we receive for our production. Our oil price differential to the NYMEX benchmark price during 2023 was $2.83 per barrel, as compared to $2.73 per barrel in 2022.
Thus, our operating results are also affected by changes in the price differentials between the applicable benchmark prices and the sales prices we receive for our production. Our average oil price differential to the NYMEX WTI benchmark price during 2024 was $3.88 per barrel, as compared to $2.83 per barrel in 2023.
For a summary as of December 31, 2023, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
For a summary as of December 31, 2024, of our open 56 Table of Contents commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of accumulated other comprehensive income or other income (expense). The resulting cash flows from derivatives are reported as cash flows from operating activities.
Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses on unsettled derivatives, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of accumulated other comprehensive income or other income (expense).
Principal Components of Our Cost Structure • Commodity price differentials . The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.
The price differential between our well head price for oil and the NYMEX WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.
We had total liquidity of $1,097.2 million as of December 31, 2023, consisting of $1,089.0 million of committed borrowing availability under the Revolving Credit Facility and $8.2 million of cash on hand. One of the primary sources of variability in our cash flows from operating activities is commodity price volatility.
As of December 31, 2024, we had total liquidity of $818.9 million, consisting of $810.0 million of committed borrowing availability under the Revolving Credit Facility and $8.9 million of cash on hand. One of the primary sources of variability in our cash flows from operating activities is commodity price volatility.
This represented significant growth from 2022, which was driven in large part by our substantial acquisition activity in 2022 and 2023, as described in Note 3 to our financial statements. During 2023, we added 76.6 new net wells to production, plus an additional 80.4 net wells added from acquisitions which were already producing when acquired.
This represented significant growth from 2023, which was driven in large part by our substantial acquisition activities in 2023 and 2024, as described in Note 3 to our financial statements. During 2024, we added 90.7 new net wells to production, plus an additional 69.4 net wells added from acquisitions which were already producing when acquired.
As of December 31, 2023, we had incurred $236 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $393 million in development capital expenditures not yet incurred for wells we had elected to participate in.
As of December 31, 2024, we had incurred $331.0 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $376.9 million in development capital expenditures not yet incurred for wells we had elected to participate in.
Executive Overview Our primary strategy is to invest in non-operated minority working and mineral interests in oil and gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 9,765 gross (951.6 net) producing wells as of December 31, 2023.
Executive Overview Our primary strategy is to invest in non-operated minority working and mineral interests in oil and natural gas properties, with a core area of focus in the premier basins within the United States. Using this strategy, we had participated in 10,868 gross (1,108 net) producing wells as of December 31, 2024.
Our cash spend for development and acquisition activities for the years ended December 31, 2023 and 2022 are summarized in the following table: Year Ended December 31, (In millions) 2023 2022 Drilling and Development Capital Expenditures $ 809.8 $ 392.5 Acquisition of Oil and Natural Gas Properties 1,047.7 958.8 Other Capital Expenditures 3.6 4.0 Total $ 1,861.1 $ 1,355.2 Cash Flows from Financing Activities Net cash provided by financing activities was $684.7 million and $467.4 million for the years ended December 31, 2023 and 2022, respectively.
Our cash spend for development and acquisition activities for the years ended December 31, 2024 and 2023 are summarized in the following table: Year Ended December 31, (In millions) 2024 2023 Drilling and Development Capital Expenditures $ 771.3 $ 809.8 Acquisition of Oil and Natural Gas Properties 900.2 1,047.7 Other Capital Expenditures 3.2 3.6 Total $ 1,674.6 $ 1,861.1 Cash Flows from Financing Activities Net cash provided by financing activities was $266.8 million and $684.7 million for the years ended December 31, 2024 and 2023, respectively.
As of December 31, 2023, we had outstanding debt consisting of $161.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028, $500.0 million aggregate principal amount of our Convertible Notes, and $500.0 million aggregate principal amount of our Senior Notes due 2031.
As of December 31, 2024, we had outstanding total debt consisting of $690.0 million of borrowings under our Revolving Credit Facility, $705.1 million aggregate principal amount of our Senior Notes due 2028 (as defined herein), $500.0 million aggregate principal amount of our Senior Notes due 2031 (as defined herein), and $500.0 million aggregate principal amount of our Convertible Notes due 2029 (as defined herein).
As a percentage of oil and natural gas sales, our production taxes were 8.4% and 8.0% in 2023 and 2022, respectively.
As a percentage of oil and natural gas sales, our production taxes were 7.3% and 8.4% in 2024 and 2023, respectively.
Fluctuations in our oil and gas price realizations are due to several factors such as pricing by basin, gathering and transportation costs, transportation method, takeaway capacity relative to production levels, regional storage capacity, seasonal refinery maintenance temporarily depressing demand, and in the case of gas realizations, the price of NGLs. Another significant factor affecting our operating results is drilling costs.
Fluctuations in our oil and gas price realizations are due to several factors, such as realized pricing by basin, gathering and transportation costs, transportation methods, takeaway capacity relative to production levels, regional storage capacity, seasonal refinery maintenance, temporarily depressing demand, and in the case of gas realizations, the price of NGLs.
Additionally, we paid common and preferred stock dividends of $51.6 million and $21.7 million, respectively, and spent $7.4 million in fees in connection with debt financing transactions in 2022. Revolving Credit Facility We have entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”).
Additionally, we paid common stock dividends of $123.9 million and spent $11.9 million in fees in connection with debt financing transactions in 2023. Revolving Credit Facility We have entered into a revolving credit facility with Wells Fargo Bank, as administrative agent, and the lenders from time to time party thereto (the “Revolving Credit Facility”).
Commodity Derivative Instruments We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our gain (loss) on commodity derivatives, net was a gain of $259.3 million in 2023, compared to a loss of $415.3 million in 2022.
Commodity Derivative Instruments We enter into commodity derivative instruments to manage the price risk attributable to future oil and natural gas production. Our net result from commodity derivatives trade was a gain of $62.0 million in 2024, compared to a gain of $259.3 million in 2023.
We seek to maintain 56 Table of Contents a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the years ended 2023 and 2022, we hedged approximately 65% and 68% of our crude oil production, respectively.
We seek to maintain a robust hedging program to mitigate volatility in commodity prices with respect to a portion of our expected production. For the years ended 2024 and 2023, we hedged approximately 73% and 65% of our crude oil production, respectively, and approximately 63% and 64% of our natural gas production, respectively.
Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $486.0 million in 2023 compared to $251.3 million in 2022. The aggregate increase in DD&A expense for 2023 compared to 2022 was driven by a 31% increase in production levels and a 48% increase in the depletion rate per Boe.
Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $740.9 million in 2024, compared to $486.0 million in 2023. The aggregate increase in DD&A expense for 2024 compared to 2023 was driven by a 26% increase in production levels and a 21% increase in the depletion rate per Boe.
Convertible Notes due 2029 As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our Convertible Notes. See Note 4 to our financial statements for further details regarding the Convertible Notes. Senior Notes due 2031 As of December 31, 2023, we had outstanding $500.0 million aggregate principal amount of our 8.750% senior notes due 2031.
See Note 4 to our financial statements for further details regarding the Senior Notes due 2028. 58 Table of Contents Senior Notes due 2031 As of December 31, 2024, we had outstanding $500.0 million aggregate principal amount of our Senior Notes due 2031. See Note 4 to our financial statements for further details regarding the Senior Notes due 2031.
Our net realized gas price during 2023 was $2.98 per Mcf, representing 112% realization relative to average Henry Hub pricing, compared to a net realized gas price of $7.43 per Mcf during 2022, which represented 113% realization relative to average Henry Hub pricing.
Our net average realized gas price during 2024 was $2.24 per Mcf, representing a 93% realization relative to the average NYMEX Henry Hub pricing, compared to a net average realized gas price of $2.98 per Mcf during 2023, which represented 112% realization relative to average NYMEX Henry Hub pricing.
The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect.
Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher commodity prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher.
For 2024, we are budgeting approximately $825 to $900 million in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity.
For 2025, we are budgeting approximately $1.05 billion to $1.20 billion in total planned capital expenditures, including development expenditures and our smaller day-to-day acquisition activity, which we refer to as our “ground game” acquisition activity.
The percentage of oil production hedged under our derivative contracts was 65% and 68% in 2023 and 2022, respectively. Unsettled commodity derivative gains and losses was a gain of $201.3 million in 2023 compared to a gain of $40.2 million in 2022.
The percentage of oil production hedged under our derivative contracts was 73% and 65% in 2024 and 2023, respectively. The Company had unsettled commodity derivative losses of $21.3 million in 2024, compared to a gain of $201.3 million in 2023.
At December 31, 2023, we had a working capital surplus of $123.6 million, compared to a deficit of $24.5 million at December 31, 2022. Current assets increased by $188.9 million and current liabilities increased by $40.8 million at December 31, 2023 as compared to December 31, 2022.
At December 31, 2024, we had a working capital deficit of $43.5 million, compared to a surplus of $123.6 million at December 31, 2023. Current assets decreased by $8.7 million and current liabilities increased by $158.5 million at December 31, 2024, as compared to December 31, 2023.
See Note 12 to our financial statements for a description of the derivative contracts. Recently Issued or Adopted Accounting Pronouncements For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements—Note 2. Significant Accounting Policies.
The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 12 to our financial statements for a description of the derivative contracts. Recently Issued or Adopted Accounting Pronouncements For discussion of recently issued or adopted accounting pronouncements, see Notes to Financial Statements—Note 2. Significant Accounting Policies.
The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2023 and 2022. December 31, 2023 2022 Average NYMEX Prices (1) Oil (per Bbl) $ 77.61 $ 94.38 Natural Gas (per Mcf) 2.66 6.56 ________________________ (1) Based on average NYMEX closing prices.
The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2024 and 2023. December 31, 2024 2023 Average NYMEX Prices (1) Oil (per Bbl) $ 75.76 $ 77.61 Natural Gas (per MMbtu) 2.41 2.66 ________________________ (1) Based on average NYMEX closing prices.
Our average realized price (including all commodity derivative cash settlements) in 2023 was $54.22 per Boe compared to $55.53 per Boe in 2022. The gain (loss) on settled commodity derivatives increased our average realized price per Boe by $1.61 in 2023 and decreased our average realized price per Boe by $16.52 in 2022.
Our average realized price (including all commodity derivative cash settlements) in 2024 was $49.21 per Boe compared to $54.22 per Boe in 2023. The gain on settled commodity derivatives increased our average realized price per Boe by $1.83 and $1.61 in 2024 and 2023, respectively.
At December 31, 2023, all of our derivative contracts are recorded at their fair value, which was a net liability of $36.2 million, a change of $200.3 million from the $236.5 million net liability recorded as of December 31, 2022.
At December 31, 2024, all of our derivative contracts were recorded at their fair value, which was a net liability of $57.2 million, a change of $21.0 million from the $36.2 million net liability recorded as of December 31, 2023.
We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells.
Gas price realizations in 2024 averaged 93% of the NYMEX average gas price, as compared to 112% in 2023 We add production through drilling success as we place new wells into production and through additions from acquisitions, which is offset by the natural decline of our oil and natural gas production from existing wells.
If internally generated cash flow and borrowing capacity under our Revolving Credit Facility are not available or sufficient, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.
Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital. If internally generated cash flow and borrowing capacity under our Revolving Credit Facility are not available or sufficient, we may issue additional equity or debt to fund capital expenditures, make acquisitions, extend maturities or to repay debt.
As of December 31, 2023, we had leased approximately 272,251 net acres, of which approximately 89% were developed and all were located in the United States. Our average daily production for full year 2023 was 98,822 Boe per day, and in the fourth quarter of 2023 was 114,363 Boe per day (approximately 60% oil).
As of December 31, 2024, we had leased approximately 292,500 net acres, of which approximately 84% were developed and all were located in the United States. Our average daily production for full year 2024 was 124,108 Boe per day, and in the fourth quarter of 2024 was 131,777 Boe per day (approximately 60% oil).
For 2023, the average NYMEX pricing was $77.61 per barrel of oil, or 18% lower than in 2022. Our average realized oil price before reflecting settled oil derivatives was $74.78 per barrel of oil in 2023.
For 2024, the average NYMEX WTI pricing was $75.76 per barrel of oil, or 2% lower than the $77.61 average pricing in 2023. Our average realized oil price before reflecting settled oil derivatives was $71.59 per barrel of oil in 2024, as compared to $74.78 in 2023.
The following table summarizes DD&A expense per Boe for 2023 and 2022: Year Ended December 31, 2023 2022 Change % Change Depletion $ 13.37 $ 9.01 $ 4.36 48 % Depreciation, Amortization, and Accretion 0.10 0.11 (0.01) (9) % Total DD&A expense $ 13.47 $ 9.12 $ 4.35 48 % 55 Table of Contents Interest Expense Interest expense, net of capitalized interest, was $135.7 million in 2023 compared to $80.3 million in 2022.
The following table summarizes DD&A expense per Boe for 2024 and 2023: 55 Table of Contents Year Ended December 31, 2024 2023 Change % Change Depletion $ 16.22 $ 13.37 $ 2.85 21 % Depreciation, Amortization, and Accretion 0.09 0.10 (0.01) (10) % Total DD&A expense $ 16.31 $ 13.47 $ 2.84 21 % Interest Expense Interest expense, net of capitalized interest, was $157.7 million in 2024, compared to $135.7 million in 2023.
In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant.
Lower commodity prices have generally had the opposite effect. In addition, individual components of drilling costs can vary depending on numerous factors, such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant used.
In 2023, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased 4% from 2022, driven by a 27% decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by a 31% increase in production volumes.
In 2024, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, increased 13% from 2023, driven by a 26% increase in production volumes, partially offset by a 10% decrease in realized prices on a per Boe basis, excluding the effect of settled commodity derivatives.
Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end. For 2023, we realized a gain on settled commodity derivatives of $57.9 million, compared to a $455.4 million loss in 2022.
Net gain or loss on commodity derivatives is comprised of (i) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (ii) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.
Quantitative and Qualitative Disclosures about Market Risk.” Our cash flows for the years ended December 31, 2023 and 2022 are presented below: Year Ended December 31, (In thousands) 2023 2022 Net Cash Provided by Operating Activities $ 1,183,321 $ 928,418 Net Cash Used for Investing Activities (1,862,346) (1,402,777) Net Cash Provided by Financing Activities 684,692 467,367 Net Change in Cash $ 5,667 $ (6,992) Cash Flows from Operating Activities Net cash provided by operating activities in 2023 was $1,183.3 million, compared to $928.4 million in 2022.
Quantitative and Qualitative Disclosures about Market Risk.” Our cash flows for the years ended December 31, 2024 and 2023 are presented below: Year Ended December 31, (In thousands) 2024 2023 Net Cash Provided by Operating Activities $ 1,408,663 $ 1,183,321 Net Cash Used for Investing Activities (1,674,754) (1,862,346) Net Cash Provided by Financing Activities 266,829 684,692 Net Increase in Cash $ 738 $ 5,667 Cash Flows from Operating Activities Net cash provided by operating activities in 2024 was $1.4 billion, compared to $1.2 billion in 2023.
Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas.
Market Conditions The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas.
The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.
Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves. 60 Table of Contents The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.
During 2023, our derivative settlements included 8.1 million barrels of oil subject to swaps at an average settlement price of $75.19 per barrel, and we had an additional 6.3 million barrels of oil hedged subject to collars. During 2022, our settled commodity derivatives included 10.9 million barrels of oil at an average settlement price of $62.52 per barrel.
During 2024, our derivative settlements included 10.5 million barrels of oil subject to swaps at an average settlement price of $74.93 per barrel, and we had an additional 8.9 million barrels of oil hedged subject to collars.
Such costs also include 49 Table of Contents field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. • Production taxes.
Production expenses are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include field personnel compensation, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. • Production taxes.
As of December 31, 2023, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.25 billion, and we had $161.0 million in borrowings outstanding under the facility, leaving $1,089.0 million in available committed borrowing capacity.
As of December 31, 2024, the Revolving Credit Facility had a borrowing base of $1.8 billion and an elected commitment amount of $1.5 billion, and we had $690.0 million in borrowings outstanding under the facility, leaving $810.0 million in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.
During the years ended December 31, 2023 and 2022, we recorded a contingent consideration gain of $10.1 million compared to a gain of $1.9 million, respectively, due to the change in the fair value of these liabilities. As of December 31, 2023, there were no remaining outstanding contingent consideration liabilities.
Contingent Consideration Gain (Loss) In 2023, we recorded a contingent consideration gain of $10.1 million due to the change in the fair value of certain contingent consideration liabilities previously recorded pursuant to certain acquisitions of oil and natural gas properties. As of December 31, 2024, there were no remaining outstanding contingent consideration liabilities.
The $40.8 million increase in current liabilities in 2023 as compared to 2022 was driven by a $90.3 million increase in accounts payable and accrued liabilities, primarily as a result of increased development activity, and a $1.9 million increase in accrued interest.
The $158.5 million increase in current liabilities in 2024 as compared to 2023 was primarily due to a $155.6 million increase in accounts payable and accrued liabilities, primarily as a result of increased development activity, and a $3.1 million increase in derivative instruments.
Our production for the last two years is set forth in the following table: Year Ended December 31, 2023 2022 Production: Oil (Bbl) 22,012,986 16,090,072 Natural Gas and NGL (Mcf) 84,341,858 68,829,142 Total (Boe) (1) 36,069,962 27,561,596 Average Daily Production: Oil (Bbl) 60,310 44,082 Natural Gas and NGL (Mcf) 231,074 188,573 Total (Boe) (1) 98,822 75,511 __________________________________ (1) Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
Our production for the last two years is set forth in the following table: Year Ended December 31, 2024 2023 Production: Oil (MBbl) 26,511 22,013 Natural Gas and NGL (MMcf) 113,476 84,342 Total (MBoe) (1) 45,423 36,070 Average Daily Production: Oil (MBbl) 72 60 Natural Gas (MMcf) 310 231 Total (MBoe) (1) 124 99 __________________________________ (1) Natural gas and NGLs are converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production.
Source of Our Revenues We derive our revenues from the sale of oil, natural gas and NGLs produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market.
We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense. • Impairment expense. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter.
We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs and bond premiums (including origination and amendment fees), commitment fees and annual agency fees as interest expense. Further, we record the settled amounts of our interest rate derivative instruments as interest expense. • Impairment expense.
The lower average realized price in 2023 as compared to 2022 was driven by lower average NYMEX oil and natural gas prices and slightly higher average oil price differential in 2023 as compared to 2022. Oil price differential during 2023 averaged $2.83 per barrel, as compared to $2.73 per barrel in 2022.
The lower average realized price in 2024 as compared to 2023 was driven by lower average NYMEX oil and natural gas prices in 2024 as compared to 2023, in addition to higher average oil price differentials and lower gas price realizations to the NYMEX average natural gas price in 2024 as compared to 2023.
Our average realized natural gas price after reflecting settled natural gas derivatives was $3.90 per Mcf in 2023, or 33% lower than in 2022, due to the lower average NYMEX price, partially offset by a gain on settled natural gas derivatives in 2023 compared to a loss in 2022. 51 Table of Contents We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production.
The lower average realized natural gas price in 2024 is due to both a lower average NYMEX Henry Hub benchmark price and lower gain on settled natural gas derivatives in 2024 compared to 2023. We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production.
In May 2022, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
In May 2022, the Company’s board of directors approved a stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock. In July 2024, the Company’s board of directors terminated the prior stock repurchase program, and approved a new stock repurchase program to acquire up to $150.0 million of the Company’s outstanding common stock.
Cash Flows from Investing Activities We had cash flows used in investing activities of $1,862.3 million and $1,402.8 million during the years ended December 31, 2023 and 2022, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs.
Changes in working capital and other items (as reflected in our statements of cash flows) in the year ended December 31, 2024 was a deficit of $53.9 million compared to a deficit of $106.1 million in 2023. 57 Table of Contents Cash Flows from Investing Activities We had cash flows used in investing activities of $1.7 billion and $1.9 billion during the years ended December 31, 2024 and 2023, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs.
To the extent capital requirements exceed internal cash flow and borrowing capacity under our Revolving Credit Facility, additional financings from the capital markets may be pursued to fund these requirements. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our projects, depending on commodity prices, cash flow and projected returns.
To the extent capital requirements exceed internal cash flow and borrowing capacity under our Revolving Credit Facility, additional financings from the capital markets may be pursued to fund these requirements.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeNatural Gas Contracts Swaps (1) Collars Contract Period Volume (MMBTU) Weighted Average Price ($/MMBTU) Volume Ceiling (MMBTU) Volume Floor (MMBTU) Weighted Average Ceiling Price ($/MMBTU) Weighted Average Floor Price ($/MMBTU) 2024: Q1 10,816,616 $ 3.57 4,725,000 4,725,000 $ 5.21 $ 3.29 Q2 10,870,805 3.45 5,062,500 5,062,500 4.50 3.05 Q3 10,860,457 3.49 5,520,000 5,520,000 4.74 3.06 Q4 7,722,909 3.49 6,336,586 6,336,586 5.15 3.10 2025: Q1 1,485,000 $ 3.61 7,416,417 7,416,417 $ 5.54 $ 3.16 Q2 915,000 3.60 6,931,297 6,931,297 5.22 3.16 Q3 920,000 3.60 6,567,569 6,567,569 5.28 3.16 Q4 765,000 3.52 5,778,723 5,778,723 5.44 3.15 2026: Q1 450,000 $ 3.20 4,048,249 4,048,249 $ 5.66 $ 3.13 Q2 455,000 3.20 4,184,706 4,184,706 5.66 3.13 Q3 460,000 3.20 4,184,706 4,184,706 5.66 3.13 Q4 460,000 3.20 2,774,642 2,774,642 5.66 3.13 _____________ (1) This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.
Biggest changeNatural Gas Contracts Swaps (1) Collars Contract Period Volume (MMBTU) Weighted Average Price ($/MMBTU) Volume Ceiling (MMBTU) Volume Floor (MMBTU) Weighted Average Ceiling Price ($/MMBTU) Weighted Average Floor Price ($/MMBTU) 2025: Q1 6,675,000 $ 3.45 10,086,417 10,086,417 $ 4.98 $ 3.12 Q2 3,220,000 3.46 9,691,297 9,691,297 4.71 3.11 Q3 3,375,000 3.52 9,327,569 9,327,569 4.73 3.11 Q4 3,210,000 3.67 8,228,723 8,228,723 4.86 3.11 2026: Q1 2,230,000 $ 3.86 5,828,249 5,828,249 $ 5.06 $ 3.09 Q2 2,145,000 3.69 6,024,706 6,024,706 5.06 3.09 Q3 1,840,000 3.78 6,024,706 6,024,706 5.06 3.09 Q4 1,370,000 3.76 4,304,642 4,304,642 4.97 3.09 2027: Q1 155,000 $ 3.20 890,000 890,000 $ 3.83 $ 3.00 Q2 — — 920,000 920,000 3.83 3.00 Q3 — — 920,000 920,000 3.83 3.00 Q4 — — 610,000 610,000 3.83 3.00 _____________ (1) This table does not include volumes subject to swaptions and call options, which are natural gas derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.
This table also does not include 63 Table of Contents basis swaps. See Note 12 to our financial statements for further details regarding our commodity derivatives, including the swaptions and call options that are not included in the foregoing table. The following table summarizes our open natural gas derivative contracts as of December 31, 2023, by fiscal quarter.
This table also does not include basis swaps. See Note 12 to our financial statements for further details regarding our commodity derivatives, including the swaptions and call options that are not included in the foregoing table. 63 Table of Contents The following table summarizes our open natural gas derivative contracts as of December 31, 2024, by fiscal quarter.
Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility. The following table summarizes our open crude oil derivative contracts as of December 31, 2023, by fiscal quarter.
Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility. The following table summarizes our open crude oil derivative contracts as of December 31, 2024, by fiscal quarter.
A 1% increase in short-term interest rates on our floating-rate debt outstanding at December 31, 2023 would cost us approximately $1.6 million in additional annual interest expense.
A 1% increase in short-term interest rates on our floating-rate debt outstanding at December 31, 2024 would cost us approximately $6.9 million in additional annual interest expense.
Properties - Proved Reserves Sensitivity by Price Scenario” for estimates of how a change in oil and gas prices from the 2023 SEC Case to the $70 Flat Case would reduce our proved reserves volumes and the PV-10 value thereof. We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility.
Properties - Proved Reserves Sensitivity by Price Scenario” for estimates of how a change in oil and gas prices from the 2024 SEC Case to the $60 Flat Case would reduce our proved reserves volumes and the PV-10 value thereof while the $80 Flat Case would increase our proved reserves volumes and the PV-10 value thereof.
All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period.
We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility. All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period.
From time to time, the Company may use interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. As of December 31, 2023, we had no interest rate swaps. Changes in interest rates can impact results of operations and cash flows.
From time to time, the Company may use interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. The following table summarizes our open interest rate derivative contracts as of December 31, 2024.
This table also does not include basis swaps. See Note 12 to our financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table. Interest Rate Risk Our long-term debt as of December 31, 2023 was comprised of borrowings that contain fixed and floating interest rates.
See Note 12 to our financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table. 64 Table of Contents NGL Contracts Swaps Contract Period Volume (BBL) Weighted Average Price ($/BBL) 2025: Q1 — $ — Q2 4,550 37.03 Q3 29,900 36.39 Q4 66,700 36.75 2026: Q1 92,250 $ 36.00 Q2 106,925 33.32 Q3 96,600 33.03 Q4 80,500 33.32 2027: Q1 65,250 $ 32.30 Q2 59,150 30.73 Q3 57,500 30.69 Q4 52,900 30.87 Interest Rate Risk Our long-term debt as of December 31, 2024 was comprised of borrowings that contain fixed and floating interest rates.
Removed
Crude Oil Contracts Swaps (1) Collars Settlement Period Volume (Bbls) Weighted Average Price ($/Bbl) Volume Ceiling (Bbls) Volume Floor (Bbls) Weighted Average Ceiling Price ($/Bbl) Weighted Average Floor Price ($/Bbl) 2024: Q1 2,130,923 $ 75.30 2,423,147 1,771,928 $ 84.43 $ 70.32 Q2 2,047,737 74.55 2,424,137 1,782,017 84.06 69.90 Q3 2,081,096 73.88 1,196,056 1,044,256 80.90 69.49 Q4 1,699,109 72.46 1,045,749 871,800 81.73 69.10 2025: Q1 567,749 $ 71.99 413,286 314,849 $ 79.20 $ 67.84 Q2 554,133 72.15 273,171 199,233 75.49 67.63 Q3 552,394 71.75 234,994 161,970 75.76 67.88 Q4 548,911 71.75 208,511 135,487 76.87 67.63 2026: Q1 263,726 $ 69.05 43,226 39,289 $ 70.25 $ 62.50 Q2 266,657 68.98 43,707 39,727 70.25 62.50 Q3 269,587 68.91 44,187 40,163 70.25 62.50 Q4 269,587 68.83 44,187 40,163 70.25 62.50 _____________ (1) This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.
Added
Crude Oil Contracts Swaps (1) Collars Contract Period Volume (MBbls) Weighted Average Price ($/Bbl) Volume Ceiling (MBbls) Volume Floor (MBbls) Weighted Average Ceiling Price ($/Bbl) Weighted Average Floor Price ($/Bbl) 2025: Q1 3,176 $ 74.58 2,303 1,890 $ 78.25 $ 69.68 Q2 2,696 74.27 2,503 2,019 77.45 69.41 Q3 2,338 73.29 2,305 1,818 77.43 69.15 Q4 2,294 73.07 2,279 1,791 77.55 69.15 2026: Q1 264 $ 70.38 1,326 894 $ 74.41 $ 66.15 Q2 267 70.31 1,340 904 74.41 66.15 Q3 270 70.24 1,355 914 74.41 66.15 Q4 270 70.15 1,355 914 74.41 66.15 _____________ (1) This table does not include volumes subject to swaptions and call options, which are crude oil derivative contracts we have entered into which may increase our swapped volumes at the option of our counterparties.
Added
This table also does not include basis swaps.
Added
Fixed Rate Swap Agreements (in thousands) Swaps Contract Period Notional Amount Fixed Rate Floating Benchmark October 1, 2024 - October 1, 2026 $ 25,000 3.423 % USD-SOFR CME Changes in interest rates can impact results of operations and cash flows.

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