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What changed in NORTHERN OIL & GAS, INC.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of NORTHERN OIL & GAS, INC.'s 2024 and 2025 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 2025 report.

+348 added−340 removedSource: 10-K (2026-02-26) vs 10-K (2025-02-20)

Top changes in NORTHERN OIL & GAS, INC.'s 2025 10-K

348 paragraphs added · 340 removed · 286 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

42 edited+19 added−10 removed148 unchanged
Biggest changeHowever, 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”).
Biggest changeThe 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.
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.
In addition, our third-party operating partners may be 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.
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.
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.
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.
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 lower-carbon fuels.
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.
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 100 experienced operating partners that provide technical insights and opportunities for acquisitions.
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.
Additionally, 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.
However, in January 2025, President Trump issued executive orders directing (i) the EPA and the Corps to identify planned or potential actions that could be subject to emergency treatment under Section 404 of the CWA and (ii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including all existing regulations and guidance documents, that are unduly 8 Table of Contents burdensome on the identification, development, or use of domestic energy resources.
However, in January 2025, President Trump issued executive orders directing (i) the EPA and the Corps to identify planned or potential actions that could be subject to emergency treatment under Section 404 of the CWA and (ii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including all existing regulations and guidance documents, that are unduly burdensome on the identification, development, or use of domestic energy resources.
In 2014, Colorado was the first state in the nation to adopt rules to control methane emissions from oil and gas facilities. In 2016, the EPA revised and expanded NSPS, also known as Subpart OOOOa, to include final rules to curb emissions of methane, a greenhouse gas, from new, reconstructed and modified oil and gas sources.
In 2014, Colorado was the first state in the nation to adopt rules to control methane emissions from oil and gas facilities. In 2016, the EPA revised and expanded NSPS, also known as Subpart OOOOa, to include final rules to curb emissions of methane, a GHG, from new, reconstructed and modified oil and gas sources.
We have a rolling target of hedging 60% or more of our anticipated next 18-month production. • Stockholder Returns . The foregoing strategies are collectively aimed at building a diversified, low-leverage, cash generating business that can deliver meaningful returns to our investors.
We have a rolling target of hedging 65% or more of our anticipated next 18-month production. • Stockholder Returns . The foregoing strategies are collectively aimed at building a diversified, low-leverage, cash generating business that can deliver meaningful returns to our investors.
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.
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 Emissions Charge (“WEC”) on GHG emissions from certain oil and gas sources and facilities.
Army Corps of Engineers (the “Corps”) issued a final rule that based the definition of WOTUS on a pre-2015 definition, which never took effect before being replaced in 2020. Separately, in May 2023, the U.S. Supreme Court’s decision in Sackett v.
Army Corps of Engineers (the “USAC”) issued a final rule that based the definition of WOTUS on a pre-2015 definition, which never took effect before being replaced in 2020. Separately, in May 2023, the U.S. Supreme Court’s decision in Sackett v.
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.
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, later published in March 2024, 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.
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.
Supreme Court held 11 Table of Contents 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.
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. 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 11 Table of Contents experience.
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. 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.
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”).
The following table provides a summary of certain information regarding our assets as of December 31, 2025, including reserves information audited by our third-party independent reserve engineers, Cawley, Gillespie & Associates, Inc. (“Cawley”).
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.
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 7 Table of Contents significant expenses to modify our operations or could force discontinuation of certain operations altogether.
The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program in the IRA. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit has commenced. In addition, in November 2024, the EPA finalized a rule to implement the IRA’s Waste Emissions Charge.
The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program in the IRA. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit has commenced. In addition, in November 2024, the EPA finalized a rule to implement the IRA’s WEC.
These include the Paris Agreement, a treaty adopted at the 21st United Nations Conference of the parties (“COP”) that is aimed at addressing climate change with member countries agreeing to nationally determine their contributions and set GHG emission reduction goals every five years and the Global Methane Pledge, a pact that aims to reduce global methane emissions 9 Table of Contents at least 30% below 2020 levels by 2030.
These include the Paris Agreement, a treaty adopted at the 21st United Nations Conference of the parties that is aimed at addressing climate change with member countries agreeing to nationally determine their contributions and set GHG emission reduction goals every five years and the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030.
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.
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.
Except as specifically incorporated by reference into this Annual Report on Form 10-K, information on those websites is not part hereof. 12 Table of Contents
Except as specifically incorporated by reference into this Annual Report on Form 10-K, information on those websites is not part hereof. 13 Table of Contents
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.
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, 2025, we had 64 full time employees. We may hire additional personnel as appropriate.
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.
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 GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.
Additionally, in September 2023, the Biden Administration announced that federal agencies will be directed to consider the Social Cost of GHGs in agency budgeting, procurement, and other agency decisions, including in environmental reviews conducted pursuant to NEPA, where appropriate.
Additionally, in September 2023, the Biden Administration announced that federal 9 Table of Contents agencies will be directed to consider the Social Cost of GHGs in agency budgeting, procurement, and other agency decisions, including in environmental reviews conducted pursuant to NEPA, where appropriate.
As of May 9, 2018, the rights of our stockholders began to be governed by Delaware General Corporation Law (the “DGCL”) and our Delaware certificate of incorporation and bylaws. Available Information – Reports to Security Holders Our website address is www.noginc.com.
As of May 9, 2018, the rights of our stockholders began to be governed by Delaware General Corporation Law (the “DGCL”) and our Delaware certificate of incorporation and bylaws. 12 Table of Contents Available Information – Reports to Security Holders Our website address is www.noginc.com.
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 10 Table of Contents 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 lower-carbon fuels.
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.
In December 2023, the EPA announced a final rule, later published in March 2024, 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.
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.
Across these operators, no single operator represented more than 11% of our fourth quarter 2025 oil and natural gas sales. Prior to 2020, we focused our operations exclusively on oil-weighted properties in the Williston Basin.
Natural Resources Defense Council, Inc. and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives at the international, state and local levels are expected to continue.
Natural Resources Defense Council, Inc. and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives at the international, state and local levels are expected to continue. Further, legislative and regulatory initiatives are underway to that purpose.
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.
Further, despite the U.S. Federal Reserve decreasing the federal funds interest rate to 3.625% between September 2024 and December 2025, 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.
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.
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, Related Person Transaction Approval Policy, ESG Policy, Anti-Corruption and Bribery Policy, Human Rights Statement, Political Contributions and Trade Associations Policy and our Compliance Hotline, in addition to all pertinent company contact information.
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.
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. However, in April 2025, the U.S.
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 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.
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.
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.
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.
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.
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.
As of December 31, 2025, we have participated in 11,702 gross (1,195 net) producing wells with an average working interest of 10.2% in each gross well, with more than 100 experienced operating partners.
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.
Our acquisition activities were a significant driver of our 6% production growth from 131,777 Boe per day in the fourth quarter of 2024 to 140,064 Boe per day in the fourth quarter of 2025.
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.
For the three months ended December 31, 2025, 42% of our production was from the Permian Basin, 30% was from the Williston Basin, 21% was from the Appalachian Basin and 7% was from the Uinta Basin. • Accelerate Growth by Pursuing Value-Enhancing Acquisitions.
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.
A subsequent rule, finalized on November 26, 2025, gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources. The final rule is subject to ongoing litigation but remains in effect.
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.
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.
EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water. In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of WOTUS to the Supreme Court’s May 2023 decision in Sackett.
EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface 8 Table of Contents connection” with or are otherwise indistinguishable from traditional navigable water.
In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our business and operations.
The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our business and operations.
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.
As of December 31, 2025 Net Acres Productive Wells Average Daily Production (1) (MBoe per day) Proved Reserves (MBoe) % Oil % Proved Developed Gross Net Williston Basin 177,656 8,573 682.5 41.3 104,403 68 % 84 % Permian Basin 45,767 2,229 349.6 58.5 146,008 56 70 Appalachian Basin 62,198 518 114.2 29.6 99,623 1 80 Uinta Basin 16,176 382 49.1 10.7 34,034 90 40 Total 301,797 11,702 1,195.4 140.1 384,068 48 % 74 % __________________ (1) Represents the average daily production over the three months ended December 31, 2025. 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.
Removed
The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue.
Added
Fish and Wildlife Service and National Marine Fisheries Service proposed to redefine “harm” to mean affirmative acts that are directed immediately and intentionally against a particular animal, excluding acts or omissions that indirectly cause injury. Additionally, in November 2025, the Trump Administration proposed several rules that would significantly alter ESA protections for plants and animals.
Removed
Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands.
Added
One proposed rule would rescind a rule that automatically extends protections for endangered species to threatened species. Another proposed rule would change regulations for listing species as endangered or threatened as well as for designating critical habitats.
Removed
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.
Added
Additionally, a third proposed rule would reinstate the framework for evaluating the benefits and cost of designating a critical habitat by considering factors like economic impact, impact on national security, and other relevant impacts. The U.S. Fish and Wildlife Service is expected to issue final rules in 2026.
Removed
At the 28th COP, member countries agreed to the first “global stocktake” which calls on countries to contribute to global efforts, including a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030; accelerating efforts towards the phase-down of unabated coal power; phasing out inefficient fossil fuel subsidies; and transitioning away from fossil fuels in energy systems.
Added
However, in March 2025, the EPA announced its intention to reconsider the March 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026.
Removed
Additionally, in March 2024, the SEC issued final rules intended to enhance and standardize climate-related disclosures (the “Climate Disclosure Rule”). The Climate Disclosure Rule was voluntarily stayed by the SEC in April 2024 pending judicial review of petitions challenging the rule, and additional legal challenges are expected going forward.
Added
A subsequent rule, finalized on November 26, 2025, gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources.
Removed
Accordingly, we cannot predict whether the Climate Disclosure Rule will be implemented as finalized, nor the costs of implementation or any potential resulting adverse impacts.
Added
Additionally, in January 2026, the Trump Administration announced the formal withdrawal of the United States from the United Nations Framework Convention on Climate Change in a presidential memorandum. The full impact of these actions remains unclear at this time.
Removed
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.
Added
At the same time, various state and local governments have publicly committed to furthering the goals of the Paris Agreement and, many related initiatives are expected to continue at the local, state and international levels.
Removed
We may also face increased litigation risks related to disclosures made pursuant to such obligations. Further, legislative and regulatory initiatives are underway to that purpose.
Added
In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of WOTUS to the Supreme Court’s May 2023 decision in Sackett.
Removed
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.
Added
In November 2025, the Corps and the EPA proposed another rule revising the definition of WOTUS to conform to the Supreme Court’s decision in Sackett by providing clarity on terms such as “relatively permanent,” “tributary,” and “continuous surface connection.” 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
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.
Added
Accordingly, on January 15, 2026, the EPA published a proposed rule to revise the Section 401 state and tribal water quality certification regulations. The proposed rule aims to narrow the “activity”-based scope of state and tribal certification to point source discharges into waters of the United States. The public comment period concludes on February 17, 2026.
Added
In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations. In January 2026, CEQ formally repealed its NEPA implementing regulations on the basis of the Supreme Court’s decision in Seven County Infrastructure Coalition v. Eagle County, Colorado .
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In Seven County , the Supreme Court directed lower courts to give “substantial deference” to reasonable agency conclusions underlying its NEPA process. Accordingly, the January 2026 rule is meant to streamline NEPA review, and has left the July 2020, Phase I, and Phase 2 rules in place. The January 2026 rule may be subject to litigation.
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Congress is also considering legislation designed to streamline NEPA through the Standardizing Permitting and Expediting Economic Development Act (“SPEED Act”). The SPEED Act aims to redefine what qualifies as a “major Federal action” and impose stricter deadlines for NEPA review. The SPEED Act has passed the House of Representatives and passage remains pending and uncertain.
Added
Additionally, in January 2026, the Trump Administration announced the formal withdrawal of the United States from the United Nations Framework Convention on Climate Change in a presidential memorandum. The full impact of these actions remains unclear at this time.
Added
However, in January 2025, the Trump Administration 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.
Added
In addition, in March 2025, President Trump signed Congress’ Joint Resolution of Disapproval of the WEC, and in May 2025, EPA issued a final rule to remove the WEC regulations from the Code of Federal Regulations. In July 2025, the One Big Beautiful Bill Act delayed the effective date of the WEC until 2034. 10 Table of Contents The U.S.
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Additionally, in September 2025, the EPA proposed to permanently remove program obligations from the Greenhouse Gas Reporting Program for most source categories, and suspend program obligations for some sources subject to subpart W (which applies to emission sources in certain segments of the petroleum and natural gas industry) until 2034.
Added
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.
Added
However, in March 2025, the EPA announced its intention to reconsider the March 8, 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

79 edited+11 added−25 removed271 unchanged
Biggest changeUnder these laws and regulations, our company (either directly or indirectly through our operating partners) could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our business and subject us to administrative, civil and criminal penalties.
Biggest changeEnvironmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, our company (either directly or indirectly through our operating partners) could also be liable for personal injuries, property and natural resource damage and other damages.
These factors include, but are not limited to, the following: • changes in global supply and demand for oil and natural gas; • the actions of OPEC and other major oil producing countries, such as Russia, relating to oil price and production levels, including announcements of potential changes to such levels; • worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics; • the price and quantity of imports of foreign oil and natural gas; • the uncertainty in capital and commodities markets and the ability of oil and gas producers to access capital; • increased focus by the investment community on sustainability practices in the oil and natural gas industry; • political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity; • the outbreak of military hostilities, including the ongoing conflict between Russia and Ukraine and the destabilizing effect such conflict continues to pose for the European continent or the global oil and natural gas markets, as well as the ongoing conflict in Israel and the surrounding region; • the level of global oil and natural gas exploration, production activity and inventories; • changes in U.S. energy policy; • weather conditions, chronic and acute climatic events associated with the effects of global climate change, and outbreak of disease; • technological advances affecting energy consumption; • the development, exploitation and market acceptance of alternative energy sources as part of a transition to a lower carbon economy; • domestic and foreign governmental taxes, tariffs and/or regulations; • proximity and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and • the price and availability of alternative fuels.
These factors include, but are not limited to, the following: • changes in global supply and demand for oil and natural gas; • the actions of OPEC and other major oil producing countries, such as Russia, relating to oil price and production levels, including announcements of potential changes to such levels; • worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics; • the price and quantity of imports of foreign oil and natural gas; • the uncertainty in capital and commodities markets and the ability of oil and gas producers to access capital; • increased focus by the investment community on sustainability practices in the oil and natural gas industry; • political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, including the effects of any changes to conditions in or impacting Venezuela; • the outbreak of military hostilities, including the ongoing conflict between Russia and Ukraine and the destabilizing effect such conflict continues to pose for the European continent or the global oil and natural gas markets, as well as the ongoing conflict in Israel and the surrounding region; • the level of global oil and natural gas exploration, production activity and inventories; • changes in U.S. energy policy; • weather conditions, chronic and acute climatic events associated with the effects of global climate change, and outbreak of disease; • technological advances affecting energy consumption; • the development, exploitation and market acceptance of alternative energy sources as part of a transition to a lower carbon economy; • domestic and foreign governmental taxes, tariffs and/or regulations; • proximity and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and • the price and availability of alternative fuels.
We will report lower net income (or greater net loss) in our financial results because generally accepted accounting principles in the United States (“GAAP”) requires interest to include both the current period’s amortization of the debt issuance costs and the instrument’s coupon interest, which could adversely affect our reported or future financial results, the market price of our common stock and the trading price of the Convertible Notes.
We will report lower net income (or greater net loss) in our financial results because the application of generally accepted accounting principles in the United States (“GAAP”) requires interest to include both the current period’s amortization of the debt issuance costs and the instrument’s coupon interest, which could adversely affect our reported or future financial results, the market price of our common stock and the trading price of the Convertible Notes.
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.
To the extent that future legislative or regulatory changes 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.
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.
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; 19 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.
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.
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. 14 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.
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.
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 22 Table of Contents alternative energy sources could reduce demand for oil and natural gas.
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.
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 24 Table of Contents transactions with our affiliates.
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.
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 gas gathering and processing constraints; • 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.
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.
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 15 Table of Contents professionals that are not reviewed or audited by an independent reserve engineering firm.
However, in January 2025, President Trump issued executive orders directing (i) 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 27 Table of Contents and (ii) 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, including the Global Methane Pledge.
However, in January 2025, President Trump issued executive orders directing (i) 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 and (ii) 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, including the Global Methane Pledge.
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.
If we are unable to use the if-converted 27 Table of Contents 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.
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.
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 16 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 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 continue to develop our business, we rely on our management team’s knowledge and expertise in the industry and 20 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.
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).
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).
In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our balance sheet as assets or liabilities and in our statements of income as gain (loss) on derivatives, net.
In accordance with applicable accounting principles, we are required to record our derivative transactions at fair market value, and they are included on our balance sheet as assets or liabilities and in our statements of income as gain (loss) on derivatives, net.
In addition, any derailment of crude oil involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Our derivative activities expose us to potential regulatory risks .
In addition, any derailment of crude oil involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Our derivatives activities expose us to potential regulatory risks .
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.
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.
Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact our earnings, cash flows and financial position as it relates to these assets.
Pennsylvania’s legislature has not thus far advanced any of the governor’s severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative 29 Table of Contents sessions. Any such tax increase or change could adversely impact our earnings, cash flows and financial position as it relates to these assets.
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.
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 under, or may exercise certain rights to terminate, the capped call transactions.
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.
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 failure or financial difficulties of many financial institutions.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our proved reserves using specified pricing and cost assumptions.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our proved reserves on specified pricing and cost assumptions.
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.
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.
Under the DGCL, our board of directors may not authorize payment of a dividend unless it is either paid out of our surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, it is paid out of our net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year.
Under the DGCL, our board of directors may not authorize payment of a dividend unless it is either paid out of our surplus, as calculated in accordance with the DGCL, or if we do not 25 Table of Contents have a surplus, it is paid out of our net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year.
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.
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.
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.
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 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 .
In 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, including in a transaction that noteholders or holders of our common stock may view as favorable .
In the future, we may issue securities to raise cash for acquisitions, as consideration in acquisitions, to pay down debt, to fund capital expenditures or general corporate expenses, in connection with the exercise of stock options or to satisfy our obligations under our incentive plans.
In the future, we may issue securities to raise cash for acquisitions, as consideration in acquisitions, to pay down debt, to fund capital expenditures or general corporate expenses, in connection with the exercise of stock options or to satisfy 33 Table of Contents our obligations under our incentive plans.
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.
To 32 Table of Contents 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.
EBITDAX, as defined in the Revolving Credit Facility, excludes, among other things, the effects of interest expense, depreciation, depletion and 23 Table of Contents amortization, income tax, certain non-cash gains and impairments, and certain restructuring costs.
EBITDAX, as defined in the Revolving Credit Facility, excludes, among other things, the effects of interest expense, depreciation, depletion and amortization, income tax, certain non-cash gains and impairments, and certain restructuring costs.
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.
To the extent the frequency of extreme weather events increases, this could impact our business in various ways, including damage to operators’ 17 Table of Contents facilities at our properties or increased insurance premiums and reduced availability of insurance coverage. Potential adverse effects on our third party operators could also include disruption of their production activities and supply chain.
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.
Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 26% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2025. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.
We underwent an “ownership change” during 2018 and, as a result, the use of our existing NOL carryforwards is subject to limitations under Section 382, which are generally determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382 of the IRC.
We underwent an “ownership change” during 2018 and, as a result, the use of $121.7 million of our remaining NOL carryforwards is subject to limitations under Section 382, which are generally determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382 of the IRC.
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.
In addition, upon a default or other failure to perform under, or a termination of, a capped call transaction 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.
Although these provisions were largely unchanged in recent federal tax legislation such as the IRA, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation.
Although these provisions were largely unchanged in recent federal tax legislation, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation.
In December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc.
In December 2023, the EPA finalized more stringent methane rules, later published in March 2024, for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc.
Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects. We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves.
Unplanned costs could divert resources from other projects. We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves.
If the amount of capital we are able to raise from financing activities, together with our cash from operations, is not sufficient to satisfy our capital requirements, we may not be able to implement our business plan and may be required to scale back our operations, sell assets at unattractive prices or obtain financing on unattractive terms, any of which could adversely affect our business, results of operations and financial condition.
If the amount of capital we are able to raise from financing activities, together with our cash from operations, is not sufficient to satisfy our capital requirements, we may not be able to implement our business plan and may be required to scale back our operations, sell assets at unattractive prices or obtain financing on unattractive terms, any of which could adversely affect our business, results of operations and financial condition. 26 Table of Contents The capped call transactions may affect the value of the Convertible Notes and our common stock.
We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes. At December 31, 2024, we had an estimated NOL carryforward of approximately $447.2 million for U.S. federal income tax purposes.
We have net operating loss (“NOL”) carryforwards that we may use to offset against taxable income for U.S. federal income tax purposes. As of December 31, 2025, we had an estimated NOL carryforward of approximately $532.8 million for U.S. federal income tax purposes.
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
As a result, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and, in certain circumstances, may increase the volatility of our cash flows and result in losses and reductions in liquidity.
If an option counterparty to one or more capped call transactions becomes subject to insolvency proceedings, we will become an unsecured creditor in those proceedings with a claim equal to our exposure at that time under our transactions with that option counterparty.
If an option counterparty to one or more capped call transactions becomes subject to insolvency proceedings, we will become an unsecured creditor in those proceedings with a claim equal to the value of our capped call transaction with that option counterparty.
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.
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 the fair market value of the repurchase and the nature and amount of any equity issuances within the same taxable year of the repurchase.
Should capitalized costs exceed this ceiling, an impairment would be recognized. Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties.
Depending on future commodity price levels, the trailing twelve-month average price used in the ceiling calculation may decline, which could cause additional future write downs of our oil and natural gas properties.
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 are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected. 21 Table of Contents Our derivatives activities could adversely affect our cash flow, results of operations and financial condition.
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.
DAPL currently remains in operation while the 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. On December 19, 2025, the USACE completed the final EIS.
Our exposure will depend on many factors but, generally, the increase in our exposure will be correlated with increases in the market price or the volatility of our common stock.
The value of our capped call transactions will depend on many factors, but, generally, will increase with increases in the market price and/or the volatility of our common stock.
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.
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 transactions for a portion of our expected production, which may include swaps, collars, puts and other structures.
The capped call transactions may affect the value of the Convertible Notes and our common stock. In connection with the pricing of our 3.625% convertible senior notes due 2029 (the “Convertible Notes”), we entered into privately negotiated capped call transactions relating to such notes with the option counterparties.
In connection with the pricing of our 3.625% convertible senior notes due 2029 (the “Convertible Notes”) in October 2022 and our offering of Additional Convertible Notes (as defined herein) in June 2025, we entered into privately negotiated capped call transactions relating to such notes with the option counterparties.
Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. The occurrence of any of the foregoing could have a material adverse effect on our business and financial condition.
Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines 23 Table of Contents involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.
The IRA provides for, among other things, a new U.S. federal 1% excise tax on certain repurchases (including redemptions) of shares by publicly traded domestic (i.e., U.S.) corporations and certain domestic subsidiaries of publicly traded foreign corporations occurring after December 31, 2022. The excise tax is imposed on the repurchasing corporation itself, not its shareholders from which shares are repurchased.
On August 16, 2022, the IRA was signed into federal law. The IRA provides for, among other things, a new U.S. federal 1% excise tax on certain repurchases (including redemptions) of shares by publicly traded domestic (i.e., U.S.) corporations and certain domestic subsidiaries of publicly traded foreign corporations occurring after December 31, 2022.
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.
Federal Reserve decreasing the federal funds interest rate to 3.625% between September 2024 and December 2025, 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. 18 Table of Contents We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise.
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.
As of December 31, 2025, we estimate that we had leases that were not developed that represented 1,899 net acres potentially expiring in 2026, 2,727 net acres potentially expiring in 2027, 3,239 net acres potentially expiring in 2028, 2,676 net acres potentially expiring in 2029, and 8,564 net acres potentially expiring in 2030 and beyond.
Ongoing inflationary pressures have resulted in and may result in additional increases to the costs of goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation caused the U.S.
We have experienced, and may continue to experience, increased inflationary pressure on our business, including increases to the costs of goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation caused the U.S.
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.
However, the final rule and its requirements are currently subject to legal challenges but remain in effect. 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.
These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs of transactions. Moreover, such changes could materially reduce our access to derivative opportunities, which could adversely affect revenues or cash flow during periods of low commodity prices.
These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs of, and/or materially reducing our access to, derivative transactions, which could adversely affect revenues and cash flow. We maintain an active hedging program related to commodity price risks.
A major risk inherent in the drilling plans in which we participate is the need for our operators to obtain drilling permits from state and local authorities.
These regulations affect our business and limit the quantity of natural gas we may produce and sell. A major risk inherent in the drilling plans in which we participate is the need for our operators to obtain drilling permits from state and local authorities.
Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Inflation has been an ongoing concern in the U.S. since 2021.
Inflationary pressure and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.
In addition, the capped call transactions are complex, and they may not operate as planned. For example, the terms of the capped call transactions may be subject to adjustment, modification or, in some cases, renegotiation if certain corporate or other transactions occur.
In addition, the capped call transactions are complex, and they may not operate as planned. For example, the terms of the capped call transactions may be subject to adjustment if certain corporate or other transactions occur. The Convertible Notes may have a material effect on our reported financial results.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended.
Our actual future production for any period may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period.
The amount of the excise tax is generally 1% of the fair market value of the shares repurchased at the time of the repurchase. However, for purposes of calculating the excise tax, repurchasing corporations are permitted to net the fair market value of certain new share issuances against the fair market value of shares repurchases during the same taxable year.
However, for purposes of calculating the excise tax, repurchasing corporations are permitted to net the fair market value of certain new share issuances (including those to employees) against the fair market value of shares repurchases during the same taxable year. In addition, certain exceptions apply to the excise tax.
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 .
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 these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the imposition of injunctive relief.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the imposition of injunctive relief. 31 Table of Contents Environmental legislation may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.
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.
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.
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.
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.
An increase in commodity prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies. Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operating partners’ ability to conduct desired or expected operations.
Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operating partners’ ability to conduct desired or expected operations.
The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violation of these rules can be substantial. However, the final rule and its requirements are currently subject to legal challenges but remain in effect.
The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements.
Due to previous declines in oil and natural gas prices, we have in the past taken significant writedowns of our oil and natural gas properties. We may be required to record further writedowns of our oil and natural gas properties in the future.
Lower oil and natural gas prices and other factors have resulted in significant writedowns of our oil and natural gas properties, and we may be required to record further writedowns of our oil and natural gas properties in the future. We follow the full cost method of accounting for our oil and gas operations.
Supreme Court overturns the lower courts’ order to conduct the EIS. Moreover, the EIS and/or the USACE’s easement decision may subsequently be challenged in court. As a result, a shut-down remains possible, and there is no guarantee that DAPL will be permitted to continue operations following the completion of the EIS and/or the DAPL Litigation.
Petitioners have filed an appeal and litigation is ongoing. As a result, a shut-down remains possible, and there is no guarantee that DAPL will be permitted to continue operations following the completion of the EIS and/or the DAPL Litigation.
In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which a counterparty to our derivative contracts is unable to satisfy its obligations under the contracts; our production is less than expected; or there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement.
In addition, instances in which a counterparty to our derivative transactions is unable to satisfy its obligations or there is an adverse widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement may result in losses and reductions in liquidity. Decommissioning costs are unknown and may be substantial.
Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Part of the regulatory environment in which we do business includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities.
Part of the regulatory environment in which we do business includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights.
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.
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 30 Table of Contents 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.
U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be implemented, interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect. For example, on August 16, 2022, the Inflation Reduction Act (“IRA”) was signed into federal law.
U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be implemented, interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect. We are subject to a 1% U.S. federal excise tax in connection with repurchases of our shares by us.
In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivatives transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.
Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative transactions. In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivative transactions may reduce our performance if oil and natural gas prices were to rise over the price established by the derivative transactions.
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.
With the continued volatility in oil and natural gas prices, and persistently high borrowing costs, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
Our operational interests, as operated by our third-party operating partners, are regulated extensively at the federal, state, tribal and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells.
Our business is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. Our operational interests, as operated by our third-party operating partners, are regulated extensively at the federal, state, tribal and local levels.
Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations. Our business is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
In addition, if a consequence of legislation and regulations is to lower commodity prices, our revenues could be adversely affected. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.
In addition, we do not make any representation that the option counterparties or their respective affiliates will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice. We are subject to counterparty risk with respect to the capped call transactions, and the capped call may not operate as planned.
We are subject to counterparty risk with respect to the capped call transactions, and the capped call transactions may not operate 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.
These increases could reduce our profitability, cash flow, and ability to complete development activities as planned. An increase in commodity prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies.
The date that the final EIS will be published is not yet known, although according to statements from the USACE the final EIS may be published in 2025. Following completion of the EIS, the USACE will determine whether to grant DAPL an easement to cross the Missouri River or to shut down the pipeline, unless the U.S.
Following this completion of the EIS, the USACE will determine whether to grant DAPL an easement to cross the Missouri River or to shut down the pipeline. Publication of the EIS does not constitute a decision, and a subsequent 30-day waiting period is required.
Removed
In 2020, we were required to write down the carrying value of certain of our oil and natural gas properties, and further writedowns could be required in the future.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeIn 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.
Biggest changeIn 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. 34 Table of Contents In the last two fiscal years, we have not experienced any material cybersecurity breach incidents.
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.
Management utilizes the National Institute of Standards and Technology (NIST) Cybersecurity Framework (CSF) as a guideline to manage our cybersecurity risks and inform the Audit Committee on the overall progress of our information security program.
In 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 to continuous cyber monitoring, 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.
Risk Factors – We depend on computer and telecommunications systems, and failures in our systems or cybersecurity attacks could significantly disrupt our business operations.” 34 Table of Contents
For additional information about our cybersecurity risks, please see “Item 1A. Risk Factors – We depend on computer and telecommunications systems, and failures in our systems or cybersecurity attacks could significantly disrupt our business operations.” 35 Table of Contents
Added
To ensure continued alignment and independent verification of our NIST CSF implementation, we engage a qualified third-party cybersecurity firm to conduct periodic assessments of our program, covering all five core functions of the NIST CSF. Findings from these reviews are reported to the Audit Committee and inform our ongoing enhancements to people, process, and technology controls.

Item 2. Properties

Properties — owned and leased real estate

43 edited+5 added−7 removed47 unchanged
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.
Biggest changeManagement’s Discussion and Analysis of Financial Condition and Results of Operations.” 41 Table of Contents Year Ended December 31, 2025 2024 2023 Net Production: Oil (MBbl) 27,611 26,511 22,013 Natural Gas (MMcf) 130,084 113,476 84,342 Total (MBoe) 49,292 45,423 36,070 Oil (MBbl) per day 76 72 60 Natural Gas (MMcf) per day 356 310 231 Total (MBoe) per day 135 124 99 Average Sales Prices: Oil (per Bbl) (1) $ 59.20 $ 71.59 $ 74.78 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) 5.15 (0.11) (0.90) Oil, Net of Settled Oil Derivatives (per Bbl) (1) 64.35 71.48 73.88 Natural Gas and NGLs (per Mcf) (1) (2) 2.87 2.24 2.98 Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.45 0.76 0.92 Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1) (2) 3.32 3.00 3.90 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1) (2) 40.74 47.38 52.61 Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) 4.08 1.83 1.61 Realized Price on a Boe Basis Including Settled Commodity Derivatives (1) (2) 44.82 49.21 54.22 Average Costs: Production Expenses (per Boe) $ 9.61 $ 9.46 $ 9.62 _________________ (1) Excludes the impact of certain non-cash adjustments to revenues (2) Excludes the impact of a legal settlement (See Note 2 to our financial statements) 42 Table of Contents The following table sets forth our production results for the years ended December 31, 2025, 2024 and 2023 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.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” 39 Table of Contents Internal Controls Over Reserves Estimation Process We employ an internal reserve engineering department which is led by our Chief Technical Officer, who is responsible for overseeing the preparation of our reserves estimates.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” 40 Table of Contents Internal Controls Over Reserves Estimation Process We employ an internal reserve engineering department which is led by our Chief Technical Officer, who is responsible for overseeing the preparation of our reserves estimates.
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.
Our executive internal reserve engineer has a B.S. in petroleum engineering from Montana Tech, has over twenty 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.
Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. 44 Table of Contents We assess all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value.
Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. 45 Table of Contents We assess all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value.
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.
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 2025, 2024 and 2023.
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.
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, 2025, 2024 and 2023. Wells are classified as oil or natural gas wells according to the predominant production stream.
The development of these reserves is dependent upon a number of factors which include, but are not limited to: financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where we hold leasehold 37 Table of Contents interests.
The development of these reserves is dependent upon a number of factors which include, but are not limited to: financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where we hold leasehold interests.
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.
Item 2. Properties Estimated Net Proved Reserves The table below summarizes our estimated net proved reserves at December 31, 2025 based on reports prepared by the Company for the year ended December 31, 2025 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, 2024 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, 2025 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
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.
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. 37 Table of Contents The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2025 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, 2024, 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 forecasted to be drilled within five years from initially being recorded in accordance with our development plan. At December 31, 2025, the PV-10 value of our proved undeveloped reserves amounted to 20% of the PV-10 value of our total proved reserves.
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.
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, 2025, we had approximately 101.3 MMBoe of proved undeveloped reserves as compared to 100.3 MMBoe at December 31, 2024.
Although our 2024 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties.
Although our 2025 producing property additions exceeded our 5-year average development plan, there are numerous uncertainties.
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.
The 2025 lease expirations carried a cost of $7.8 million. We believe that the expired acreage was not material to our capital deployed. As of December 31, 2025, we estimate that less than 1% of our proved undeveloped reserves were attributable to locations scheduled to be drilled after lease expiration.
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.
December 31, 2025 2024 2023 Gross Net (1) Gross Net (1) Gross Net (1) Development Wells: Oil 774 71.0 790 86.9 803 76.1 Natural Gas 90 9.7 29 3.8 16 0.5 Non-Productive — — — — — — Total Development Wells 864 80.7 819 90.7 819 76.6 ______________ (1) Net Well totals in 2025, 2024 and 2023 do not include an additional 18.6, 69.4 and 80.4 net wells, respectively, from acquisitions which were already producing when acquired.
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.
Year Ended December 31, (In thousands, except per Boe data) 2025 2024 2023 Depletion of Oil and Natural Gas Properties $ 810,095 $ 736,600 $ 482,306 Depletion Expense (per Boe) 16.43 16.22 13.37 Research and Development We do not anticipate performing any significant research and development under our plan of operation.
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).
Additionally, our proved undeveloped reserves at December 31, 2025 included 37.9 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, 2025 were $113.3 million).
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.
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 $59.72 per Bbl for oil and $3.18 per Mcf for natural gas. Production costs were held constant for the life of the wells.
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.
Our proved undeveloped locations were decreased from 146.4 net wells at December 31, 2024 to 140.8 net wells at December 31, 2025 due to our 2025 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 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.
Our development plan for drilling proved undeveloped wells calls for the drilling of 62.9 net wells during 2026 (includes 31.5 net wells spud at December 31, 2025, 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), 33.1 net wells during 2027, 24.4 net wells during 2028, 12.8 net wells during 2029, and 7.6 net wells during 2030 for a total of 140.8 net wells.
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.
During 2025, we decreased our capital spending by 38% compared to 2024. With 77% of the PV-10 value of our 38 Table of Contents total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan.
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.
SEC Pricing Proved Reserves (In thousands) Standardized Measure Reconciliation Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $ 4,530,656 Future Income Taxes, Discounted at 10% (1) (707,854) Standardized Measure of Discounted Future Net Cash Flows $ 3,822,802 ____________ (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.
Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves.
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves.
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).
Proved developed property additions in 2025 also included 38.3 MMBoe from the conversion of previously undeveloped locations that were not booked in our December 31, 2024 proved undeveloped reserves (the related development costs incurred at December 31, 2025 were $410.8 million).
Leasehold Properties As of December 31, 2024, our principal assets included approximately 292,500 net acres located in the United States.
Leasehold Properties As of December 31, 2025, our principal assets included approximately 301,797 net acres located in the United States.
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.
Estimated net proved reserves at December 31, 2025 were 384,068 MBoe, a 1% increase from estimated net proved reserves of 378,484 MBoe at December 31, 2024. The increase was primarily due to the impact of our 2025 acquisitions, as well as organic drilling activities in 2025.
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.
The average resulting price used as of December 31, 2025, after adjustment to reflect applicable transportation and quality differentials, was $59.72 per barrel of oil and $3.18 per Mcf of natural gas.
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.
At December 31, 2025, we had spent a total of $291.0 million related to the development of proved undeveloped reserves, which resulted in the conversion of 19.2 MMBoe of proved undeveloped reserves as of December 31, 2024 to proved developed reserves as of December 31, 2025.
(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.
(2) 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.
(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.
See “Reconciliation of PV-10 to Standardized Measure” above for a reconciliation of the PV-10 of our 2025 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.
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.
December 31, 2025 2024 2023 Gross Net Gross Net Gross Net Williston Basin 8,573 682.5 8,278 664.0 7,981 643.7 Permian Basin 2,229 349.6 1,895 302.3 1,387 207.6 Appalachian Basin 518 114.2 424 104.3 397 100.3 Uinta Basin 382 49.1 271 37.4 — — Total 11,702 1,195.4 10,868 1,108.0 9,765 951.6 As of December 31, 2025, we had an additional 441 gross (45.6 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.
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.
Year Ended December 31, 2025 2024 2023 Net Production: Oil (MBbl) Williston Basin 10,607 12,241 12,747 Permian Basin 13,275 13,529 9,266 Appalachian Basin 159 56 — Uinta Basin 3,570 685 — Total 27,611 26,511 22,013 Natural Gas and NGLs (MMcf) Williston Basin 29,187 31,518 31,103 Permian Basin 48,731 44,621 28,594 Appalachian Basin 49,804 36,785 24,645 Uinta Basin 2,362 552 — Total 130,084 113,476 84,342 Crude Oil Equivalents (MBoe) Williston Basin 15,471 17,494 17,931 Permian Basin 21,398 20,966 14,032 Appalachian Basin 8,460 6,186 4,108 Uinta Basin 3,963 777 — Total 49,292 45,423 36,070 43 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, 2025, 2024 and 2023.
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.
In 2025, we also added 27.4 MMBoe of proved undeveloped reserves as a result of our development activity. We added an additional 1.8 MMBoe from our acquisitions.
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.
The SEC-prescribed commodity prices (after adjustment for transportation, quality and basis differentials) were $10.88 lower per barrel of oil and $1.16 higher per Mcf of natural gas at year-end 2025 as compared to year-end 2024. Additionally, we had negative revisions of 9.1 MMBoe primarily due to the significant downward trend in oil commodity prices.
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.
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 table below shows our proved reserves utilizing the 2025 SEC Case compared with the $70 Flat Case and the $50 Flat Case.
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.
December 31, 2025 December 31, 2024 Proved Reserves (MBoe) (1) % of Total Proved Reserves (MBoe) (2) % of Total SEC Proved Reserves: Developed 282,789 74 % 278,151 73 % Undeveloped 101,279 26 % 100,333 27 % Total Proved Properties 384,068 100 % 378,484 100 % ___________________ (1) The table above values oil and natural gas reserve quantities as of December 31, 2025, assuming constant realized prices of $59.72 per barrel of oil and $3.18 per Mcf of natural gas.
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.
A reconciliation of the change in proved undeveloped reserves during 2025 is as follows: MBoe Estimated Proved Undeveloped Reserves at 12/31/2024 100,333 Converted to Proved Developed Through Drilling (19,162) Added from Extensions and Discoveries 27,432 Purchases of Minerals in Place 1,761 Revisions (9,085) Estimated Proved Undeveloped Reserves at 12/31/2025 101,279 Our future development drilling program includes the drilling of approximately 140.8 proved undeveloped net wells before the end of 2030 at an estimated cost of $1.1 billion.
(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.
(2) Prices based on $70.00 per Bbl for oil and $4.50 per MMbtu for natural gas, which were then adjusted for transportation and quality differentials to arrive at prices of $64.40 per Bbl for oil and $4.30 per Mcf for natural gas.
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.
The first case scenario uses a flat pricing deck of $70.00 per Bbl for oil and $4.50 per MMbtu for natural gas (the “$70 Flat Case”). The second scenario uses a flat pricing deck of $50.00 per Bbl for oil and $3.00 per MMbtu for natural gas (the “$50 Flat Case”). The sensitivity scenarios were not audited by a third-party.
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.
The approximate expiration of our net acres which are subject to expire between 2026 and 2030 and thereafter, are set forth below: Acreage Subject to Expiration Year Ended Gross Net December 31, 2026 8,651 1,899 December 31, 2027 11,161 2,727 December 31, 2028 10,308 3,239 December 31, 2029 4,158 2,676 December 31, 2030 and thereafter 12,463 8,564 Total 46,741 19,105 During 2025, we had leases expire covering approximately 4,206 net acres.
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.
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 have chosen to compare our proved reserves calculated using SEC Pricing (the “2025 SEC Case”) to two alternate pricing cases.
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.
As of December 31, 2025 and 2024, we had 140.8 and 146.4 net proved undeveloped wells, respectively, included in our reserves. 36 Table of Contents The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2025: 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 123,102 899,512 273,021 71 % $ 3,498,946 77 % PDNP Properties 3,952 34,892 9,768 3 % 140,004 3 % PUD Properties 57,807 260,833 101,279 26 % 891,706 20 % Total 184,861 1,195,237 384,068 100 % $ 4,530,656 100 % _____ ___________ (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, 2025, based on average prices of $65.34 per barrel of oil and $3.39 per MMbtu of natural gas.
Removed
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.
Added
In these sensitivity scenarios, all operating cost assumptions and other factors, other than the commodity price assumptions, have been held constant with the 2025 SEC Case. The change in pricing in the $50 Flat Case resulted in fewer future drilling locations that were considered economic compared to the 2025 SEC Case.
Removed
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”).
Added
Price Cases 2025 SEC Case (1) $70 Flat Case (2) $50 Flat Case (3) Net Proved Reserves (December 31, 2025) Oil (MBbl) Developed 127,054 132,340 112,308 Undeveloped 57,807 60,387 44,777 Total 184,861 192,727 157,085 Natural Gas (MMcf) Developed 934,404 968,756 876,193 Undeveloped 260,833 268,543 235,511 Total 1,195,237 1,237,299 1,111,704 Total Proved Reserves (MBOE) 384,068 398,944 342,369 Pre-tax PV10% (in thousands) (4) $ 4,530,656 $ 5,704,714 2,788,331 _________________ (1) Represents reserves based on pricing prescribed by the SEC.
Removed
The table below shows our proved reserves utilizing the 2024 SEC Case compared with the $80 Flat Case and the $60 Flat Case.
Added
(3) Prices based on $50.00 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 $44.53 per Bbl for oil and $2.77 per Mcf for natural gas. 39 Table of Contents (4) Pre-tax PV10%, or PV-10, may be considered a non-GAAP financial measure.
Removed
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.
Added
The following table summarizes our estimated gross and net developed and undeveloped acreage by geographic area at December 31, 2025. 44 Table of Contents Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Williston Basin 875,662 169,016 43,721 8,640 919,383 177,656 Permian Basin 181,279 39,317 29,050 6,450 210,329 45,767 Appalachian Basin 131,605 27,410 97,337 34,789 228,942 62,198 Uinta Basin 225,422 14,470 56,487 1,706 281,909 16,176 Total 1,413,968 250,213 226,595 51,585 1,640,563 301,797 As of December 31, 2025, approximately 83% 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, 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.
Added
Delivery Commitments The Company does not have any outstanding delivery commitments as of December 31, 2025.
Removed
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.
Removed
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

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

11 edited+1 added−0 removed5 unchanged
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.
Biggest changeSubsequently, our board of directors declared and paid incrementally higher quarterly cash dividends, through the $0.45 per share cash dividend declared in January 2025, and paid on April 30, 2025 to stockholders of record as of the close of business on March 28, 2025.
The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock. 47 Table of Contents Recent Sales of Unregistered Securities None, except to the extent previously included by the Company in a Quarterly Report on Form 10-Q or Current Report on Form 8-K.
The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock. 48 Table of Contents Recent Sales of Unregistered Securities None, except to the extent previously included by the Company in a Quarterly Report on Form 10-Q or Current Report on Form 8-K.
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.
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 2026.
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.
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, 2025.
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.
The following graph compares the 60-month cumulative total stockholder return on our common stock since December 31, 2020, 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.
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.
Most recently, in February 2026, our board of directors declared a cash dividend on our common stock in the amount of $0.45 per share, payable on April 30, 2026 to stockholders of record as of the close of business on March 30, 2026.
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.
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 23, 2026 was $27.30 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, 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.
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, 2025 to October 31, 2025 — $ — — $ 160.3 million November 1, 2025 to November 30, 2025 — — — 160.3 million December 1, 2025 to December 31, 2025 356,168 21.51 326,301 153.3 million Total 356,168 $ 21.51 326,301 $ 153.3 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.
Holders As of February 18, 2025, we had 99,113,645 shares of our common stock outstanding, held by approximately 130 stockholders of record.
Holders As of February 23, 2026, we had 97,294,661 shares of our common stock outstanding, held by approximately 116 stockholders of record.
(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.
(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. On March 10, 2025, the Company’s board of directors approved and promptly announced an additional $100 million authorization under this stock repurchase program.
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.
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, 2020 to December 31, 2025. 47 Table of Contents The following table sets forth the total returns utilized to generate the foregoing graph. 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024 12/31/2025 Northern Oil & Gas, Inc. 100.00 236.69 365.49 458.4 480.21 297.02 S&P 500 100.00 128.71 105.40 133.10 166.4 196.16 SPDR S&P Oil & Gas Exploration & Production ETF 100.00 166.74 242.38 251.01 248.50 243.15 The stock price performance included in this graph is not necessarily indicative of future stock price performance.
Added
The program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions. Item 6. [RESERVED] 49 Table of Contents

Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

3 edited+0 added−0 removed0 unchanged
Biggest changeOther Information 68 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 68 Part III Item 10. Directors, Executive Officers and Corporate Governance 68 Item 11. Executive Compensation 69 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 69 Item 13. Certain Relationships and Related Transactions, and Director Independence 70 Item 14.
Biggest changeOther Information 69 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 69 Part III Item 10. Directors, Executive Officers and Corporate Governance 69 Item 11. Executive Compensation 70 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 70 Item 13. Certain Relationships and Related Transactions, and Director Independence 71 Item 14.
Principal Accountant Fees and Services 70 Part IV Item 15. Exhibits and Financial Statement Schedules 71 Item 16. Form 10-K Summary 74 Signatures 75 Index to Financial Statements F-1 1 Table of Contents NORTHERN OIL AND GAS, INC. ANNUAL REPORT ON FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2024 PART I
Principal Accountant Fees and Services 71 Part IV Item 15. Exhibits and Financial Statement Schedules 72 Item 16. Form 10-K Summary 75 Signatures 76 Index to Financial Statements F-1 1 Table of Contents NORTHERN OIL AND GAS, INC. ANNUAL REPORT ON FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2025 PART I
Item 6. [RESERVED] 48 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 49 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 63 Item 8. Financial Statements and Supplementary Data 65 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 65 Item 9A. Controls and Procedures 66 Item 9B.
Item 6. [RESERVED] 49 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 50 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 64 Item 8. Financial Statements and Supplementary Data 66 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 66 Item 9A. Controls and Procedures 67 Item 9B.

Item 7. Management's Discussion & Analysis

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

94 edited+24 added−11 removed66 unchanged
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.
Biggest changeYear Ended December 31, 2025 2024 Net Production: Oil (MBbl) 27,611 26,511 Natural Gas (MMcf) 130,084 113,476 Total (MBoe) 49,292 45,423 Net Sales (in thousands): Oil Sales $ 1,627,493 $ 1,897,857 Natural Gas and NGL Sales 453,795 254,222 Gain on Settled Commodity Derivatives 201,321 83,225 Gain (Loss) on Unsettled Commodity Derivatives 179,343 (21,258) Other Revenue 13,771 11,683 Total Revenues 2,475,723 2,225,729 Average Sales Prices: Oil (per Bbl) (1) $ 59.20 $ 71.59 Effect of Loss on Settled Oil Derivatives on Average Price (per Bbl) 5.15 (0.11) Oil, Net of Settled Oil Derivatives (per Bbl) (1) 64.35 71.48 Natural Gas and NGLs (per Mcf) (1) (2) 2.87 2.24 Effect of Gain on Settled Natural Gas Derivatives on Average Price (per Mcf) 0.45 0.76 Natural Gas and NGLs, Net of Settled Natural Gas and NGL Derivatives (per Mcf) (1) (2) 3.32 3.00 Realized Price on a Boe Basis Excluding Settled Commodity Derivatives (1) (2) 40.74 47.38 Effect of Gain on Settled Commodity Derivatives on Average Price (per Boe) 4.08 1.83 Realized Price on a Boe Basis Including Settled Commodity Derivatives (1) (2) 44.82 49.21 Operating Expenses (in thousands): Production Expenses $ 473,666 $ 429,792 Production Taxes 131,334 157,091 General and Administrative Expenses 61,332 50,463 Depletion, Depreciation, Amortization and Accretion 814,859 740,901 Other Expense 12,848 9,650 Costs and Expenses (per Boe): Production Expenses $ 9.61 $ 9.46 Production Taxes 2.66 3.46 General and Administrative Expenses 1.24 1.11 Depletion, Depreciation, Amortization and Accretion 16.53 16.31 Net Producing Wells at Period-End 1,195.4 1,108.0 ______________ (1) Excludes the impact of certain non-cash adjustments to revenues (2) Excludes the impact of a legal settlement (See Note 2 to our financial statements) 54 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.
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.
Fluctuations in our oil and natural 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.
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.
We include interest expense that is not capitalized into the unproved cost pool, the amortization of deferred financing costs (including origination and amendment fees), the amortization of bond premiums and discounts, 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.
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.
In addition, ceiling impairment charges may occur if we experience poor drilling results or if estimations of our proved reserves are substantially reduced. A ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity.
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 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.
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.
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; 51 Table of Contents • 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.
General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. • Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings.
General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, audit and other professional fees and legal compliance. • Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings.
Off-Balance Sheet Arrangements We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. 62 Table of Contents
Off-Balance Sheet Arrangements We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. 63 Table of Contents
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.
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, 2025. Our estimates of proved reserves quantities were prepared in accordance with the rules promulgated by the SEC.
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.
Gain (loss) on commodity derivatives, net is comprised of (i) 50 Table of Contents 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.
If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods. • Income tax expense.
If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record an additional non-cash ceiling test impairment of its oil and gas property costs in future periods. • Income tax expense.
Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost method differs from the successful efforts method of accounting for oil and natural gas investments.
Although some of these costs will ultimately result in no additional reserves, they are part of a program from which we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. The full cost 62 Table of Contents method differs from the successful efforts method of accounting for oil and natural gas investments.
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.
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, 2024 for discussion and analysis of results of operations for the year ended December 31, 2023.
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.
For a summary as of December 31, 2025, 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.
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 (“Oil Price Differential”) is primarily driven by the cost to transport oil via train, pipeline or truck to refineries.
Cash Flows Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility.
Cash Flows Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, 58 Table of Contents cash flows from operations or borrowings under our Revolving Credit Facility.
We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. See also “Capital Requirements” below. Capital Stock and Debt Security Repurchases .
We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditure budget. See also “Capital Requirements” below. 60 Table of Contents Capital Stock and Debt Security Repurchases .
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 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 See Note 2 to the financial statements for a discussion of recently issued or adopted accounting pronouncements.
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.
During 2025 and 2024, we added 80.7 and 90.7 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.
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.
See also Note 12 to our financial statements. 53 Table of Contents Results of Operations for 2025 and 2024 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.
Once recognized, a ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. At December 31, 2024, we performed an impairment review using prices that reflect an average of 2024’s monthly prices as prescribed pursuant to the SEC’s guidelines.
Once recognized, a ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. At December 31, 2025, we performed an impairment review using prices that reflect an average of 2025’s monthly prices as prescribed pursuant to the SEC’s guidelines.
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.
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, 2025, our average depletion expense per unit of production w as $16.43 per Boe.
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.
For instance, during the year ended December 31, 2025, 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 $1.2 billion, while the actual cash spend in this regard amounted to $1.3 billion. Development and acquisition activities are discretionary.
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.
Oil accounted for 81% and 88% of our total oil and gas sales in 2025 and 2024, 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 18% in 2024 as compared to 2023, 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 11% in 2025 as compared to 2024, due to our growing organic acreage footprint and increased development on our properties.
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.
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 2025 was $5.53 per barrel, as compared to $3.88 per barrel in 2024.
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.
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 26% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves as of December 31, 2025.
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.
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 2025 and 2024, we hedged approximately 77% and 73% of our crude oil production, respectively, and approximately 62% and 63% of our natural gas production, respectively.
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.
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 $380.7 million in 2025, compared to a gain of $62.0 million in 2024.
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.
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 11,702 gross (1,195 net) producing wells as of December 31, 2025.
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.
This represented significant growth from 2024, which was driven in large part by our substantial acquisition activities in 2024 and 2025, as described in Note 3 to our financial statements. During 2025, we added 80.7 new net wells to production, plus an additional 18.6 net wells added from acquisitions which were already producing when acquired.
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.
For a summary as of December 31, 2025, of our open commodity swap contracts for future periods, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.
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.
Senior Notes due 2031 As of December 31, 2025, 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 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.
Our net average realized gas price during 2025 was $2.87 per Mcf, representing a 79% realization relative to the average NYMEX Henry Hub pricing, compared to a net average realized gas price of $2.24 per Mcf during 2024, which represented 93% realization relative to average NYMEX Henry Hub pricing.
We financed these acquisitions with a combination of credit facility borrowings, equity consideration and internally generated cash flow from operations.
We financed these acquisitions with a combination of debt issuances, credit facility borrowings, and internally generated cash flow from operations.
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.
For 2026, we are budgeting approximately $0.9 billion to $1.1 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.
Convertible Notes due 2029 As of December 31, 2024, 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. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations.
Senior Notes due 2033 As of December 31, 2025, we had outstanding $725.0 million aggregate principal amount of our Senior Notes due 2033. See Note 4 to our financial statements for further details regarding the Senior Notes due 2033. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations.
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.
As of December 31, 2025, we had incurred $328.9 million in capital expenditures that were included in accounts payable and accrued liabilities, and we estimate that we were committed to an additional approximately $430.6 million in development capital expenditures not yet incurred for wells we had elected to participate in.
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.
The higher average realized natural gas price in 2025 is due to a higher average NYMEX Henry Hub benchmark price, partially offset by lower gains on settled natural gas derivatives in 2025 compared to 2024. We have entered into derivatives contracts to hedge commodity price risk on a portion of our future expected oil and natural gas production.
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.
Our acquisition activities in 2025 and 2024 (see Note 3 to our financial statements) helped drive the 9% increase in production levels in 2025 as compared to 2024.
General and Administrative Expenses General and administrative expenses were $50.5 million for 2024, compared to $46.8 million for 2023. The increase in 2024 compared to 2023 was driven in part by an increase in professional fees and employee compensation to support the Company’s growth, partially offset by lower acquisition-related costs.
General and Administrative Expenses General and administrative expenses were $61.3 million for 2025, compared to $50.5 million for 2024. The increase in 2025 compared to 2024 was driven by an increase in employee compensation costs to support the Company’s growth and higher acquisition-related costs, partially offset by lower professional fees.
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.
Depletion, Depreciation, Amortization and Accretion Depletion, depreciation, amortization and accretion (“DD&A”) was $814.9 million in 2025, compared to $740.9 million in 2024. The aggregate increase in DD&A expense for 2025 compared to 2024 was driven by a 9% increase in production levels and a 1% increase in the depletion rate per Boe.
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.
As of December 31, 2025, we had total liquidity of $1,136.3 million, consisting of $1,122.0 million of committed borrowing availability under the Revolving Credit Facility and $14.3 million of cash on hand. One of the primary sources of variability in our cash flows from operating activities is commodity price volatility.
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.
In 2025, our oil, natural gas and NGL sales, excluding the effect of settled commodity derivatives, decreased by 3% from 2024, driven by a 14% decrease in realized prices on a per Boe basis, excluding the effect of settled commodity derivatives, partially offset by a 9% increase in production volumes.
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.
Our production for the last two years is set forth in the following table: Year Ended December 31, 2025 2024 Production: Oil (MBbl) 27,611 26,511 Natural Gas and NGL (MMcf) 130,084 113,476 Total (MBoe) (1) 49,292 45,423 Average Daily Production: Oil (MBbl) 76 72 Natural Gas (MMcf) 356 310 Total (MBoe) (1) 135 124 __________________________________ (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.
Additionally, during 2024, our derivative settlements included 41.7 million MMBtu of natural gas subject to swaps at an average settlement price of $3.50 per MMBtu, and we had an additional 29.6 million MMBtu of natural gas hedged subject to collars. 54 Table of Contents 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.
Additionally, during 2024, our derivative settlements included 41.7 million MMBtu of natural gas subject to swaps at an average settlement price of $3.50 per MMBtu, and we had an additional 29.6 million MMBtu of gas hedged subject to collars.
As a percentage of oil and natural gas sales, our production taxes were 7.3% and 8.4% in 2024 and 2023, respectively.
As a percentage of oil and natural gas sales, our production taxes were 6.5% and 7.3% in 2025 and 2024, respectively.
For 2024, we realized a gain on settled commodity derivatives of $83.2 million, compared to a $57.9 million gain in 2023. The increased gain on settled derivatives was primarily due to a decrease in the average NYMEX oil and continued depressed NYMEX gas price in 2024 compared to 2023.
For 2025, we realized a gain on settled commodity derivatives of $201.3 million, compared to a $83.2 million gain in 2024. The increased gain on settled derivatives was primarily due to a decrease in the average NYMEX oil price in 2025 compared to 2024.
Additionally, during 2023, our derivative settlements included 33.8 million MMBtu of gas subject to swaps at an average settlement price of $3.95 per MMBtu, and we had an additional 20.0 million MMBtu of gas hedged subject to collars.
Additionally, during 2025, our derivative settlements included 40.0 million MMBtu of natural gas subject to swaps at an average settlement price of $3.88 per MMBtu, and we had an additional 40.9 million MMBtu of natural gas hedged subject to collars.
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.
The lower average realized price in 2025 as compared to 2024 was driven primarily by lower average NYMEX oil prices in 2025 as compared to 2024, in addition to higher average oil price differentials, partially offset by higher realized gas and NGL prices in 2025 as compared to 2024.
The lower average realized oil price in 2024 is due to a lower average NYMEX WTI benchmark price in 2024 compared to 2023, partially offset by a lower average loss on settled oil derivatives. For 2024, the average NYMEX Henry Hub pricing for natural gas was $2.41 per MMbtu, or 9% lower than the $2.66 per MMbtu price in 2023.
The lower average realized oil price in 2025 was principally due to a 15% lower average NYMEX WTI benchmark price in 2025 compared to 2024, partially offset by higher gains on settled oil derivatives. For 2025, the average NYMEX Henry Hub pricing for natural gas was $3.62 per MMbtu, or 50% higher than the $2.41 per MMbtu price in 2024.
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.
The percentage of oil production hedged under our derivative contracts was 77% and 73% in 2025 and 2024, respectively. The Company had unsettled commodity derivative gains of $179.3 million in 2025, compared to a loss of $21.3 million in 2024.
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.
At December 31, 2025, all of our derivative contracts were recorded at their fair value, which was a net asset of $121.6 million, a change of $178.8 million from the $57.2 million net liability recorded as of December 31, 2024.
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.
At December 31, 2025, we had a working capital surplus of $46.7 million, compared to a deficit of $43.5 million at December 31, 2024. Current assets increased by $85.3 million and current liabilities decreased by $5.0 million at December 31, 2025, as compared to December 31, 2024.
During the year ended December 31, 2024 the Company repurchased 2,535,391 shares of its common stock under the stock repurchase programs at a total cost of $95.4 million (including commissions and $0.9 million in excise tax). The Company may in the future engage in similar transactions.
During the year ended December 31, 2025 the Company repurchased 1,948,996 shares of its common stock under the stock repurchase programs at a total cost of $57.3 million (including commissions and $0.3 million in excise tax). The Company may in the future engage in similar transactions.
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.
Our cash spend for development and acquisition activities for the years ended December 31, 2025 and 2024 are summarized in the following table: Year Ended December 31, (In millions) 2025 2024 Drilling and Development Capital Expenditures $ 919.2 $ 771.3 Acquisition of Oil and Natural Gas Properties 328.0 900.2 Other Capital Expenditures 4.5 3.2 Total $ 1,251.7 $ 1,674.6 Cash Flows from Financing Activities Net cash used for financing activities was $247.5 million in the year ended December 31, 2025.
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.
Quantitative and Qualitative Disclosures about Market Risk.” Our cash summary for the years ended December 31, 2025 and 2024 is presented below: Year Ended December 31, (In thousands) 2025 2024 Net Cash Provided by Operating Activities $ 1,505,288 $ 1,408,663 Net Cash Used for Investing Activities (1,252,462) (1,674,754) Net Cash Provided by (Used for) Financing Activities (247,460) 266,829 Net Increase in Cash $ 5,366 $ 738 Cash Flows from Operating Activities Net cash provided by operating activities in 2025 was $1.5 billion, compared to $1.4 billion in 2024.
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.
Our average realized price 55 Table of Contents (including all commodity derivative cash settlements) in 2025 was $44.82 per Boe compared to $49.21 per Boe in 2024. The gain on settled commodity derivatives increased our average realized price per Boe by $4.08 and $1.83 in 2025 and 2024, respectively.
Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Production Expenses Production expenses were $429.8 million in 2024, compared to $347.0 million in 2023. On a per unit basis, production expenses decreased 2%, from $9.62 per Boe in 2023 to $9.46 per Boe in 2024, due to higher production volumes in 2024.
Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Production Expenses Production expenses were $473.7 million in 2025, compared to $429.8 million in 2024. On a per unit basis, production expenses increased 2%, from $9.46 per Boe in 2024 to $9.61 per Boe in 2025, primarily due to higher workover costs in 2025.
If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods. 61 Table of Contents Derivative Instrument Activities We use derivative instruments from time to time to manage market risks resulting primarily from fluctuations in the prices of oil and natural gas.
If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods.
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.
Oil price differentials during 2025 averaged $5.53 per barrel, as compared to $3.88 per barrel in 2024. 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.
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.
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 average realized natural gas price before reflecting settled natural gas derivatives was $2.24 per Mcf in 2024, as compared to $2.98 per Mcf in 2023. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.00 per Mcf in 2024, as compared to $3.90 per Mcf in 2023, representing a 23% decline year-over-year.
Our average realized natural gas price before reflecting settled natural gas derivatives was $2.87 per Mcf in 2025, as compared to $2.24 per Mcf in 2024. Our average realized natural gas price after reflecting settled natural gas derivatives was $3.32 per Mcf in 2025, as compared to $3.00 per Mcf in 2024, representing an 11% increase year-over-year.
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.
As of December 31, 2025, we had $478.0 million in borrowings outstanding under the facility, leaving approximately $1.3 billion in available committed borrowing capacity. See Note 4 to our financial statements for further details regarding the Revolving Credit Facility.
On an absolute dollar basis, production expenses increased 24% in 2024 compared to 2023, primarily due to a 26% increase in production volumes partially caused by an 18% increase in net wells. Production Taxes We pay production taxes based on realized oil and natural gas sales. Production taxes were $157.1 million in 2024, compared to $160.1 million in 2023.
On an absolute dollar basis, production expenses increased 10% in 2025 compared to 2024, primarily due to a 9% increase in production volumes. Production Taxes We pay production taxes based on realized oil and natural gas sales. Production taxes were $131.3 million in 2025, compared to $157.1 million in 2024.
During 2024, we repurchased and retired 2,535,391 shares of our common stock for total consideration of $95.4 million, or an average price of $37.27 per share excluding excise taxes. We completed over $883.5 million in substantial bolt-on acquisitions that closed during 2024 (see Note 3 to our financial statements).
During 2025, we repurchased and retired 1,948,996 shares of our common stock for total consideration of $57.0 million, or an average price of $29.25 per share excluding excise taxes. We completed over $333.5 million in bolt-on acquisitions that closed during 2025 (see Note 3 to our financial statements).
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).
As of December 31, 2025, we had leased approximately 301,797 net acres, of which approximately 83% were developed and all were located in the United States. Our average daily production for full year 2025 was 135,045 Boe per day, and in the fourth quarter of 2025 was 140,064 Boe per day (approximately 53% oil).
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.
The change in the fair value of our derivative contracts year-over-year was primarily due to changes in forward commodity prices relative to prices on our open commodity derivative contracts since December 31, 2024. Our open commodity derivative contracts are summarized in “Item 7A.
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.
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.
With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments. Further, we have contractual commitments under a Joint Development Agreement with an unaffiliated operator to develop certain oil and natural properties in Appalachia. See Note 8 to our financial statements. Planned Capital Expenditures.
We have future obligations related to the abandonment of our oil and natural gas properties. See Note 9 to our financial statements. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments. Planned Capital Expenditures.
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.
Such costs also include field personnel compensation, natural gas processing, salt water disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties. • Production taxes.
Our average realized oil price after reflecting settled oil derivatives was $71.48 per barrel of oil in 51 Table of Contents 2024, as compared to $73.88 in 2023, representing a 3% decline year-over-year.
Our average realized oil price before reflecting settled oil derivatives was $59.20 per barrel of oil in 2025, as compared to $71.59 in 2024. Our average realized oil price after reflecting settled oil derivatives was $64.35 per barrel of oil in 2025, as compared to $71.48 in 2024, representing a 10% decline year-over-year.
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 of December 31, 2025, we had outstanding total debt of $2,423.2 million consisting of $478.0 million of borrowings under our Revolving Credit Facility, $20.2 million aggregate principal amount of our Senior Notes due 2028 (as defined herein), $700.0 million aggregate principal amount of our Convertible Notes (as defined herein), $500.0 million aggregate principal amount of our 8.750% senior notes due 2031 (the “Senior Notes due 2031”) (as defined herein), and $725.0 million aggregate principal amount of our Senior Notes due 2033 (as defined herein).
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.
Cash Flows from Investing Activities We had cash flows used in investing activities of $1.3 billion and $1.7 billion during the years ended December 31, 2025 and 2024, respectively, primarily as a result of our capital expenditures for drilling, development and acquisition costs.
The $8.7 million decrease in current assets in 2024 as compared to 2023 was primarily driven by a $29.2 million decrease in derivative instruments and a $36.9 million decrease in advances to operators, partially offset by a $19.1 million increase in accounts receivable and a $34.8 million increase in income tax receivable.
The $85.3 million increase in current assets in 2025 as compared to 2024 was primarily driven by a $120.2 million increase in derivative instruments, a $17.7 million increase in advances to operators, and a $7.2 million increase in cash and other current assets, partially offset by a $39.7 million decrease in accounts receivable and a $20.0 million decrease in income tax receivable.
Our financial and operating performance for the year ended December 31, 2024 included the following: • Total production of 124,108 Boe per day, a 26% increase compared to 2023 • Cash flows from operations of $1.4 billion, a 19% increase compared to 2023 • Proved reserves of 378.5 MMBoe at year-end, an 11% increase compared to year-end 2023 • Grew and diversified the business through over $883.5 million in substantial bolt-on acquisitions that closed during 2024 • Grew our total quarterly common stock dividends by 10%, from $1.49 per share total during 2023 to $1.64 per share total during 2024 • Provided returns to shareholders totaling approximately $256.5 million, comprised of $162.0 million in common stock dividend payments and $94.5 million in repurchases of common stock.
Our financial and operating performance for the year ended December 31, 2025 included the following: • Total production of 135,045 Boe per day, a 9% increase compared to 2024 • Cash flows from operations of $1.5 billion, a 7% increase compared to 2024 • Proved reserves of 384.1 MMBoe at year-end, a 1% increase compared to year-end 2024 • Grew our total quarterly common stock dividends by 10%, from $1.64 per share total during 2024 to $1.80 per share total during 2025 • Provided returns to shareholders totaling approximately $230.4 million, comprised of $173.4 million in common stock dividend payments and $57.0 million in repurchases of common stock • Extended the weighted average maturity on our outstanding indebtedness to 5.4 years at year-end 2025, compared to 3.9 years at year-end 2024.
The Company did not have any ceiling test impairment for the years ended December 31, 2024 and 2023. Average commodity prices have declined in recent months.
As a result of its ceiling test, the Company recorded a non-cash impairment charge of $702.7 million in the year ending December 31, 2025. The Company did not have any ceiling test impairment charges for the years ended December 31, 2024 and 2023. Average commodity prices have declined in recent months.
World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future.
World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can significantly impact oil prices. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.
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.
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”). 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.
Critical Accounting Estimates The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting.
Based on current conditions and expectations, we are not presently budgeting for any material change in per well drilling and completion and other associated costs in 2026 compared to 2025. 61 Table of Contents Critical Accounting Estimates The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting.

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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) 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.
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) 2026: Q1 11,130,000 $ 4.08 12,203,249 12,203,249 $ 4.93 $ 3.39 Q2 12,420,000 3.97 12,924,706 12,924,706 4.96 3.42 Q3 12,420,000 4.01 12,924,706 12,924,706 4.92 3.45 Q4 14,415,000 4.14 12,889,642 12,889,642 5.10 3.47 2027: Q1 9,350,000 $ 4.02 6,965,000 6,965,000 $ 4.79 $ 3.46 Q2 9,660,000 4.01 5,980,000 5,980,000 4.43 3.45 Q3 9,660,000 4.01 5,980,000 5,980,000 4.43 3.45 Q4 7,485,000 3.98 4,275,000 4,275,000 4.41 3.45 2028: Q1 2,555,000 $ 3.83 900,000 900,000 $ 4.17 $ 3.50 Q2 1,840,000 3.83 920,000 920,000 4.17 3.50 Q3 1,840,000 3.83 920,000 920,000 4.17 3.50 Q4 1,530,000 3.85 920,000 920,000 4.07 3.50 2029: Q1 — $ — 890,000 890,000 $ 3.88 $ 3.50 Q2 — — 920,000 920,000 3.88 3.50 Q3 — — 920,000 920,000 3.88 3.50 Q4 — — 610,000 610,000 3.88 3.50 _____________ (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.
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.
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, 2025, by fiscal quarter.
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.
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, 2025.
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.
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. 64 Table of Contents The following table summarizes our open natural gas derivative contracts as of December 31, 2025, by fiscal quarter.
Our Senior Notes, and Convertible Notes bear cash interest at fixed rates. Our Revolving Credit Facility interest rate is a floating rate option that is designated by us within the parameters established by the underlying agreement (see Note 4 to our financial statements).
Our Senior Notes due 2028, Senior Notes due 2031, Senior Notes due 2033 and Convertible Notes bear cash interest at fixed rates. Our Revolving Credit Facility interest rate is a floating rate option that is designated by us within the parameters established by the underlying agreement (see Note 4 to our financial statements).
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.
A 1% increase in short-term interest rates on our floating-rate debt outstanding at December 31, 2025 would cost us approximately $1.5 million in additional annual interest expense.
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.
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 May 1, 2025 - May 1, 2027 $ 50,000 3.423 % USD-SOFR CME September 19, 2025 - October 1, 2027 $ 50,000 3.300 % USD-SOFR CME October 20, 2025 - November 1, 2027 $ 100,000 3.187 % USD-SOFR CME December 10, 2025 - December 1, 2027 $ 50,000 3.393 % USD-SOFR CME December 10, 2025 - December 1, 2028 $ 50,000 3.392 % USD-SOFR CME Changes in interest rates can impact results of operations and cash flows.
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.
Properties - Proved Reserves Sensitivity by Price Scenario” for estimates of how a change in oil and gas prices from the 2025 SEC Case to either the $50 Flat Case or the $70 Flat Case would impact our proved reserves volumes and the associated PV-10 values.
See Note 12 to our financial statements for further details regarding our commodity derivatives, including the call options and basis swaps that are not included in the foregoing table. 64 Table of Contents NGL Contracts Swaps Contract Period Volume (BBL) Weighted Average Price ($/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.
NGL Contracts Swaps Contract Period Volume (BBL) Weighted Average Price ($/BBL) 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, 2025 was comprised of borrowings that contain fixed and floating interest rates.
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.
Crude Oil Contracts Swaps (1) Collars Contract Period Volume (Bbls) Weighted Average Price ($/Bbl) Volume Ceiling (Bbls) Volume Floor (Bbls) Weighted Average Ceiling Price ($/Bbl) Weighted Average Floor Price ($/Bbl) 2026: Q1 2,291,876 $ 68.34 3,121,226 2,446,789 $ 72.98 $ 62.94 Q2 1,930,956 66.44 2,245,907 1,563,977 71.35 63.55 Q3 1,494,567 68.93 1,810,587 1,121,163 72.33 65.01 Q4 1,494,567 68.91 1,810,587 1,121,163 72.33 65.01 _____________ (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.
Removed
This table also does not include basis swaps.
Added
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. 65 Table of Contents The following table summarizes our open NGL derivative contracts as of December 31, 2025, by fiscal quarter.

Other NOG 10-K year-over-year comparisons