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What changed in Granite Ridge Resources, Inc.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of Granite Ridge Resources, 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.

+266 added−280 removedSource: 10-K (2026-03-06) vs 10-K (2025-03-06)

Top changes in Granite Ridge Resources, Inc.'s 2025 10-K

266 paragraphs added · 280 removed · 221 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

46 edited+15 added−19 removed147 unchanged
Biggest changeAs of December 31, 2024 Productive Oil Wells Productive Gas Wells Net Acres Gross Net Gross Net Average Daily Production (Boe per day) Proved Reserves (MBoe) % Oil % Proved Developed Permian 15,065 714 64.70 — — 13,191 37,232 56% 61% Eagle Ford 6,587 129 27.40 100 7.30 3,495 4,835 58% 94% Bakken 13,167 985 39.80 — — 2,095 3,739 71% 99% Haynesville 5,495 — — 127 17.20 4,219 3,288 0% 92% DJ 2,502 1,070 44.60 15 1.30 1,947 4,426 37% 93% Appalachian 1,067 6 0.10 — — 26 795 45% 86% Total 43,883 2,904 176.60 242 25.80 24,973 54,315 52% 72% Business Strategy Key elements of our business strategy include: Build a Diversified Portfolio : We invest in a large number of high-graded (typically directly sourced) opportunities which allow us to build a portfolio of oil and gas assets across the United States that is highly diversified in terms of geography, geology, hydrocarbon mix, and operator (both public and private) as well as operatorship.
Biggest changeAs of December 31, 2025 Productive Oil Wells Productive Gas Wells Net Acres Gross Net Gross Net Average Daily Production (Boe per day) Proved Reserves (MBoe) % Oil % Proved Developed Permian 30,190 962 100.73 — — 20,307 41,805 58% 69% Eagle Ford 4,366 138 28.31 106 7.86 2,532 4,659 43% 96% Bakken 13,167 998 39.81 — — 1,800 3,023 68% 100% Haynesville 5,495 — — 187 19.21 3,751 6,691 0% 86% DJ 2,502 1,127 44.94 18 1.28 2,044 3,767 35% 97% Appalachian 4,318 63 2.59 3 0.01 1,550 2,402 44% 82% Total 60,038 3,288 216.38 314 28.36 31,984 62,347 49% 76% Business Strategy Key elements of our business strategy include: Build a Diversified Portfolio : We invest in a large number of high-graded (typically directly sourced) opportunities which allow us to build a portfolio of oil and gas assets across the United States that is highly diversified in terms of geography, geology, hydrocarbon mix, and operator (both public and private) as well as operatorship.
Regulation of Transportation of Oil Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms, and cost of transportation.
Regulation of Transportation and Sales of Oil Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms, and cost of transportation.
Regulation of Transportation and Sales of Natural Gas Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes.
Regulation of Transportation and Sales of Natural Gas Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 and regulations issued under those statutes.
Subject to compliance with applicable law, and depending on, among other things, economic conditions, financial condition, results of operations, projections, liquidity, earnings, legal requirements, and restrictions in the Credit Agreement, we expect that Granite Ridge will pay quarterly cash dividends.
Subject to compliance with applicable law, and depending on, among other things, economic conditions, financial condition, results of operations, projections, liquidity, earnings, legal requirements, and restrictions in the Credit Agreement and Note Purchase Agreement, we expect that Granite Ridge will pay quarterly cash dividends.
The following table sets forth the percentage of revenues attributable to third-party operating partners who have accounted for 10% or more of revenues attributable to our assets during the years ended December 31, 2024, 2023 and 2022.
The following table sets forth the percentage of revenues attributable to third-party operating partners who have accounted for 10% or more of revenues attributable to our assets during the years ended December 31, 2025, 2024 and 2023.
The following is a summary of information regarding our assets as of December 31, 2024, including reserves information as estimated by our third-party independent reserve engineers, Netherland, Sewell & Associates, Inc.
The following is a summary of information regarding our assets as of December 31, 2025, including reserves information as estimated by our third-party independent reserve engineers, Netherland, Sewell & Associates, Inc.
Major Operators 2024 2023 2022 Operator A * 11 % 12 % Operator B * 12 % 10 % Operator C * * 10 % Operator D 14 % * * __________________________________________ * Less than 10% No other operator accounted for 10% or more of revenue attributable to our assets on a combined basis in the years ended December 31, 2024, 2023, or 2022.
Major Operators 2025 2024 2023 Operator A * * 11 % Operator B * * 12 % Operator C 11 % * * Operator D 26 % 14 % * __________________________________________ * Less than 10% No other operator accounted for 10% or more of revenue attributable to our assets on a combined basis in the years ended December 31, 2025, 2024, or 2023.
DJ The Denver-Julesburg Basin, also known as the DJ Basin, is a geologic basin centered in eastern Colorado stretching into southeast Wyoming, western Nebraska and western Kansas. Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations. At December 31, 2024, 8% of our total proved reserves were located in the DJ Basin.
DJ The Denver-Julesburg Basin, also known as the DJ Basin, is a geologic basin centered in eastern Colorado stretching into southeast Wyoming, western Nebraska and western Kansas. Development in this area is currently focused on horizontal drilling in the Niobrara and Codell formations. At December 31, 2025, 6% of our total proved reserves were located in the DJ Basin.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on the Properties.
In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified 20 Table of Contents onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on the Properties.
We furnish or file our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments and exhibits to such reports or other documents with the SEC under the Securities Exchange 22 Table of Contents Act of 1934, as amended (the "Exchange Act").
We furnish or file our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments and exhibits to such reports or other documents with the SEC under the Securities Exchange Act of 1934, as amended (the "Exchange Act").
These rules, if adopted, along with increasing pressure related to ESG from the investor community could lead to increased operating costs that would materially adversely affect our operating partners and our revenues and results of operations.
These rules, if adopted, along with increasing pressure related to ESG from the investor 21 Table of Contents community could lead to increased operating costs that would materially adversely affect our operating partners and our revenues and results of operations.
Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Properties to 18 Table of Contents dispose of produced water and ultimately increase the cost of operation of the Properties or delay production schedules.
Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Properties to dispose of produced water and ultimately increase the cost of operation of the Properties or delay production schedules.
The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. At December 31, 2024, 69% of our total proved reserves were located in the Permian Basin.
The extensive operating history, favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, horizontal development potential and liquids-rich reserves make the Permian Basin one of the most prolific oil-producing regions in the United States. At December 31, 2025, 67% of our total proved reserves were located in the Permian Basin.
These statutes include the federal Endangered Species 19 Table of Contents Act, the Migratory Bird Treaty Act (“MTBA”), the Bald and Golden Eagle Protection Act, the Clean Water Act, CERCLA, analogous state laws, and each of their implementing regulations.
These statutes include the federal Endangered Species Act, the Migratory Bird Treaty Act (“MTBA”), the Bald and Golden Eagle Protection Act, the Clean Water Act, CERCLA, analogous state laws, and each of their implementing regulations.
Human Capital Resources As of December 31, 2024, we had three full time employees. We have an MSA with the Manager, pursuant to which the Manager provides general and administrative, engineering, land, contract administration, tax, accounting, legal and compliance services to us.
Human Capital Resources As of December 31, 2025, we had six full time employees. We have an MSA with the Manager, pursuant to which the Manager provides general and administrative, engineering, land, contract administration, tax, accounting, legal and compliance services to us.
In addition, compliance with CWA requirements could limit the locations where wells, other oil and natural gas facilities, and associated access resources can be constructed. The scope of regulated waters has been subject to substantial controversy.
In addition, compliance with CWA requirements could limit the locations where wells, other oil and natural gas facilities, and associated access resources can be constructed. The scope of regulated waters, or waters of the United States (“WOTUS”) has been subject to substantial controversy.
We share a portion of the Manager’s office space (which consists of approximately 11,700 square feet), pursuant to the MSA. We believe our office space is sufficient to meet our needs and that additional office space can be obtained if necessary.
We share a portion of the Manager’s office space (which consists of approximately 18,400 square feet), pursuant to the MSA. We believe our office space is sufficient to meet our needs and that additional office space can be obtained if necessary.
Information on our website is not incorporated into this Annual Report or our other filings with the SEC and is not a part of them.
Information on our website is not incorporated into this Annual Report or our other filings with the SEC and is not a part of them. 22 Table of Contents
The EPA has also promulgated regulations establishing construction and operating permit requirements for greenhouse gas emissions from stationary sources that already emit conventional pollutants (i.e., sulfur dioxide, particulate matter, nitrogen dioxide, carbon monoxide, ozone, and lead) above certain thresholds.
The EPA had also promulgated regulations establishing construction and operating permit requirements for GHG emissions from stationary sources that already emit conventional pollutants (i.e., sulfur dioxide, particulate matter, nitrogen dioxide, carbon monoxide, ozone, and lead) above certain thresholds.
During the year ended December 31, 2024, operators completed 80 gross (1.78 net) wells in the DJ Basin. Appalachian The Appalachian Basin is a geologic basin in the eastern United States. Our acquisition and development efforts in this area are currently focused in the northern Utica Shale play within Ohio.
During the year ended December 31, 2025, operators completed 79 gross (1.37 net) wells in the DJ Basin. Appalachian The Appalachian Basin is a geologic basin in the eastern United States. Our acquisition and development efforts in this area are currently focused in the northern Utica Shale play within Ohio.
Any changes to the NEPA review 20 Table of Contents process would affect the assessment of projects ranging from oil and natural gas leasing to development on public and Indian lands.
Any further changes to the NEPA review process would affect the assessment of projects ranging from oil and natural gas leasing to development on public and Indian lands.
On January 14, 2021, the EPA issued a guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. However, on September 16, 2021, the EPA rescinded its January 14, 2021 guidance.
On January 14, 2021, the EPA issued a guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters.
During the year ended December 31, 2024, operators completed 18 gross (3.36 net) wells in the Eagle Ford Basin. Bakken The Williston Basin stretches through North Dakota, the northwest part of South Dakota, and eastern Montana and is best known for the Bakken/Three Forks shale formations. The Bakken ranks as one of the largest oil developments in the United States.
During the year ended December 31, 2025, operators completed 7 gross (0.50 net) wells in the Eagle Ford Basin. Bakken The Williston Basin stretches through North Dakota, the northwest part of South Dakota, and eastern Montana and is best known for the Bakken/Three Forks shale formations. The Bakken ranks as one of the largest oil developments in the United States.
To the extent the implementation of the final rule, results of the litigation, or any action further expands the scope of the CWA’s jurisdiction, operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
To the extent the implementation of the September 2023 rule, challenges to the November 2025 proposed rule, results of the litigation, or any action further expands the scope of the CWA’s jurisdiction, operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
During the year ended December 31, 2024, operators completed 133 gross (16.81 net) wells in the Permian Basin. Eagle Ford The Eagle Ford shale formation stretches across south Texas and includes Austin Chalk and Buda formations. At December 31, 2024, 9% of our total proved reserves were located in the Eagle Ford Basin.
During the year ended December 31, 2025, operators completed 148 gross (31.77 net) wells in the Permian Basin. Eagle Ford The Eagle Ford shale formation stretches across south Texas and includes Austin Chalk and Buda formations. At December 31, 2025, 7% of our total proved reserves were located in the Eagle Ford Basin.
At December 31, 2024, 7% of our total proved reserves were located in the Bakken Basin. During the year ended December 31, 2024, operators completed 56 gross (1.00 net) wells in the Bakken Basin. 12 Table of Contents Haynesville The Haynesville Basin is a premier natural gas basin located in northwestern Louisiana and east Texas.
At December 31, 2025, 5% of our total proved reserves were located in the Bakken Basin. During the year ended December 31, 2025, operators completed 14 gross (0.26 net) wells in the Bakken Basin. 12 Table of Contents Haynesville The Haynesville Basin is a premier natural gas basin located in northwestern Louisiana and east Texas.
While the Trump Administration may take action to repeal or modify the final rules, we cannot predict the substance or timing of such changes. The requirements of the EPA's final methane rules have the potential to increase the operating costs of our operators and thus may adversely affect our financial results and cash flows.
We cannot predict when or whether the EPA may take further action to repeal or modify the final rules. The requirements of the EPA's final methane rules have the potential to increase the operating costs of our operators and thus may adversely affect our financial results and cash flows.
At December 31, 2024, 1% of our total proved reserves were located in the Appalachian Basin. During the year ended December 31, 2024, operators completed 6 gross (0.14 net) wells in the Appalachian Basin.
At December 31, 2025, 11% of our total proved reserves were located in the Haynesville Basin. During the year ended December 31, 2025, operators completed 14 gross (1.90 net) wells in the Haynesville Basin.
President Biden recommitted the United States to the Paris Agreement on January 20, 2021; however, on January 20, 2025, President Trump signed an Executive Order once again withdrawing the U.S. from the Paris Agreement and from any commitments made under the United Nations Framework Convention on Climate Change.
However, on January 20, 2025, President Trump signed an Executive Order once again withdrawing the U.S. from the Paris Agreement and from any commitments made under the United Nations Framework Convention on Climate Change. Additionally, President Trump revoked any purported financial commitment made by the U.S. pursuant to the same.
Hawaii Wildlife Fund , holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters.
In April 2020, the Supreme Court issued a ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters.
At December 31, 2024, 6% of our total proved reserves were located in the Haynesville Basin. During the year ended December 31, 2024, operators completed 6 gross (0.34 net) wells in the Haynesville Basin.
At December 31, 2025, 4% of our total proved reserves were located in the Appalachian Basin. During the year ended December 31, 2025, operators completed 60 gross (2.47 net) wells in the Appalachian Basin.
Operations in any area that is designated as the DSL’s habitat may be limited, delayed or, in some circumstances, prohibited, and our operators could be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat, thereby impacting our profitability.
To the extent the DSL is re-listed, operations in any area that is designated as the DSL’s habitat may be limited, delayed or, in some circumstances, prohibited, and our operators could be required to comply with expensive mitigation measures intended to protect the dunes sagebrush lizard and its habitat, thereby impacting our profitability. 19 Table of Contents The purpose of the Occupational Safety and Health Act (“OSHA”), comparable state statutes, and each of their implementing regulations is to protect the health and safety of workers.
The charge starts at $900 per metric ton of methane in 2025 (using 2024 data), and increases to $1,500 after two years. While Congress has from time to time considered legislation to reduce emissions of GHGs, in recent years there has not been significant activity at the federal level in the form of adopted legislation aimed at reducing GHG emissions.
While Congress has from time to time considered legislation to reduce emissions of GHGs, in recent years there has not been significant activity at the federal level in the form of adopted legislation aimed at reducing GHG emissions.
Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. 21 Table of Contents Environmental, social, and governance (“ESG”) programs and goals, which are often aspirational, typically include voluntary targets related to environmental stewardship, social responsibility, and corporate governance matters, have become an increasing focus of certain investors and stockholders across the industry that often have conflicting priorities and perspectives.
Environmental, social, and governance (“ESG”) programs and goals, which are often aspirational, typically include voluntary targets related to environmental stewardship, social responsibility, and corporate governance matters, have become an increasing focus of certain investors and stockholders across the industry that often have conflicting priorities and perspectives.
Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis.
For example, the Dunes Sagebrush Lizard (“DSL”) was listed as endangered by the USFWS in May 2024. The DSL is found in southeastern New Mexico and adjacent portions of Texas.
For example, the Dunes Sagebrush Lizard (“DSL”) was listed as endangered by the USFWS in May 2024; however, in August 2025, the U.S. District Court for the Western District of Texas vacated and remanded the final rule listing the DSL. An appeal challenging this order is pending. The DSL is found in southeastern New Mexico and adjacent portions of Texas.
In addition, several cases have in recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established.
Most recently, in May 2025, the RRC released updated guidance for disposal well permits in the Permian Basin that placed new limits on maximum injection pressure and volumes to ensure safety. 18 Table of Contents In addition, several cases have in recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established.
In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold.
Notwithstanding the EPA’s final rule in February 2026 rescinding the GHG “Endangerment Finding” that provides the basis for its authority to regulate GHG emissions, the EPA under previous administrations has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold.
If in the future CWA permitting is required for saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund , the costs of permitting and compliance for injection well operations by the companies that operate the Properties could increase.
Hawaii Wildlife Fund , the costs of permitting and compliance for injection well operations by the companies that operate the Properties could increase.
Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. On January 20, 2022, the FERC established a new price index for the five-year period which commenced on July 1, 2021. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.
Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. On December 17, 2020, the FERC established a new price index for the five-year period which commenced on July 1, 2021. Following an appeal to and remand from the D.C.
Under the CAA, the EPA has enacted final regulations requiring owners and operators of certain facilities that emit greenhouse gases above certain thresholds to report those emissions.
Notwithstanding the EPA’s final rule in February 2026 revoking the greenhouse gas (“GHG”) “Endangerment Finding” that provides the basis for its authority to regulate GHG emissions, the EPA in previous administrations had enacted final regulations under the CAA requiring owners and operators of certain facilities that emit GHGs above certain thresholds to report those emissions.
However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges. Similarly, certain states have enacted or are otherwise considering disclosure requirements for certain climate-related risks.
However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges, with such litigation held in abeyance until the SEC repeals, reconsiders, or otherwise modifies the rule.
We cannot predict whether other similar legislation in other states will ever be enacted and if so, what the provisions of such legislation would be.
Further, the February 2026, the Colorado Department of Public Health and Environment finalized regulations for methane emissions from oil and gas operations to align with the federal subparts OOOOb and OOOOc. We cannot predict whether other similar legislation in other states will ever be enacted and if so, what the provisions of such legislation would be.
Additionally, the CAA regulates the emission of methane from oil and gas facilities, which has been subject to uncertainty in recent years. Most recently, 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 for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc that set standards for emission capture and control systems and equipment, leak detection equipment and monitoring, and so-called “green well” completion requirements.
Additionally, President Trump revoked any purported financial commitment made by the U.S. pursuant to the same. The full impact of these actions is uncertain at this time.
The full impact of these actions is uncertain at this time.
Other activities are covered under categorical exclusions which results in a shorter NEPA review process. In April 2022, the Biden Administration’s Council on Environmental Quality (“CEQ”) issued a final rule considered as “Phase I” of a two-phased approach to modifying the NEPA.
Other activities are covered under categorical exclusions which results in a shorter NEPA review process. In November 2024, the U.S. Court of Appeals for the D.C. Circuit held that the Council on Environmental Quality (“CEQ”) lacks authority to issue NEPA regulations, and a federal district court in North Dakota reached the same conclusion in February 2025.
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Under the final rules, states have two years to prepare and submit their 17 Table of Contents plants to impose methane emission controls on existing sources.
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Circuit, the FERC confirmed on November 20, 2025 that the index established in December 2020 will remain in place through June 30, 2026. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.
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The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of 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.
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State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements.
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In 2015 and 2020, respectively, the Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over waters of the United States (“WOTUS”). However, both of these rulemakings were subject to legal challenge.
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Litigation has already been filed challenging the February 2026 rule, and while we cannot predict the final outcome, as a result, there is significant uncertainty with respect to regulation of GHG emissions.
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In January 2023, the EPA and Corps published a final rule based on the pre-2015 definition, with updates to incorporate existing Supreme Court decisions and regulatory guidance. However, the January 2023 rule was challenged and is currently enjoined in 27 states. In May 2023 the U.S. Supreme Court released its opinion in Sackett v.
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Additionally, the CAA regulates the emission of methane from oil and gas 17 Table of Contents facilities, which has been subject to uncertainty in recent years.
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EPA, which involved issues relating to the legal tests used to determine whether wetlands qualify as WOTUS. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023.
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In March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc, and in November 2025, the EPA issued an interim final rule extending several compliance for certain provisions in the December 2023 rule. Litigation challenging the interim final rule remains pending.
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However, due to the injunction on the January 2023 rule, the implementation of the September 2023 rule currently varies by state.
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In September 2023, the EPA and USACE issued a final rule conforming the regulatory definition of WOTUS to the U.S. Supreme Court’s decision in Sackett v. EPA, which narrowed the scope of WOTUS. However, the rule is currently subject to litigation, and as a result, the September 2023 rule is only in effect in 24 states.
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In the 27 states subject to the injunction, the agencies are interpreting the definition of WOTUS consistent with the pre-2015 regulatory regime and the changes made by the Sackett decision, which utilizes the “continuous surface connection” test to determine if wetlands qualify as WOTUS.
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Thus, the operative definition of WOTUS currently varies by state. In November 2025, the EPA and USACE issued a proposed rule to further update and narrow the definition of WOTUS.
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In the remaining 23 states, the agencies are implementing the September 2023 rule, which did not define the term “continuous surface connection.” Therefore, some uncertainty remains as to how broadly the September 2023 rule and the Sackett decision will be interpreted by the agencies.
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For example, in recent years, the RRC has imposed prohibitions and restrictions on SWD wells in response to a number of earthquakes in recent years in the Midland Basin.
Removed
For example, in response to a number of earthquakes in recent years in the Midland Basin, in September 2021 the RRC announced that it will not issue any new saltwater disposal (“SWD”) well permits in an area known as the Gardendale Seismic Response Area (“SRA”), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well.
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However, on September 16, 2021, the EPA rescinded its January 14, 2021 guidance, and the EPA’s rule updating the definition of WOTUS proposed in November 2025 would exclude groundwater. If in the future CWA permitting is required for saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v.
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In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. And in October 2021 and January 2022, respectively, the RRC identified two additional SRAs: the Northern Culberson-Reeves SRA and the Stanton SRA.
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On February 25, 2025, the CEQ published an Interim Final Rule rescinding its regulations implementing NEPA and adopted this rule as final in January 2026. In June 2025, several federal agencies issued their own regulations or procedures for implementing NEPA. Further, in May 2025, the U.S. Supreme Court held in Seven County Infrastructure Coalition v.
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Operators in the Northern Culberson-Reeves and Stanton SRAs have implemented seismic response plans, which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff. In December 2023, the RRC suspended the permits of 23 deep disposal wells in the Northern Culberson-Reeves SRA.
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Eagle County, Colorado that agency determinations under NEPA are owed substantial judicial deference and that agencies are not required to consider environmental effects associated with separate projects. As a result, there is significant uncertainty with respect to the scope of environmental reviews under NEPA, and NEPA procedures currently vary by agency.
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The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs.
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Litigation has already been filed challenging the February 2026 rule, and while we cannot predict the final outcome, as a result, there is significant uncertainty with respect to regulation of GHG emissions.
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In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in County of Maui, Hawaii v.
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Further, the Inflation Reduction Act (“IRA”), which passed in August 2022, includes a charge for excess methane emissions from certain facilities, though the EPA’s rule implementing the charge was revoked in March 2025 following a Joint Resolution of Disapproval under the Congressional Review Act, and the One Big Beautiful Bill Act, passed in July 2025, delayed implementation of the charge until 2034.
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The purpose of the Occupational Safety and Health Act (“OSHA”), comparable state statutes, and each of their implementing regulations is to protect the health and safety of workers.
Added
Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
Removed
Then, in May 2024, the CEQ finalized “Phase 2,” which revised the implementing regulations of the procedural provisions of NEPA. The final rule was challenged by various states. Most recently, in November 2024, the U.S. Court of Appeals for the D.C. Circuit held that the CEQ lacks authority to issue NEPA regulations.
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In March 2025, the SEC voted to end its defense of the rule, though to date no further action has been taken to repeal the rule. Similarly, certain states have enacted or are otherwise considering disclosure requirements for certain climate-related risks.
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As a result of this ruling and the new Trump Administration, there is significant uncertainty with respect to current and future NEPA regulations.
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For example, on January 20, 2025, President Trump issued an Executive Order directing the CEQ to issue new guidance and propose rescinding the existing NEPA regulations to “expedite and simplify the permitting process.” And, on February 25, 2025, in response to this direction, the CEQ published an Interim Final Rule, requesting public comment through March 27, 2025.
Removed
Further, the Inflation Reduction Act (“IRA”), which passed in August 2022, includes a charge for methane emissions from specific types of facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year, and, although the IRA generally provides for a conditional exemption under certain circumstances, the charge applies to emissions that exceed an established emissions threshold for each type of covered facility.
Removed
For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including alleged greenwashing.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

65 edited+11 added−23 removed234 unchanged
Biggest changeAlthough the reserve information contained herein is reviewed by our independent reserve engineers, estimates of crude oil and natural gas reserves are inherently imprecise. The process also requires economic assumptions about matters such as oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Biggest changeThe process also requires economic assumptions about matters such as oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our estimated reserves relies in part on the ability of the Manager’s reserve engineers to make accurate assumptions.
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; • 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; • political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, particularly those in the Middle East, Russia, South America and Africa; • the outbreak or escalation of military hostilities, including between Russia and Ukraine, Israel and Hamas, continued instability in the Middle East, and the potential destabilizing effect such conflicts may pose for the European continent or the global oil and natural gas markets; • the level of global oil and natural gas exploration, production activity and inventories; • changes in U.S. energy policy; • weather conditions and world health events; • technological advances affecting energy consumption; • domestic, local and foreign governmental taxes, tariffs and/or regulations; • proximity and capacity of processing, gathering, storage, 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; • 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; • political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, particularly those in the Middle East, Russia, South America and Africa; • the outbreak or escalation of military hostilities, including between Russia and Ukraine, Israel and Hamas, the U.S., Israel and Iran, continued instability in the Middle East, and the potential destabilizing effect such conflicts may pose for the European continent or the global oil and natural gas markets; • the level of global oil and natural gas exploration, production activity and inventories; • changes in U.S. energy policy; • weather conditions and world health events; • technological advances affecting energy consumption; • domestic, local and foreign governmental taxes, tariffs and/or regulations; • proximity and capacity of processing, gathering, storage, 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.
Factors affecting the trading price of our securities may include: • actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us; • changes in the market’s expectations about our operating results; • lack of adjacent competitors; • our operating results failing to meet the expectation of securities analysts or investors in a particular period; • changes in financial estimates and recommendations by securities analysts concerning us or the industries in which we operate in general; • operating and stock price performance of other companies that investors deem comparable to us; • announcements by us or our competitors of significant contracts, acquisitions, joint ventures, other strategic relationships or capital commitments; • changes in laws and regulations affecting our business; • commencement of, or involvement in, litigation involving us; • changes in our capital structure, such as future issuances of securities or the incurrence of additional debt; • the volume of shares of our common stock available for public sale; • any significant change in our Board of Directors or management; • speculation by the press or investment community; • sales of substantial amounts of our common stock by our directors, executive officers or significant stockholders or the perception that such sales could occur; 42 Table of Contents • general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations and acts of war or terrorism; and • changes in accounting standards, policies, guidelines, interpretations or principles.
Factors affecting the trading price of our securities may include: • actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us; • changes in the market’s expectations about our operating results; • lack of adjacent competitors; • our operating results failing to meet the expectation of securities analysts or investors in a particular period; • changes in financial estimates and recommendations by securities analysts concerning us or the industries in which we operate in general; • operating and stock price performance of other companies that investors deem comparable to us; • announcements by us or our competitors of significant contracts, acquisitions, joint ventures, other strategic relationships or capital commitments; • changes in laws and regulations affecting our business; • commencement of, or involvement in, litigation involving us; • changes in our capital structure, such as future issuances of securities or the incurrence of additional debt; • the volume of shares of our common stock available for public sale; • any significant change in our Board of Directors or management; 41 Table of Contents • speculation by the press or investment community; • sales of substantial amounts of our common stock by our directors, executive officers or significant stockholders or the perception that such sales could occur; • general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations and acts of war or terrorism; and • changes in accounting standards, policies, guidelines, interpretations or principles.
Examples of laws and regulations that govern the environmental aspects of the oil and gas business include the following: • the CAA, which restricts the emission of air pollutants from many sources, imposes various pre-construction, operating, permitting monitoring, control, recordkeeping, and reporting requirements and is relied upon by the EPA as an authority for adopting climate change regulatory initiatives, including relating to GHG emissions; • the CWA, which regulates discharges of pollutants and dredge and fill material to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction as protected waters of the United States; • the OPA, which requires oil spill prevention, control, and countermeasure planning and imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States; • the SDWA, which protects the quality of the nation’s public drinking water sources through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations; • the CERCLA, which imposes liability without regard to fault on certain categories of potentially responsible parties including generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as on present and certain past owners and operators of sites were hazardous substance releases have occurred or are threatening to occur; • the RCRA, which imposes requirements for the generation, treatment, storage, transport, disposal and cleanup of non-hazardous and hazardous wastes; • the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas.
Examples of laws and regulations that govern the environmental aspects of the oil and gas business include the following: • the CAA, which restricts the emission of air pollutants from many sources, imposes various pre-construction, operating, permitting monitoring, control, recordkeeping, and reporting requirements and is relied upon by the EPA as an authority for adopting climate change regulatory initiatives, including relating to GHG emissions; 32 Table of Contents • the CWA, which regulates discharges of pollutants and dredge and fill material to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction as protected waters of the United States; • the OPA, which requires oil spill prevention, control, and countermeasure planning and imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States; • the SDWA, which protects the quality of the nation’s public drinking water sources through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations; • the CERCLA, which imposes liability without regard to fault on certain categories of potentially responsible parties including generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as on present and certain past owners and operators of sites were hazardous substance releases have occurred or are threatening to occur; • the RCRA, which imposes requirements for the generation, treatment, storage, transport, disposal and cleanup of non-hazardous and hazardous wastes; • the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas.
These provisions, among other things: • establish a staggered board of directors divided into three classes serving staggered three-year terms, such that not all members of our Board will be elected at one time; • authorize our Board to issue new series of preferred stock without stockholder approval and create, subject to applicable law, a series of preferred stock with preferential rights to dividends or our assets upon liquidation, or with superior voting rights to existing common stock; • eliminate the ability of stockholders to call special meetings of stockholders; • eliminate the ability of stockholders to fill vacancies on our Board; • establish advance notice requirements for nominations for election to our Board or for proposing matters that can be acted upon by stockholders at annual stockholder meetings; 39 Table of Contents • permit our Board to establish the number of directors; • provide that our Board is expressly authorized to make, alter or repeal our amended and restated bylaws; • provide that stockholders can remove directors only for cause; and • limit the jurisdictions in which certain stockholder litigation may be brought.
These provisions, among other things: • establish a staggered board of directors divided into three classes serving staggered three-year terms, such that not all members of our Board will be elected at one time; • authorize our Board to issue new series of preferred stock without stockholder approval and create, subject to applicable law, a series of preferred stock with preferential rights to dividends or our assets upon liquidation, or with superior voting rights to existing common stock; • eliminate the ability of stockholders to call special meetings of stockholders; 38 Table of Contents • eliminate the ability of stockholders to fill vacancies on our Board; • establish advance notice requirements for nominations for election to our Board or for proposing matters that can be acted upon by stockholders at annual stockholder meetings; • permit our Board to establish the number of directors; • provide that our Board is expressly authorized to make, alter or repeal our amended and restated bylaws; • provide that stockholders can remove directors only for cause; and • limit the jurisdictions in which certain stockholder litigation may be brought.
In addition, drilling and producing operations on our acreage may be curtailed, delayed, or canceled by the operators of the Properties 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, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents; • title problems; • pipe or cement failures and casing collapses; • lost or damaged oilfield development and service tools; • compliance with environmental, health, safety and other governmental requirements; • increases in severance taxes; • regulations, restrictions, moratoria and bans on hydraulic fracturing; • unusual or unexpected geological formations, and pressure or irregularities in formations; • loss of drilling fluid circulation; • 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 the operators of the Properties as a result of other factors, including: • declines in oil or natural gas prices; 25 Table of Contents • infrastructure limitations, such as gas gathering and processing constraints; • the high cost, shortages or delays of equipment, materials and services; • unexpected operational events, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents; • title problems; • pipe or cement failures and casing collapses; • lost or damaged oilfield development and service tools; • compliance with environmental, health, safety and other governmental requirements; • increases in severance taxes; • regulations, restrictions, moratoria and bans on hydraulic fracturing; • unusual or unexpected geological formations, and pressure or irregularities in formations; • loss of drilling fluid circulation; • 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 2024 and 2023, we were required to write down the carrying value of certain properties that constitute our oil and natural gas properties, and further writedowns could be required by us in the future.
In 2025, 2024, and 2023, we were required to write down the carrying value of certain properties that constitute our oil and natural gas properties, and further writedowns could be required by us in the future.
Furthermore, various third-party resources that we or the Manager rely on, directly or indirectly, in the operation of our business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyberattacks or similar events that are entirely outside the control of us or the Manager, and any such events could significantly disrupt our business operations and/or have a material adverse effect on our results of operations.
Furthermore, various third-party resources that we or the Manager rely on, directly or indirectly, in the operation of our business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyberattacks or similar events that are entirely outside the control of us or the Manager, and any such events could significantly disrupt our business operations and/or have a material adverse effect on our results of operations and financial condition.
Restrictions on emissions of methane or carbon dioxide, such as restrictions 35 Table of Contents on venting and flaring of natural gas, that may be imposed in various states, as well as state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets.
Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas, that may be imposed in various states, as well as state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets.
“Risk Factors.” 43 Table of Contents Adverse developments affecting the financial services industry, such as actual events or concerns involving liquidity, defaults or non-performance by financial institutions or transactional counterparties, could adversely affect our current and projected business operations and financial condition and results of operations.
“Risk Factors.” 42 Table of Contents Adverse developments affecting the financial services industry, such as actual events or concerns involving liquidity, defaults or non-performance by financial institutions or transactional counterparties, could adversely affect our current and projected business operations and financial condition and results of operations.
The insolvency of an operator of any of the Properties, the failure of an operator of any of the Properties to adequately perform operations or an operator’s breach of applicable agreements (including failure to spud or place wells into production) could result in penalties, reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety, and other regulatory requirements, to the operator’s 23 Table of Contents suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner.
The insolvency of an operator of any of the Properties, the failure of an operator of any of the Properties to adequately perform operations or an operator’s breach of applicable agreements (including failure to spud or place wells into production) could result in penalties, reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety, and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner.
Seismicity concerns associated with injection of produced water and certain other field fluids into disposal wells has led to increased regulation of saltwater injection and disposal wells in certain areas of states in which the Properties are 34 Table of Contents located, which could increase the cost of, or limit the number of facilities available for, disposal of produced water from oil and gas exploration and production operations at the Properties.
Seismicity concerns associated with injection of produced water and certain other field fluids into disposal wells has led to increased regulation of saltwater injection and disposal wells in certain areas of states in which the Properties are located, which could increase the cost of, or limit the number of facilities available for, disposal of produced water from oil and gas exploration and production operations at the Properties.
For example, the ongoing armed conflicts between Russia and Ukraine and Israel and Hamas and the continuation of, and the escalation in the severity of, these conflicts has led to extreme regional instability, caused dramatic fluctuations in global financial markets and has increased the level of global economic uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has caused increased volatility in commodity prices.
For example, the ongoing armed conflicts between Russia and Ukraine, Israel and Hamas, the U.S., Israel and Iran and the continuation of, and the escalation in the severity of, these conflicts has led to extreme regional instability, caused dramatic fluctuations in global financial markets and has increased the level of global economic uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has caused increased volatility in commodity prices.
In addition, our amended and restated certificate of incorporation provides that the federal district courts of the United States will be the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act; however, there is uncertainty as to whether a court would enforce such provision.
In addition, our amended and restated certificate of incorporation provides that the federal district courts of the United States will be the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act; 39 Table of Contents however, there is uncertainty as to whether a court would enforce such provision.
We are subject to credit risk due to the relative concentration of our oil and natural gas receivables with a limited number of operating partners. This may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions.
We are subject to credit risk due to the relative concentration of our oil and natural gas receivables with a limited number 23 Table of Contents of operating partners. This may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions.
Any significant variance from these assumptions by actual figures could greatly affect our estimated reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows.
Any significant variance from these assumptions by actual figures could greatly affect our estimated reserves, the economically recoverable quantities of oil 27 Table of Contents and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows.
Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our operators' wells but have not established any cash reserve account for these potential costs in respect of any of the Properties.
Abandonment and reclamation of these 30 Table of Contents facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our operators' wells but have not established any cash reserve account for these potential costs in respect of any of the Properties.
To the extent not addressed by the MSA, we and the Manager have implemented policies as necessary or appropriate to deal with such potential conflicts. Investment analyses and decisions by the Manager may frequently be required to be undertaken on an expedited basis to take advantage of investment opportunities.
To the 36 Table of Contents extent not addressed by the MSA, we and the Manager have implemented policies as necessary or appropriate to deal with such potential conflicts. Investment analyses and decisions by the Manager may frequently be required to be undertaken on an expedited basis to take advantage of investment opportunities.
Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will 26 Table of Contents expire. If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related Properties.
Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to participate in the development of the related Properties.
Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.
Delays in the development of our reserves or increases in costs to drill and develop such reserves 28 Table of Contents will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.
The passage of any legislation as a result of these proposals and other changes in tax laws or the imposition of new or increased taxes or fees could increase our future tax liabilities and adversely affect our operating results and cash flows.
The passage of any legislation as a result of these proposals and 40 Table of Contents other changes in tax laws or the imposition of new or increased taxes or fees could increase our future tax liabilities and adversely affect our operating results and cash flows.
It is possible that we, the Manager, or these third parties, could incur interruptions from cybersecurity attacks, computer viruses or malware, user error, or that third-party service providers could cause a breach of our systems or our data.
It is possible that we, the Manager, or these third parties, could incur interruptions from cybersecurity attacks, computer viruses or malware, user error, or that third-party service providers 31 Table of Contents could cause a breach of our systems or our data.
Fuel and energy 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.
Fuel and energy 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 35 Table of Contents competitiveness of alternative energy sources could reduce demand for oil and natural gas.
Please see the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources — Granite Ridge Credit Agreement” for more information.
Please see the section 37 Table of Contents entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources — Granite Ridge Credit Agreement” for more information.
In addition, certain organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions.
In addition, certain organizations that provide information, ratings or proxy advisory services to investors on corporate governance and related matters have developed processes for evaluating companies on their approach to ESG matters. Such ratings or recommendations are used by some investors to inform their investment and voting decisions.
If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected. 31 Table of Contents We and our operating partners depend on computer and telecommunications systems, and failures in those systems or cybersecurity threats, attacks and other disruptions could significantly disrupt our business operations.
If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected. We and our operating partners depend on computer and telecommunications systems and other information and operational technology systems, and failures in those systems or cybersecurity threats, attacks and other disruptions could significantly disrupt our business operations.
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 our operators use for production of oil and natural gas reserves.
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 our operators use for production of oil and natural gas reserves.
If maintained, the newly announced tariffs and the potential escalation of trade disputes could pose a risk to our business and also directly impact our operating expenses. For example, recently announced 25% tariffs on imported steel are likely to lead to increased material costs. Item 1B. Unresolved Staff Comments None. 44 Table of Contents
If maintained or implemented, tariffs and the potential escalation of trade disputes could pose a risk to our business and also directly impact our operating expenses. For example, previously announced 25% tariffs on imported steel are likely to lead to increased material costs. Item 1B. Unresolved Staff Comments None. 43 Table of Contents
Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 28% 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.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced. Approximately 24% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2025.
The ongoing military conflicts between Ukraine and Russia, Israel and Hamas, and continued instability in the Middle East has caused unstable market and economic conditions and is expected to have additional global consequences, such as heightened risks of cyberattacks.
The ongoing military conflicts between Ukraine and Russia, Israel and Hamas, the joint U.S.-Israel strikes on Iran, and continued instability in the Middle East has caused unstable market and economic conditions and is expected to have additional global consequences, such as heightened risks of cyberattacks.
As a result, following the Business Combination, we are a “controlled company” within the meaning of the corporate governance standards of the rules of the NYSE.
As a result, we are a “controlled company” within the meaning of the corporate governance standards of the rules of the NYSE.
Additionally, some states in which the Properties are located, such as Colorado and New Mexico, have adopted stringent rules and regulations to reduce methane emissions and emissions of other hydrocarbons, VOCs, and nitrogen oxides associated with oil and gas facilities.
These rules could further increase the cost of development and operation of the Properties. Additionally, some states in which the Properties are located, such as Colorado and New Mexico, have adopted stringent rules and regulations to reduce methane emissions and emissions of other hydrocarbons, VOCs, and nitrogen oxides associated with oil and gas facilities.
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 our 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. 30 Table of Contents Decommissioning costs are unknown and may be substantial.
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 our 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.
Also, institutional 36 Table of Contents lenders may, of their own accord, elect not to provide or place additional restrictions on funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.
Certain financial institutions may also, of their own accord, elect not to provide or place additional restrictions on funding or insurance for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.
Although we seek to mitigate volatility and potential declines in commodity prices through derivative arrangements that hedge a portion of the expected production associated with our working interests, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks.
Although we seek to mitigate volatility and potential declines in commodity prices through derivative arrangements that hedge a portion of the expected production associated with our working interests, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks. 24 Table of Contents The prices we receive for the production and the levels of the production associated with our working interests depend on numerous factors beyond our control.
As of December 31, 2024, the Company had 5.0 million shares of common stock remaining available for future awards under the Incentive Plan.
As of December 31, 2025, the Company had 3.8 million shares of common stock remaining available for future awards under the Incentive Plan.
In the future, the tax 41 Table of Contents authorities could challenge our interpretation of laws, regulations and treaties, resulting in additional tax liability or adjustment to our income tax provision that could increase our effective tax rate which could adversely affect our operating results and cash flows.
In the future, the tax authorities could challenge our interpretation of laws, regulations and treaties, resulting in additional tax liability or adjustment to our income tax provision that could increase our effective tax rate which could adversely affect our operating results and cash flows. Changes to tax laws may also adversely affect our ability to attract and retain key personnel.
As of December 31, 2024, we had leases that were not developed that represented 6,160 net acres potentially expiring in 2025, 3,208 net acres potentially expiring in 2026 and 1,844 net acres potentially expiring in 2027 and beyond. We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise.
As of December 31, 2025, we had leases that were not developed that represented 3,922 net acres potentially expiring in 2026, 1,065 net acres potentially expiring in 2027 and 5,524 net acres potentially expiring in 2028 and beyond. 26 Table of Contents We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise.
We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. Our future success will depend, in part, upon our ability to manage our expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and basins and associated increased costs and complexity.
Our future success will depend, in part, upon our ability to manage our expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and basins and associated increased costs and complexity.
If the Manager were to lose key members of its management team, neither the Manager nor we may be able to replace the knowledge or relationships that they possess, and our ability to execute our business plan could be materially harmed.
If the Manager were to lose key members of its management team, neither the Manager nor we may be able to replace the knowledge or relationships that they possess, and our ability to execute our business plan could be materially harmed. As a result, our operations and financial condition could suffer. Oil and natural gas prices are volatile.
The prices we receive for the oil and natural gas production associated with our working interests heavily influence our production, revenue, cash flows, profitability, reserve bookings and access to capital.
Oil and natural gas prices have fluctuated significantly, including periods of rapid and material decline, in recent years. The prices we receive for the oil and natural gas production associated with our working interests heavily influence our production, revenue, cash flows, profitability, reserve bookings and access to capital.
While such ratings do not impact all investors’ investment or voting decisions, unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital.
Although this trend has waned recently, to the extent unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets leads to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, such ratings could have a negative impact on our access to and costs of capital or the ability to complete projects.
As a result, our operations and financial condition could suffer. 24 Table of Contents Oil and natural gas prices are volatile. Extended declines in such prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow.
Extended declines in such prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow. The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices.
Unknown liabilities with respect to assets acquired could include, for example: liabilities for clean-up of undiscovered or undisclosed environmental contamination; claims by developers, site owners, vendors or other persons relating to the asset or project site; liabilities 29 Table of Contents incurred in the ordinary course of business; and claims for indemnification by general partners, directors, officers and others indemnified by the former owners of the asset or project sites.
Unknown liabilities with respect to assets acquired could include, for example: liabilities for clean-up of undiscovered or undisclosed environmental contamination; claims by developers, site owners, vendors or other persons relating to the asset or project site; liabilities incurred in the ordinary course of business; and claims for indemnification by general partners, directors, officers and others indemnified by the former owners of the asset or project sites. 29 Table of Contents We may not be able to successfully integrate future acquisitions or realize all of the anticipated benefits from our future acquisitions, and our future results will suffer if we do not effectively manage our expanded operations.
Lower oil and natural gas prices may limit our ability to comply with the covenants under any credit facilities (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. 25 Table of Contents Drilling for and producing oil and natural gas 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 any credit facilities (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.
AQCC is expected to undertake several additional rulemaking efforts to further reduce emissions over the next several years. Additionally, the Colorado Energy and Carbon Management Commission in October 2024 finalized rules that consider the cumulative impacts of air emissions from oil and gas projects in permitting decisions.
Additionally, the Colorado Energy and Carbon Management Commission in October 2024 finalized rules that consider the cumulative impacts of air emissions from oil and gas projects in permitting decisions.
These constraints and the resulting shortages or high costs could delay or temporarily halt operations on the affected Properties and materially increase operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. 28 Table of Contents The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
These constraints and the resulting shortages or high costs could delay or temporarily halt operations on the affected Properties and materially increase operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.
At the closing of the Business Combination, we entered into a Credit Agreement, secured by a first priority mortgage and security interest in substantially all of our assets and our restricted subsidiaries.
The borrowing base under our Credit Agreement may be reduced in light of commodity price declines, which could limit us in the future. At the closing of the Business Combination, we entered into a Credit Agreement, secured by a first priority mortgage and security interest in substantially all of our assets and our restricted subsidiaries.
Our operating partners’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.
Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.
Additionally, if we or our independent registered public accounting firm were to conclude that third-party internal controls over financial reporting were not effective, any material weaknesses in such internal controls could require significant expense and management time to remediate. 37 Table of Contents The borrowing base under our Credit Agreement may be reduced in light of commodity price declines, which could limit us in the future.
Additionally, if we or our independent registered public accounting firm were to conclude that third-party internal controls over financial reporting were not effective, any material weaknesses in such internal controls could require significant expense and management time to remediate.
Although we believe these provisions benefit us by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against us or our directors and officers. 40 Table of Contents Alternatively, if a court were to find the choice of forum provision contained in our amended and restated certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, financial condition, and operating results.
Alternatively, if a court were to find the choice of forum provision contained in our amended and restated certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, financial condition, and operating results.
In recent years, the United States increased tariffs for certain goods, which triggered other nations to also increase tariffs on certain of their goods. In recent weeks, the Trump administration has made many announcements regarding tariffs and the extent and duration of such tariffs remain uncertain.
In recent years, the United States increased tariffs for certain goods, which triggered other nations to also increase tariffs on certain of their goods.
Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties, injunctive relief, or other liabilities. 32 Table of Contents Additionally, compliance with these laws and regulations may, from time to time, result in increased costs of operations, delay in operations, or decreased production, and may affect acquisition costs.
Additionally, compliance with these laws and regulations may, from time to time, result in increased costs of operations, delay in operations, or decreased production, and may affect acquisition costs.
In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold.
Notwithstanding the EPA’s final rule in February 2026 revoking the GHG “Endangerment Finding” that provides the basis for its authority to regulate GHG emissions, the EPA under previous administrations has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold.
We paid dividends of $57.5 million, or $0.44 per share, and $58.6 million, or $0.44 per share during the years ended December 31, 2024 and 2023, respectively. However, our Board of Directors is not obligated to make any future dividend payments.
The payment of dividends is at the discretion of our Board of Directors, and we cannot assure you that we will continue making dividend payments in the future. We paid dividends of $57.7 million, or $0.44 per share, and $57.5 million, or $0.44 per share during the years ended December 31, 2025 and 2024, respectively.
Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history.
Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.
Fuel and energy conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.
In March 2025, the SEC voted to end its defense of the rule, though to date no further action has been taken to repeal the rule. Fuel and energy conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.
A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business.
A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business. Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties, injunctive relief, or other liabilities.
The charge starts at $900 per metric ton of methane in 2025 (using 2024 data), and increases to $1,500 after two years. In the absence of comprehensive federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs.
In the absence of comprehensive federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.
As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. 27 Table of Contents 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 estimates prepared by our 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 estimates prepared by our independent reserve engineering firm. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of crude oil and natural gas reserves are inherently imprecise.
Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. These rules could further increase the cost of development and operation of the Properties.
However, the requirements of the EPA’s final methane rules have the potential to increase the operating costs of our operators and thus may adversely affect our financial results and cash flows. Moreover, failure to 33 Table of Contents comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief.
While the Trump Administration may take action to repeal or modify the final rules, we cannot predict the substance or timing of such changes, if any. However, the requirements of the EPA’s final methane rules have the potential to increase the operating costs of our operators and thus may adversely affect our financial results and cash flows.
We cannot predict when or whether the EPA or the Trump administration may take further action to repeal or modify the final rules, we cannot predict the substance or timing of such changes, if any.
Most recently, 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. Under the final rules, states have two years to prepare and submit their plants to impose methane emission controls on existing sources.
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 that set standards for emission capture and control systems and equipment, leak detection equipment and monitoring, and so-called “green well” completion requirements.
The potential for conflict with Iran, a major oil producer, the Houthi movement in Yemen or the Hezbollah movement in Lebanon has increased as a result of continued, increasing hostilities in the Middle East.
The joint U.S.-Israel military strikes on Iran have heightened the potential for further conflict with Iran, a major oil producer. Continued hostilities involving the Houthi movement in Yemen and the Hezbollah movement in Lebanon have further contributed to instability in the region.
However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges as well as changed priorities under the new Presidential administration that could impact the fate of the final rules, though the timing and impact of any such changes are difficult to predict at this time.
However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges, with such litigation held in abeyance until the SEC repeals, reconsiders, or otherwise modifies the rule.
Removed
The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Oil and natural gas prices have fluctuated significantly, including periods of rapid and material decline, in recent years.
Added
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations. Our operating partners’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs.
Removed
The prices we receive for the production and the levels of the production associated with our working interests depend on numerous factors beyond our control.
Added
Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.
Removed
Some of these assumptions are inherently subjective, and the accuracy of our estimated reserves relies in part on the ability of the Manager’s reserve engineers to make accurate assumptions.
Added
Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market.
Removed
We may not be able to successfully integrate future acquisitions or realize all of the anticipated benefits from our future acquisitions, and our future results will suffer if we do not effectively manage our expanded operations. Our growth strategy will, in part, rely on acquisitions.
Added
In March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc, and in November 2025, the EPA issued an interim final rule extending several compliance for certain provisions in the December 2023 rule. Litigation challenging the interim final rule remains pending.
Removed
The 33 Table of Contents presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of 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.
Added
AQCC is expected to undertake several additional rulemaking efforts to further reduce emissions over the next several years, and in February 2026, adopted regulations to reduce methane emissions from oil and gas operations in line with the federal Subparts OOOOb and OOOOc.
Removed
In addition, in 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question.
Added
In recent years, the RRC has also imposed prohibitions and restrictions on SWD wells in response to a number of earthquakes in the Midland Basin. 34 Table of Contents Most recently, in May 2025, the RRC released updated guidance for disposal well permits in the Permian Basin that placed new limits on maximum injection pressure and volumes to ensure safety.
Removed
If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well.
Added
Litigation has already been filed challenging the February 2026 rule, and while we cannot predict the final outcome, as a result, there is significant uncertainty with respect to regulation of GHG emissions.
Removed
Furthermore, in response to a number of earthquakes in recent years in the Midland Basin, in September 2021 the RRC announced that it will not issue any new SWD well permits in the SRA area, and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

2 edited+1 added−0 removed10 unchanged
Biggest changeIn addition, we and the Manager have developed or may develop proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. The Company integrates cybersecurity risks into its overall enterprise risk management program. Pursuant to the MSA, the Manager provides us with back-office services, including services for the management of our data and cybersecurity risk.
Biggest changeIn addition, we and the Manager have developed or may develop proprietary software systems, management techniques and other information and operational technologies incorporating software licensed from third parties. The Company integrates cybersecurity risks into its overall enterprise risk management program.
Item 1C. Cybersecurity Risk Management and Strategy We recognize the importance of implementing and maintaining measures to safeguard our information technology systems and data. We and the Manager have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business.
Item 1C. Cybersecurity Risk Management and Strategy We recognize the importance of implementing and maintaining measures to safeguard our information and operational technology systems and data. We and the Manager have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business.
Added
Pursuant to the MSA, the Manager provides us with back-office services, including services for the management of our data and cybersecurity risk.

Item 2. Properties

Properties — owned and leased real estate

32 edited+0 added−0 removed39 unchanged
Biggest changeDecember 31, 2024 Gross Productive Wells Net Productive Wells Oil Natural Gas Total Oil Natural Gas Total Permian 714 — 714 64.70 — 64.70 Eagle Ford 129 100 229 27.40 7.30 34.70 Bakken 985 — 985 39.80 — 39.80 Haynesville — 127 127 — 17.20 17.20 DJ 1,070 15 1,085 44.60 1.30 45.90 Appalachian 6 — 6 0.10 — 0.10 Total 2,904 242 3,146 176.60 25.80 202.40 The following table summarizes our cumulative gross and net productive oil and natural gas wells by basin at December 31, 2023: December 31, 2023 Gross Productive Wells Net Productive Wells Oil Natural Gas Total Oil Natural Gas Total Permian 575 1 576 46.30 — 46.30 Eagle Ford 120 93 213 24.80 6.90 31.70 Bakken 938 — 938 39.00 — 39.00 Haynesville — 117 117 — 16.40 16.40 DJ 967 15 982 42.20 0.90 43.10 Total 2,600 226 2,826 152.30 24.20 176.50 The following table summarizes our cumulative gross and net productive oil and natural gas wells by basin at December 31, 2022: December 31, 2022 Gross Productive Wells Net Productive Wells Oil Natural Gas Total Oil Natural Gas Total Permian 448 2 450 40.82 0.02 40.84 Eagle Ford 105 81 186 19.08 4.26 23.34 Bakken 907 1 908 37.73 0.20 37.93 Haynesville — 62 62 — 12.18 12.18 DJ 681 70 751 16.43 2.16 18.59 Total 2,141 216 2,357 114.06 18.82 132.88 51 Table of Contents Developed and Undeveloped Acreage The following table summarizes our estimated gross and net developed and undeveloped acreage by area at December 31, 2024.
Biggest changeDecember 31, 2025 Gross Productive Wells Net Productive Wells Oil Natural Gas Total Oil Natural Gas Total Permian 962 — 962 100.73 — 100.73 Eagle Ford 138 106 244 28.31 7.86 36.17 Bakken 998 — 998 39.81 — 39.81 Haynesville — 187 187 — 19.21 19.21 DJ 1,127 18 1,145 44.94 1.28 46.22 Appalachian 63 3 66 2.59 0.01 2.60 Total 3,288 314 3,602 216.38 28.36 244.74 The following table summarizes our cumulative gross and net productive oil and natural gas wells by basin at December 31, 2024: December 31, 2024 Gross Productive Wells Net Productive Wells Oil Natural Gas Total Oil Natural Gas Total Permian 714 — 714 64.70 — 64.70 Eagle Ford 129 100 229 27.40 7.30 34.70 Bakken 985 — 985 39.80 — 39.80 Haynesville — 127 127 — 17.20 17.20 DJ 1,070 15 1,085 44.60 1.30 45.90 Appalachian 6 — 6 0.10 — 0.10 Total 2,904 242 3,146 176.60 25.80 202.40 The following table summarizes our cumulative gross and net productive oil and natural gas wells by basin at December 31, 2023: December 31, 2023 Gross Productive Wells Net Productive Wells Oil Natural Gas Total Oil Natural Gas Total Permian 575 1 576 46.30 — 46.30 Eagle Ford 120 93 213 24.80 6.90 31.70 Bakken 938 — 938 39.00 — 39.00 Haynesville — 117 117 — 16.40 16.40 DJ 967 15 982 42.20 0.90 43.10 Total 2,600 226 2,826 152.30 24.20 176.50 50 Table of Contents Developed and Undeveloped Acreage The following table summarizes our estimated gross and net developed and undeveloped acreage by area at December 31, 2025.
NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical expert primarily responsible for preparing the estimates set forth in the NSAI 2024 Reserve Report is Mr. Nathan Shahan.
NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical expert primarily responsible for preparing the estimates set forth in the NSAI 2025 Reserve Report is Mr. Nathan Shahan.
In those instances, we, together with the Manager, still review each lease and drilling opportunity on a lease-by-lease basis and well-by-well basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 5 of the Notes to the Consolidated Financial Statements regarding our recent acquisition activity. 52 Table of Contents
In those instances, we, together with the Manager, still review each lease and drilling opportunity on a lease-by-lease basis and well-by-well basis to ensure that the package as a whole meets our acquisition criteria and drilling expectations. See Note 5 of the Notes to the Consolidated Financial Statements regarding our recent acquisition activity. 51 Table of Contents
The following discussion of our properties should be read in conjunction 45 Table of Contents with the accompanying audited consolidated financial statements and related notes included elsewhere in this Annual Report. Please see the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Results of Operations” for information on our production, prices, and production cost.
The following discussion of our properties should be read in conjunction 44 Table of Contents with the accompanying audited consolidated financial statements and related notes included elsewhere in this Annual Report. Please see the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Results of Operations” for information on our production, prices, and production cost.
We use this measure when assessing the 46 Table of Contents potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows.
We use this measure when assessing the 45 Table of Contents potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows.
Drilling and Development Activities The following table sets forth the number of gross and net productive wells drilled in the years ended December 31, 2024, 2023 and 2022. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.
Drilling and Development Activities The following table sets forth the number of gross and net productive wells drilled in the years ended December 31, 2025, 2024 and 2023. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.
In preparing its reports, NSAI 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, NSAI 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.
Due to normal production declines, increases or decreases in drilling activity and the effects of 49 Table of Contents acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
Due to normal production declines, increases or decreases in drilling activity and the effects of 48 Table of Contents acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
The following table provides a reconciliation of the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2024, 2023 and 2022 to the Standardized Measure of Discounted Future Net Cash Flows.
The following table provides a reconciliation of the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2025, 2024 and 2023 to the Standardized Measure of Discounted Future Net Cash Flows.
A significant majority of our wells in the Permian, Bakken, DJ, and Appalachian Basins are classified 50 Table of Contents as oil wells, although they also produce natural gas and condensate. All of our wells in the Haynesville Basin are classified as natural gas wells.
A significant majority of our wells in the Permian, Bakken, DJ, and Appalachian Basins are classified 49 Table of Contents as oil wells, although they also produce natural gas and condensate. All of our wells in the Haynesville Basin are classified as natural gas wells.
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.
With 85% 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.
Estimated Net Proved Reserves The tables below summarize our estimated net proved reserves at December 31, 2024, based on reports prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our third-party independent reserve engineers.
Estimated Net Proved Reserves The tables below summarize our estimated net proved reserves at December 31, 2025, based on reports prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our third-party independent reserve engineers.
The Manager’s Partner - Engineering has a degree in petroleum engineering from the University of Calgary, and has over 20 years of oil and gas experience, with more than 15 years focused on reservoir engineering.
The Manager’s Partner - Engineering has a degree in petroleum engineering from the University of Calgary and has over 25 years of oil and gas experience, with more than 20 years focused on reservoir engineering.
(3) Pre-tax PV10% or “PV-10”, is a non-GAAP financial measure and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP measure. The amounts disclosed in the table above include net abandonment costs of $23.9 million as of December 31, 2024. See “Reconciliation of PV-10 to Standardized Measure” below.
(3) Pre-tax PV10% or “PV-10”, is a non-GAAP financial measure and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP measure. The amounts disclosed in the table above include net abandonment costs of $26.5 million as of December 31, 2025. See “Reconciliation of PV-10 to Standardized Measure” below.
Based on SEC pricing as of December 31, 2024, estimated future development costs required for the development of proved undeveloped reserves are projected to be approximately $253.5 million over the next five years. Independent Petroleum Engineers We have engaged NSAI to independently prepare our estimated net proved reserves.
Based on SEC pricing as of December 31, 2025, estimated future development costs required for the development of proved undeveloped reserves are projected to be approximately $225.3 million over the next five years. Independent Petroleum Engineers We have engaged NSAI to independently prepare our estimated net proved reserves.
See Note 2 of the Notes to the Consolidated Financial Statements for additional discussion of our proved reserves. Proved Undeveloped Reserves At December 31, 2024, we had approximately 15,362 MBoe of proved undeveloped reserves as compared to 22,361 MBoe at December 31, 2023.
See Note 2 of the Notes to the Consolidated Financial Statements for additional discussion of our proved reserves. Proved Undeveloped Reserves At December 31, 2025, we had approximately 14,822 MBoe of proved undeveloped reserves as compared to 15,362 MBoe at December 31, 2024.
At December 31, 2024, we had 202 gross (14.85 net) wells for which drilling was either in-progress or were pending completion. These wells are not included in the table above. The following table summarizes our cumulative gross and net productive oil and natural gas wells by basin at December 31, 2024.
At December 31, 2025, we had 137 gross (12.18 net) wells for which drilling was either in-progress or were pending completion. These wells are not included in the table above. The following table summarizes our cumulative gross and net productive oil and natural gas wells by basin at December 31, 2025.
December 31, 2024 2023 2022 Gross Net Gross Net Gross Net Productive development wells 299 23.43 314 24.55 265 20.78 Dry development wells (1) — — 2 0.57 — — (1) The dry hole category includes 2 (0.57 net) wells that were unsuccessful due to mechanical issues for the year ended December 31, 2023.
December 31, 2025 2024 2023 Gross Net Gross Net Gross Net Productive development wells 322 38.40 299 23.43 314 24.55 Dry development wells (1) — — — — 2 0.57 (1) The dry hole category includes 2 (0.57 net) wells that were unsuccessful due to mechanical issues for the year ended December 31, 2023.
The reserve data set forth in the NSAI report represents only estimates and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts.
The reserve data set forth in the NSAI report represents only estimates and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
In 2024, proved undeveloped reserves increased by 4,765 MBoe as a result of new proved undeveloped locations added primarily in the Permian Basin. • Acquisition of reserves . In 2024, acquisitions of proved undeveloped reserves of 3,733 MBoe were primarily attributable to the acquisitions of oil and natural gas properties in the Permian Basin.
In 2025, proved undeveloped reserves increased by 3,250 MBoe as a result of new proved undeveloped locations added primarily in the Permian Basin. • Acquisition of reserves . In 2025, acquisitions of proved undeveloped reserves of 6,089 MBoe were primarily attributable to the acquisitions of oil and natural gas properties in the Permian Basin.
Standardized Measure Reconciliation December 31, (in thousands) 2024 2023 2022 Pre-tax present value of estimated future net revenues (Pre-Tax PV10%) $ 841,929 $ 856,428 $ 1,559,123 Future income taxes, discounted at 10% (120,961) (134,520) (293,196) Standardized measure of discounted future net cash flows $ 720,968 $ 721,908 $ 1,265,927 Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.
Standardized Measure Reconciliation December 31, (in thousands) 2025 2024 2023 Pre-tax present value of estimated future net revenues (Pre-Tax PV10%) $ 896,885 $ 841,929 $ 856,428 Future income taxes, discounted at 10% (107,004) (120,961) (134,520) Standardized measure of discounted future net cash flows $ 789,881 $ 720,968 $ 721,908 Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.
Year Ended December 31, 2024 2023 2022 Net Production: Oil (MBbl) 4,483 4,162 3,656 Natural gas (MMcf) 27,944 28,266 21,351 Total (MBoe) (1) 9,140 8,873 7,215 Average Daily Production: Oil (Bbl) 12,248 11,404 10,016 Natural gas (Mcf) 76,350 77,442 58,496 Total (Boe) (1) 24,973 24,311 19,765 Average Sales Prices: Oil (per Bbl) $ 73.06 $ 76.18 $ 92.50 Natural gas and related product sales (per Mcf) 1.88 2.72 7.46 Realized price (per Boe) 41.58 44.41 68.94 Costs and Expenses (per Boe): Lease operating expenses $ 6.29 $ 6.82 $ 6.19 Production and ad valorem taxes $ 2.85 $ 3.12 $ 4.24 Depletion and accretion $ 19.31 $ 18.11 $ 14.66 General and administrative $ 2.70 $ 3.15 $ 1.97 __________________________________________ (1) Natural gas is converted to Boe using the ratio of one barrel of oil to six Mcf of natural gas.
Year Ended December 31, 2025 2024 2023 Net Production: Oil (MBbl) 5,855 4,483 4,162 Natural gas (MMcf) 34,912 27,944 28,266 Total (MBoe) (1) 11,674 9,140 8,873 Average Daily Production: Oil (Bbl) 16,041 12,248 11,404 Natural gas (Mcf) 95,649 76,350 77,442 Total (Boe) (1) 31,984 24,973 24,311 Average Sales Prices: Oil (per Bbl) $ 61.63 $ 73.06 $ 76.18 Natural gas and related product sales (per Mcf) 2.56 1.88 2.72 Realized price (per Boe) 38.57 41.58 44.41 Costs and Expenses (per Boe): Lease operating expenses $ 7.27 $ 6.29 $ 6.82 Production and ad valorem taxes $ 2.36 $ 2.85 $ 3.12 Depletion and accretion $ 18.48 $ 19.31 $ 18.11 General and administrative $ 2.66 $ 2.70 $ 3.15 __________________________________________ (1) Natural gas is converted to Boe using the ratio of one barrel of oil to six Mcf of natural gas.
In 2024, revisions of previous estimates decreased proved undeveloped reserves by 3,288 MBoe primarily due to the removal of undeveloped drilling locations as they were no longer expected to be developed within five years of their initial recognition as well as lower oil and natural gas prices.
In 2025, revisions of previous estimates decreased proved undeveloped reserves by 3,239 MBoe primarily due to the removal of undeveloped drilling locations as they were no longer expected to be developed within five years of their initial recognition as well as lower oil prices. 46 Table of Contents All of our recorded proved undeveloped reserves are scheduled to be drilled within five years of the date of their initial recognition.
A reconciliation of the change in proved undeveloped reserves during 2024 is as follows: MBoe Estimated proved undeveloped reserves at December 31, 2023 22,361 Extensions and discoveries 4,765 Acquisition of reserves 3,733 Divestiture of reserves (3,525) Conversion to proved developed reserves (8,684) Revisions of previous estimates (3,288) Estimated proved undeveloped reserves at December 31, 2024 15,362 __________________________________________ • Extensions and discoveries .
A reconciliation of the change in proved undeveloped reserves during 2025 is as follows: MBoe Estimated proved undeveloped reserves at December 31, 2024 15,362 Extensions and discoveries 3,250 Acquisition of reserves 6,089 Divestiture of reserves — Conversion to proved developed reserves (6,640) Revisions of previous estimates (3,239) Estimated proved undeveloped reserves at December 31, 2025 14,822 __________________________________________ • Extensions and discoveries .
There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary.
The accuracy of any reserve estimate is a 47 Table of Contents function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary.
All of our recorded proved undeveloped reserves are scheduled to be drilled within five years of the date of their initial recognition. At December 31, 2024, the PV-10 value of our proved undeveloped reserves amounted to 14% of the PV-10 value of our total proved reserves. There are numerous uncertainties regarding the proved and undeveloped reserves.
At December 31, 2025, the PV-10 value of our proved undeveloped reserves amounted to 13% of the PV-10 value of our total proved reserves. There are numerous uncertainties regarding the proved and undeveloped reserves.
See Note 5 of the Notes to Consolidated Financial Statements for additional discussion of acquisitions during 2024. • Divestiture of reserves. In 2024, the Company divested of 3,525 MBoe of proved undeveloped reserves primarily in the Permian Basin. • Conversion to proved developed reserves.
See Note 5 of the Notes to Consolidated Financial Statements for additional discussion of acquisitions during 2025. • Conversion to proved developed reserves. In 2025, development of oil and natural gas properties resulted in the conversion of 6,640 MBoe from proved undeveloped reserves to proved developed reserves.
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) % Proved developed producing 17,372 104,292 34,754 64 % $ 634,483 75 % Proved developed non-producing 1,897 13,811 4,199 8 % 90,983 11 % Proved undeveloped 8,918 38,666 15,362 28 % 116,463 14 % Total proved 28,187 156,769 54,315 100 % $ 841,929 100 % Total proved developed 19,269 118,103 38,953 72 % $ 725,466 86 % __________________________________________ (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 $76.32 per barrel of oil and $2.13 per MMbtu of natural gas.
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) % Proved developed producing 21,141 155,327 47,029 75 % $ 763,594 85 % Proved developed non-producing 357 834 496 1 % 14,389 2 % Proved undeveloped 9,075 34,482 14,822 24 % 118,902 13 % Total proved 30,573 190,643 62,347 100 % $ 896,885 100 % Total proved developed 21,498 156,161 47,525 76 % $ 777,983 87 % __________________________________________ (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 $66.01 per barrel of oil and $3.39 per MMbtu of natural gas.
The following table sets forth the future expiration amounts of our gross and net undeveloped acreage at December 31, 2024 by area: 2025 2026 2027 and Thereafter Gross Net Gross Net Gross Net Permian (1) 9,485 3,662 5,976 3,104 1,148 724 Eagle Ford (1) 6,876 2,449 282 28 — — Haynesville 459 49 1,264 76 861 53 Appalachian — — — — 2,317 1,067 Total: 16,820 6,160 7,522 3,208 4,326 1,844 __________________________________________ (1) Certain acreage within the basin is subject to continuous drilling obligations.
The following table sets forth the future expiration amounts of our gross and net undeveloped acreage at December 31, 2025 by area: 2026 2027 2028 and Thereafter Gross Net Gross Net Gross Net Permian (1) 9,147 3,670 1,875 1,036 8,476 3,568 Eagle Ford (1) 2,571 251 — — — — Haynesville 29 1 592 28 — — Appalachian — — 3 1 3,108 1,956 Total: 11,747 3,922 2,470 1,065 11,584 5,524 __________________________________________ (1) Certain acreage within the basin is subject to continuous drilling obligations.
Moreover, estimates of reserves may increase or decrease as a result of future operations. 48 Table of Contents Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner.
Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control.
Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Permian 48,731 8,427 14,787 6,638 63,518 15,065 Eagle Ford 25,750 4,243 5,815 2,344 31,565 6,587 Bakken 169,897 13,167 — — 169,897 13,167 Haynesville 55,926 5,317 2,584 178 58,510 5,495 DJ 22,749 2,502 — — 22,749 2,502 Appalachian 169 89 2,148 978 2,317 1,067 Total: 323,222 33,745 25,334 10,138 348,556 43,883 Acreage Expirations As a non-operator, we are subject to lease expirations if an operator does not commence the development of operations within the agreed terms of our leases.
Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Permian 73,811 20,529 21,811 9,661 95,622 30,190 Eagle Ford 25,805 4,244 1,229 122 27,034 4,366 Bakken 169,897 13,167 — — 169,897 13,167 Haynesville 55,962 5,318 2,449 177 58,411 5,495 DJ 22,749 2,502 — — 22,749 2,502 Appalachian 7,028 1,774 7,910 2,544 14,938 4,318 Total: 355,252 47,534 33,399 12,504 388,651 60,038 Acreage Expirations As a non-operator, we are subject to lease expirations if an operator does not commence the development of operations within the agreed terms of our leases.
In 2024, development of oil and natural gas properties resulted in the conversion of 8,684 MBoe from proved undeveloped reserves to proved developed reserves. We incurred development costs of approximately $138.4 million related to these locations. 47 Table of Contents • Revisions of previous estimates .
We incurred development costs of approximately $134.0 million related to these locations. • Revisions of previous estimates .

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeItem 3. Legal Proceedings Our Company was not a party to any material legal proceedings during the year ended December 31, 2024. In the future, the Company may be subject from time to time to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. Item 4. Mine Safety Disclosures Not applicable. PART II
Biggest changeItem 3. Legal Proceedings Our Company was not a party to any material legal proceedings during the year ended December 31, 2025. In the future, the Company may be subject from time to time to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. Item 4. Mine Safety Disclosures Not applicable. PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities Market Information Our common stock is listed and traded on the New York Stock Exchange under the symbol “GRNT”. As of March 3, 2025 there were 72 holders of record of our common stock.
Biggest changeItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchasers of Equity Securities Market Information Our common stock is listed and traded on the New York Stock Exchange under the symbol “GRNT”. As of March 2, 2026 there were 62 holders of record of our common stock.
Removed
Financial Statements and Supplementary Data." Repurchases of Equity Securities During the quarter ended December 31, 2024, the Company repurchased shares of common stock from certain employees to satisfy the employees' tax withholding obligations in connection with the vesting of stock-based awards.
Added
Financial Statements and Supplementary Data." Share Performance Graph The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2022 through December 31, 2025, to that of the cumulative return on a $100 investment in the S&P 500 Index and the SPDR S&P Oil & Gas Exploration & Production ETF for the same period.
Removed
The following table sets forth our share repurchase activity for the period presented: Period Total number of shares purchased Average price paid per share Total number of shares purchased as part of publicly announced plans Approximate dollar value of shares that may yet be purchased under the plans or programs (in millions) October 1, 2024 - October 31, 2024 — $ — — $ — November 1, 2024 - November 30, 2024 3,666 $ 6.40 — $ — December 1, 2024 - December 31, 2024 — $ — — $ — Item 6. [RESERVED]
Added
In calculating the cumulative return, reinvestment of dividends, if any, is assumed.
Added
This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before, on, or after the date hereof and irrespective of any general incorporation language in any such filing.
Added
This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. 52 Table of Contents Repurchases of Equity Securities During the quarter ended December 31, 2025, the Company did not repurchase any shares of common stock. Item 6. [RESERVED]

Item 7. Management's Discussion & Analysis

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

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Biggest changeBase rate loans bear interest at a rate per annum equal to the greatest of: (i) the U.S. prime rate as published by the Wall Street Journal; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted SOFR rate for a one-month interest period plus 100 basis points, plus, in the case of this clause (iii) an additional 10 basis point credit spread adjustment, plus, in the case of any base rate loan, an applicable margin ranging from 200 to 300 basis points, depending on the percentage of the borrowing base utilized.
Biggest changeOn November 5, 2025, the Company and its lenders entered into the Sixth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) reaffirm the borrowing base and aggregate elected commitment amounts at $375.0 million, (ii) permit the issuance of the 2029 Senior Notes (as defined below), (iii) extend the maturity date to the earliest to occur of (A) November 5, 2029 or (B) the date that is ninety-one days prior to the stated maturity date of the 2029 Senior Notes if any 2029 Senior Notes remain outstanding on such date, and (iv) adjust the interest payable on (A) SOFR loans to interest at a rate per annum equal to SOFR plus an applicable margin ranging from 275 to 375 basis points, depending on the percentage of the borrowing base utilized and (B) base rate loans to interest at a rate per annum equal to the greatest of: (a) the U.S. prime rate as publicly announced from time to time by Bank of America, N.A.; (b) the federal funds effective rate plus 50 basis points; (c) the adjusted SOFR rate for a one-month interest period plus 100 basis points; and (d) 100 basis points, plus, in the case of any base rate loan, an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized. 2029 Senior Notes On November 5, 2025, the Company, as issuer, completed an issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes at 96.0% of par with stated maturity on November 5, 2029 (the “2029 Senior Notes”) pursuant to a note purchase agreement (the “Note Purchase Agreement”).
The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates, and other factors.
The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to develop and produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates, and other factors.
Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects.
Unproved oil and natural gas properties are assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects.
Income Tax Expense (Benefit) For the year ended December 31, 2024, we recorded income tax expense of $6.2 million, which included current income tax expense of $0.2 million and deferred income tax expense of $6.0 million.
For the year ended December 31, 2024, we recorded income tax expense of $6.2 million, which included current income tax expense of $0.2 million and deferred income tax expense of $6.0 million.
Results of Operations The following tables and related discussion set forth key operating and financial data as of and for the years ended December 31, 2024 and 2023. For similar operating and financial data and discussion of our 2023 results compared to our 2022 results, refer to “Item 7.
Results of Operations The following tables and related discussion set forth key operating and financial data as of and for the years ended December 31, 2025 and 2024. For similar operating and financial data and discussion of our 2024 results compared to our 2023 results, refer to “Item 7.
We will carefully monitor and may adjust our projected capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, 63 Table of Contents the timing of regulatory approvals, contractual obligations, internally generated cash flow, and other factors both within and outside our control.
We will carefully monitor and may adjust our projected capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, contractual obligations, internally generated cash flow, and other factors both within and outside our control.
Please read “Cautionary Note Regarding Forward ‑ Looking Statements.” Also, please read the risk factors and other cautionary statements described 53 Table of Contents under “ Part I, Item 1A. Risk Factors. ” We assume no obligation to update any of these forward ‑ looking statements, except as required by applicable law.
Please read “Cautionary Note Regarding Forward ‑ Looking Statements.” Also, please read the risk factors and other cautionary statements described under “ Part I, Item 1A. Risk Factors. ” We assume no obligation to update any of these forward ‑ looking statements, except as required by applicable law.
Cash Flows Provided by (Used in) Financing Activities For the year ended December 31, 2024, our net cash provided by financing activities was $33.7 million primarily due to $95.0 million of net borrowings under our Credit Agreement, partially offset by $57.5 million of dividends paid on our common stock.
For the year ended December 31, 2024, our net cash provided by financing activities was $33.7 million primarily due to $95.0 million of net borrowings under our Credit Agreement, partially offset by $57.5 million of dividends paid on our common stock.
Liquidity and Capital Resources Our main sources of liquidity and capital resources as of the periods covered by this report have been internally generated cash flow from operations and credit facility borrowings. Our primary use of capital has been for the development and acquisition of oil and natural gas properties.
Liquidity and Capital Resources Our main sources of liquidity and capital resources as of the periods covered by this report have been internally generated cash flow from operations, credit facility borrowings, and the issuance of senior notes. Our primary use of capital has been for the development and acquisition of oil and natural gas properties.
As of December 31, 2024, as a result of widening differentials and higher production cost assumptions, it was determined that the carrying amount of proved oil and gas properties in the Bakken exceeded undiscounted future net cash flows.
During the year ended December 31, 2024, as a result of widening differentials and higher production cost assumptions, it was determined that the carrying amount of proved oil and gas properties in the Bakken exceeded undiscounted future net cash flows.
A portion of our operating cost components are variable and change in correlation to production levels. 54 Table of Contents Production and ad valorem taxes Production taxes are paid on produced oil and natural gas. Ad valorem taxes are paid on the value of our properties in certain states.
A portion of our operating cost components are variable and change in correlation to production levels. Production and ad valorem taxes Production taxes are paid on produced oil and natural gas. Ad valorem taxes are paid on the value of our properties in certain states.
Thus, our operating results are also affected by changes in the oil and natural gas price differentials between the applicable benchmark and the sales prices we receive for our oil and natural gas production. Our oil price differential to the NYMEX benchmark price during 2024, 2023 and 2022 was $(3.57) per barrel, $(1.40) per barrel and $(1.89) per barrel, respectively.
Thus, our operating results are also affected by changes in the oil and natural gas price differentials between the applicable benchmark and the sales prices we receive for our oil and natural gas production. Our oil price differential to the NYMEX benchmark price during 2025, 2024 and 2023 was $(3.76) per barrel, $(3.57) per barrel and $(1.40) per barrel, respectively.
With our cash on hand, cash flow from operations, and borrowing capacity under the Credit Agreement, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity.
With our cash on hand, cash flow from operations, and borrowing capacity under the Credit Agreement, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at 60 Table of Contents least the next twelve months. However, we may seek additional access to capital and liquidity.
These cash flows used in investing activities are partially offset by cash proceeds from disposal of oil and natural gas properties of $14.0 million and refund of advances from operators of $19.7 million during 2024.
These cash flows used in investing activities are partially offset by proceeds from the disposal of oil and natural gas properties of 14.0 million and proceeds from refund of advances from operators of $19.7 million .
As the carrying amount of the assets was higher than the expected undiscounted future net cash flows, an impairment loss was recorded as the difference between the carrying value and the estimated fair value.
As the carrying amount of the assets was higher than the expected undiscounted future net cash flows, an impairment loss of $44.7 million was recorded as the difference between the carrying value and the estimated fair value.
Our natural gas price differential during 2024, 2023 and 2022 was $(0.31) per Mcf, $0.19 per Mcf and $0.91 per Mcf, respectively. Market Conditions The price that we receive for the oil and natural gas our operators produce is largely a function of market supply and demand.
Our natural gas price differential during 2025, 2024 and 2023 was $(0.96) per Mcf, $(0.31) per Mcf and $0.19 per Mcf, respectively. Market Conditions The price that we receive for the oil and natural gas our operators produce is largely a function of market supply and demand.
To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses. Interest Expense Interest expense was $18.5 million for the year ended December 31, 2024 compared to $5.3 million for 2023.
To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses. Interest Expense Interest expense was $25.5 million for the year ended December 31, 2025 compared to $18.5 million for 2024.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Part II of our annual report on Form 10-K for the year ended December 31, 2023, which was filed with the SEC on March 8, 2024.
Management’s Discussion and Analysis of Financial Condition and Results of Operations” under Part II of our annual report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on March 6, 2025.
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. As of December 31, 2024, approximately 28% of our total proved reserves were 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. As of December 31, 2025, approximately 24% of our total proved reserves were categorized as proved undeveloped reserves.
The third-party independent reserve engineers, NSAI, evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2024. Oil and Natural Gas Properties Oil and natural gas producing activities are accounted for under the successful efforts method of accounting.
The third-party independent reserve engineers, NSAI, evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2025. 64 Table of Contents Oil and Natural Gas Properties Oil and natural gas producing activities are accounted for under the successful efforts method of accounting.
During the years ended December 31, 2024, 2023, and 2022, we recognized depletion expense of $175.7 million, $160.2 million and $105.3 million, respectively. Any reduction in proved reserves could result in an acceleration of future depletion expense. Such a decline may result from lower commodity prices which may make it uneconomical to drill certain proved undeveloped locations.
During the years ended December 31, 2025, 2024, and 2023, we recognized depletion expense of $214.8 million, $175.7 million and $160.2 million, respectively. Any reduction in proved reserves could result in an acceleration of future depletion expense. Such a decline may result from lower commodity prices which may make it uneconomical to drill certain proved undeveloped locations.
Because our oil and natural 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.
Because our oil and natural gas revenues are heavily weighted toward oil, we are more significantly impacted by 55 Table of Contents changes in oil prices than by changes in the price of natural gas.
These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement.
These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty 65 Table of Contents and are subject to contractual terms which provide for net settlement.
This increase in total production is offset by the natural decline of the production rate of existing oil and natural gas wells. The number of wells we participated in increased from 176.50 net wells in 2023 to 202.40 net wells in 2024. The following table sets forth information regarding our oil and natural gas production by basin.
This increase in total production is offset by the natural decline of the production rate of existing oil and natural gas wells. The number of wells we participated in increased from 202.40 net wells in 2024 to 244.74 net wells in 2025. The following table sets forth information regarding our oil and natural gas production by basin.
External petroleum engineers independently estimated all of the proved reserve quantities included in our financial statements, which were prepared in accordance with the rules promulgated by the SEC.
External petroleum engineers independently estimated all of the proved reserve quantities included in our Annual Report, which were prepared in accordance with the rules promulgated by the SEC.
On February 14, 2025, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2025 that will be paid on March 14, 2025 to stockholders of record as of February 28, 2025. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.
On February 13, 2026, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2026 that will be paid on March 13, 2026 to stockholders of record as of February 27, 2026. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.
Ad valorem taxes increased during the year ended December 31, 2024 as compared to 2023, primarily due to additional wells drilled and completed and new wells acquired. Depletion and Accretion Depletion and accretion was $176.5 million ($19.31 per Boe) for the year ended December 31, 2024, an increase of 10% from $160.7 million ($18.11 per Boe) in 2023.
Ad valorem taxes increased during the year ended December 31, 2025 as compared to 2024, primarily due to additional wells drilled and completed and new wells acquired. Depletion and Accretion Depletion and accretion was $215.7 million ($18.48 per Boe) for the year ended December 31, 2025, an increase of 22% from $176.5 million ($19.31 per Boe) in 2024.
Our effective income tax rate of 24.9% for the year ended December 31, 2024 differs from the federal statutory rate due primarily to the impact of certain discrete items, state income taxes and changes in state tax rates.
Our effective income tax rate of 24.9% for the year ended December 31, 2024 differed from the federal statutory rate of 21% primarily due to the impact of certain discrete items and state income taxes.
Common stock dividends We paid dividends of $57.5 million, or $0.44 per share, and $58.6 million, or $0.44 per share, during the years ended December 31, 2024 and 2023, respectively.
Common stock dividends We paid dividends of $57.7 million, or $0.44 per share, and $57.5 million, or $0.44 per share, during the years ended December 31, 2025 and 2024, respectively.
Oil revenues for the year ended December 31, 2024 increased by 3% compared to the same period in 2023, driven by an 8% increase in production, partially offset by a 4% decrease in realized prices, excluding the effect of settled derivatives.
Oil revenues for the year ended December 31, 2025 increased by 10% compared to the same period in 2024, driven by an 31% increase in production, partially offset by a 16% decrease in realized prices, excluding the effect of settled derivatives.
Cash Flows Our cash flows for the years ended December 31, 2024, 2023 and 2022 are presented below: Year Ended December 31, (in thousands) 2024 2023 2022 Net cash provided by operating activities $ 275,733 $ 302,867 $ 346,389 Net cash used in investing activities (310,768) (356,676) (230,562) Net cash provided by (used in) financing activities 33,724 13,406 (76,848) Net change in cash $ (1,311) $ (40,403) $ 38,979 Cash Flows Provided by Operating Activities The primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our commodity derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense.
Cash Flows Our cash flows for the years ended December 31, 2025, 2024 and 2023 are presented below: Year Ended December 31, (in thousands) 2025 2024 2023 Net cash provided by operating activities $ 296,414 $ 275,733 $ 302,867 Net cash used in investing activities (409,808) (310,768) (356,676) Net cash provided by financing activities 118,821 33,724 13,406 Net change in cash $ 5,427 $ (1,311) $ (40,403) Cash Flows Provided by Operating Activities The primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our commodity derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense.
Our net cash provided by operating activities included a benefit of $0.9 million and a benefit of $4.6 million for the years 61 Table of Contents ended December 31, 2024 and 2023, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.
Our net cash provided by operating activities included a benefit of $5.5 million and $0.9 million for the years ended December 31, 2025 and 2024, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.
Additionally, for the year ended December 31, 2024, an impairment of $0.7 million to the Company's unproved properties in the Permian Basin as the operator of those properties no longer intends to drill certain locations. During the year ended December 31, 2023, we recognized impairment expense of $26.5 million.
Additionally, for the year ended December 31, 2024, an impairment of 0.7 million to the Company's unproved properties in the Permian Basin as the operator of those properties no longer intends to drill certain locations.
The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2024, 2023 and 2022. December 31, 2024 2023 2022 Average NYMEX Prices (1) Oil (per Bbl) $ 76.63 $ 77.58 $ 94.39 Natural gas (per Mcf) $ 2.19 $ 2.53 $ 6.55 __________________________________________ (1) Based on average NYMEX closing prices.
The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2025, 2024 and 2023. December 31, 2025 2024 2023 Average NYMEX Prices (1) Oil (per Bbl) $ 65.39 $ 76.63 $ 77.58 Natural gas (per Mcf) $ 3.52 $ 2.19 $ 2.53 __________________________________________ (1) Based on average NYMEX closing prices.
Granite Ridge Credit Agreement At December 31, 2024, the Company had outstanding borrowings of $205.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $119.7 million.
Granite Ridge Credit Agreement At December 31, 2025, the Company had outstanding borrowings of $50.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $324.7 million.
The increase in depletion and accretion expense was primarily due to the increase in depletion expense resulting from the increase in production and depletion rate. Impairment of Long-Lived Assets During the years ended December 31, 2024 and 2023, we recognized impairment expense of $36.4 million and $26.5 million, respectively.
The increase in depletion and accretion expense was primarily due to the increase in depletion expense resulting from the increase in production during the year ended December 31, 2025. Impairment of Long-Lived Assets During the years ended December 31, 2025 and 2024, we recognized impairment expense of $44.7 million and $36.4 million, respectively.
Natural gas revenues decreased by 32% for the year ended December 31, 2024 compared to 2023, driven by a 31% decrease in realized natural gas prices, excluding the effect of settled commodity derivatives, and a 1% decrease in production. Production from oil and gas properties increased because of drilling success and the acquisition of additional net revenue interests.
Natural gas revenues increased by 70% for the year ended December 31, 2025 compared to 2024, driven by a 36% increase in realized natural gas prices, excluding the effect of settled commodity derivatives, and a 25% increase in production. Production from oil and gas properties increased because of drilling success and the acquisition of additional net revenue interests.
Our effective income tax rate of 23.2% for the year ended December 31, 2023 differed from the federal statutory rate of 21% primarily due to the impact of certain discrete items and state income taxes.
Our effective income tax rate of 24.2% for the year ended December 31, 2025 differs from the federal statutory rate of 21% due primarily to the impact of certain discrete items, state income taxes, and certain nontaxable or nondeductible items.
Cash Flows Used in Investing Activities For the year ended December 31, 2024, our net cash used in investing activities was $310.8 million, which consisted primarily of $285.8 million of capital expenditures for oil and natural gas properties and $61.2 million of acquisitions of oil and natural gas properties.
Cash Flows Used in Investing Activities For the year ended December 31, 2025, our net cash used in investing activities was $409.8 million, which consisted primarily of $300.8 million of capital expenditures for oil and natural gas properties and $118.5 million of acquisitions of oil and natural gas properties.
Business Combination On October 24, 2022 (the “Closing Date”), Granite Ridge and Executive Network Partnering Corporation ("ENPC") consummated the business combination pursuant to the terms of the Business Combination Agreement, dated as of May 16, 2022 (the “Business Combination Agreement”), by and among ENPC, Granite Ridge, ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub”), and Granite Ridge Holdings, LLC, a Delaware limited liability company formerly known as GREP Holdings, LLC (“GREP”).
Our average daily production for the year ended December 31, 2025 was 31,984 Boe per day. 53 Table of Contents Business Combination On October 24, 2022 (the “Closing Date”), Granite Ridge and Executive Network Partnering Corporation ("ENPC") consummated the business combination pursuant to the terms of the Business Combination Agreement, dated as of May 16, 2022 (the “Business Combination Agreement”), by and among ENPC, Granite Ridge, ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub”), and Granite Ridge Holdings, LLC, a Delaware limited liability company formerly known as GREP Holdings, LLC (“GREP”).
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 and natural gas; • 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 the price of oil and natural gas; • our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and • the level of our operating expenses. 55 Table of Contents In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage in the Eagle Ford, Permian, Bakken, Haynesville, Denver-Julesburg and Appalachian Basins subjects our operating results to factors specific to these regions.
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 and natural gas; • 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 the price of oil and natural gas; • our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and • the level of our operating expenses.
See Note 6 of the Notes to the Consolidated 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 For 2025, we are budgeting approximately $300 million to $320 million in total planned capital expenditures.
See Note 6 of the Notes to the Consolidated 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.
Impairment expense We evaluate capitalized costs related to proved and unproved oil and natural gas properties, including wells and related oil sales support equipment and facilities, for impairment on an annual basis, or more frequently if indicators of impairment exist.
Impairment expense We evaluate capitalized costs related to proved and unproved oil and natural gas properties, including wells and related oil sales support equipment and facilities, for recoverability when indicators of impairment exist.
General and Administrative The following table provides components of our general and administrative expenses for the years ended December 31, 2024 and 2023: Year Ended December 31, (in thousands) 2024 2023 General and administrative expenses $ 22,351 $ 25,758 Non-cash stock-based compensation 2,298 2,162 Total general and administrative expenses $ 24,649 $ 27,920 Total general and administrative expenses were $24.6 million ($2.70 per Boe) for the year ended December 31, 2024, a decrease of 12% from $27.9 million ($3.15 per Boe) in 2023.
General and Administrative The following table provides components of our general and administrative expenses for the years ended December 31, 2025 and 2024: Year Ended December 31, (in thousands) 2025 2024 General and administrative expenses $ 27,253 $ 22,351 Non-cash stock-based compensation 3,756 2,298 Total general and administrative expenses $ 31,009 $ 24,649 Total general and administrative expenses were $31.0 million ($2.66 per Boe) for the year ended December 31, 2025, a increase of 26% from $24.6 million ($2.70 per Boe) in 2024.
Our oil and natural gas sales for the year ended December 31, 2024 decreased 4% from the year ended December 31, 2023.
Our oil and natural gas sales for the year ended December 31, 2025 increased 18% from the year ended December 31, 2024.
As a result of the decline in gas prices as well as reserve revisions in the Haynesville Basin, we compared the sum of the expected undiscounted future net cash flows to the carrying amount of the assets.
As of December 31, 2025, as a result of the decline in oil prices in the Eagle Ford Basin, we compared the sum of the expected undiscounted future net cash flows to the carrying amount of the assets.
Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves. 64 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.
On November 1, 2024, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which amended the Credit Agreement to, among other things, (a) increase the borrowing base from $300.0 million to $325.0 million, and (b) increase the aggregate elected commitments from $300.0 million to $325.0 million.
On April 29, 2025, the Company and its lenders entered into the Fifth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) increase the borrowing base from $325.0 million to $375.0 million, and (ii) increase the aggregate elected commitments from $325.0 million to $375.0 million.
Year Ended December 31, 2024 2023 Net Sales (in thousands): Oil sales $ 327,491 $ 317,099 Natural gas and related product sales 52,539 76,970 Revenues 380,030 394,069 Net Production: Oil (MBbl) 4,483 4,162 Natural gas (MMcf) 27,944 28,266 Total (MBoe) (1) 9,140 8,873 Average Daily Production: Oil (Bbl) 12,248 11,404 Natural gas (Mcf) 76,350 77,442 Total (Boe) (1) 24,973 24,311 Average Sales Prices: Oil (per Bbl) $ 73.06 $ 76.18 Effect of gain (loss) on settled oil derivatives on average price (per Bbl) 0.34 1.10 Oil net of settled oil derivatives (per Bbl) (2) $ 73.40 $ 77.28 Natural gas and related product sales (per Mcf) $ 1.88 $ 2.72 Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf) 0.53 0.65 Natural gas and related product sales net of settled natural gas derivatives (per Mcf) (2) $ 2.41 $ 3.37 Realized price on a Boe basis excluding settled commodity derivatives $ 41.58 $ 44.41 Effect of gain (loss) on settled commodity derivatives on average price (per Boe) 1.79 2.58 Realized price on a Boe basis including settled commodity derivatives (2) $ 43.37 $ 46.99 Operating Expenses (in thousands): Lease operating expenses $ 57,461 $ 60,521 Production and ad valorem taxes 26,007 27,707 Depletion and accretion expense 176,529 160,662 Impairments of long-lived assets 36,369 26,496 General and administrative 24,649 27,920 Costs and Expenses (per Boe): Lease operating expenses $ 6.29 $ 6.82 Production and ad valorem taxes $ 2.85 $ 3.12 Depletion and accretion $ 19.31 $ 18.11 Impairments of long-lived assets $ 3.98 $ 2.99 General and administrative $ 2.70 $ 3.15 Net Producing Wells at Period-End: 202.40 176.50 __________________________________________ (1) Natural gas is converted to Boe using the ratio of one barrel of oil to six Mcf of natural gas.
Year Ended December 31, 2025 2024 Net Sales (in thousands): Oil sales $ 360,832 $ 327,491 Natural gas and related product sales 89,474 52,539 Revenues 450,306 380,030 Net Production: Oil (MBbl) 5,855 4,483 Natural gas (MMcf) 34,912 27,944 Total (MBoe) (1) 11,674 9,140 Average Daily Production: Oil (Bbl) 16,041 12,248 Natural gas (Mcf) 95,649 76,350 Total (Boe) (1) 31,984 24,973 Average Sales Prices: Oil (per Bbl) $ 61.63 $ 73.06 Effect of gain on settled oil derivatives on average price (per Bbl) 0.28 0.34 Oil net of settled oil derivatives (per Bbl) (2) $ 61.91 $ 73.40 Natural gas and related product sales (per Mcf) $ 2.56 $ 1.88 Effect of gain on settled natural gas derivatives on average price (per Mcf) 0.08 0.53 Natural gas and related product sales net of settled natural gas derivatives (per Mcf) (2) $ 2.64 $ 2.41 Realized price on a Boe basis excluding settled commodity derivatives $ 38.57 $ 41.58 Effect of gain on settled commodity derivatives on average price (per Boe) 0.38 1.79 Realized price on a Boe basis including settled commodity derivatives (2) $ 38.95 $ 43.37 Operating Expenses (in thousands): Lease operating expenses $ 84,903 $ 57,461 Production and ad valorem taxes 27,554 26,007 Depletion and accretion expense 215,701 176,529 Impairments of long-lived assets 44,654 36,369 General and administrative 31,009 24,649 Costs and Expenses (per Boe): Lease operating expenses $ 7.27 $ 6.29 Production and ad valorem taxes 2.36 2.85 Depletion and accretion 18.48 19.31 Impairments of long-lived assets 3.83 3.98 General and administrative 2.66 2.70 Net Producing Wells at Period-End: 244.74 202.40 __________________________________________ (1) Natural gas is converted to Boe using the ratio of one barrel of oil to six Mcf of natural gas.
Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions.
Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions.
We had $129.1 million of liquidity as of December 31, 2024, consisting of $119.7 million of committed borrowing availability under the Credit Agreement and $9.4 million of cash on hand.
We had $339.5 million of liquidity as of December 31, 2025, consisting of $324.7 million of committed borrowing availability under the Credit Agreement and $14.8 million of cash on hand.
See Note 8 of the Notes to the Consolidated Financial Statements for information regarding future interest payment obligations on our Credit Agreement. • We entered into the MSA with the Manager in which we pay the Manager an annual services fee of $10.0 million and reimburse the Manager for certain Granite Ridge group costs related to the operation of our oil and gas assets and other properties.
See Note 8 of the Notes to the Consolidated Financial Statements for information regarding future interest payment obligations on our Credit Agreement. • As of December 31, 2025, we had $350.0 million of principal debt outstanding on our 2029 Senior Notes with quarterly repayments of $8.75 million beginning September 30, 2026. • We entered into the MSA with the Manager in which we pay the Manager an annual services fee for certain Granite Ridge group costs related to the operation of our oil and gas assets and other properties of $11.75 million, subject to annual CPI-based adjustments beginning January 1, 2027.
See Note 10 of the Notes to the Consolidated Financial Statements. • We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 of the Notes to the Consolidated Financial Statements. • We have future obligations related to the abandonment of our oil and natural gas properties.
See Note 3 of the Notes to the Consolidated Financial Statements. • We have future obligations related to the abandonment of our oil and natural gas properties.
Unproved oil and natural gas properties are assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. 65 Table of Contents Derivative Instruments – Commodity Derivatives In order to reduce uncertainty around commodity prices received for our oil and natural gas operators’ production, we enter into commodity price derivative contracts from time to time.
Unproved oil and natural 54 Table of Contents gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects.
Production and Ad Valorem Taxes We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $21.0 million ($2.30 per Boe) for the year ended December 31, 2024 compared to $24.9 million ($2.81 per Boe) for 2023. As a percentage of oil and natural gas sales, our production taxes were 6% in 2024 and 2023.
Production taxes were $22.4 million ($1.92 per Boe) for the year ended December 31, 2025 compared to $21.0 million ($2.30 per Boe) for 2024. As a percentage of oil and natural gas sales, our production taxes were 5% and 6% for the years ended December 31, 2025 and 2024, respectively.
Year Ended December 31, 2024 2023 Net Production: Oil (MBbl) Permian 2,956 2,656 Eagle Ford 638 529 Bakken 561 665 Haynesville — — DJ 322 312 Appalachian 6 — Total 4,483 4,162 Natural Gas (MMcf) Permian 11,229 9,146 Eagle Ford 3,847 3,055 Bakken 1,235 1,105 Haynesville 9,264 12,251 DJ 2,345 2,709 Appalachian 24 — Total 27,944 28,266 Total (MBoe) Permian 4,828 4,180 Eagle Ford 1,279 1,038 Bakken 767 849 Haynesville 1,544 2,042 DJ 712 764 Appalachian 10 — Total 9,140 8,873 Lease Operating Expenses Lease operating expenses were $57.5 million ($6.29 per Boe) for the year ended December 31, 2024, a decrease of 5% from $60.5 million ($6.82 per Boe) for 2023.
Year Ended December 31, 2025 2024 Net Production: Oil (MBbl) Permian 4,288 2,956 Eagle Ford 387 638 Bakken 465 561 Haynesville — — DJ 373 322 Appalachian 342 6 Total 5,855 4,483 Natural Gas (MMcf) Permian 18,744 11,229 Eagle Ford 3,224 3,847 Bakken 1,150 1,235 Haynesville 8,212 9,264 DJ 2,240 2,345 Appalachian 1,342 24 Total 34,912 27,944 Total (MBoe) Permian 7,412 4,828 Eagle Ford 924 1,279 Bakken 657 767 Haynesville 1,369 1,544 DJ 746 712 Appalachian 566 10 Total 11,674 9,140 Lease Operating Expenses Lease operating expenses were $84.9 million ($7.27 per Boe) for the year ended December 31, 2025, a increase of 48% from $57.5 million ($6.29 per Boe) for 2024.
As of December 31, 2024, we were in compliance with all covenants required by the Credit Agreement. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations • As of December 31, 2024, we had $205.0 million of debt outstanding under our Credit Agreement.
The principal remaining outstanding at the time of maturity is required to be paid in full by the Issuer. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations • As of December 31, 2025, we had $50.0 million of debt outstanding under our Credit Agreement.
For the year ended December 31, 2023, our net cash provided by financing activities was $13.4 million primarily due to $110.0 million of net borrowings under our Credit Agreement, partially offset by $58.6 million of dividends paid on our common stock and $35.4 million of common stock repurchases.
Cash Flows Provided by (Used in) Financing Activities For the year ended December 31, 2025, our net cash provided by financing activities was $118.8 million primarily due to proceeds from senior notes, net of discount, of $336.0 million, partially offset by $155.0 million of net repayments under our Credit Agreement and $57.7 million of dividends paid on our common stock.
Effects of Inflation and Pricing The oil and natural gas industry is typically very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs.
However, there can be no assurance that any additional capital will be available to us on favorable terms or at all. 63 Table of Contents Effects of Inflation and Pricing The oil and natural gas industry is typically very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry.
We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Credit Agreement. The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors.
The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors.
We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. 60 Table of Contents As of December 31, 2024, we had $205.0 million of debt outstanding under our Credit Agreement.
We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. As of December 31, 2025, the Company had $350.0 million of principal debt outstanding on 8.875% senior unsecured notes (the “2029 Senior Notes”) and $50.0 million of debt outstanding under our senior secured revolving credit agreement (as amended, the “Credit Agreement”).
Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes.
Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes. The $20.7 million increase in operating cash flows during the year ended December 31, 2025 as compared to 2024 was primarily due to the increase in oil and natural gas sales during 2025 as compared to 2024.
The decrease was primarily due to $2.5 million of costs directly related to the Warrant Exchange in 2023. 59 Table of Contents Gain/(Loss) on Derivatives – Commodity Derivatives The following table sets forth the gain (loss) on derivatives for the years ended December 31, 2024 and 2023: Year Ended December 31, (in thousands) 2024 2023 Gain (loss) on commodity derivatives Oil derivatives $ (10,260) $ 6,459 Natural gas derivatives 9,352 19,085 Total $ (908) $ 25,544 The following table represents our net cash receipts from (payments on) derivatives for the years ended December 31, 2024 and 2023: Year Ended December 31, (in thousands) 2024 2023 Net cash receipts from (payments on) commodity derivatives Oil derivatives $ 1,503 $ 4,576 Natural gas derivatives 14,860 18,319 Total $ 16,363 $ 22,895 Our earnings are affected by the changes in the value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant.
The increase was primarily due to severance expense incurred during the period as a result of a management transition as well as expenses related to capital market activities. 59 Table of Contents Gain/(Loss) on Derivatives – Commodity Derivatives The following table summarizes the amounts reported as gain (loss) on derivatives - commodity derivatives in the condensed consolidated statements of operations for the years ended December 31, 2025, and 2024: Year Ended December 31, (in thousands) 2025 2024 Net cash receipts from commodity derivatives Oil derivatives $ 1,624 $ 1,503 Natural gas derivatives 2,835 14,860 Total net cash receipts from commodity derivatives $ 4,459 $ 16,363 Unrealized gain (loss) on commodity derivatives Oil derivatives $ 15,084 $ (5,508) Natural gas derivatives 6,726 (11,763) Power capacity contract 852 — Total unrealized gain (loss) on commodity derivatives $ 22,662 $ (17,271) Total gain (loss) on derivatives - commodity derivatives $ 27,121 $ (908) Our earnings are affected by the changes in the value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant.
For the year ended December 31, 2023, our net cash used in investing activities was $356.7 million, which consisted primarily of $282.4 million of capital expenditures for oil and natural gas properties and $76.8 million of acquisitions of oil and natural gas properties.
These cash flows used in investing activities are partially offset by cash proceeds from refund of advances from operators of $4.3 million, and proceeds from the sale of equity investments of $5.0 million during 2025. 61 Table of Contents For the year ended December 31, 2024, our net cash used in investing activities was $310.8 million, which consisted primarily of $285.8 million of capital expenditures for oil and natural gas properties and $61.2 million of acquisitions of oil and natural gas properties.
For the year ended December 31, 2023, we recorded income tax expense of $24.5 million, which included current income tax expense of $0.2 million and deferred income tax expense of $24.3 million.
See the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources" for more information. Income Tax Expense (Benefit) For the year ended December 31, 2025, we recorded income tax expense of $7.8 million, which included current income tax expense of $0.4 million and deferred income tax expense of $7.4 million.
As of December 31, 2024, we owned an interest in 3,146 gross (202 net) producing wells, 323,222 gross (33,745 net) developed acres, and 25,334 gross (10,138 net) undeveloped acres, all located in the United States. Our average daily production for the year ended December 31, 2024 was 24,973 Boe per day.
As of December 31, 2025, we owned an interest in 3,602 gross (245 net) producing wells, 355,252 gross (47,534 net) developed acres, and 33,399 gross (12,504 net) undeveloped acres, all located in the United States.
In addition, workover and repair and maintenance expenses for the year ended December 31, 2024 are 58 Table of Contents lower than the same period of 2023, partially offset by an increase in certain other lease operating expenses as a result of an increase in well count due to acquisitions and additional wells successfully drilled and completed.
Additionally, there has been an increase in certain other lease operating expenses as a result of an increase in well count due to acquisitions and additional wells successfully drilled and completed. 58 Table of Contents Production and Ad Valorem Taxes We generally pay production taxes based on realized oil and natural gas sales.
The increase in interest expense was primarily due to the increase in interest rates and higher average outstanding balance on the revolving credit facility. Gain (Loss) on Derivatives – Common Stock Warrants We recognized a loss of $5.7 million during 2023 from the change in fair value of the warrant liability.
The increase in interest expense was primarily due to a higher average outstanding balance on the revolving credit facility, as well as the issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes in November 2025.
Removed
The decrease was primarily due to a decrease of $1.6 million in transportation and gathering expenses related to certain take in-kind arrangements on natural gas volumes, which have declined in the Haynesville area.
Added
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage in the Eagle Ford, Permian, Bakken, Haynesville, Denver-Julesburg and Appalachian Basins subjects our operating results to factors specific to these regions.
Removed
See Note 3 and Note 9 in the Notes to the Consolidated Financial Statements for additional information on the common stock warrants and the Warrant Exchange.
Added
The increase was primarily due to a $6.2 million increase in saltwater disposal costs, as well as a $4.0 million increase in contract labor.
Removed
On November 1, 2024, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which amended the Credit Agreement to, among other things, increase the borrowing base and aggregate elected commitments from $300 million to $325 million. See Note 8 to the Notes to the Consolidated Financial Statements for additional information.
Added
The Company used the net proceeds from issuance of the 2029 Senior Notes to repay certain amounts under the Credit Agreement and to pay related fees and expenses.
Removed
The $27.1 million decrease in operating cash flows during the year ended December 31, 2024 as compared to 2023 was primarily due to the decrease in oil and natural gas sales and deferred income taxes during 2024 as compared to 2023.
Added
The Note Purchase Agreement allows the ability for the Company to incur up to $100.0 million of incremental notes for purposes of acquisition financing, subject to, among other things, the willingness of holders to provide such incremental notes and a pro forma net leverage ratio not greater than 2.00 to 1.00.
Removed
These cash flows used in investing activities are partially offset by cash proceeds from refund of advances from operators of $2.5 million.
Added
Interest is due to be paid at the end of each quarter, commencing December 31, 2025. In addition, the Company will repay quarterly 2.5% of the original principal amount of the notes issued on the closing date beginning on September 30, 2026.
Removed
On October 24, 2022, Granite Ridge entered into a senior secured revolving credit agreement (as amended, the “Credit Agreement”) among Granite Ridge, as borrower, currently led by Bank of America, N.A., as administrative agent, and the lenders from time to time party thereto. The Credit Agreement has a maturity date of five years from the effective date thereof.
Added
If quarterly scheduled repayments are missed, the coupon increases to 11.875% and the Company is restricted from making any dividend payments until all delinquent scheduled repayments have been fulfilled. The Company has $17.5 million included in current liabilities in our consolidated balance sheets related to quarterly principal repayments due within the next 12 months.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

6 edited+1 added−0 removed4 unchanged
Biggest changeThe impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $2.1 million. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.
Biggest changeWe had total indebtedness of $50.0 million outstanding under our Credit Agreement at December 31, 2025. The impact of a 100 basis point increase in the interest rate on this amount of debt would result in increased annual interest expense of approximately $0.5 million.
We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place. 66 Table of Contents We generally use derivatives to economically hedge a portion of our anticipated future production.
We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place. We generally use derivatives to economically hedge a portion of our anticipated future production.
Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on our earnings. For the year ended December 31, 2024, a 10% increase in average commodity prices would have decreased the fair value of commodity derivatives by $19.3 million.
Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on our earnings. For the year ended December 31, 2025, a 10% increase in average commodity prices would have decreased the fair value of our collar option and swap commodity derivatives by $23.4 million.
Interest Rate Risk At December 31, 2024, our exposure to interest rate changes related primarily to the borrowings under the Credit Agreement. The interest we pay on these borrowings is set periodically based upon market rates. We had total indebtedness of $205.0 million outstanding under our Credit Agreement at December 31, 2024.
Interest Rate Risk At December 31, 2025, our exposure to interest rate changes related primarily to the borrowings under the Credit Agreement as the 2029 Senior Notes bear a fixed interest rate. The interest we pay on these borrowings is set periodically based upon market rates.
Financial Statements and Supplementary Data The financial statements and supplementary financial information required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F-1. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None.
We had no outstanding interest rate derivative contracts at December 31, 2025. 66 Table of Contents Item 8. Financial Statements and Supplementary Data The financial statements and supplementary financial information required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F-1. Item 9.
Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We had no outstanding interest rate derivative contracts at December 31, 2024. Item 8.
We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Added
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None.

Other GRNT 10-K year-over-year comparisons