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What changed in Granite Ridge Resources, Inc.'s 10-K — 2023 vs 2024

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

+338 added−383 removedSource: 10-K (2025-03-06) vs 10-K (2024-03-08)

Top changes in Granite Ridge Resources, Inc.'s 2024 10-K

338 paragraphs added · 383 removed · 270 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

59 edited+32 added−29 removed121 unchanged
Biggest changeEnvironmental, social, and governance (“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and stockholders across the industry. While reporting on ESG metrics is currently voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place.
Biggest changeLimitation 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.
For example, North Dakota, Montana, Louisiana, Colorado, Oklahoma, New Mexico, and Texas require permits for drilling operations, drilling bonds or other forms of financial security, and reports concerning operations, and impose other requirements relating to the exploration and production of oil and natural gas.
For example, North Dakota, Montana, Louisiana, Colorado, Oklahoma, New Mexico, Ohio, and Texas require permits for drilling operations, drilling bonds or other forms of financial security, and reports concerning operations, and impose other requirements relating to the exploration and production of oil and natural gas.
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 20 Table of Contents to emissions that exceed an established emissions threshold for each type of covered facility.
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.
Our land and engineering team uses an extensive proprietary data set to assist us in making these economic decisions. Given our acreage footprint and substantial number of well participations, we believe we can make relatively accurate decisions regarding the economics of well participation.
Our land and engineering team uses an extensive proprietary data set to assist us in making these investment decisions. Given our acreage footprint and substantial number of well participations, we believe we can make relatively accurate decisions regarding the economics of well participation.
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 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.
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.
If in the future CWA permitting is required for saltwater injection wells as a result of the 18 Table of Contents 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.
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.
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, 2023, 7% 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, 2024, 8% of our total proved reserves were located in the DJ Basin.
Also, institutional lenders may, of their own accord, decide not to provide funding for fossil fuel energy companies or related infrastructure projects based on climate or other ESG-related concerns, which could affect our access to capital.
Additionally, certain institutional lenders may, of their own accord, decide not to provide funding for fossil fuel energy companies or related infrastructure projects based on climate or other ESG-related concerns, which could affect our access to capital.
Under the CAA and comparable state laws, the Environmental Protection Agency (“EPA”) and state environmental regulatory agencies have developed stringent 16 Table of Contents regulations governing both permitting of emissions and emissions of certain air pollutants at specified sources, including certain oil and gas sources.
Under the CAA and comparable state laws, the Environmental Protection Agency (“EPA”) and state environmental regulatory agencies have developed stringent regulations governing both permitting of emissions and emissions of certain air pollutants at specified sources, including certain oil and gas sources.
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.
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.
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, 2023, 60% 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, 2024, 69% of our total proved reserves were located in the Permian Basin.
Consequently, we are also exposed to increased litigation risks relating to alleged climate-related damages resulting from our operators’ operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimation required with respect to calculating and reporting GHG emissions.
Consequently, we may also be exposed to increased litigation risks relating to alleged climate-related damages resulting from our operators’ operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties, estimation and evolving methodologies required with respect to collecting, calculating and reporting GHG emissions.
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.
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.
Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC.
Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. 16 Table of Contents Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC.
Major Operators 2023 2022 2021 Operator A 11 % 12 % 12 % Operator B * * 15 % Operator C 12 % 10 % * Operator D * 10 % * __________________________________________ * 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, 2023, 2022, or 2021.
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.
In January 2024, the Colorado Energy and Carbon Management Commission (formerly the Colorado Oil and Gas Conversation Commission) released draft rules that, if finalized as proposed, would require regulators to consider cumulative impacts of oil and gas operations in permitting decisions and increase scrutiny on the project’s proximity to other industrial sites, residential and school areas, “disproportionately impacted communities,” and “cumulatively impacted communities.” The draft rules would also set GHG emissions intensity targets for oil and gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas.
In October 2024, the Colorado Energy and Carbon Management Commission (formerly the Colorado Oil and Gas Conversation Commission) finalized rules that require regulators to consider cumulative impacts of oil and gas operations in permitting decisions and increase scrutiny on the project’s proximity to other industrial sites, residential and school areas, “disproportionately impacted communities,” and “cumulatively impacted communities.” The rules also set GHG emissions intensity targets for oil and gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on 15 Table of Contents the same terms and under the same rates.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates.
Enhanced climate-related disclosure requirements could increase our operators’ operating costs and lead to reputational or other harm with customers, regulators, or other stakeholders to the 21 Table of Contents extent our, disclosures do not meet their own standards or expectations.
Enhanced climate-related disclosure requirements could increase our operators’ operating costs and lead to reputational or other harm with customers, regulators, or other stakeholders to the extent our, disclosures do not meet their own standards or expectations.
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 to such reports or other documents with the SEC under the Securities Exchange 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 22 Table of Contents Act of 1934, as amended (the "Exchange Act").
Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or natural gas prices may affect planned capital expenditures and 12 Table of Contents the oil and natural gas reserves that the Properties can economically produce.
Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or natural gas prices may affect planned capital expenditures and the oil and natural gas reserves that the Properties can economically produce.
The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability.
The regulatory burden on the oil and natural gas industry will most likely increase our cost of 15 Table of Contents doing business and may affect our profitability.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors.
There have also recently been increasing financial risks for fossil fuel producers as certain shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors.
During the year ended December 31, 2023, operators completed 24 gross (5.84 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, 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.
However, due to 17 Table of Contents the injunction on the January 2023 rule, the implementation of the September 2023 rule currently varies by state.
However, due to the injunction on the January 2023 rule, the implementation of the September 2023 rule currently varies by state.
Immediately prior to the Transactions, the net assets of certain funds managed by Grey Rock Energy Management, LLC (“Grey Rock”) were contributed to GREP and are now held by the Company. Assets of Granite Ridge We hold interests in wells in core operating areas of the Permian, Eagle Ford, Bakken, Haynesville and Denver-Julesburg (“DJ”) plays (collectively, our “Properties”).
Immediately prior to the Transactions, the net assets of certain funds managed by Grey Rock Energy Management, LLC (“Grey Rock”) were contributed to GREP and are now held by the Company. Assets of Granite Ridge We hold assets in the Permian (Delaware and Midland basins), Eagle Ford, Bakken, Haynesville, Denver-Julesburg (“DJ”) and Appalachian basins (collectively, our “Properties”).
At the closing of the Business Combination, we entered into a credit agreement with Texas Capital Bank, as administrative agent, and the lenders named therein (as amended, the “Credit Agreement”), secured by a first priority mortgage and security interest in substantially all of our and our restricted subsidiaries' assets.
At the closing of the Business Combination, we entered into a credit agreement with a syndicate of lenders, currently led by Bank of America, N.A, as administrative agent (as amended, the “Credit Agreement”), secured by a first priority mortgage and security interest in substantially all of our and our restricted subsidiaries' assets.
During the year ended December 31, 2023, operators completed 123 gross (13.26 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, 2023, 15% of our total proved reserves were located in the Eagle Ford Basin.
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.
If the DSL is ultimately listed as an endangered or threatened species, 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.
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.
At December 31, 2023, 8% of our total proved reserves were located in the Bakken Basin. During the year ended December 31, 2023, operators completed 34 gross (1.47 net) wells in the Bakken Basin. Haynesville The Haynesville Basin is a premier natural gas basin located in Northwestern Louisiana and East Texas.
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, 2023, 9% of our total proved reserves were located in the Haynesville Basin. During the year ended December 31, 2023, operators completed 9 gross (1.13 net) wells in the Haynesville Basin.
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.
Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our operating partners to market and sell our production.
Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We generally rely on our operating partners to market and sell our production. Our operating partners include a variety of exploration and production companies, from large publicly traded companies to privately-owned companies.
We and the Manager strive to provide employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. Together with our Manager, we seek to provide a working environment that empowers employees, allows them to execute at their highest potential, keeps them safe, and promotes their professional growth.
Together with our Manager, we seek to provide a working environment that empowers employees, allows them to execute at their highest potential, keeps them safe, and promotes their professional growth.
These new and (if enacted) additional anticipated 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.
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.
As such, we seek to capture opportunities at an attractive entry cost by targeting non-marketed packages and developing creative partnerships. Capture Accretive Opportunities with Upside : We focus on investments with high-graded drilling inventory rather than simply buying production.
As such, we seek to capture opportunities at an attractive entry cost by targeting non-marketed packages and developing creative partnerships. Capture Accretive Opportunities with Upside : We focus on investments with high-graded drilling inventory. Historically, we have achieved higher returns by focusing on projects with near-term development rather than buying assets with a higher proportion of flowing production.
Our operating partners include a variety of exploration and production companies, from large publicly traded companies to privately-owned companies. 13 Table of Contents 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, 2023, 2022 and 2021.
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.
Seasonality Weather events and conditions, such as ice storms, freezing conditions, droughts, floods, and tornados can limit or temporarily halt the drilling and producing activities of our operating partners and other oil and natural gas operations.
As is customary in the oil and natural gas industry, due diligence investigation of title is made at the time of acquisition of any properties. 14 Table of Contents Seasonality Weather events and conditions, such as ice storms, freezing conditions, droughts, floods, and tornados can limit or temporarily halt the drilling and producing activities of our operating partners and other oil and natural gas operations.
Our operating partners coordinate the transportation of our oil and natural gas production from their wells to appropriate pipelines or rail transport facilities pursuant to arrangements that they negotiate and maintain with various parties purchasing the production. We may, from time to time, enter into financial hedging contracts to help mitigate pricing risk and volatility with respect to differentials.
Our operating partners coordinate the transportation of our oil and natural gas production from their wells to appropriate pipelines or rail transport 13 Table of Contents facilities pursuant to arrangements that they negotiate and maintain with various parties purchasing the production.
The operators of our Properties include public exploration and production companies and experienced private companies. 10 Table of Contents The following is a summary of information regarding our assets as of December 31, 2023, 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, 2024, including reserves information as estimated by our third-party independent reserve engineers, Netherland, Sewell & Associates, Inc.
For example, on August 26, 2022, EPA announced a proposal to designate as hazardous substances perfluorooctanoic acid (“PFOA”) and perfluorooctanesulfonic acid (“PFOS”), which have been commonly used in a variety of industrial and consumer products. EPA is expected to finalize that proposal in 2024.
For example, in May 2024, the EPA designated perfluorooctanoic acid (“PFOA”) and perfluorooctanesulfonic acid (“PFOS”), which have been commonly used in a variety of industrial and consumer products, as hazardous substances.
Competition Although we focus on a target asset class and deal size where we believe competition and costs are reduced as compared to the broader oil and natural gas industry, the overall industry remains intensely competitive.
We may, from time to time, enter into financial hedging contracts to help mitigate pricing risk and volatility with respect to differentials. Competition Although we focus on a target asset class and transaction size where we believe competition and costs are reduced as compared to the broader oil and natural gas industry, the overall industry remains intensely competitive.
In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), and comparable state statutes and any implementing regulations thereof may require disclosure of information about hazardous materials stored, used, or produced in operations on the Properties and that such information be provided to employees, state and local governmental authorities, and/or citizens, as applicable. 19 Table of Contents These regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment, additional evaluation or assessment, or more stringent permitting or environmental protection measures could have a material adverse impact on our business, results of operations, and financial condition.
In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), and comparable state statutes and any implementing regulations thereof may require disclosure of information about hazardous materials stored, used, or produced in operations on the Properties and that such information be provided to employees, state and local governmental authorities, and/or citizens, as applicable.
At the closing of the Business Combination, we entered into a Management Services Agreement (“MSA”) with the Manager, pursuant to which the Manager supplies land, accounting, engineering, finance, and other back-office services to us in connection with continued management of the Properties contributed to us as part of the Business Combination. 14 Table of Contents Governmental Regulation and Environmental Matters Our operations are subject to various rules, regulations, and limitations impacting the oil and natural gas exploration and production industry as a whole.
At the closing of the Business Combination, we entered into a Management Services Agreement (“MSA”) with Grey Rock Administration, LLC (the "Manager"), pursuant to which the Manager supplies land, accounting, engineering, finance, and other back-office services to us in connection with continued management of the Properties contributed to us as part of the Business Combination.
The results of these studies or similar governmental reviews could spur initiatives to further regulate oil and gas production activities. Several states, including states where the Properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing.
Several states, including states where the Properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing. However, in May 2015, the Texas legislature enacted a bill preempting local bans on hydraulic fracturing.
In addition to entering into hedging derivative instruments tied to the price of oil or natural gas, we actively pursue diversification across hydrocarbon, basin, and operator to mitigate price swings specific to any particular area, company or contract. 11 Table of Contents Adapt : Be it from technology, macro events, political dynamics or investor sentiment, change is the only constant in the oil and gas industry.
In addition to entering into hedging derivative instruments tied to the price of oil or natural gas, we actively pursue diversification across hydrocarbon, basin, and operator to mitigate price swings specific to any particular area, company or contract. Be a Good Partner : We lean heavily on our operating partners.
Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies.
Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies, although this trend has waned recently, with several high-profile banks and institutional investors withdrawing from various associations that aim to limit the financing of such industries.
In addition, the majority of scientific studies on climate change suggest that extreme weather conditions and other risks may occur in the future in the areas where we operate, although the scientific studies are not unanimous.
In addition, scientific studies on climate change suggest that extreme weather conditions and other risks may occur in the future in the areas where we operate, although the scientific studies are not unanimous. Although operators may take steps to mitigate any such risks, no assurance can be given that they will not have material adverse effect on our business.
However, in May 2015, the Texas legislature enacted a bill preempting local bans on hydraulic fracturing. Colorado has also begun to increasingly regulate oil and gas operations with consideration towards GHG emissions and cumulative impacts.
Colorado has also begun to increasingly regulate oil and gas operations with consideration towards GHG emissions and cumulative impacts.
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.
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.
For example, the Dunes Sagebrush Lizard (“DSL”) is one species that, if listed as endangered or threatened under the ESA, could impact our profitability. The DSL is found in southeastern New Mexico and adjacent portions of Texas. The USFWS proposed to list the DSL as endangered in July 2023.
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.
By building relationships across multiple disciplines and actively seeking creative opportunities to be a value-added partner, we can often access more and more timely data as well as mitigate some of the challenges inherent in non-op around development plans and timing. Empower People : Our people are the lifeblood of our organization.
By building relationships across multiple disciplines and actively seeking creative opportunities to be a value-added partner, we can often access off-market opportunities and mitigate risks inherent in the energy business. Empower People : Our people are the lifeblood of our organization. We aim to encourage, support, and incentivize our team to develop and implement ideas that make us better.
Given the current pace of drilling in the areas of our operations, we do not believe lease expiration issues will materially affect our acreage position.
Given the current pace of drilling in the areas of our operations, we do not believe lease expiration issues will materially affect our acreage position. Our operated partnerships are governed by joint development agreements that outline the terms for the joint evaluation, acquisition, exploration, development, and production of hydrocarbons from jointly owned interests subject to such agreements.
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. We believe, and the Manager believes, that our future success depends partially on our ability to attract, retain, and motivate qualified personnel.
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.
Other activities are covered under categorical exclusions which results in a shorter NEPA review process. In April 2022, the Biden Administration finalized a rule to undo some of the changes to NEPA enacted under the Trump Administration that were intended to streamline NEPA review (the “2020 NEPA Rule”).
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.
We believe that we have satisfactory title to, or rights in, the Properties. As is customary in the oil and natural gas industry, due diligence investigation of title is made at the time of acquisition of any properties.
We believe that we have satisfactory title to, or rights in, the Properties.
Fines and penalties for violations of these rules can be substantial. It is likely, however, that the final rule and its requirements will be subject to legal challenges. 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.
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.
During the year ended December 31, 2023, operators completed 124 gross (2.85 net) wells in the DJ Basin.
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.
Pay a Quarterly Dividend : We believe that a quarterly cash dividend is the cornerstone of a sustainable and resilient business model. We expect that Granite Ridge will initially pay quarterly cash dividends of $0.11 (or $0.44 per fiscal year). Be a Good Partner : As a non-operator, we lean heavily on our operating partners.
Pay a Quarterly Dividend : We believe that a quarterly cash dividend is the cornerstone of a sustainable and resilient business model.
Overview Granite Ridge is a scaled, non-operated oil and gas exploration and production company. We own a portfolio of wells and top-tier acreage across the Permian and four other prolific unconventional basins across the United States.
Overview Granite Ridge is a scaled energy company which aims to provide shareholders with exposure similar to energy private equity through operated partnerships and traditional non-operated assets. We own assets in six prolific unconventional basins across the United States.
While the United States under the Trump Administration withdrew from the Paris Agreement effective November 4, 2020, President Biden recommitted the United States to the Paris Agreement on January 20, 2021.
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.
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Rather than drill wells ourselves, we increase asset diversity and decrease overhead by investing in a smaller piece of a larger number of high-graded wells drilled by proven public and private operators. As a non-operating partner, we pay our pro rata share of expenses, but we are not burdened by long-term contracts and drilling obligations common to operators.
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We aim to deliver a diversified portfolio with best-in-class full cycle returns by investing in a large number of high-graded opportunities developed by proven public and private operators. We focus on success as measured by total shareholder returns, which we seek to balance with a low leverage profile.
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We drive capital appreciation by reinvesting cash flow generated from our oil and gas wells to: • participate in the development of new wells alongside operators with significant experience in developing and producing hydrocarbons in our core asset areas; • acquire additional rights to participate in future wells; and • leverage our scalable, tech-enabled platform to consolidate non-operated assets.
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To this end, we aim to: • manage our current portfolio of assets to generate cash flow; • participate in the development of new wells alongside operators with significant expertise in our core asset areas; • source and evaluate new opportunities which provide healthy risk-adjusted returns; and • return cash to shareholders as appropriate while maintaining a low leverage profile.
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Non-operated working interests constitute the central part of our investment strategy. However, we have also made certain investments in minerals, and certain other oil and natural gas assets that are incidental or ancillary to preserve, protect, or enhance our assets, or are acquired as part of a package with the non-operated working interests.
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The operators of our Properties include other public companies and experienced private companies. Operated partnerships are comprised of transactions where Granite Ridge makes controlled investments with proven teams in their area of expertise.
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As of December 31, 2023 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 9,593 575 46.30 1 — 11,453 32,300 56% 42% Eagle Ford 6,809 120 24.80 93 6.90 2,843 7,874 55% 64% Bakken 13,487 938 39.00 — — 2,326 4,500 73% 96% Haynesville 5,502 — — 117 16.40 5,595 4,834 0% 89% DJ 2,086 967 42.20 15 0.90 2,094 3,963 34% 98% Total 37,477 2,600 152.30 226 24.20 24,311 53,472 51% 58% Business Strategy We are focused on creating long-term stockholder value by recycling cash flow into accretive growth opportunities while paying a quarterly cash dividend and maintaining a healthy balance sheet.
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Traditional non-operated assets are comprised of minority interests in core areas managed by experienced operators. 10 Table of Contents Operated Partnerships We create operated partnerships by investing in assets which are drilled, developed and operated by private operators.
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Key elements of our strategy include: Build a Diversified Portfolio : Our non-operated strategy of investing in a smaller piece of a larger number of high-graded wells allows us to build a portfolio of upstream 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).
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We aim to partner with energy entrepreneurs who are experts within concentrated areas and back them with sufficient capital to develop a defined project. In these partnerships, we account for a significant majority of the capital at risk, so we have significant control over acquisition costs and strategy, development costs, timing and rig schedules, and well design.
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We, and Grey Rock Administration, LLC (the "Manager") which supplies land, accounting, engineering, finance, and other back-office services to us in connection with continued management of the Properties contributed to us as part of the Business Combination, employ a case-based recruiting process to identify talent that has both the ability and desire to have a positive impact on an organization but may have been restricted by the bureaucracy of larger companies.
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While it's unlikely that we would choose to do so, we also have a right to remove the operator of the position if need be and bring in a substitute operator for the asset. These partnerships resemble traditional energy private equity structures for the private operators as well as for Granite Ridge's investors.
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We then encourage, support, and incentivize our team to develop and implement ideas that make us better. Leverage Data : As an owner in over 3,100 gross wells under 66 operators across 7 states and 35 counties/parishes, we have an immense amount of data.
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Typically, we structure these transactions to have an economic interest in the wells that benefits the operator after certain return hurdles are met to incentivize and align the operator with our interest.
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We continually invest both human and financial capital to further develop our proprietary information systems to help us make better investment decisions faster. Source Deals Directly: While we evaluate marketed assets, we typically find higher risk-adjusted returns from aggregating multiple smaller transactions as opposed to buying larger marketed packages.
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Traditional Non-Operated Assets Our non-operated asset base is built by investing in minority interests which give us a right to participate on a proportionate basis alongside third-party operators who propose, drill, and operate the assets.
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While development offers a wider range of outcomes, we mitigate risk by partnering with experienced operators in proven areas and believe drilling offers superior risk-adjusted returns. Mitigate Price Risk : While we cannot remove commodity price risk, we seek opportunities to reduce volatility.
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Once we own an asset in our portfolio, we assess each well proposal on a case-by-case basis to see if the well meets our return thresholds based upon our estimates of production from such well, capital expenditures, operating costs, expected oil and gas prices, operator expertise, as well as other factors.
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With a diversified asset base and limited long-term contracts or drilling obligations (we elect to participate in drilling on a well-by-well basis), our business is built to maximize adaptability. Commit to Environmental Stewardship : As a non-operator, it is critical that we partner with operators that are proven and responsible environmental stewards.
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Our team uses an extensive proprietary data set to make these investment decisions. Given our acreage footprint and substantial number of well participations, we believe we can make reliably accurate decisions regarding the economics of participating in any proposed development project.
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In additional to the moral and ethical drivers, it is a prudent business decision because if an operator with poor ESG standards loses the social license to operate, we may end up with stranded inventory.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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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.
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.
Increasing attention to climate change, fuel conservation measures, alternative fuel requirements, incentives to conserve energy or use alternative energy sources, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets.
Increased attention to climate change, fuel conservation measures, alternative fuel requirements, incentives to conserve energy or use alternative energy sources, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets.
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; 42 Table of Contents • 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; • 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; • 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.
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; • 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; • 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.
Any acquisition involves other potential risks, including, among other things: • the validity of our assumptions about reserves, future production, revenues and costs; 28 Table of Contents • a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; • the ultimate value of any contingent consideration agreed to be paid in an acquisition; • the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; • “geological risk,” which refers to the risk that hydrocarbons may not be present or, if present, may not be recoverable economically; • an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and • an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
Any acquisition involves other potential risks, including, among other things: • the validity of our assumptions about reserves, future production, revenues and costs; • a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; • the ultimate value of any contingent consideration agreed to be paid in an acquisition; • the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; • “geological risk,” which refers to the risk that hydrocarbons may not be present or, if present, may not be recoverable economically; • an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and • an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
In addition, 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 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.
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 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 could cause a breach of our systems or our data.
Although we and the Manager utilize various procedures and controls designed to monitor these threats and mitigate their exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.
Although we and the Manager utilize various procedures and controls designed to monitor these threats and mitigate exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.
For example, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) recently adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, the development of pre-production air monitoring plans at certain oil and gas facilities, enclosed combustion device testing, a methane intensity reduction requirement based on statewide volume of production and additional measures for reducing and eliminating emissions from pneumatic devices.
For example, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) have adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, the development of pre-production air monitoring plans at certain oil and gas facilities, enclosed combustion device testing, a methane intensity reduction requirement based on statewide volume of production and additional measures for reducing and eliminating emissions from pneumatic devices.
In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals.
In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces demand for corporate transparency and a demonstrated commitment to sustainability goals.
As such, we are eligible for and take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including, but not limited to, (i) not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, (ii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and (iii) exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.
As such, we are eligible for and take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth 38 Table of Contents companies for as long as we continue to be an emerging growth company, including, but not limited to, (i) not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, (ii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and (iii) exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.
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.
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.
Under these rules, a listed company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements, including: • the requirement that a majority of our Board of Directors consist of independent directors; 41 Table of Contents • the requirement that our director nominations be made, or recommended to the full Board of Directors, by our independent directors or by a nominations committee that is comprised entirely of independent directors and that we adopt a written charter or board resolution addressing the nominations process; and • the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
Under these rules, a listed company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements, including: • the requirement that a majority of our Board of Directors consist of independent directors; • the requirement that our director nominations be made, or recommended to the full Board of Directors, by our independent directors or by a nominations committee that is comprised entirely of independent directors and that we adopt a written charter or board resolution addressing the nominations process; and • the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.
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.
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.
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.
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.
Similar protections are afforded to migratory birds under the Migratory Bird Treaty Act (“MBTA”) and bald and golden eagles under the Bald and Golden Eagle Protection Act (“BGEPA”); 32 Table of Contents • the EPCRA, which requires certain facilities to report toxic chemical uses, inventories, and releases and to disseminate such information to local emergency planning committees and response departments; and • the OSHA and comparable state statutes, which impose regulations related to the protection of worker health and safety, including requiring employers to implement a hazard communication program and disseminate hazard information to employees.
Similar protections are afforded to migratory birds under the Migratory Bird Treaty Act (“MBTA”) and bald and golden eagles under the Bald and Golden Eagle Protection Act (“BGEPA”); • the EPCRA, which requires certain facilities to report toxic chemical uses, inventories, and releases and to disseminate such information to local emergency planning committees and response departments; and • the OSHA and comparable state statutes, which impose regulations related to the protection of worker health and safety, including requiring employers to implement a hazard communication program and disseminate hazard information to employees.
Officers and directors, including those nominated by the funds managed by Grey Rock or its affiliates, may become 40 Table of Contents aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to affiliates (subject to the MSA that sets forth an allocation of certain acquisition opportunities between us and funds associated with the Manager) or other businesses in which they have invested or are otherwise associated, in which case we may not become aware of or otherwise have the ability to pursue such opportunity.
Officers and directors, including those nominated by the funds managed by Grey Rock or its affiliates, may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to affiliates (subject to the MSA that sets forth an allocation of certain acquisition opportunities between us and funds associated with the Manager) or other businesses in which they have invested or are otherwise associated, in which case we may not become aware of or otherwise have the ability to pursue such opportunity.
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.
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.
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.
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.
Increasing attention to climate change and any related negative public perception regarding us and/or our industry, for example, may result in demand shifts for our products, increased litigation risk for us, and increased regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state, local, tribal and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.
Increased attention to climate change and any related negative public perception regarding us and/or our industry, for example, may result in demand shifts for our products, increased litigation risk for us, and increased, and sometimes conflicting, regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state, local, tribal and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.
On March 3, 2023, the Audit Committee of our Board of Directors concluded that our previously issued 37 Table of Contents unaudited condensed combined financial statements as of and for the three and nine month periods ended September 30, 2022, included in the Company’s Quarterly Report on Form 10-Q filed on November 14, 2022 were materially misstated.
On March 3, 2023, the Audit Committee of our Board of Directors concluded that our previously issued unaudited condensed combined financial statements as of and for the three and nine month periods ended September 30, 2022, included in the Company’s Quarterly Report on Form 10-Q filed on November 14, 2022 were materially misstated.
In 2020 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 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.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition. 27 Table of Contents Our future success depends on our ability to replace reserves that our operators produce.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition. Our future success depends on our ability to replace reserves that our operators produce.
If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected. 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. 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.
Also, institutional 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.
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.
“Risk Factors.” 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.” 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.
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, as occurred in 2020 in connection with the COVID-19 pandemic; • 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; 25 Table of Contents • 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; • 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.
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.
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.
In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and 23 Table of Contents transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area.
In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area.
Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other Company materials. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report, subsequent reports we file with the SEC or other Company materials. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
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 (such as the global COVID-19 coronavirus outbreak); • 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; 24 Table of Contents • the outbreak or escalation of military hostilities, including between Russia and Ukraine, Israel and Hamas, continued instability in the Middle East, including from the Houthi rebels in Yemen, 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, 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.
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.
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.
We may face additional risks and uncertainties 22 Table of Contents that are not presently known to us, or that we currently deem immaterial, which may also impair our business or financial condition. The following discussion should be read in conjunction with the financial statements and notes to the financial statements included herein.
We may face additional risks and uncertainties that are not presently known to us, or that we currently deem immaterial, which may also impair our business or financial condition. The following discussion should be read in conjunction with the financial statements and notes to the financial statements included herein.
Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Furthermore, 29 Table of Contents title issues may arise at a later date that were not initially detected in any title review or examination.
Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination.
In addition, the Company did not have effective controls over ITGC pertaining to user access management. In connection with the material misstatement and lack of effective user access controls, our Company’s management identified material weaknesses in our disclosure controls and internal control over financial reporting.
In addition, the Company did not have effective controls over Information Technology General Controls pertaining to user access management. In connection with the material misstatement and lack of effective user access controls, our Company’s management identified material weaknesses in our disclosure controls and internal control over financial reporting.
In addition, competitors may have greater financial, technical and personnel 26 Table of Contents resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before we or our operating partners can.
In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before we or our operating partners can.
The ongoing military conflicts between Ukraine and Russia, Israel and Hamas, and continued instability in the Middle East, including from the Houthi rebels in Yemen, 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, 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.
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.
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.
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 42% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2023.
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 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 could 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.
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.
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 is currently reviewing draft rules that would consider the cumulative impacts of air emissions from oil and gas projects in permitting decisions.
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.
To the extent not addressed by the MSA, we and the Manager intend to implement policies as necessary or appropriate to deal with such potential conflicts. 36 Table of Contents 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 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.
As of December 31, 2023, the Company had 5.7 million shares of common stock remaining available for future awards under the Incentive Plan.
As of December 31, 2024, the Company had 5.0 million shares of common stock remaining available for future awards under the Incentive Plan.
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.
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.
We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position.
We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance.
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.
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.
We have not, to our knowledge, experienced any material losses relating to cyberattacks; however, there can be no assurance that we will not suffer material losses in the future.
As of the date of this Annual Report, we have not, to our knowledge, experienced any material losses relating to cyberattacks; however, there can be no assurance that we will not suffer material losses in the future.
We are a “controlled company” under the corporate governance rules of the NYSE and, as a result, qualifies for exemptions from certain corporate governance requirements. We rely on certain of these exemptions, which means you will not have the same protections afforded to stockholders of companies that are subject to such requirements.
We are a “controlled company” under the corporate governance rules of the NYSE and, as a result, qualify for exemptions from certain corporate governance requirements. We rely on certain of these exemptions, which means you will not have the same protections afforded to stockholders of companies that are subject to such requirements. Grey Rock Energy Partners GP III, L.P.
Such restrictions and requirements could limit oil and gas well exploration and production activities underlying the investments or increase the cost of those activities if wastewater disposal options become limited (see Item 1.
Such restrictions and requirements could limit oil and gas well exploration and production activities underlying the investments or increase the cost of those activities if wastewater disposal options become limited (see Item 1. "Business - Governmental Regulation and Environmental Matters - Environmental Matters" for further discussion).
"Business - Governmental Regulation and Environmental Matters - Environmental Matters" for further discussion). 34 Table of Contents Specific climate legislation and regulation regarding emissions of carbon dioxide, methane, and other greenhouse gases may develop or be enacted, which could adversely affect the oil and gas industry and demand for the oil and gas produced from the Properties.
Specific climate legislation and regulation regarding emissions of carbon dioxide, methane, and other greenhouse gases may develop or be enacted, which could adversely affect the oil and gas industry and demand for the oil and gas produced from the Properties.
As of December 31, 2023, we had leases that were not developed that represented 5,498 net acres potentially expiring in 2024, 1,459 net acres potentially expiring in 2025 and 491 net acres potentially expiring in 2026 and beyond. We could experience periods of higher costs as activity levels fluctuate or if commodity prices rise.
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.
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.
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.
These risks are heightened in a low commodity price environment, which may present significant challenges to our operators. The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital.
The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital.
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.
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.
ESG goals and programs, which may include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and stakeholders across the industry, and companies without robust ESG programs may find access to capital and investors more challenging in the future.
ESG programs and goals, which are often aspirational, and which may include voluntary targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing, and sometimes conflicting, focus of certain investors and stakeholders, and companies that are perceived to be ESG laggards or are without robust ESG programs may find access to capital and investors more challenging in the future.
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.
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.
Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance. 31 Table of Contents Additionally, as cyberattacks become more sophisticated, we may incur significant cost to upgrade or enhance our security measures and procedures to protect against such cyberattacks.
Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.
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.
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.
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.
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.
In addition, the United States and other countries have imposed sanctions on Russia which increases the risk that Russia, as a retaliatory action, may launch cyberattacks against the United States, its government, infrastructure and businesses.
In addition, the United States and other countries have imposed sanctions on Russia which increases the risk that Russia, as a retaliatory action, may launch cyberattacks against the United States, its government, infrastructure and businesses. The extent and duration of the military action, sanctions and resulting market disruptions are impossible to predict, but could be substantial.
In such circumstances, the trading price of our securities may not recover and may experience a further decline.
Our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.
These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that it deems appropriate. 38 Table of Contents In addition, the shares of our common stock reserved for future issuance under the Granite Ridge 2022 Omnibus Incentive Plan (the “Incentive Plan”) will become eligible for sale in the public market once those shares are issued, subject to provisions relating to various vesting requirements and, in some cases, limitations on volume and manner of sale applicable to affiliates under Rule 144.
In addition, the shares of our common stock reserved for future issuance under the Granite Ridge 2022 Omnibus Incentive Plan (the “Incentive Plan”) will become eligible for sale in the public market once those shares are issued, subject to provisions relating to various vesting requirements and, in some cases, limitations on volume and manner of sale applicable to affiliates under Rule 144.
Hydraulic fracturing is an important and commonly used process that we anticipate will be engaged in by some or all opportunities in which it invests. Hydraulic fracturing is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The EPA has asserted authority over certain hydraulic-fracturing activities that use diesel fuel under the SDWA.
Hydraulic fracturing is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The EPA has asserted authority over certain hydraulic-fracturing activities that use diesel fuel under the SDWA.
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.
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.
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.
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.
Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable.
Our 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.
Environmental laws and regulations change frequently and tend to become more stringent over time, and the implementation of new, or the modification of existing, laws or regulations could adversely affect our business.
Environmental laws and regulations change frequently and tend to become more stringent over time, and the implementation of new, or the modification of existing, laws or regulations could adversely affect our business. For example, the regulation of methane from oil and gas facilities has been subject to uncertainty in recent years.
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.
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.
Price volatility may be greater if the public float and trading volume of our common stock is low. Any of the factors listed below could have a material adverse effect on your investment. Our securities may trade at prices significantly below the price you paid for them.
The trading price of our securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Price volatility may be greater if the public float and trading volume of our common stock is low. Any of the factors listed below could have a material adverse effect on your investment.
We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.
This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. We conduct business in a highly competitive industry. The oil and natural gas industry is highly competitive.
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. The relative lack of public company experience by our management team may put us at a competitive disadvantage.
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, 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.
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.
We may experience production interruptions for which we do not have production interruption insurance. 30 Table of Contents We intend to reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions.
We intend to reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.
Any of these impacts, or any other impacts resulting from the factors described above or other related or similar factors, could have material adverse impacts on our liquidity and our business, financial condition or results of operations. Item 1B. Unresolved Staff Comments None. 44 Table of Contents
Any of these impacts, or any other impacts resulting from the factors described above or other related or similar factors, could have material adverse impacts on our liquidity and our business, financial condition or results of operations. Our operations and financial performance may be negatively affected directly or indirectly by changes in trade policies and tariffs.
Access to funding sources and other credit arrangements could be significantly impaired by factors that affect the financial services industry or economy in general.
Borrowers under credit agreements, letters of credit and certain other financial instruments with any financial institution that is placed into receivership by the FDIC may be unable to access undrawn amounts thereunder. Access to funding sources and other credit arrangements could be significantly impaired by factors that affect the financial services industry or economy in general.
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.
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.
State rules and regulations such as these could significantly increase the costs to develop and operate the Properties, result in a delay in operations or decreased production, and may affect acquisition costs. 33 Table of Contents We anticipate that hydraulic fracturing will be engaged in by some or all opportunities in which we invest, which could be adversely affected by regulatory initiatives related to hydraulic fracturing.
State rules and regulations such as these could significantly increase the costs to develop and operate the Properties, result in a delay in operations or decreased production, and may affect acquisition costs.
In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage.
No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations.
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.
A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business.
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.
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.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeCompany management meets as needed with relevant employees of the Manager to discuss cybersecurity risks and incident trends and escalates them, as appropriate, to the Audit Committee.
Biggest changeCompany management, including our Chief Financial Officer, meets as needed with relevant employees of the Manager, who collectively have over ten years of experience in managing cybersecurity related issues on behalf of the Manager, to discuss cybersecurity risks and incident trends and escalate them, as appropriate, to the Audit Committee.
The Manager engages an independent cybersecurity vendor to review, assess, and make recommendations regarding our information security program and information technology strategic plan. We recognize that third-party service providers introduce cybersecurity risks. In an effort to mitigate these risks, before engaging with any third-party cybersecurity service provider, we conduct due diligence to evaluate their cybersecurity capabilities.
We and the Manager engage an independent cybersecurity vendor to review, assess, and make recommendations regarding our information security program and information technology strategic plan. We recognize that third-party service providers introduce cybersecurity risks. In an effort to mitigate these risks, before engaging with any third-party cybersecurity service provider, we conduct due diligence to evaluate their cybersecurity capabilities.
While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. See Item 1A. “Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our information technology systems.
While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. See Item 1A. “Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our or our operators’ information and operational technology systems.
However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our information technology systems could have significant consequences to the business.
However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our or our operators’ information or operational technology systems could have significant consequences to the business.
An employee of the Manager is responsible for day to day oversight of our cybersecurity risks and management of our cybersecurity vendor, and that employee escalates higher business cybersecurity risks to the Audit Committee or the Board as appropriate.
An employee of the Manager is responsible for day to day oversight of our cybersecurity risks and management of our cybersecurity vendor, and that employee escalates cybersecurity risks to the Audit Committee or the Board as appropriate.
Impact of Risks from Cybersecurity Threats As of the date of this Annual Report, though the Company and our service provider have experienced certain minor cybersecurity incidents, we are not aware of any previous cybersecurity threats or incidents that may have materially affected or are reasonably likely to materially affect the Company.
Impact of Risks from Cybersecurity Threats As of the date of this Annual Report, though the Company and our service providers have experienced certain cybersecurity incidents, we are not aware of any risks from cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations, or financial condition.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeDecember 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 The following table summarizes our cumulative gross and net productive oil and natural gas wells by basin at December 31, 2021: December 31, 2021 Gross Productive Wells Net Productive Wells Oil Natural Gas Total Oil Natural Gas Total Permian 307 1 308 26.09 0.19 26.28 Eagle Ford 95 72 167 16.38 3.80 20.18 Bakken 866 1 867 35.96 0.20 36.16 Haynesville — 53 53 — 9.43 9.43 DJ 557 68 625 14.50 2.09 16.59 Total 1,825 195 2,020 92.93 15.71 108.64 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, 2023.
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.
The following discussion of our properties should be read in conjunction with the accompanying audited consolidated financial statements and related notes included elsewhere in this Annual 45 Table of Contents 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 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.
We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the 46 Table of Contents Standardized Measure of discounted future net cash flows.
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.
In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have been commenced. While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there can be no guarantee they can do so.
In addition, our leases typically provide that the lease does not expire at the end of the primary term if drilling operations have been commenced. While we generally expect to establish production from most of our acreage prior to expiration of the applicable lease terms, there can be no guarantee we can do so.
The Manager’s internal controls over the reserves estimation process includes inter-departmental verification of input data into the Manager’s reserves evaluation software such as, but not limited to the following: • Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in the Manager’s reserves database; • Review of working interests and net revenue interests in the Manager’s reserves database against the Manager’s well ownership system; • Review of historical realized prices and differentials from index prices as compared to the differentials used in the Manager’s reserves database; • Review of updated projected capital costs for upcoming projects; • Review of internal reserve estimates by well and by area by the Manager’s reservoir engineers; • Discussion of material reserve variances among the Manager’s reservoir engineer and our executive management; and • Review of a preliminary copy of the reserve report by our management.
The Manager’s internal controls over the reserves estimation process includes inter-departmental verification of input data into the Manager’s reserves evaluation software such as, but not limited to the following: • Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in the Manager’s reserves database; • Review of working interests and net revenue interests in the Manager’s reserves database against the Manager’s well ownership system; • Review of historical realized prices and differentials from index prices as compared to the differentials used in the Manager’s reserves database; • Review of updated projected capital costs for upcoming projects; • Review of reserve estimates, inclusive of decline curves, by well and by area by the Manager’s reservoir engineers; • Discussion of material reserve variances among the Manager’s reservoir engineer and our executive management; and • Review of a preliminary copy of the reserve report by our management.
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 2023 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 2024 Reserve Report is Mr. Nathan Shahan.
Drilling and Development Activities The following table sets forth the number of gross and net productive wells drilled in the years ended December 31, 2023, 2022 and 2021. 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, 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.
In preparing its reports, NSAI evaluated properties representing all of our proved reserves at December 31, 2023 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
In preparing its reports, 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.
The following table provides a reconciliation of the pre-tax PV10% value of our SEC Pricing Proved Reserves as of December 31, 2023, 2022 and 2021 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, 2024, 2023 and 2022 to the Standardized Measure of Discounted Future Net Cash Flows.
With 72% 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 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.
Estimated Net Proved Reserves The tables below summarize our estimated net proved reserves at December 31, 2023, 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, 2024, based on reports prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our third-party independent reserve engineers.
The Manager’s EVP — 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 20 years of oil and gas experience, with more than 15 years focused on reservoir engineering.
In addition, estimates of reserves are subject to revision based 48 Table of Contents upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material.
In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material.
(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 $22.7 million as of December 31, 2023. 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 $23.9 million as of December 31, 2024. See “Reconciliation of PV-10 to Standardized Measure” below.
In 2023, revisions of previous estimates decreased proved undeveloped reserves by 2,580 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 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.
Based on SEC pricing as of December 31, 2023, estimated future development costs required for the development of proved undeveloped reserves are projected to be approximately $343.9 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, 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.
A significant majority of our wells in the Permian, Bakken, and DJ Basins are classified as oil wells, 50 Table of Contents although they also produce natural gas and condensate. All of our wells in the Haynesville Basin are classified as natural gas wells. Our wells within the Eagle Ford Basin are classified as either oil or natural gas wells.
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.
See Note 2 of the Notes to the Consolidated Financial Statements for additional discussion of our proved reserves. Proved Undeveloped Reserves At December 31, 2023, we had approximately 22,361 MBoe of proved undeveloped reserves as compared to 19,648 MBoe at December 31, 2022.
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.
The Manager employs an internal reservoir engineering department which is led by the Manager’s Executive Vice President (EVP) — Engineering, who is responsible for overseeing the internal preparation of our reserves pursuant to the MSA.
The Manager employs an internal reservoir engineering department which is led by the Manager’s Partner - Engineering, who is responsible for overseeing the internal preparation of our reserves pursuant to the MSA.
All of our recorded proved undeveloped reserves are scheduled to be drilled within five years of the date of their initial recognition. 47 Table of Contents At December 31, 2023, the PV-10 value of our proved undeveloped reserves amounted to 28% of the PV-10 value of our total proved reserves. There are numerous uncertainties regarding the proved and undeveloped reserves.
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, 2023, we had 212 gross (15.99 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, 2023.
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.
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.
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.
Year Ended December 31, 2023 2022 2021 Net Production: Oil (MBbl) 4,162 3,656 3,413 Natural gas (MMcf) 28,266 21,351 14,861 Total (MBoe) (1) 8,873 7,215 5,890 Average Daily Production: Oil (Bbl) 11,404 10,016 9,351 Natural gas (Mcf) 77,442 58,496 40,715 Total (Boe) (1) 24,311 19,765 16,137 Average Sales Prices: Oil (per Bbl) $ 76.18 $ 92.50 $ 63.70 Natural gas and related product sales (per Mcf) 2.72 7.46 5.04 Realized price (per Boe) 44.41 68.94 49.27 Costs and Expenses (per Boe): Lease operating expenses $ 6.82 $ 6.19 $ 4.47 Production and ad valorem taxes $ 3.12 $ 4.24 $ 3.07 Depletion and accretion $ 18.11 $ 14.66 $ 16.07 General and administrative $ 3.15 $ 1.97 $ 1.73 __________________________________________ (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, 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.
Standardized Measure Reconciliation December 31, (in thousands) 2023 2022 2021 Pre-tax present value of estimated future net revenues (Pre-Tax PV10%) $ 856,428 $ 1,559,123 $ 778,230 Future income taxes, discounted at 10% (134,520) (293,196) (3,879) Standardized measure of discounted future net cash flows $ 721,908 $ 1,265,927 $ 774,351 Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control.
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.
In 2023, proved undeveloped reserves increased by 11,144 MBoe as a result of new proved undeveloped locations added primarily in the Permian Basin. • Acquisition of Reserves . In 2023, acquisitions of proved undeveloped reserves of 4,207 MBoe were primarily attributable to the acquisitions of oil and natural gas properties in the Permian Basin.
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.
December 31, 2023 2022 2021 Gross Net Gross Net Gross Net Productive development wells 314 24.55 265 20.78 213 14.18 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 years ended December 31, 2023.
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.
To estimate economically recoverable oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.
To estimate economically recoverable oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.
A reconciliation of the change in proved undeveloped reserves during 2023 is as follows: MBoe Estimated proved undeveloped reserves at December 31, 2022 19,648 Extensions and discoveries 11,144 Acquisition of reserves 4,207 Divestiture of reserves (496) Conversion to proved developed reserves (9,562) Revisions of previous estimates (2,580) Estimated proved undeveloped reserves at December 31, 2023 22,361 __________________________________________ • Extensions and discoveries .
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 .
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.
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.
See Note 5 of the Notes to Consolidated Financial Statements for additional discussion of acquisitions during 2023. • Conversion to proved developed reserves. In 2023, development of oil and natural gas properties resulted in the conversion of 9,562 MBoe from proved undeveloped reserves to proved developed 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.
The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2023: SEC Pricing Proved Reserves (1) Reserve Volumes PV-10 (3) Reserve Category Oil (MBbls) Natural Gas (MMcf) Total (MBoe) (2) % Amount (in thousands) % Proved developed producing 14,947 96,746 31,071 58 % $ 616,220 72 % Proved developed non-producing 25 87 40 — % 1,218 — % Proved undeveloped 12,345 60,095 22,361 42 % 238,990 28 % Total proved 27,317 156,928 53,472 100 % $ 856,428 100 % Total proved developed 14,972 96,833 31,111 58 % $ 617,438 72 % __________________________________________ (1) The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2023 based on average prices of $78.21 per barrel of oil and $2.64 per MMbtu of natural gas.
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.
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.
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.
The following table sets forth the future expiration amounts of our gross and net undeveloped acreage at December 31, 2023 by area: 2024 2025 2026 and Thereafter Gross Net Gross Net Gross Net Permian 2,245 2,147 3,352 1,229 1,680 455 Eagle Ford (1) 6,305 2,845 — — 282 28 Bakken 320 320 — — — — Haynesville 4,549 186 3,859 230 854 8 DJ — — — — — — Total: 13,419 5,498 7,211 1,459 2,816 491 __________________________________________ (1) These acres are subject to continuous drilling obligations.
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.
Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Permian 44,738 6,462 6,166 3,131 50,904 9,593 Eagle Ford 24,025 3,936 6,587 2,873 30,612 6,809 Bakken 169,897 13,167 320 320 170,217 13,487 Haynesville 49,248 5,077 9,262 425 58,510 5,502 DJ 21,564 2,086 — — 21,564 2,086 Total: 309,472 30,728 22,335 6,749 331,807 37,477 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 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.
Removed
During the year ended December 31, 2023, we incurred development costs of approximately $79 million related to these locations. • Revisions of previous estimates .
Added
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 .
Added
Our wells within the Eagle Ford Basin are classified as either oil or natural gas wells.

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, 2023. 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, 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

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeDividend Policy We expect that Granite Ridge will pay quarterly cash dividends totaling approximately $60 million per fiscal year. For information about dividends, see "Item 8. Financial Statements and Supplementary Data." Repurchases of Equity Securities In December 2022, the Company announced that its Board of Directors approved a share repurchase program for up to $50.0 million of the Company’s common.
Biggest changeDividend Policy 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 of $0.11 per share (or $0.44 per share per fiscal year). For information about dividends, see "Item 8.
Item 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 symbols “GRNT”. As of March 5, 2024, there were 74 holders of record of our common stock.
Item 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.
The following table sets forth our share repurchase activity for each 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, 2023 - October 31, 2023 1,009,656 $ 6.14 1,009,656 $ — November 1, 2023 - November 30, 2023 1,316,575 $ 6.15 1,316,575 $ — December 1, 2023 - December 31, 2023 1,510,969 $ 6.10 1,510,969 $ — Item 6. [RESERVED]
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]
Removed
The stock repurchase program terminated on December 31, 2023.
Added
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.

Item 7. Management's Discussion & Analysis

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

78 edited+16 added−48 removed52 unchanged
Biggest changeGain (loss) on derivative contracts is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end. 55 Table of Contents 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.
Biggest changeSelected 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.
In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our proved properties for impairment. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record depletion and accretion expense would increase, reducing net income.
In addition, a decline in proved reserve estimates may impact the outcome of our assessment of proved properties for impairment. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record depletion and accretion expense would increase, reducing net income.
Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the basis differential from market on a basin-by-basin basis. The expected sales volumes and prices for these properties are estimated and recorded within Revenue receivable line item in the accompanying consolidated balance sheets.
Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the basis differential from market on a basin-by-basin basis. The expected sales volumes and prices for these properties are estimated and recorded within the revenue receivable line item in the accompanying consolidated balance sheets.
Base rate loans now 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.
Base 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.
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 will pay the Manager an annual services fee of $10.0 million and will 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. • 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.
Impairment of Oil and Natural Gas Properties All of our long-lived assets are monitored for potential impairment annually, or when circumstances indicate that the carrying value of an asset may be greater than management’s estimates of its future net cash flows, including cash flows from proved reserves, risk-adjusted probable and possible reserves, and integrated assets.
Impairment of Oil and Natural Gas Properties All of our long-lived assets are monitored for potential impairment annually, or when circumstances indicate that the carrying value of an asset may be greater than management’s estimates of its future net cash flows, including cash flows from proved reserves and risk-adjusted probable and possible reserves.
The Credit Agreement also contains certain financial covenants, including the maintenance of the following financial ratios: (i) a Current Ratio, (as defined in the Credit Agreement) of not less than 1.00 to 1.00 as of the last day of each fiscal quarter; and (ii) a leverage ratio, which is the ratio of Consolidated Total Debt to EBITDAX (each as defined in the Credit Agreement), of not greater than 3.00 to 1.00 as of the last day of each fiscal quarter.
The Credit Agreement contains certain financial covenants, including the maintenance of the following financial ratios: (i) a leverage ratio, which is the ratio of Consolidated Total Debt to EBITDAX (each as defined in the Credit Agreement), of not greater than 3.00 to 1.00 as of the last day of each fiscal quarter, and (ii) a Current Ratio (as defined in the Credit Agreement), of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.
This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community. 59 Table of Contents Oil, Natural Gas and Related Product Sales Our revenues vary from year to year primarily due to changes in realized commodity prices and production volumes.
This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community. 57 Table of Contents Oil, Natural Gas and Related Product Sales Our revenues vary from year to year primarily due to changes in realized commodity prices and production volumes.
Cash Flows from Financing Activities 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.
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.
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, 2023. 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, 2024. Oil and Natural Gas Properties Oil and natural gas producing activities are accounted for under the successful efforts method of accounting.
Because of normal production declines, increased or decreased drilling activities, fluctuations in 58 Table of Contents commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.
Because of normal production declines, increased or decreased drilling activities, fluctuations in 56 Table of Contents commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.
Cash Flows from Investing Activities 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.
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.
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.
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.
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.
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.
From time to time, we expect that we may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. 56 Table of Contents Prices for various quantities of natural gas and oil that we produce significantly impact our revenues and cash flows.
From time to time, we expect that we may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. Prices for various quantities of natural gas and oil that we produce significantly impact our revenues and cash flows.
Further, these estimates and other factors, including those outside of management’s control could have significant adverse impact to the financial condition, results of operations and cash flows of the Company. 66 Table of Contents Use of Estimates The preparation of financial statements under U.S.
Further, these estimates and other factors, including those outside of management’s control could have significant adverse impact to the financial condition, results of operations and cash flows of the Company. Use of Estimates The preparation of financial statements under U.S.
In addition, any unfavorable adjustments to some of the 67 Table of Contents above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.
In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.
As a result of the First Amendment, SOFR loans now bear interest at SOFR plus an applicable margin ranging from 300 to 400 basis points, depending on the percentage of the borrowing base utilized, plus an additional 10, 15 or 20 basis point credit spread adjustment for a one, three or six month interest period, respectively.
SOFR loans bear interest at SOFR plus an applicable margin ranging from 300 to 400 basis points, depending on the percentage of the borrowing base utilized, plus an additional 10, 15 or 20 basis point credit spread adjustment for a one, three, or six month interest period, respectively.
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, cash flows from integrated assets 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 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.
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, 2023, approximately 42% 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, 2024, approximately 28% of our total proved reserves were categorized as proved undeveloped reserves.
As of December 31, 2023, 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, 2023, we had $110.0 million of debt outstanding under our Credit Agreement.
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.
However, we may seek additional access to capital and liquidity. We cannot assure you that any additional capital will be available to us on favorable terms or at all. Capital commitments Our recent capital commitments have been to fund the development and acquisition of oil and natural gas properties.
We cannot assure you that any additional capital will be available to us on favorable terms or at all. Capital commitments Our recent capital commitments have been to fund the development and acquisition of oil and natural gas properties.
Our natural gas price differential during 2023, 2022 and 2021 was $0.19 per Mcf, $0.91 per Mcf and $1.32 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 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.
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 $5.3 million for the year ended December 31, 2023 compared to $2.0 million for 2022.
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.
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 2023, 2022 and 2021 was $(1.40) per barrel, $(1.89) per barrel and $(5.00) 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 2024, 2023 and 2022 was $(3.57) per barrel, $(1.40) per barrel and $(1.89) per barrel, respectively.
On February 15, 2024, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2024 that will be paid on March 15, 2024 to stockholders of record as of March 1, 2024. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.
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.
If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets.
If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value, using the income or market approach, and the carrying value of the assets.
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 year ended December 31, 2023, we recognized impairment expense of $26.5 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.
We had $140.1 million of liquidity as of December 31, 2023, consisting of $129.7 million of committed borrowing availability under the Credit Agreement and $10.4 million of cash on hand.
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.
Cash Flows Our cash flows for the years ended December 31, 2023, 2022 and 2021 are presented below: Year Ended December 31, (in thousands) 2023 2022 2021 Net cash provided by operating activities $ 302,867 $ 346,389 $ 181,181 Net cash used in investing activities (356,676) (230,562) (186,024) Net cash provided by (used in) financing activities 13,406 (76,848) 8,489 Net change in cash $ (40,403) $ 38,979 $ 3,646 Cash Flows from 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) 63 Table of Contents costs of our general and administrative activities and (v) interest expense.
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.
Fund I, Fund II and Fund III are collectively referred to herein as, the “Funds.” Business Combination On October 24, 2022 (the “Closing Date”), Granite Ridge and 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”).
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”).
As of December 31, 2023, the Company had repurchased a total of 5,677,627 shares since the inception of the program at an aggregate cost of $36.3 million.
During the year ended December 31, 2023, the Company repurchased 5,651,707 shares under the program at an aggregate cost of $36.1 million. As of December 31, 2023, the Company had repurchased a total of 5,677,627 shares since the inception of the program at an aggregate cost of $36.3 million.
Our net cash provided by operating activities included a benefit of $4.6 million and a reduction of $17.2 million for the years ended December 31, 2023 and 2022, 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 $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.
During the years ended December 31, 2023, 2022, and 2021, we recognized depletion expense of $160.2 million, $105.3 million and $94.2 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 for and produce higher cost fields.
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.
Common stock dividends We paid dividends of $58.6 million, or $0.44 per share, and $10.7 million, or $0.08 per share during the years ended December 31, 2023 and 2022, respectively.
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.
See Note 8 to the Notes to the Consolidated Financial Statements for additional information. 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.
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.
Ad valorem taxes decreased during the year ended December 31, 2023 as compared to 2022, primarily due to additional wells drilled and completed and new wells acquired. Depletion and Accretion Depletion and accretion was $160.7 million ($18.11 per Boe) for the year ended December 31, 2023, an increase of 52% from $105.8 million ($14.66 per Boe) in 2022.
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.
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.
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.
As a percentage of oil and natural gas sales, our production taxes were 6% and 5% in 2023 and 2022, respectively. 60 Table of Contents Production taxes generally fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.
Production taxes generally fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.
In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. Depletion and accretion expense Depletion and accretion include the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas.
We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. Depletion and accretion expense Depletion and accretion include the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas.
Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.
Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur. Revenue Recognition The Company’s revenues are derived from its interests in the sale of oil and natural gas production.
For similar operating and financial data and discussion of our 2022 results compared to our 2021 results, refer to “Item 7. 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, 2022, which was filed with the SEC on March 27, 2023.
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.
For the year ended December 31, 2022, our net cash used in investing activities was $230.6 million, which consisted primarily of $185.5 million of capital expenditures for oil and natural gas properties and $49.2 million of acquisitions of oil and natural gas properties.
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.
See Note 10 of the Notes to the Consolidated Financial Statements. 65 Table of Contents • We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts.
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.
For additional information on the Business Combination See Note 1 in the Notes to the Consolidated Financial Statements. 54 Table of Contents Source of Our Revenues We derive our revenues from our interests in the sale of oil and natural gas production.
For additional information on the Business Combination See Note 1 in the Notes to the Consolidated Financial Statements. Source of Our Revenues We derive our revenues from our interests in the sale of oil and natural gas production. Revenues are a function of production, the prevailing market price at the time of sale, oil quality, and transportation costs to market.
General and Administrative The following table provides components of our general and administrative expenses for the years ended December 31, 2023 and 2022: Year Ended December 31, (in thousands) 2023 2022 General and administrative expenses $ 25,758 $ 14,223 Non-cash stock-based compensation 2,162 — Total general and administrative expenses $ 27,920 $ 14,223 Total general and administrative expenses were $27.9 million ($3.15 per Boe) for the year ended December 31, 2023, an increase of 96% from $14.2 million ($1.97 per Boe) in 2022.
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.
The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties.
Any significant variance in these assumptions could materially affect the estimated quantity and value of our 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.
Year Ended December 31, 2023 2022 Net Sales (in thousands): Oil sales $ 317,099 $ 338,163 Natural gas and related product sales 76,970 159,254 Revenues 394,069 497,417 Net Production: Oil (MBbl) 4,162 3,656 Natural gas (MMcf) 28,266 21,351 Total (MBoe) (1) 8,873 7,215 Average Daily Production: Oil (Bbl) 11,404 10,016 Natural gas (Mcf) 77,442 58,496 Total (Boe) (1) 24,311 19,765 Average Sales Prices: Oil (per Bbl) $ 76.18 $ 92.50 Effect of gain (loss) on settled oil derivatives on average price (per Bbl) 1.10 (6.48) Oil net of settled oil derivatives (per Bbl) (2) 77.28 86.02 Natural gas and related product sales (per Mcf) 2.72 7.46 Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf) 0.65 (0.88) Natural gas and related product sales net of settled natural gas derivatives (per Mcf) (2) 3.37 6.58 Realized price on a Boe basis excluding settled commodity derivatives 44.41 68.94 Effect of gain (loss) on settled commodity derivatives on average price (per Boe) 2.58 (5.88) Realized price on a Boe basis including settled commodity derivatives (2) 46.99 63.06 Operating Expenses (in thousands): Lease operating expenses $ 60,521 $ 44,678 Production and ad valorem taxes 27,707 30,619 Depletion and accretion expense 160,662 105,752 Impairments of long-lived assets 26,496 — General and administrative 27,920 14,223 Costs and Expenses (per Boe): Lease operating expenses $ 6.82 $ 6.19 Production and ad valorem taxes $ 3.12 $ 4.24 Depletion and accretion $ 18.11 $ 14.66 Impairments of long-lived assets $ 2.99 $ — General and administrative $ 3.15 $ 1.97 Net Producing Wells at Period-End: 176.50 132.88 __________________________________________ (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, 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.
Granite Ridge Credit Agreement On October 24, 2022, the Funds terminated their revolving credit facilities, and we entered into the Credit Agreement among us, as borrower, Texas Capital Bank, as administrative agent, and the lenders from time to time party thereto. The Credit Agreement has a maturity of five years from the effective date thereof.
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.
Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. As of December 31, 2023, we had $110.0 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. 60 Table of Contents As of December 31, 2024, we had $205.0 million of debt outstanding under our Credit Agreement.
See Note 13 in the Notes to the Consolidated Financial Statements for additional information on stock-based compensation. 61 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, 2023 and 2022: Year Ended December 31, (in thousands) 2023 2022 Gain (loss) on commodity derivatives Oil derivatives $ 6,459 $ (14,985) Natural gas derivatives 19,085 (10,339) Total $ 25,544 $ (25,324) The following table represents our net cash receipts from (payments on) derivatives for the years ended December 31, 2023 and 2022: Year Ended December 31, (in thousands) 2023 2022 Net cash receipts from (payments on) commodity derivatives Oil derivatives $ 4,576 $ (23,695) Natural gas derivatives 18,319 (18,742) Total $ 22,895 $ (42,437) 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 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.
Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans.
Borrowings under the Credit Agreement may be base rate loans or secured overnight financing rate (“SOFR”) loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans.
Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. A portion of our operating cost components are variable and change in correlation to production levels.
Expenses for field employees’ salaries, saltwater disposal, repairs and maintenance comprise the most significant portion of our lease operating expenses. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period.
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. Income Tax Expense (Benefit) We recorded an income tax expense of $24.5 million and $12.9 million in 2023 and 2022, respectively.
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.
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.
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.
Gain (Loss) on Derivatives – Common Stock Warrants We recognized a loss of $5.7 million and a gain of $0.4 million during 2023 and 2022, respectively, from the change in fair value of the warrant liability.
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.
On November 7, 2023, we entered into a First Amendment to the Credit Agreement (the "First Amendment") which, among other things, decreased the borrowing base from $325.0 million to $275.0 million and increased the aggregate elected commitments from $150.0 million to $240.0 million.
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.
As of December 31, 2023, we owned an interest in 2,826 gross (176.50 net) producing wells, 309,472 gross (30,728 net) developed acres, and 22,335 gross (6,749 net) undeveloped acres, all located in the United States. Our average daily production for the year ended December 31, 2023 was 24,311 Boe per day.
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.
Year Ended December 31, 2023 2022 Net Production: Oil (MBbl) Permian 2,656 2,347 Eagle Ford 529 467 Bakken 665 616 Haynesville — — DJ 312 226 Total 4,162 3,656 Natural Gas (MMcf) Permian 9,146 5,957 Eagle Ford 3,055 2,001 Bakken 1,105 1,101 Haynesville 12,251 10,161 DJ 2,709 2,131 Total 28,266 21,351 Total (MBoe) Permian 4,180 3,339 Eagle Ford 1,038 801 Bakken 849 800 Haynesville 2,042 1,694 DJ 764 581 Total 8,873 7,215 Lease Operating Expenses Lease operating expenses were $60.5 million ($6.82 per Boe) for the year ended December 31, 2023, an increase of 35% from $44.7 million ($6.19 per Boe) for 2022.
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.
Actual results and the timing of events may differ materially from those contained in these forward ‑ looking statements due to a number of factors.
The following discussion contains “ forward ‑ looking statements ” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward ‑ looking statements due to a number of factors.
At December 31, 2023, we had $110.0 million of outstanding debt and $0.3 million of letters of credit issued and outstanding under our Credit Agreement, resulting in committed borrowing availability of $129.7 million.
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.
The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors.
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.
Production from oil and gas properties increased because of drilling success and the acquisition of additional net revenue interests. This increase in 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 132.88 net wells in 2022 to 176.50 net wells in 2023.
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.
We did not sell any shares of our common stock in the Secondary Offering and did not receive any proceeds from the Secondary Offering. 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, 2023 and 2022.
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.
See Note 7 to the Notes to the Consolidated Financial Statements for additional discussion of income taxes. 62 Table of Contents 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.
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.
We also pay a commitment fee on unused elected commitment amounts under our facility of 50 basis points. We may repay any amounts borrowed under the Credit Agreement prior to the maturity date without any premium or penalty.
The Company may repay any amounts borrowed under the Credit Agreement prior to the maturity date without any premium or penalty.
The Credit 64 Table of Contents Agreement is guaranteed by our restricted subsidiaries and is secured by a first priority mortgage and security interest in substantially all of our assets and of our restricted subsidiaries. Borrowings under the Credit Agreement may be base rate loans or secured overnight financing rate (“SOFR”) loans.
The Credit Agreement is guaranteed by the restricted subsidiaries of Granite Ridge and is secured by a first priority mortgage and security interest in substantially all of the Company's and its restricted subsidiaries' assets.
The effective income tax rate differs from the statutory rate in 2023 primarily due to the impact of certain discrete items and state income taxes. The effective income tax rate differs from the statutory rate in 2022 primarily due to the allocation of profits and losses to the partners of the Funds for the period prior to the Business Combination.
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.
The $43.5 million decrease in operating cash flows during the year ended December 31, 2023 as compared to 2022 was primarily due to the decrease in oil and natural gas sales and higher operating costs, partially offset by $22.9 million of settlements received from commodity derivatives during 2023, as compared to $42.4 million of settlements paid on commodity derivatives during 2022.
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.
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. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions.
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.
The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2023, 2022 and 2021.
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.
We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
We use derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations.
Production taxes were $24.9 million ($2.81 per Boe) for the year ended December 31, 2023 compared to $26.9 million ($3.73 per Boe) for 2022.
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.
For the year ended December 31, 2022, our net cash used in financing activities was $76.8 million. We made net payments of $51.1 million on our credit facilities and paid $10.7 million of dividends during 2022.
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.
In 2023, our oil and natural gas sales decreased 21% from 2022, driven by the decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by the increase in production. The lower average realized prices were driven by lower average NYMEX oil and natural gas prices.
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.
Overview Granite Ridge is a scaled, non-operated oil and gas exploration and production company. We own a portfolio of wells and top-tier acreage across the Permian and four other prolific unconventional basins across the United States.
Overview Granite Ridge is a scaled energy company which aims to provide shareholders with exposure similar to energy private equity through operated partnerships and traditional non-operated assets. We own assets in six prolific unconventional basins across the United States.
Principal Components of Our Cost Structure Lease operating expenses Lease operating expenses are the costs incurred in the operation of producing properties, including workover costs. Expenses for field employees’ salaries, saltwater disposal, repairs and maintenance comprise the most significant portion of our lease operating expenses.
The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements. Principal Components of Our Cost Structure Lease operating expenses Lease operating expenses are the costs incurred in the operation of producing properties, including workover costs.
On November 7, 2023, Granite Ridge amended the Credit Agreement which, among other things, decreased the borrowing base from $325.0 million to $275.0 million and provided for aggregate elected commitments of $240.0 million, and amended the applicable margin charged on the loans and other obligations under the Credit Agreement.
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.
Removed
The information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the following: (1) as it pertains to periods prior to the completion of the Business Combination, the accounts of each of the Funds (as defined below) and all related wholly owned subsidiaries, and Granite Ridge Resources, Inc.
Added
We aim to deliver a diversified portfolio with best-in-class full cycle returns by investing in a large number of high-graded opportunities developed by proven public and private operators. We focus on success as measured by total shareholder returns, which we seek to balance with a low leverage profile.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeInterest 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, 2023. 69 Table of Contents Item 8.
Biggest changeInterest 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.
The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $1.1 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.
The 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.
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.
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.
Interest Rate Risk At December 31, 2023, 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 $110.0 million outstanding under our Credit Agreement at December 31, 2023.
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.
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, 2023, a 10% increase in average commodity prices would have decreased the fair value of commodity derivatives by $10.4 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, 2024, a 10% increase in average commodity prices would have decreased the fair value of commodity derivatives by $19.3 million.

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