Granite Ridge Resources Inc

In this “Business” section, unless otherwise specified or the context otherwise requires, “Granite Ridge,” the “Company,” “we,” “us,” and “our” refer to Granite Ridge Resources, Inc. and its consolidated subsidiaries. The following discussion of our business should be read in conjunction with the accompanying audited consolidated financial statements and related notes included elsewhere in this Annual Report.

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. 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.

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.

Granite Ridge is a Delaware corporation, formed on May 9, 2022 to consummate the Business Combination (as defined below). On October 24, 2022 (the “Closing Date”), Granite Ridge and Executive Network Partnering Corporation, a Delaware corporation (“ENPC”) consummated a 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 GREP Holdings, LLC, a Delaware limited liability company (“GREP”).

Pursuant to the Business Combination Agreement, on the Closing Date, (i) ENPC Merger Sub merged with and into ENPC (the “ENPC Merger”), with ENPC surviving the ENPC Merger as a wholly-owned subsidiary of Granite Ridge and (ii) GREP Merger Sub merged with and into GREP (the “GREP Merger,” and together with the ENPC Merger, the “Mergers”), with GREP surviving the GREP Merger as a wholly-owned subsidiary of Granite Ridge (the transactions contemplated by the foregoing clauses (i) and (ii) the “Business Combination,” and together with the other transactions contemplated by the Business Combination Agreement, the “Transactions”). 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”). 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. The operators of our Properties include public exploration and production companies and experienced private companies.

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.

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. 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).

Maintain a Healthy Balance Sheet: Prudent balance sheet management is a core tenet of both our risk management and value-creation strategies. In a challenging commodity price environment, our goal is to maintain liquidity to capitalize on accretive opportunities and to stay comfortably within credit covenants across commodity price cycles.

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. 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. 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. 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. 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. 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. 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. 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.

Adapt: Be it from technology, macro events, political dynamics or investor sentiment, change is the only constant in the oil and gas industry. 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. 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.

Operating Areas

Permian

The Permian Basin extends from southeastern New Mexico into west Texas and is currently one of the most active drilling regions in the United States. The Permian Basin consists of mature legacy onshore oil and liquids-rich natural gas reservoirs. 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. 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, 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. 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, 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.

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. During the year ended December 31, 2023, operators completed 124 gross (2.85 net) wells in the DJ Basin.

Industry Operating Environment

The oil and natural gas industry is a global market impacted by many factors, including government regulations, particularly in the areas of taxation, energy, climate change and the environment, political and social developments in the Middle East and Russia, demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas as it is a primary heating source.

Oil and natural gas prices have been volatile and may continue to be volatile in the future. 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. If commodity prices decline, the cost of developing, completing, and operating a well may not decline in proportion to prices received for the production, resulting in higher operating and capital costs as a percentage of revenues.

Development

We primarily engage in oil and natural gas development and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. In addition, we acquire wellbore-only working interests in wells separate from the underlying leasehold interests from third parties unable or unwilling to participate in particular well proposals. We typically depend on drilling partners to propose, permit, and initiate the drilling of wells. Prior to commencing drilling, our operating partners are required to provide all owners of oil, natural gas, and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well proportionate to their pro-rata share of such interest within the spacing unit. We assess each participation opportunity in any given well on a case-by-case basis and expect to meet our return thresholds based upon our estimates of ultimate recoverable oil and natural gas from such well, forward curve pricing, expected oil and gas prices, expertise of the operator in such well, and completed well costs from each project, as well as other factors.

Historically, we have participated, pursuant to our working interests, in a vast majority of the wells proposed to us. However, declines in oil and natural gas prices typically reduce both the number of well proposals we receive and the proportion of well proposals in which we elect to participate. 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.

While we regularly have the right to take a portion of our production in kind, we typically elect to have our operating partners market and sell oil and natural gas produced from wells in which we have an interest. 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.

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 compete with other oil and natural gas exploration and production companies, some of which have substantially greater resources and may be able to pay more for exploratory prospects and productive oil and natural gas properties, and competition for our target asset classes is subject to increase in the future. Our larger or integrated competitors may be better able to absorb the burden of existing, as well as any changes to, federal, state, and local laws and regulations, which would adversely affect our competitive position. Our ability to acquire additional properties in the future is dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Marketing and Customers

The market for oil and natural gas produced from our Properties depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation and storage facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets. 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 operating partners include a variety of exploration and production companies, from large publicly traded companies to privately-owned companies.

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.

*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. The loss of any such operator could adversely affect revenues attributable to the Company’s assets in the short term.

Title to Properties

Our oil and natural gas properties are subject to customary royalty and other interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes, and other burdens, including other mineral encumbrances and restrictions. 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.

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.

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. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of our operating partners and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operating partners’ operations.

Principal Agreements Affecting Our Business

We generally do not own physical real estate but, instead, our assets are primarily comprised of leasehold interests subject to the terms and provisions of lease agreements that provide us with the right to participate in drilling and maintenance of wells in specific geographic areas. Lease arrangements that comprise our acreage positions are generally established using industry-standard terms that have been established and used in the oil and natural gas industry for many years. Many of our leases are or were acquired from other parties that obtained the original leasehold interest prior to our acquisition of the leasehold interest.

In general, our lease agreements stipulate three-year primary terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production is established, the leased acreage in the applicable spacing unit is considered developed acreage and is held by production or continuous drilling obligations. Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production and continuous drilling obligations are satisfied. 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.

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.

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.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration and production business and development and operation of the Properties are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. 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. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion, and production, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the current administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands. The effect of these regulations is to limit the amount of oil and natural gas that can be produced from the wells in which we participate and to limit the number of wells or the locations at which our operating partners can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties or other liabilities. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, and typically become more stringent over time, we are unable to predict the future cost or impact of our and our operating partners’ compliance with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and profitability. Additionally, unforeseen environmental incidents may occur on the Properties or past non-compliance with environmental laws or regulations may be discovered, resulting in unforeseen liabilities. Additional proposals, proceedings, and regulations that affect the oil and natural gas industry are regularly considered by Congress; the courts; federal regulatory agencies such as the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency, and the Bureau of Land Management; and state legislatures and regulatory authorities. We cannot predict when or whether any such proposals may become effective, the substance of those regulations, or the outcome of such proceedings. Therefore, we are unable to predict with certainty the future compliance costs or implications of compliance on profitability.

Regulation of Transportation of Oil

Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms, and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted, and market-based rates may be permitted in certain circumstances.

Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. On January 20, 2022, the FERC established a new price index for the five-year period which commenced on July 1, 2021.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect operations on the Properties in any way that is of material difference from those of our competitors who are similarly situated.

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. In Texas, when oil or natural gas pipelines operate at full capacity, access is generally governed by pro-rationing rules established by the Railroad Commission of Texas (“RRC”), in addition to certain pro-rationing provisions that may be set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operating partners to the same extent as to our similarly situated competitors.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.

Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. 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. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which our operating partners operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that is produced from wells in which we hold an interest, as well as the revenues we receive from sales of natural gas.

Environmental Matters

A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may: (i) require the acquisition of a permit or other authorization and procurement of financial assurance before construction or drilling commences and for certain other activities; (ii) limit or prohibit construction, drilling or other activities on certain lands lying within wilderness and other protected areas; and (iii) impose substantial liabilities for pollution resulting from our operations. Any noncompliance with these laws and regulations could subject us or any of our properties to material administrative, civil, or criminal penalties; investigatory or remedial obligations; injunctive relief; or other liabilities. 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.

The permits required for development and construction of and operations on the Properties may be subject to revocation, modification, and renewal by issuing authorities, and such permitting could cause delays in development, construction, or operation of the Properties, thus increasing costs and potentially affecting our profitability. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of our management, the operators of the Properties are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us or any of our properties or operating partners, as well as the oil and natural gas industry in general.

The federal Clean Air Act (“CAA”) and comparable state laws and regulations impose obligations related to the emission of air pollutants, including emissions from 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. Both existing CAA and state regulations, and any future regulations, may require pre-approval for the construction, expansion, or modification of certain facilities that produce, or which are expected to produce, air emissions. Such regulations may also impose stringent air permit requirements, limit natural gas venting and flaring activity, and require the use of specific equipment or technologies to control emissions. Under the CAA, the EPA has enacted final regulations requiring owners and operators of certain facilities that emit greenhouse gases above certain thresholds to report those emissions. The EPA has also promulgated regulations establishing construction and operating permit requirements for greenhouse gas emissions from stationary sources that already emit conventional pollutants (i.e., sulfur dioxide, particulate matter, nitrogen dioxide, carbon monoxide, ozone, and lead) above certain thresholds. Further, the CAA requires that owners and operators of stationary sources producing, processing, and storing extremely hazardous substances have a general duty to identify hazards associated with an accidental release, design and maintain a safe facility, and minimize the consequences of any releases that occur. The CAA further requires such facilities that handle more than threshold amounts of extremely hazardous substances to develop risk management plans intended to prevent and minimize impacts if releases do occur.

CAA regulations also include New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production, storage, transportation, and processing activities. These rules currently require all oil or natural gas wells that have been hydraulically fractured or refractured since November 30, 2016 to be completed using so-called “green completion” technology, which significantly reduces VOC emissions, and has the co-benefit of also limiting methane, a greenhouse gas. These regulations, referred to as NSPS Subpart OOOO and OOOOa, also apply to storage tanks and other equipment in the affected oil and natural gas industry segments, and, commencing with Subpart OOOOa, were designed to also limit methane from new and modified sources in the oil and gas sector. The EPA has since modified and rolled back various aspects of the rules, including removal of the transmission and storage sectors of the oil and gas industry from regulation and of the methane-specific standards for the production and processing segments of the industry. Subsequently, Congress partially overturned that rollback in June 2021. 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. 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. 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. Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief.

The federal Clean Water Act (“CWA”) and comparable state laws and regulations impose strict obligations related to discharges of pollutants and dredge and fill material into regulated bodies of water, including wetlands. The discharge of pollutants into regulated waters is prohibited except in accordance with a permit issued by the EPA, the United States Army Corps of Engineers (“USACE”), or state agency or tribe with a delegated CWA permit program. Permitting of discharges of stormwater associated with oil and gas facility construction or operation activities may also be required. Compliance with permitting requirements could increase the length of time it takes to construct an oil and gas facility, and impose heightened operating standards, which in turn could increase our operators' cost of construction and operation. In addition, compliance with CWA requirements could limit the locations where wells, other oil and natural gas facilities, and associated access resources can be constructed.

The scope of regulated waters has been subject to substantial controversy. In 2015 and 2020, respectively, the Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over waters of the United States (“WOTUS”). However, both of these rulemakings were subject to legal challenge. In January 2023, the EPA and Corps published a final rule based on the pre-2015 definition, with updates to incorporate existing Supreme Court decisions and regulatory guidance. However, the January 2023 rule was challenged and is currently enjoined in 27 states. In May 2023 the U.S. Supreme Court released its opinion in Sackett v. EPA, which involved issues relating to the legal tests used to determine whether wetlands qualify as WOTUS. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023. However, due to the injunction on the January 2023 rule, the implementation of the September 2023 rule currently varies by state. In the 27 states subject to the injunction, the agencies are interpreting the definition of WOTUS consistent with the pre-2015 regulatory regime and the changes made by the Sackett decision, which utilizes the “continuous surface connection” test to determine if wetlands qualify as WOTUS. In the remaining 23 states, the agencies are implementing the September 2023 rule, which did not define the term “continuous surface connection.” Therefore, some uncertainty remains as to how broadly the September 2023 rule and the Sackett decision will be interpreted by the agencies. To the extent the implementation of the final rule, results of the litigation, or any action further expands the scope of the CWA’s jurisdiction, operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the federal CWA, imposes duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain Spill Prevention, Control, and Countermeasure (“SPCC”) Plans.

The federal Safe Drinking Water Act (“SDWA”), its implementing regulations, and delegated regulatory programs (e.g., state programs) impose requirements on drilling and operation of underground injection wells, including injection wells used for the injection disposal of oil and gas wastes, such as produced water. In addition, the EPA has asserted authority under the SDWA to regulate hydraulic fracturing that uses diesel fuel. The EPA directly administers the Underground Injection Control (“UIC”) program in some states, and in others, administration of all or portions of the program is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. In addition, because some states, including Oklahoma and Texas, have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have issued directives to operators and/or have adopted or are considering additional regulations regarding such disposal methods. 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. For example, in 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant for a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. 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. In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. And in October 2021 and January 2022, respectively, the RRC identified two additional SRAs: the Northern Culberson-Reeves SRA and the Stanton SRA. Operators in the Northern Culberson-Reeves and Stanton SRAs have implemented seismic response plans, which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff. In December 2023, the RRC suspended the permits of 23 deep disposal wells in the Northern Culberson-Reeves SRA.

In addition, several cases have in recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. On January 14, 2021, the EPA issued a guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. However, on September 16, 2021, the EPA rescinded its January 14, 2021 guidance. 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.

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose strict liability, and in some cases joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who generated, transported, disposed or arranged for the transport or disposal of a hazardous substance. Such persons may be responsible for the costs of investigating releases of hazardous substances, remediating releases of hazardous substances, and compensating for damages to natural resources. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action, including the costs of certain health studies. From time to time, the EPA may designate additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or the reopening of Superfund sites that previously received regulatory closure. 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. While CERCLA does contain an exclusion for petroleum, the exclusion is limited and could ultimately be repealed, and oil and gas facilities often contain hazardous substances subject to regulation under CERCLA. Although the non-operating status of our interests in the Properties likely presents a lower risk that we would be held subject to CERCLA liability, should we or any of our operating partners become subject to strict liability under federal or state laws for environmental damages caused by previous owners or operators of properties we purchase, without regard to fault, our profitability could be negatively affected.

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Most wastes associated with the exploration, development, and production of oil or gas, including drilling fluids and produced water, are currently regulated as non-hazardous wastes pursuant to an exemption from regulation as a hazardous waste under RCRA. However, certain wastes generated at oil and gas exploration, development, production, and transmission sites are regulated as hazardous under RCRA. It is also possible that “RCRA-exempt” exploration and production wastes currently regulated as non- hazardous could be regulated as hazardous wastes in the future.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, and natural resources. 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. The United States Fish and Wildlife Service (“USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances, sediments, or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties. 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. 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.

The purpose of the Occupational Safety and Health Act (“OSHA”), comparable state statutes, and each of their implementing regulations is to protect the health and safety of workers. 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.

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.

Scrutiny of oil and natural gas production activities continues in other ways. The federal government has in recent years undertaken several studies of the oil and gas industry’s potential impacts. For example, in 2016 the EPA published a final report of a four-year study focused on the possible relationship between hydraulic fracturing and drinking water. In its assessment, the EPA concluded that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. In addition, in May 2022, the U.S. Government Accountability Office (“GAO”) released a study on methane emissions from oil and gas development, which included a recommendation that the Bureau of Land Management (“BLM”) consider whether to require gas capture plans, including gas capture targets, from operators on federal lands. 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. 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. 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. We cannot predict whether other similar legislation in other states will ever be enacted and if so, what the provisions of such legislation would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our operating partners and our revenues and results of operations.

The National Environmental Policy Act (“NEPA”) establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. If, for example, our third-party operating partners conduct activities on federal land, receive federal funding, or require federal permits, such activities may be covered under NEPA. Certain activities are subject to robust NEPA review which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations. 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”). The April 2022 rule promulgation is considered phase one of a two-phase review of the 2020 NEPA Rule that was announced by the Biden Administration to emphasize the need to review federal actions for climate change and environmental justice impacts, among other factors. The Council on Environmental Quality ("CEQ") proposed the "Phase 2" revisions to NEPA in July 2023. 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.

Climate Change

The energy industry is affected from time to time in varying degrees by political developments and a wide range of federal, tribal, state and local statutes, rules, orders and regulations that may, in turn, affect the operations and costs of the companies engaged in the energy industry. In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on the Properties. 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. The charge starts at $900 per metric ton of methane in 2025 (using 2024 data), and increases to $1,500 after two years. While Congress has from time to time considered legislation to reduce emissions of GHGs, in recent years there has not been significant activity at the federal level in the form of adopted legislation aimed at reducing GHG emissions.

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. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact us, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require it to incur costs to reduce emissions of GHGs associated with its operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from the Properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas or increased fuel or energy efficiency requirements, that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural 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 natural gas assets.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their greenhouse gas emissions through individually determined reduction goals every five years after 2020. 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. In December 2023, the United Arab Emirates hosted the 28th session of the Conference of the Parties ("COP28") where parties signed onto an agreement to transition "away from fossil fuels in energy systems in a just, orderly and equitable manner" and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. Finally, it should be noted that climate changes may have significant physical effects, such as increased frequency and severity of storms, freezes, floods, drought, hurricanes and other climatic events; if any of these effects were to occur, they could have an adverse effect on the operations of our operating partners, and ultimately, our business. In addition, spurred by increasing concerns regarding climate change, the oil and gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals.

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. 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. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, in late 2020, the Federal Reserve announced that it had joined the NGFS, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In September 2022, the Federal Reserve announced that six of the U.S.’ largest banks would participate in a pilot climate scenario analysis to enhance the ability of firms and supervisors to measure and manage climate-related risk. Taking place throughout 2023, the pilot exercise is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

Environmental, 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. Furthermore, in March 2022 the SEC proposed rule amendments that, if adopted, would require public companies to disclose certain climate-related information in their public filings. A final rule is expected in 2024. Similarly, certain states have enacted or are otherwise considering disclosure requirements for certain climate-related risks. 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. 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. These rules, if adopted, along with increasing pressure related to ESG from the investor community could lead to increased operating costs that would materially adversely affect our operating partners and our revenues and results of operations. 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.

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. 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.

Human Capital Resources

As of December 31, 2023, we had two 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.

We believe, and the Manager believes, that our future success depends partially on our ability to attract, retain, and motivate qualified personnel. 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. We and our Manager offer a competitive total rewards program to employees, comprised of base salary, short-term incentives tied to our performance, comprehensive employee benefits that include medical and dental coverage, and paid parental leave for both birth and non-birth parents. Our Manager also offers a 401(k) program, which includes fully-vested employer matched contributions. We believe that our values, rewarding work environment, and competitive pay help us retain our employees and those of our Manager and minimize employee turnover in a very challenging personnel market.

Office Locations, Internet Website and Availability of Public Filings

Our principal office is located at 5217 McKinney Avenue, Suite 400, Dallas, TX 75205. Our website address is www.graniteridge.com.

We share a portion of the Manager’s office space (which consists of approximately 11,700 square feet), pursuant to the MSA. We believe our office space is sufficient to meet our needs and that additional office space can be obtained if necessary.

We 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"). The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.

We also make these documents available free of charge at www.graniteridge.com under the "Investors" link as soon as reasonably practicable after they are filed or furnished with the SEC.

Information on our website is not incorporated into this Annual Report or our other filings with the SEC and is not a part of them.