GRNT 10-K & 10-Q changes, risk factors and insider trading

•the outbreak or escalation of military hostilities, including between Russia and Ukraine, Israel and Hamas, the U.S., Israel and Iran, continued instability in the Middle East, and the potential destabilizing effect such conflicts may pose for the European continent or the global oil and natural gas markets;

In 20242025, 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. Under the successful efforts method of accounting, capitalized costs related to proved oil and natural gas properties, including wells and related support equipment and facilities, are evaluated for impairment on an annual basis, or more frequently if indicators of impairment exist. If undiscounted cash flows are insufficient to recover the net capitalized costs, an impairment charge for the difference between the net capitalized cost of proved properties and their estimated fair values is recognized. A substantial or extended decline in oil or natural gas prices, could result in future impairments of our proved oil and natural gas properties.

We and our operating partners depend on computer and telecommunications systems and other information and operational technology systems, and failures in those systems or cybersecurity threats, attacks and other disruptions could significantly disrupt our business operations.

We and the Manager have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we and the Manager have developed or may develop proprietary software systems, management techniques and other information and operational technologies incorporating software licensed from third parties. 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. We believe that we and the Manager have positive relations with their information and operational technology vendors; however, any interruptions to our or the Manager’s arrangements with third parties for their computing, communications, or operational infrastructure or any other interruptions to, or breaches of, their information or operational systems could lead to data corruption, communication interruption, corruption or loss of sensitive or confidential information, misdirected wire transfers, and an inability to perform services for our customers; complete or settle transactions; maintain our books and records; prevent environmental damage; and maintain communications or operations; or otherwise significantly disrupt our business operations. 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. Furthermore, various third-party resources that we or the Manager rely on, directly or indirectly, in the operation of our business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyberattacks or similar events that are entirely outside the control of us or the Manager, and any such events could significantly disrupt our business operations and/or have a material adverse effect on our results of operations.operations and financial condition. 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.

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. Most recently, inIn 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.OOOOc Underthat the final rules, states have two years to prepare and submit their plants to impose methane emission controls on existing sources. The presumptiveset 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% throughemission capture and control systems, zero-emission requirements for certain devices,systems and theequipment, establishmentleak ofdetection a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigationequipment and repairmonitoring, and so-called “green well” completion requirements. Fines and penalties for violations of these rules can be substantial. The rules have been subject to legal challenge, and in February 2025, the D.C. Circuit granted the EPA’s motion to hold the cases in abeyance while the agency reviews the final rules. WhileIn March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc, and in November 2025, the EPA issued an interim final rule extending several compliance for certain provisions in the December 2023 rule. Litigation challenging the interim final rule remains pending. We cannot predict when or whether the EPA or the Trump Administrationadministration may take further action to repeal or modify the final rules, we cannot predict the substance or timing of such changes, if any. However, the requirements of the EPA’s final methane rules have the potential to increase the operating costs of our operators and thus may adversely affect our financial results and cash flows. Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. These rules could further increase the cost of development and operation of the Properties.

Additionally, some states in which the Properties are located, such as Colorado and New Mexico, have adopted stringent rules and regulations to reduce methane emissions and emissions of other hydrocarbons, VOCs, and nitrogen oxides associated with oil and gas facilities. 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. AQCC is expected to undertake several additional rulemaking efforts to further reduce emissions over the next several years.years, and in February 2026, adopted regulations to reduce methane emissions from oil and gas operations in line with the federal Subparts OOOOb and OOOOc. 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. 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.

Flowback and produced water or certain other field fluids gathered from oil and natural gas exploration and production operations are often injected or disposed of in underground disposal wells. This disposal process has been linked to increased induced seismicity events in certain areas of the country. Certain states (including states in which the Properties are located) have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or in underground disposal wells, and state agencies implementing these requirements may issue orders directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, the Colorado Oil and Gas Conservation Commission adopted regulations in November 2020 that impose various new requirements on the underground injection of fluid wastes to further seismic safety and protection of the environment. In addition,recent in 2014,years, the RRC publishedhas aalso finalimposed ruleprohibitions governingand permitting or re-permitting of disposal wells that would require, among other things, the submission of informationrestrictions on seismicSWD 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 of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Furthermore,wells in response to a number of earthquakes in recent years in the Midland Basin, in September 2021 the RRC announced that it will not issue any new SWD well permits in the SRA area, and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well. 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 were required to develop and implement 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 a seismic response area in the Northern Culberson-Reeves SRA. 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).Basin.

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. InNotwithstanding responsethe EPA’s final rule in February 2026 revoking the GHG “Endangerment Finding” that provides the basis for its authority to findingsregulate thatGHG emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment,emissions, the EPA under previous administrations has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. Litigation has already been filed challenging the February 2026 rule, and while we cannot predict the final outcome, as a result, there is significant uncertainty with respect to regulation of GHG emissions. 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 IRA, which the U.S. Congress passed in August 2022, includes a charge for excess methane emissions from specificcertain types of facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year,oil and althoughgas facilities, though the IRAEPA’s generallyrule provides for a conditional exemption under certain circumstances,implementing the charge applieswas torevoked emissionsin thatMarch exceed2025 anfollowing establisheda emissionsJoint threshold for each typeResolution of coveredDisapproval facility.under Thethe Congressional Review Act, and the One Big Beautiful Bill Act, passed in July 2025, delayed implementation of the charge startsuntil at $900 per metric ton of methane in 2025 (using 2024 data), and increases to $1,500 after two years.2034.

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. 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. Further, while reporting on most ESG information is, generally, currently voluntary, in March 2024, the SEC finalized rules establishing a framework for the reporting of climate risks, targets, and metrics. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challengeschallenges, aswith wellsuch aslitigation changedheld prioritiesin underabeyance until the newSEC Presidentialrepeals, administrationreconsiders, thator couldotherwise impactmodifies the faterule. In March 2025, the SEC voted to end its defense of the final rules,rule, though theto timingdate andno impactfurther ofaction anyhas suchbeen changes are difficulttaken to predictrepeal atthe this time.rule.

In addition, certain organizations that provide informationinformation, ratings or proxy advisory services to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings or recommendations are used by some investors to inform their investment and voting decisions. WhileAlthough suchthis ratingstrend dohas notwaned impactrecently, allto investors’the investment or voting decisions,extent unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could leadleads to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, whichsuch ratings could have a negative impact on our access to and costs of capital.capital Also,or institutionalthe lendersability may,to complete projects. Certain financial institutions may also, of their own accord, elect not to provide or place additional restrictions on funding or insurance for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

In addition, our amended and restated certificate of incorporation provides that the federal district courts of the United States will be the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act; however, there is uncertainty as to whether a court would enforce such provision. 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.

Grey Rock Energy Partners GP III, L.P. ("Grey Rock Fund III"), pursuant to a Voting Agreement, dated as of August 25, 2023, by and among Grey Rock Fund III, Grey Rock Energy Partners GP II, L.P., and the other stockholders party thereto, controls a majority of our voting common stock. As a result, following the Business Combination, we are a “controlled company” within the meaning of the corporate governance standards of the rules of the NYSE. 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 ongoing military conflicts between Ukraine and Russia, Israel and Hamas, the joint U.S.-Israel strikes on Iran, and continued instability in the Middle East has caused unstable market and economic conditions and is expected to have additional global consequences, such as heightened risks of cyberattacks. Our business, financial condition, and results of operations may be materially adversely affected by the negative global and economic impact resulting from these conflicts or any other geopolitical tensions.

Worldwide economic, political and military events, including war, terrorist activity, and events in the Middle East, have contributed, and are likely to continue to contribute, to oil and natural gas price volatility. For example, the ongoing armed conflicts between Russia and Ukraine andUkraine, Israel and HamasHamas, the U.S., Israel and Iran and the continuation of, and the escalation in the severity of, these conflicts has led to extreme regional instability, caused dramatic fluctuations in global financial markets and has increased the level of global economic uncertainty, including uncertainty about world-wide oil supply and demand, which in turn has caused increased volatility in commodity prices. Further, the Houthi movement, which controls parts of Yemen, has targeted and launched numerous attacks on Israeli, American and international commercial marine vessels in the Red Sea as the ships approach the Suez Canal, resulting in many shipping companies re-routing to avoid the region altogether and worsening existing supply chain issues, including delays in supplier deliveries, extended lead times and increased cost of freight, impacts to the shipping of oil and gas, insurance and materials. The joint U.S.-Israel military strikes on Iran have heightened the potential for further conflict with Iran, a major oil producer,producer. Continued hostilities involving the Houthi movement in Yemen orand the Hezbollah movement in Lebanon hashave increasedfurther ascontributed ato result of continued, increasing hostilitiesinstability in the Middle East.region.

In recent years, the United States increased tariffs for certain goods, which triggered other nations to also increase tariffs on certain of their goods. In recent weeks, theThe Trump administration has made many announcements regarding tariffs and the extent andand, although the Supreme Court recently ruled that certain reciprocal tariffs are unconstitutional, the duration of suchother existing tariffs or the imposition of new tariffs remain uncertain. If maintained,maintained theor newly announcedimplemented, tariffs and the potential escalation of trade disputes could pose a risk to our business and also directly impact our operating expenses. For example, recentlypreviously announced 25% tariffs on imported steel are likely to lead to increased material costs.

We evaluate capitalized costs related to proved and unproved oil and natural gas properties, including wells and related oil sales support equipment and facilities, for impairmentrecoverability on an annual basis, or more frequently ifwhen indicators of impairment exist. If undiscounted cash flows are insufficient to recover the net capitalized costs of proved properties, we recognize an impairment charge for the difference between the net capitalized cost of proved properties and their estimated fair values. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects.

Our oil price differential to the NYMEX benchmark price during 2024,2025, 20232024 and 20222023 was $(3.573.76) per barrel, $(1.403.57) per barrel and $(1.891.40) per barrel, respectively. Our natural gas price differential during 2024,2025, 2024 and 2023 andwas 2022$(0.96) wasper Mcf, $(0.31) per Mcf, $0.19 per Mcf and $0.91$0.19 per Mcf, respectively.

Our revenues vary from year to year primarily due to changes in realized commodity prices and production volumes. Our oil and natural gas sales for the year ended December 31, 20242025 decreasedincreased 4%18% from the year ended December 31, 2023.2024. Oil revenues for the year ended December 31, 20242025 increased by 3%10% compared to the same period in 2023,2024, driven by an 8%31% increase in production, partially offset by a 4%16% decrease in realized prices, excluding the effect of settled derivatives. Natural gas revenues decreasedincreased by 32%70% for the year ended December 31, 20242025 compared to 2023,2024, driven by a 31%36% decreaseincrease in realized natural gas prices, excluding the effect of settled commodity derivatives, and a 1%25% decreaseincrease in production.

Lease operating expenses were $57.5$84.9 million ($6.29$7.27 per Boe) for the year ended December 31, 2024,2025, a decreaseincrease of 5%48% from $60.5$57.5 million ($6.82$6.29 per Boe) for 2023.2024. The decreaseincrease was primarily due to a decrease of $1.6$6.2 million in transportation and gathering expenses related to certain take in-kind arrangements on natural gas volumes, which have declinedincrease in thesaltwater Haynesvilledisposal area.costs, Inas addition,well workoveras anda repair$4.0 andmillion maintenanceincrease expensesin forcontract thelabor. yearAdditionally, endedthere Decemberhas 31, 2024 are lower than the same period of 2023, partially offset bybeen an increase in certain other lease operating expenses as a result of an increase in well count due to acquisitions and additional wells successfully drilled and completed.

We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $21.0$22.4 million ($2.30$1.92 per Boe) for the year ended December 31, 20242025 compared to $24.9$21.0 million ($2.81$2.30 per Boe) for 2023.2024. As a percentage of oil and natural gas sales, our production taxes were 6% in 20245% and 2023.6% for the years ended December 31, 2025 and 2024, respectively.

Depletion and accretion was $176.5$215.7 million ($19.31$18.48 per Boe) for the year ended December 31, 2024,2025, an increase of 10%22% from $160.7$176.5 million ($18.11$19.31 per Boe) in 2023.2024. The increase in depletion and accretion expense was primarily due to the increase in depletion expense resulting from the increase in production andduring depletionthe rate.year ended December 31, 2025.

During the yearyears ended December 31, 2023,2025 and 2024, we recognized impairment expense of $26.5$44.7 million.million and $36.4 million, respectively. As of December 31, 2025, as a result of the decline in gasoil prices as well as reserve revisions in the HaynesvilleEagle Ford Basin, we compared the sum of the expected undiscounted future net cash flows to the carrying amount of the assets. As the carrying amount of the assets was higher than the expected undiscounted future net cash flows, an impairment loss of $44.7 million was recorded as the difference between the carrying value and the estimated fair value.

Total general and administrative expenses were $24.6$31.0 million ($2.70$2.66 per Boe) for the year ended December 31, 2024,2025, a decreaseincrease of 12%26% from $27.9$24.6 million ($3.15$2.70 per Boe) in 2023.2024. The decreaseincrease was primarily due to $2.5severance millionexpense incurred during the period as a result of costsa directlymanagement transition as well as expenses related to thecapital Warrantmarket Exchange in 2023.activities.

The following table sets forthsummarizes the amounts reported as gain (loss) on derivatives - commodity derivatives in the condensed consolidated statements of operations for the years ended December 31, 20242025, and 20232024:

Interest expense was $18.5$25.5 million for the year ended December 31, 20242025 compared to $5.3$18.5 million for 2023.2024. The increase in interest expense was primarily due to the increase in interest rates anda higher average outstanding balance on the revolving credit facility.facility, as well as the issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes in November 2025. See the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources" for more information.

Our main sources of liquidity and capital resources as of the periods covered by this report have been internally generated cash flow from operations andoperations, credit facility borrowings.borrowings, and the issuance of senior notes. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

The $27.1$20.7 million decreaseincrease in operating cash flows during the year ended December 31, 20242025 as compared to 20232024 was primarily due to the decreaseincrease in oil and natural gas sales and deferred income taxes during 20242025 as compared to 2023.2024. Our net cash provided by operating activities included a benefit of $0.9$5.5 million and a benefit of $4.6$0.9 million for the years ended December 31, 20242025 and 2023,2024, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

For the year ended December 31, 2023,2025, our net cash used in investing activities was $356.7$409.8 million, which consisted primarily of $282.4$300.8 million of capital expenditures for oil and natural gas properties and $76.8$118.5 million of acquisitions of oil and natural gas properties. These cash flows used in investing activities are partially offset by cash proceeds from refund of advances from operators of $2.5$4.3 million.million, and proceeds from the sale of equity investments of $5.0 million during 2025.

On NovemberApril 1,29, 2024,2025, the Company and its lenders entered into the FourthFifth Amendment to the Credit Agreement, which amended the Credit Agreement to, among other things, (ai) increase the borrowing base from $300.0$325.0 million to $325.0$375.0 million, and (bii) increase the aggregate elected commitments from $300.0$325.0 million to $325.0$375.0 million.

BorrowingsOn underNovember 5, 2025, the Company and its lenders entered into the Sixth Amendment to Credit Agreement, which amended the Credit Agreement mayto, beamong other things, (i) reaffirm the borrowing base rateand loansaggregate orelected securedcommitment overnight financing rate (“SOFR”) loans. Interest is payable quarterly for base rate loans andamounts at $375.0 million, (ii) permit the endissuance of the applicable2029 Senior Notes (as defined below), (iii) extend the maturity date to the earliest to occur of (A) November 5, 2029 or (B) the date that is ninety-one days prior to the stated maturity date of the 2029 Senior Notes if any 2029 Senior Notes remain outstanding on such date, and (iv) adjust the interest periodpayable foron SOFR loans.(A) SOFR loans bearto interest at a rate per annum equal to SOFR plus an applicable margin ranging from 300275 to 400375 basis points, depending on the percentage of the borrowing base utilized,utilized plusand an(B) additional 10, 15 or 20 basis point credit spread adjustment for a one, three, or six month interest period, respectively. Basebase rate loans bearto interest at a rate per annum equal to the greatest of: (ia) the U.S. prime rate as publishedpublicly announced from time to time by theBank Wallof StreetAmerica, JournalN.A.; (iib) the federal funds effective rate plus 50 basis points; and (iiic) the adjusted SOFR rate for a one-month interest period plus 100 basis points,points; plus, in the case of this clauseand (iiid) an additional 10100 basis point credit spread adjustment,points, plus, in the case of any base rate loan, an applicable margin ranging from 200175 to 300275 basis points, depending on the percentage of the borrowing base utilized. The Company's weighted average effective interest rate under the Credit Agreement as of December 31, 2024 and 2023 was 8.12% and 8.71%, respectively.

•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.properties of $11.75 million, subject to annual CPI-based adjustments beginning January 1, 2027. The authority to increase the Services Fee up to a maximum total of $12.5 million annually has been delegated to management. See Note 10 of the Notes to the Consolidated Financial Statements.

For 2025,2026, we are budgeting approximately $300$320 million to $320$360 million in total planned capital expenditures.expenditures, including approximately $20 million to $30 million of acquisitions of oil and natural gas properties. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Credit Agreement.

External petroleum engineers independently estimated all of the proved reserve quantities included in our financialAnnual statements,Report, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we provided them our historical information, such as oil and natural gas production, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. 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, 2024.2025.

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. 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 evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to develop and produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates, and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods.

Our oil price differential to the NYMEX benchmark price during the three months ended MarchJune 31,30, 2026 and 2025 was a discount of $(2.801.72) per barrel and a discount of $(2.603.16) per barrel, respectively. OurFor naturalthe gassix months ended June 30, 2026 and 2025, our oil price differential to the average NYMEX benchmark price during the three months ended March 31, 2026 and 2025 was a discount of $(2.162.32) per Mcfbarrel and $(0.173.01) per Mcf,barrel, respectively.

Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. Although we cannot predict the occurrence of events that may affect future commodity prices, or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. 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 oil and natural gas that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX spot prices for oil and natural gas for the three and six months ended MarchJune 31,30, 2026 and 2025.

For the three months ended MarchJune 31,30, 2026, the average NYMEX oil pricing was $72.74$95.65 per barrel of oil, or 1%48% higher than the average NYMEX price per barrel for the three months ended MarchJune 31,30, 2025. Our settled derivatives decreased our realized oil price per barrel by $4.27$18.28 for the three months ended MarchJune 31,30, 2026 and decreasedincreased our realized oil price per barrel by $0.05$0.49 for the three months ended MarchJune 31,30, 2025. For the three months ended MarchJune 31,30, 2026, our average realized oil price per barrel after reflecting settled derivatives was $65.67$75.65 compared to $69.13$61.90 for the three months ended MarchJune 31,30, 2025. For the six months ended June 30, 2026, the average NYMEX oil pricing was $84.29 per barrel of oil, or 24% higher than the average NYMEX price per barrel for the six months ended June 30, 2025. Our settled derivatives decreased our realized oil price per barrel by $11.30 for the six months ended June 30, 2026 and increased our realized oil price per barrel by $0.23 for the six months ended June 30, 2025. For the six months ended June 30, 2026, our average realized oil price per barrel after reflecting settled derivatives was $70.67 compared to $65.34 for the six months ended June 30, 2025.

For the three months ended MarchJune 31,30, 2026, the average NYMEX natural gas pricing was $4.71$2.95 per Mcf, or 14%8% higherlower than the average NYMEX price per Mcf for the three months ended MarchJune 31,30, 2025. Our settled derivatives decreasedincreased our realized natural gas price per Mcf by $0.57$0.52 and $0.03 for the three months ended MarchJune 31,30, 2026 and decreased2025, our realized natural gas price per Mcf by $0.01 for the three months ended March 31, 2025.respectively. For the three months ended MarchJune 31,30, 2026, our average realized natural gas price per Mcf after reflecting settled derivatives was $1.98$1.64 compared to $3.96$2.35 for the three months ended MarchJune 31,30, 2025. For the six months ended June 30, 2026, the average NYMEX natural gas pricing was $3.81 per Mcf, or 4% higher than the average NYMEX price per Mcf for the six months ended June 30, 2025. Our settled derivatives decreased our realized natural gas price per Mcf by $0.06 for the six months ended June 30, 2026 and increased our realized natural gas price per Mcf by $0.01 for the six months ended June 30, 2025. For the six months ended June 30, 2026, our average realized natural gas price per Mcf after reflecting settled derivatives was $1.82 compared to $3.12 for the six months ended June 30, 2025.

Our revenues vary from year to year primarily due to changes in realized commodity prices and production volumes. Our oil and natural gas sales for the three months ended MarchJune 31,30, 2026 increased 4%37% from the same period in 2025. Oil revenues for the three months ended MarchJune 31,30, 2026 increased by 13% compared to the same period in 2025, driven by an 11% increase in production and a 1% increase in realized prices, excluding the effect of settled derivatives. Natural gas revenues decreased by 20% for the three months ended March 31, 202656% compared to the same period in 2025, driven by a 36%2% increase in production and a 53% increase in realized prices, excluding the effect of settled commodity derivatives. Natural gas revenues decreased by 51% for the three months ended June 30, 2026 compared to 2025, driven by a 52% decrease in realized natural gas prices, excluding the effect of settled commodity derivatives, partially offset by a 24%1% increase in production.

Production from oil and gas properties increased as a result of drilling success and the acquisition of additional net revenue interests. The number of wells we participated in during the period increased from 211.63227.42 net wells on MarchJune 31,30, 2025 to 245.55249.92 net wells on MarchJune 31,30, 2026.

Lease operating expenses were $29.7$30.0 million ($9.57$10.27 per Boe) for the three months ended MarchJune 31,30, 2026, an increase of 83%49% from $16.2$20.1 million ($6.17$7.00 per Boe) during the same period in 2025. The increase in lease operating expenses per Boe was primarily due to an increase in well count due to acquisitions and additional wells successfully drilled and completed, increased saltwater disposal costs as a result of higher water cuts and flowback operations, surface equipment rentals, and contract labor.

We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $6.1$6.6 million ($1.96$2.26 per Boe) for the three months ended MarchJune 31,30, 2026 compared to $6.6$5.3 million ($2.49$1.86 per Boe) during the same period in 2025. As a percentage of oil and natural gas sales, our production taxes were 4% and 5% during the three months ended MarchJune 31,30, 2026 and 2025.2025, respectively.

Depletion and accretion was $55.0$52.7 million ($17.72$18.06 per Boe) for the three months ended MarchJune 31,30, 2026, ana increasedecrease of 13%1% from $48.4$53.4 million ($18.41$18.59 per Boe) during the same period in 2025. The increase in depletionDepletion and accretion expense was primarilylargely dueflat tobetween periods, with a slight decrease driven by a shift in the increaserelative incost basis weighting of the depletion expense resulting from an increase in production between the two periods.pools.

For the three and six months ended MarchJune 31,30, 2026, wethe Company recognized impairment expense of $11.2$9.1 million and $20.3 million on unproved properties in the Permian Basin as a result of a changechanges in operator development plans.plans and reassessment of the economic viability of certain acreage in the Permian Basin resulting from unfavorable drilling results and further geologic and reservoir analysis of the acreage. No unproved property impairment was recorded for the three and six months ended June 30, 2025.

The following table provides components of our general and administrative expenses for the three and six months ended MarchJune 31,30, 2026 and 2025:

Total general and administrative expenses were $9.1$9.2 million ($2.93$3.14 per Boe) for the three months ended MarchJune 31,30, 2026, an increase of 22%7% from $7.5$8.5 million ($2.84$2.96 per Boe) during the same period in 2025. The increase was primarily duefor expenses related to increased legal fees, stock-based compensationcompensation, and managementservice feefees expenses duringunder the threeManagement monthsServices endedAgreement Marchwith 31,Grey 2026Rock asAdministration, compared to the same period in 2025.LLC.

The following table summarizessets forth the amounts reported as gain (loss) on derivatives - commodity derivatives in the condensed consolidated statements of operations for the three and six months ended MarchJune 31,30, 2026,2026 and 2025:

Interest expense was $10.3$11.1 million for the three months ended MarchJune 31,30, 2026 compared to $5.0$5.9 million for the three months ended MarchJune 31,30, 2025. The increase in interest expense during the three months ended MarchJune 31,30, 2026 as compared to 2025 was primarily due to the issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes in November 2025 that was outstanding during the entirety of the three months ended MarchJune 31,30, 2026.

We recorded a gainloss on equity investments of $6.7$2.2 million for the three months ended MarchJune 31,30, 2026 comparedas toa result of a $2.2 million realized loss on sale of common stock. We recorded a loss of $10.0$5.8 million for the three months ended MarchJune 31,30, 2025 resultingas a result of a $10.5 million realized loss on sale of common stock and an unrealized gain of $4.7 million from the change in fair value of the common stock held by the Company during the periods.held.

We recorded income tax expense of $8.9 million and income tax benefit of $13.6$4.8 million for the three and six months ended MarchJune 31,30, 2026 compared to income$7.8 taxmillion expenseand of $2.9$10.7 million for the three and six months ended MarchJune 31,30, 2025. The effective income tax rate differs from the statutory rate primarily due to the impact of certain discrete items and state income taxes.

As of MarchJune 31,30, 2026, we had $350.0 million of principal debt outstanding on 8.875% senior unsecured notes and $90.0$125.0 million of debt outstanding under our senior secured revolving credit agreement. We had $314.8$293.8 million of liquidity as of MarchJune 31,30, 2026, consisting of $284.7$249.7 million of committed borrowing availability under the Credit Agreement and $30.1$44.1 million of cash on hand.

We paid dividends of $14.5 million, or $0.11 per share, and $14.4 million, or $0.11 per share, during the first quarter of 2026 and 2025, respectively. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.

The following table summarizes our changes in cash for the threesix months ended MarchJune 31,30, 2026 and 2025:

The $17.7$40.2 million decrease in operating cash flows during the threesix months ended MarchJune 31,30, 2026 as compared to the same period in 2025 was primarily due to the increase in realized loss on derivatives of $34.6 million and increase in lease operating expenses of $23.3 million, partially offset by an increase in oil and natural gas sales of $45.4 million during the threesix months ended MarchJune 31,30, 2026 as compared to the same period in 2025.

Our net cash provided by operating activities included a reduction of $3.4$17.3 million and a reduction of $10.6$2.0 million for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

For the threesix months ended MarchJune 31,30, 2026, our net cash used in investing activities was $68.6$130.7 million, which consisted primarily of $60.4$122.6 million of capital expenditures for development of oil and natural gas properties and $9.5$26.2 million of acquisitions of oil and natural gas properties, partially offset by $15.4 million of proceeds from sale of oilequity and natural gas properties of $1.2 million.investments.

For the threesix months ended MarchJune 31,30, 2025, our net cash used in investing activities was $100.0$200.5 million, which consisted primarily of $66.7$164.5 million of capital expenditures for development of oil and natural gas properties and $34.7$44.9 million of acquisitions of oil and natural gas properties.properties, partially offset by $5.0 million of proceeds from sale of equity investments.

For the threesix months ended MarchJune 31,30, 2026, our net cash provided by financing activities was $25.5$46.0 million, primarily due to $40.0$75.0 million of net borrowings under our Credit Agreement, partially offset by $14.5$29.0 million of dividends paid on our common stock.

For the threesix months ended MarchJune 31,30, 2025, our net cash provided by financing activities was $30.6$40.7 million, primarily due to $45.0$70.0 million of net borrowings under our Credit Agreement, partially offset by $14.4$28.8 million of dividends paid on our common stock.

At MarchJune 31,30, 2026, the Company had outstanding borrowings of $90.0$125.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $284.7$249.7 million. 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'sCompany’s and its restricted subsidiaries'subsidiaries’ assets.

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. SOFR loans bear interest at SOFR plus an applicable margin ranging from 275 to 375 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 publicly announced from time to time by Bank of America, N.A.; (ii) the federal funds effective rate plus 50 basis points; (iii) the adjusted SOFR rate for a one-month interest period plus 100 basis points; and (iv) 100 basis points,points plus, in the case of any base rate loan, an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized.

(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 any 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, and (iii)an Asset Coverage Ratio (as defined in the Credit Agreement), commencing with the fiscal quarter endingended June 30, 2026, of not less than (a) for each such fiscal quarter ending prior to December 31, 2026, 1.25 to 1.00 and (b) for each such fiscal quarter ending on or after December 31, 2026, 1.50 to 1.00.

AtAs Marchof 31,June 30, 2026, thewe Company waswere in compliance with all covenants required by the Credit Agreement.

Interest is due to be paid at the end of each quarter. In addition, the Company will repay quarterly 2.5% of the original principal amount of the notes issued on the closing date beginning on September 30, 2026. If quarterly scheduled repayments are missed, the coupon increases to 11.875% and the Company is restricted from making any dividend payments until all delinquent scheduled repayments have been fulfilled. TheAs of June 30, 2026, the Company hashad $26.3$35.0 million included in current liabilities in the condensed consolidated balance sheets related to quarterly principal repayments due within the next 12 months. On or after May 5, 2027 and on or prior to May 5, 2028, the Company may, at its option, redeem, at any time some or all of the 2029 Senior Notes at 103.0% of par, as set forth in the Note Purchase Agreement, plus accrued and unpaid interest, if any. Any redemption of the 2029 Senior Notes prior to May 5, 2027 is subject to payment of a make-whole amount. After May 5, 2028, the Company may redeem some or all of the Senior Notes at 100.0% of the principal amount thereof plus accrued and unpaid interest, if any. The principal remaining outstanding at the time of maturity is required to be paid in full by the Issuer.

The 2029 Senior Notes include certain covenants, which, among other things, requires the maintenance of (i) a net leverage ratio not greater than 3.25 to 1.00 and an (ii) an asset coverage ratio greater than or equal to (A) for each Fiscal Quarter ending prior to December 31, 2026, 1.25 to 1.00 and (B) for each Fiscal Quarter ending on or after December 31, 2026, 1.50 to 1.00. The 2029 Senior Notes also contain a total leverage ratio and asset coverage ratio basket for Restricted Payments (as defined in the 2029 Senior Notes), which permits Restricted Payments in the form of cash distributions so long as, subject to certain other conditions, the leverage ratio, after giving pro forma effect to such Restricted Payments, cannot exceed 1.75 to 1.00, and the asset coverage ratio, after giving effect to such Restricted Payments, must be greater than or equal to 1.50 to 1.00. Under the 2029 Senior Notes, the Company must maintain a minimum hedging requirement included within the Senior Notes for oil and natural gas based on our proved developed producing projected volumes for each commodity on a rolling 18-month basis.

At MarchJune 31,30, 2026, the Company was in compliance with all financial covenants required by the Note Purchase Agreement.

For 2026, we are budgeting approximately $345 million to $385 million in total planned capital expenditures, including approximately $45 million to $55 million of acquisitions of oil and natural gas properties. Our costs incurred on oil and natural gas properties, excluding acquisitions, during the three months ended MarchJune 31,30, 2026 and 2025 totaled $58.3$78.5 million and $71.4$77.2 million, respectively, and $136.8 million and $148.6 million during the six months ended June 30, 2026 and 2025, respectively. Our capital expenditures for the threesix months ended MarchJune 31,30, 2026 were primarily funded with cash flows from operations and borrowings under the Credit Agreement. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Credit Agreement.

The following table reflects our expenditures for acquisitions of proved and unproved properties for the three and six months ended MarchJune 31,30, 2026 and 2025:

With our Credit Agreement and our positive cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expensesexpenses, and other cash needs for the next twelve months. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital. We may also choose to seek additional capital rather than utilize our credit to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

There have been no material changes in our critical accounting policies and procedures during the threesix months ended MarchJune 31,30, 2026. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our 2025 Form 10-K.