GRNT

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q. The following discussion contains “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Report. Please read “Cautionary Note Regarding Forward‑Looking Statements.” Also, please read the risk factors and other cautionary statements described under “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 (the "2025 Form 10-K") and elsewhere in this Report. We assume no obligation to update any of these forward‑looking statements, except as required by applicable law. Overview Granite Ridge is a scaled energy company which aims to provide shareholders with exposure similar to energy private equity through operated partnerships and traditional non-operated assets. We own assets in six prolific unconventional basins across the United States. We aim to deliver a diversified portfolio with best-in-class full cycle returns by investing in a large number of high-graded opportunities developed by proven public and private operators. We focus on success as measured by total shareholder returns, which we seek to balance with a low leverage profile. Selected Factors That Affect Our Operating Results Our revenues, cash flows from operations and future growth depend substantially upon: •the timing and success of drilling and production activities by our operating partners; •the prices and the supply and demand for oil and natural gas; •the quantity of oil and natural gas production from the wells in which we participate; •changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil and natural gas; •our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and •the level of our operating expenses. In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage in the Eagle Ford, Permian, Bakken, Haynesville, Denver-Julesburg, and Appalachian Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters, and other factors that may specifically affect one or more of these regions. The price of oil and natural gas can vary depending on the market in which it is sold and the means of transportation used to transport the oil and natural gas to market. The price at which our oil and natural gas production is sold typically reflects either a premium or discount to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil and natural gas price differentials between the applicable benchmark and the sales prices we receive for our oil and natural gas production. Our oil price differential to the NYMEX benchmark price during the three months ended June 30, 2026 and 2025 was a discount of $(1.72) per barrel and $(3.16) per barrel, respectively. For the six months ended June 30, 2026 and 2025, our 27 Table of Contents oil price differential to the NYMEX benchmark price was a discount of $(2.32) per barrel and $(3.01) per barrel, respectively. Our natural gas price differential to the average NYMEX price during the three months ended June 30, 2026 and 2025 was a discount of $(1.83) per Mcf and $(0.87) per Mcf, respectively. For the six months ended June 30, 2026 and 2025, our natural gas price differential to the average NYMEX price was a discount of $(1.93) per Mcf and $(0.55) per Mcf, respectively. Market Conditions The price that we receive for the oil and natural gas our operators produce is largely a function of market supply and demand. Because our oil and natural gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. Worldwide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices. 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 June 30, 2026 and 2025. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Average NYMEX Prices(1) Oil (per Bbl) $ 95.65 $ 64.57 $ 84.29 $ 68.12 Natural gas (per Mcf) $ 2.95 $ 3.19 $ 3.81 $ 3.66 (1)Based on average NYMEX spot prices. For the three months ended June 30, 2026, the average NYMEX oil pricing was $95.65 per barrel of oil, or 48% higher than the average NYMEX price per barrel for the three months ended June 30, 2025. Our settled derivatives decreased our realized oil price per barrel by $18.28 for the three months ended June 30, 2026 and increased our realized oil price per barrel by $0.49 for the three months ended June 30, 2025. For the three months ended June 30, 2026, our average realized oil price per barrel after reflecting settled derivatives was $75.65 compared to $61.90 for the three months ended June 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 June 30, 2026, the average NYMEX natural gas pricing was $2.95 per Mcf, or 8% lower than the average NYMEX price per Mcf for the three months ended June 30, 2025. Our settled derivatives increased our realized natural gas price per Mcf by $0.52 and $0.03 for the three months ended June 30, 2026 and 2025, respectively. For the three months ended June 30, 2026, our average realized natural gas price per Mcf after reflecting settled derivatives was $1.64 compared to $2.35 for the three months ended June 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. 28 Table of Contents Results of Operations The following table sets forth summary production and operating data for the periods indicated. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of 29 Table of Contents acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Net Sales (in thousands): Oil sales $ 139,674 $ 89,462 $ 243,120 $ 181,309 Natural gas and related product sales 9,599 19,757 34,417 50,841 Total revenues $ 149,273 $ 109,219 $ 277,537 $ 232,150 Net Production: Oil (MBbl) 1,487 1,457 2,966 2,784 Natural gas (MMcf) 8,574 8,500 18,311 16,326 Total (MBoe)(1) 2,916 2,874 6,018 5,505 Average Daily Production: Oil (Bbl) 16,341 16,009 16,387 15,384 Natural gas (Mcf) 94,220 93,404 101,166 90,200 Total (Boe)(1) 32,044 31,576 33,249 30,417 Average Sales Prices: Oil (per Bbl) $ 93.93 $ 61.41 $ 81.97 $ 65.11 Effect of gain (loss) on settled oil derivatives on average price (per Bbl) (18.28) 0.49 (11.30) 0.23 Oil net of settled oil derivatives (per Bbl)(2) $ 75.65 $ 61.90 $ 70.67 $ 65.34 Natural gas sales (per Mcf) $ 1.12 $ 2.32 $ 1.88 $ 3.11 Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf) 0.52 0.03 (0.06) 0.01 Natural gas sales net of settled natural gas derivatives (per Mcf)(2) $ 1.64 $ 2.35 $ 1.82 $ 3.12 Realized price on a Boe basis excluding settled commodity derivatives $ 51.19 $ 38.01 $ 46.12 $ 42.17 Effect of gain (loss) on settled commodity derivatives on average price (per Boe) (7.80) 0.34 (5.75) 0.16 Realized price on a Boe basis including settled commodity derivatives(2) $ 43.39 $ 38.35 $ 40.37 $ 42.33 Operating Expenses (in thousands): Lease operating expenses $ 29,961 $ 20,118 $ 59,640 $ 36,358 Production and ad valorem taxes 9,284 6,437 17,520 14,805 Depletion and accretion expense 52,666 53,412 107,645 101,857 General and administrative 9,151 8,517 18,231 15,980 Costs and Expenses (per Boe): Lease operating expenses $ 10.27 $ 7.00 $ 9.91 $ 6.60 Production and ad valorem taxes 3.18 2.24 2.91 2.69 Depletion and accretion 18.06 18.59 17.89 18.50 General and administrative 3.14 2.96 3.03 2.90 Net Producing Wells at Period-End: 249.92 227.42 249.92 227.42 (1)Natural gas is converted to Boe using the ratio of one barrel of oil to six Mcf of natural gas.(2)The presentation of realized prices including settled commodity derivatives is a result of including the net cash receipts from (payments on) commodity derivatives that are presented in the footnotes to our condensed consolidated financial statements. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community. 30 Table of Contents Oil, Natural Gas and Related Product Sales Our revenues vary from year to year primarily due to changes in realized commodity prices and production volumes. Our oil and natural gas sales for the three months ended June 30, 2026 increased 37% from the same period in 2025. Oil revenues for the three months ended June 30, 2026 increased by 56% compared to the same period in 2025, driven by a 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 1% increase in production. Our oil and natural gas sales for the six months ended June 30, 2026 increased 20% from the same period in 2025. Oil revenues increased by 34% compared to the same period in 2025, driven by a 7% increase in production and a 26% increase in realized prices, excluding the effect of settled commodity derivatives. Natural gas revenues decreased by 32% compared to the same period in 2025 as a result of a 40% decrease in realized natural gas prices, excluding the effect of settled commodity derivatives, partially offset by a 12% 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 increased from 227.42 net wells on June 30, 2025 to 249.92 net wells on June 30, 2026. Lease Operating Expenses Lease operating expenses were $30.0 million ($10.27 per Boe) for the three months ended June 30, 2026, an increase of 49% from $20.1 million ($7.00 per Boe) during the same period in 2025. The increase 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. Lease operating expenses were $59.6 million ($9.91 per Boe) for the six months ended June 30, 2026, an increase of 64% from $36.4 million ($6.60 per Boe) during the same period in 2025. The increase 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, contract labor, and recognition of minimum volume commitment delinquencies. Production and Ad Valorem Taxes We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $6.6 million ($2.26 per Boe) for the three months ended June 30, 2026 compared to $5.3 million ($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 June 30, 2026 and 2025, respectively. Production taxes were $12.7 million ($2.11 per Boe) for the six months ended June 30, 2026 compared to $11.9 million ($2.16 per Boe) during the same period in 2025. As a percentage of oil and natural gas sales, our production taxes were 5% during both the six months ended June 30, 2026 and 2025. Production taxes fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate. Ad valorem taxes were $2.7 million and $4.8 million for the three and six months ended June 30, 2026, respectively, compared to $1.1 million and $2.9 million during the same periods in 2025. Depletion and Accretion Depletion and accretion was $52.7 million ($18.06 per Boe) for the three months ended June 30, 2026, a decrease of 1% from $53.4 million ($18.59 per Boe) during the same period in 2025. Depletion and accretion expense was largely flat between periods, with a slight decrease driven by a shift in the relative cost basis weighting of the depletion pools. 31 Table of Contents Depletion and accretion was $107.6 million ($17.89 per Boe) for the six months ended June 30, 2026, an increase of 6% from $101.9 million ($18.50 per Boe) during the same period in 2025. The increase in depletion and accretion expense was primarily due to the increase in production. Impairment of Unproved Properties For the three and six months ended June 30, 2026, the Company recognized impairment expense of $9.1 million and $20.3 million on unproved properties in the Permian Basin as a result of changes in operator development 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. General and Administrative The following table provides components of our general and administrative expenses for the three and six months ended June 30, 2026 and 2025: Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2026 2025 2026 2025 General and administrative expenses $ 7,901 $ 8,122 $ 15,583 $ 14,932 Non-cash stock-based compensation 1,250 395 2,648 1,048 Total general and administrative expenses $ 9,151 $ 8,517 $ 18,231 $ 15,980 Total general and administrative expenses were $9.2 million ($3.14 per Boe) for the three months ended June 30, 2026, an increase of 7% from $8.5 million ($2.96 per Boe) during the same period in 2025. The increase was primarily for expenses related to increased legal fees, stock-based compensation, and service fees under the Management Services Agreement with Grey Rock Administration, LLC. Total general and administrative expenses were $18.2 million ($3.03 per Boe) for the six months ended June 30, 2026, an increase of 14% from $16.0 million ($2.90 per Boe) during the same period in 2025. The increase was primarily for expenses related to increased legal fees, stock-based compensation, and service fees under the Management Services Agreement with Grey Rock Administration, LLC. Gain/(Loss) on Derivatives – Commodity Derivatives The following table sets forth the gain (loss) on derivatives for the three and six months ended June 30, 2026 and 2025: Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2026 2025 2026 2025 Net cash receipts from (payments on) commodity derivatives Oil derivatives $ (27,189) $ 708 $ (33,505) $ 642 Natural gas derivatives 4,456 263 (1,070) 216 Total net cash receipts from (payments on) commodity derivatives $ (22,733) $ 971 $ (34,575) $ 858 Unrealized gain (loss) on commodity derivatives Oil derivatives $ 39,851 $ 9,519 $ (26,593) $ 10,873 Natural gas derivatives (3,437) 13,435 1,547 (2,663) Power capacity contract (689) — 586 — Total unrealized gain (loss) on commodity derivatives $ 35,725 $ 22,954 $ (24,460) $ 8,210 Total gain (loss) on derivatives - commodity derivatives $ 12,992 $ 23,925 $ (59,035) $ 9,068 Our earnings are affected by the changes in the value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines 32 Table of Contents between measurement periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses. Interest Expense Interest expense was $11.1 million for the three months ended June 30, 2026 compared to $5.9 million for the three months ended June 30, 2025. The increase in interest expense during the three months ended June 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 June 30, 2026. Interest expense was $21.4 million for the six months ended June 30, 2026 compared to $10.9 million for the six months ended June 30, 2025. The increase in interest expense during the six months ended June 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 six months ended June 30, 2026. Gain/(Loss) on Equity Investments We recorded a loss on equity investments of $2.2 million for the three months ended June 30, 2026 as a result of a $2.2 million realized loss on sale of common stock. We recorded a loss of $5.8 million for the three months ended June 30, 2025 as 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. We recorded a gain on equity investments of $4.5 million for the six months ended June 30, 2026. The gain is a result of an unrealized gain of $6.7 million from the change in fair value of the common stock held during the first quarter of 2026 offset by a $2.2 million realized loss on sale of common stock during the second quarter of 2026. We recorded a loss of $15.8 million for the six months ended June 30, 2025. The loss is a result of a $10.5 million realized loss on sale of common stock and an unrealized loss of $5.2 million from the change in fair value of common stock held. Income Tax Expense We recorded income tax expense of $8.9 million and income tax benefit of $4.8 million for the three and six months ended June 30, 2026 compared to $7.8 million and $10.7 million for the three and six months ended June 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. Liquidity and Capital Resources Our main sources of liquidity and capital resources as of the periods covered by this Report have been internally generated cash flow from operations, credit facility borrowings, and the issuance of senior notes. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. As of June 30, 2026, we had $350.0 million of principal debt outstanding on 8.875% senior unsecured notes and $125.0 million of debt outstanding under our senior secured revolving credit agreement. We had $293.8 million of liquidity as of June 30, 2026, consisting of $249.7 million of committed borrowing availability under the Credit Agreement and $44.1 million of cash on hand. With our cash on hand, cash flow from operations, senior unsecured notes and borrowing capacity under the Credit Agreement, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity. We cannot assure you that any additional capital will be available to us on favorable terms or at all. Capital Commitments Our recent capital commitments have been to fund the development and acquisition of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash on hand, cash flows from operations and available borrowing capacity under our Credit Agreement. Our capital expenditures could be curtailed if our cash flows decline from expected levels. 33 Table of Contents Common Stock Dividends We paid dividends of $14.5 million, or $0.11 per share, and $29.0 million, or $0.22 per share during the three and six months ended June 30, 2026, respectively. For the three and six months ended June 30, 2025, the Company paid dividends of $14.4 million, or $0.11 per share, and $28.8 million, or $0.22 per share, respectively. Any payment of future dividends will be at the discretion of the Company’s Board of Directors. Cash Flows The following table summarizes our changes in cash for the six months ended June 30, 2026 and 2025: Six Months Ended June 30, (in thousands) 2026 2025 Net cash provided by operating activities $ 113,928 $ 154,134 Net cash used in investing activities (130,682) (200,533) Net cash provided by financing activities 46,000 40,723 Net change in cash $ 29,246 $ (5,676) Cash Flows from Operating Activities The primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our commodity derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes. The $40.2 million decrease in operating cash flows during the six months ended June 30, 2026 as compared to the same period in 2025 was primarily due to 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 six months ended June 30, 2026 as compared to the same period in 2025. Our net cash provided by operating activities included a reduction of $17.3 million and a reduction of $2.0 million for the six months ended June 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. Cash Flows from Investing Activities For the six months ended June 30, 2026, our net cash used in investing activities was $130.7 million, which consisted primarily of $122.6 million of capital expenditures for development of oil and natural gas properties and $26.2 million of acquisitions of oil and natural gas properties, partially offset by $15.4 million of proceeds from sale of equity investments. For the six months ended June 30, 2025, our net cash used in investing activities was $200.5 million, which consisted primarily of $164.5 million of capital expenditures for development of oil and natural gas properties and $44.9 million of acquisitions of oil and natural gas properties, partially offset by $5.0 million of proceeds from sale of equity investments. Cash Flows from Financing Activities For the six months ended June 30, 2026, our net cash provided by financing activities was $46.0 million, primarily due to $75.0 million of net borrowings under our Credit Agreement, partially offset by $29.0 million of dividends paid on our common stock. For the six months ended June 30, 2025, our net cash provided by financing activities was $40.7 million, primarily due to $70.0 million of net borrowings under our Credit Agreement, partially offset by $28.8 million of dividends paid on our common stock. 34 Table of Contents Granite Ridge Credit Agreement At June 30, 2026, the Company had outstanding borrowings of $125.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $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’s and its restricted subsidiaries’ assets. On October 24, 2022, Granite Ridge entered into a senior secured revolving credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks, currently led by Bank of America, N.A., as administrative agent. The Credit Agreement has a maturity date of 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 unsecured senior notes issued in November 2025 if any such notes remain outstanding on such date. The Company and the Required Lenders (as defined in the Credit Agreement) may request one unscheduled redetermination of the borrowing base between each scheduled redetermination. The amount of the borrowing base is determined by the lenders in their sole discretion and consistent with the oil and gas lending criteria of the lenders at the time of the relevant redetermination. The amount the Company is able to borrow under the Credit Agreement is subject to compliance with the financial covenants, satisfaction of various conditions precedent to borrowing and other provisions of the Credit Agreement. 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 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. The Company also pays a commitment fee on unused elected commitment amounts under its facility ranging from 37.5 to 50 basis points. The Company may repay any amounts borrowed under the Credit Agreement prior to the maturity date without any premium or penalty. The Credit Agreement contains certain financial covenants, including the maintenance of the following financial ratios: (i)a leverage ratio, which is the ratio of Consolidated Total Debt to EBITDAX (each as defined in the Credit Agreement), of not greater than 3.00 to 1.00 as of the last day of 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 ended 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. On August 3, 2026, the Company and its lenders entered into the Seventh Amendment to Credit Agreement, which amended the Credit Agreement to increase the pro forma net leverage ratio requirement for purposes of the restricted payment and debt redemption covenants to 1.75 to 1.00 (from 1.50 to 1.00) for the period between August 3, 2026 and January 1, 2027. As of June 30, 2026, we were in compliance with all covenants required by the Credit Agreement. 2029 Senior Notes On November 5, 2025, the Company, as issuer, completed an issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes at 96.0% of par with stated maturity on November 5, 2029 pursuant to the Note Purchase Agreement. The Company used the net proceeds from issuance of the 2029 Senior Notes to repay certain amounts under 35 Table of Contents the Credit Agreement and to pay related fees and expenses. The Note Purchase Agreement allows the ability for the Company to incur up to $100.0 million of incremental notes for purposes of acquisition financing, subject to, among other things, the willingness of holders to provide such incremental notes and a pro forma net leverage ratio not greater than 2.00 to 1.00. Interest is due 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. As of June 30, 2026, the Company had $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 (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. The Senior Notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Note Purchase Agreement contains customary terms and covenants and events of default, including limitations on the Company’s ability to incur additional secured and unsecured indebtedness. At June 30, 2026, the Company was in compliance with all financial covenants required by the Note Purchase Agreement. Known Contractual and Other Obligations; Planned Capital Expenditures Contractual and Other Obligations Our contractual obligations include long-term debt, cash interest expense on debt, derivative liabilities, asset retirement obligations, joint development agreements, and an annual service fee to the Manager. Since December 31, 2025, there have been no material changes in our contractual obligations, other than (i) the $75.0 million increase in long-term debt due to borrowings under the Credit Agreement and (ii) increase in contractually obligated fees under our joint development agreements. The Company enters into joint development agreements that outline the terms for the joint evaluation, acquisition, exploration, development, and production of hydrocarbons from jointly owned interests subject to such agreements. These agreements designate a third party as the operator of all jointly owned interests in the applicable development area, while Granite Ridge retains the right to manage and control acquisition costs and strategy, development costs, timing and rig schedules, well design and other development operations in exchange for a fee. The aggregate minimum financial commitment amount over the noncancellable term of these joint development agreements is $12.4 million, which is due over the next two years. Planned Capital Expenditures 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 36 Table of Contents oil and natural gas properties, excluding acquisitions, during the three months ended June 30, 2026 and 2025 totaled $78.5 million and $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 six months ended June 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 amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, contractual obligations, internally generated cash flow, and other factors both within and outside our control. Acquisitions The following table reflects our expenditures for acquisitions of proved and unproved properties for the three and six months ended June 30, 2026 and 2025: Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2026 2025 2026 2025 Property acquisition costs: Proved $ 2 $ — $ 591 $ 13,341 Unproved 16,682 10,069 26,234 31,090 Total property acquisition costs $ 16,684 $ 10,069 $ 26,825 $ 44,431 Satisfaction of Our Cash Obligations for the Next Twelve Months 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 expenses, 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. Effects of Inflation and Pricing The oil and natural gas industry is typically very cyclical and the demand for goods and services of oilfield companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel. Critical Accounting Estimates The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, 37 Table of Contents proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions. Further, these estimates and other factors, including those outside of management’s control, could have a significant adverse impact to the financial condition, results of operations and cash flows of the Company. In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, revenue recognition, impairment of long-lived assets and valuation of financial derivatives. There have been no material changes in our critical accounting policies and procedures during the six months ended June 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. Recently Issued or Adopted Accounting Pronouncements For discussion of recent accounting pronouncements, see Note 2 of the Notes to Condensed Consolidated Financial Statements. Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.