Granite Ridge Resources, Inc.
For the period ended Dec 31, 2025. Filed Mar 6, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Mar 6, 2026
GRNT$5.29+13.3%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-03-06.
0001928446-25-000010
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-06.
0001928446-26-000007
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 151 previous paragraphs and 145 current paragraphs.
108 unchanged; 30 reworded; 7 added; 12 removed; 1 previous and 0 current paragraphs rearranged.
Tables are not compared: 7 previous and 6 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (7)
Current report
The following table summarizes the amounts reported as gain (loss) on derivatives - commodity derivatives in the condensed consolidated statements of operations for the years ended December 31, 2025, and 2024:
Current report
On November 5, 2025, the Company and its lenders entered into the Sixth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) reaffirm the borrowing base and aggregate elected commitment amounts at $375.0 million, (ii) permit the issuance of the 2029 Senior Notes (as defined below), (iii) extend the maturity date to the earliest to occur of (A) November 5, 2029 or (B) the date that is ninety-one days prior to the stated maturity date of the 2029 Senior Notes if any 2029 Senior Notes remain outstanding on such date, and (iv) adjust the interest payable on (A) SOFR loans to interest at a rate per annum equal to SOFR plus an applicable margin ranging from 275 to 375 basis points, depending on the percentage of the borrowing base utilized and (B) base rate loans to interest at a rate per annum equal to the greatest of: (a) the U.S. prime rate as publicly announced from time to time by Bank of America, N.A.; (b) the federal funds effective rate plus 50 basis points; (c) the adjusted SOFR rate for a one-month interest period plus 100 basis points; and (d) 100 basis points, plus, in the case of any base rate loan, an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized.
Current report
2029 Senior Notes
Current report
On November 5, 2025, the Company, as issuer, completed an issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes at 96.0% of par with stated maturity on November 5, 2029 (the “2029 Senior Notes”) pursuant to a note purchase agreement (the “Note Purchase Agreement”). The Company used the net proceeds from issuance of the 2029 Senior Notes to repay certain amounts under the Credit Agreement and to pay related fees and expenses. 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.
Current report
Interest is due to be paid at the end of each quarter, commencing December 31, 2025. In addition, the Company will repay quarterly 2.5% of the original principal amount of the notes issued on the closing date beginning on September 30, 2026. If quarterly scheduled repayments are missed, the coupon increases to 11.875% and the Company is restricted from making any dividend payments until all delinquent scheduled repayments have been fulfilled. The Company has $17.5 million included in current liabilities in our consolidated balance sheets related to quarterly principal repayments due within the next 12 months. 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
Current report
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.
Current report
•As of December 31, 2025, we had $350.0 million of principal debt outstanding on our 2029 Senior Notes with quarterly repayments of $8.75 million beginning September 30, 2026.
Removed paragraphs (12)
Previous report
The following table sets forth the gain (loss) on derivatives for the years ended December 31, 2024 and 2023:
Previous report
Gain (Loss) on Derivatives – Common Stock Warrants
Previous report
We recognized a loss of $5.7 million during 2023 from the change in fair value of the warrant liability. See Note 3 and Note 9 in the Notes to the Consolidated Financial Statements for additional information on the common stock warrants and the Warrant Exchange.
Previous report
On October 24, 2022, Granite Ridge entered into a senior secured revolving credit agreement (as amended, the “Credit Agreement”) among Granite Ridge, as borrower, currently led by Bank of America, N.A., as administrative agent, and the lenders from time to time party thereto. The Credit Agreement has a maturity date of five years from the effective date thereof.
Previous report
On April 1, 2024, the Company entered into the Resignation, Appointment, Assignment and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Credit Agreement to, among other things, (a) appoint a new administrative agent and L/C Issuer (as defined therein) (b) increase the size of the lender group by adding nine new banks, with one bank exiting the facility, (c) increase the borrowing base from $275.0 million to $300.0 million, and (d) increase the aggregate elected commitments from $240.0 million to $300.0 million.
Previous report
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 300 to 400 basis points, depending on the percentage of the borrowing base utilized, plus an additional 10, 15 or 20 basis point credit spread adjustment for a one, three, or six month interest period, respectively. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the U.S. prime rate as published by the Wall Street Journal; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted SOFR rate for a one-month interest period plus 100 basis points, plus, in the case of this clause (iii) an additional 10 basis point credit spread adjustment, plus, in the case of any base rate loan, an applicable margin ranging from 200 to 300 basis points, depending on the percentage of the borrowing base utilized. 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.
Previous report
The Company also pays a commitment fee on unused elected commitment amounts under its facility of 50 basis points. The Company may repay any amounts borrowed under the Credit Agreement prior to the maturity date without any premium or penalty.
Previous report
The Credit Agreement contains certain financial covenants, including the maintenance of the following financial ratios:
Previous report
(i)a leverage ratio, which is the ratio of Consolidated Total Debt to EBITDAX (each as defined in the Credit Agreement), of not greater than 3.00 to 1.00 as of the last day of each fiscal quarter, and
Previous report
(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.
Previous report
The Credit Agreement contains additional restrictive covenants that limit our ability and our restricted subsidiaries to, among other things, incur additional indebtedness, incur additional liens, enter into mergers and acquisitions, make or declare dividends, repurchase or redeem junior debt, make investments and loans, engage in transactions with affiliates, sell assets and enter into certain hedging transactions. In addition, the Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the administrative agent may, with the consent of majority lenders, or shall, at the direction of the majority lenders, accelerate any amounts outstanding and terminate lender commitments.
Previous report
As of December 31, 2024, we were in compliance with all covenants required by the Credit Agreement.
Reworded paragraphs (30)
Previous wording
As of December 31, 2024, we owned an interest in 3,146 gross (202 net) producing wells, 323,222 gross (33,745 net) developed acres, and 25,334 gross (10,138 net) undeveloped acres, all located in the United States.
Current wording
As of December 31, 2025, we owned an interest in 3,602 gross (245 net) producing wells, 355,252 gross (47,534 net) developed acres, and 33,399 gross (12,504 net) undeveloped acres, all located in the United States.
Previous wording
Our average daily production for the year ended December 31, 2024 was 24,973 Boe per day.
Current wording
Our average daily production for the year ended December 31, 2025 was 31,984 Boe per day.
Previous wording
We evaluate capitalized costs related to proved and unproved oil and natural gas properties, including wells and related oil sales support equipment and facilities, for impairment on an annual basis, or more frequently if indicators of impairment exist. 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.
Current wording
We evaluate capitalized costs related to proved and unproved oil and natural gas properties, including wells and related oil sales support equipment and facilities, for recoverability when indicators of impairment exist. 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.
Previous wording
Our oil price differential to the NYMEX benchmark price during 2024, 2023 and 2022 was $(3.57) per barrel, $(1.40) per barrel and $(1.89) per barrel, respectively. Our natural gas price differential during 2024, 2023 and 2022 was $(0.31) per Mcf, $0.19 per Mcf and $0.91 per Mcf, respectively.
Current wording
Our oil price differential to the NYMEX benchmark price during 2025, 2024 and 2023 was $(3.76) per barrel, $(3.57) per barrel and $(1.40) per barrel, respectively. Our natural gas price differential during 2025, 2024 and 2023 was $(0.96) per Mcf, $(0.31) per Mcf and $0.19 per Mcf, respectively.
Previous wording
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, 2024 decreased 4% from the year ended December 31, 2023. Oil revenues for the year ended December 31, 2024 increased by 3% compared to the same period in 2023, driven by an 8% increase in production, partially offset by a 4% decrease in realized prices, excluding the effect of settled derivatives. Natural gas revenues decreased by 32% for the year ended December 31, 2024 compared to 2023, driven by a 31% decrease in realized natural gas prices, excluding the effect of settled commodity derivatives, and a 1% decrease in production.
Current wording
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, 2025 increased 18% from the year ended December 31, 2024. Oil revenues for the year ended December 31, 2025 increased by 10% compared to the same period in 2024, driven by an 31% increase in production, partially offset by a 16% decrease in realized prices, excluding the effect of settled derivatives. Natural gas revenues increased by 70% for the year ended December 31, 2025 compared to 2024, driven by a 36% increase in realized natural gas prices, excluding the effect of settled commodity derivatives, and a 25% increase in production.
Previous wording
Production from oil and gas properties increased because of drilling success and the acquisition of additional net revenue interests. This increase in total production is offset by the natural decline of the production rate of existing oil and natural gas wells. The number of wells we participated in increased from 176.50 net wells in 2023 to 202.40 net wells in 2024.
Current wording
Production from oil and gas properties increased because of drilling success and the acquisition of additional net revenue interests. This increase in total production is offset by the natural decline of the production rate of existing oil and natural gas wells. The number of wells we participated in increased from 202.40 net wells in 2024 to 244.74 net wells in 2025.
Previous wording
Lease operating expenses were $57.5 million ($6.29 per Boe) for the year ended December 31, 2024, a decrease of 5% from $60.5 million ($6.82 per Boe) for 2023. The decrease was primarily due to a decrease of $1.6 million in transportation and gathering expenses related to certain take in-kind arrangements on natural gas volumes, which have declined in the Haynesville area. In addition, workover and repair and maintenance expenses for the year ended December 31, 2024 are lower than the same period of 2023, partially offset by an increase in certain other lease operating expenses as a result of an increase in well count due to acquisitions and additional wells successfully drilled and completed.
Current wording
Lease operating expenses were $84.9 million ($7.27 per Boe) for the year ended December 31, 2025, a increase of 48% from $57.5 million ($6.29 per Boe) for 2024. The increase was primarily due to a $6.2 million increase in saltwater disposal costs, as well as a $4.0 million increase in contract labor. Additionally, there has been an increase in certain other lease operating expenses as a result of an increase in well count due to acquisitions and additional wells successfully drilled and completed.
Previous wording
We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $21.0 million ($2.30 per Boe) for the year ended December 31, 2024 compared to $24.9 million ($2.81 per Boe) for 2023. As a percentage of oil and natural gas sales, our production taxes were 6% in 2024 and 2023.
Current wording
We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $22.4 million ($1.92 per Boe) for the year ended December 31, 2025 compared to $21.0 million ($2.30 per Boe) for 2024. As a percentage of oil and natural gas sales, our production taxes were 5% and 6% for the years ended December 31, 2025 and 2024, respectively.
Previous wording
Depletion and accretion was $176.5 million ($19.31 per Boe) for the year ended December 31, 2024, an increase of 10% from $160.7 million ($18.11 per Boe) in 2023. The increase in depletion and accretion expense was primarily due to the increase in depletion expense resulting from the increase in production and depletion rate.
Current wording
Depletion and accretion was $215.7 million ($18.48 per Boe) for the year ended December 31, 2025, an increase of 22% from $176.5 million ($19.31 per Boe) in 2024. The increase in depletion and accretion expense was primarily due to the increase in depletion expense resulting from the increase in production during the year ended December 31, 2025.
Previous wording
During the year ended December 31, 2023, we recognized impairment expense of $26.5 million. As a result of the decline in gas prices as well as reserve revisions in the Haynesville Basin, we compared the sum of the expected undiscounted future net cash flows to the carrying amount of the assets. As the carrying amount of the assets was higher than the expected undiscounted future net cash flows, an impairment loss was recorded as the difference between the carrying value and the estimated fair value.
Current wording
During the years ended December 31, 2025 and 2024, we recognized impairment expense of $44.7 million and $36.4 million, respectively. As of December 31, 2025, as a result of the decline in oil prices in the Eagle Ford Basin, we compared the sum of the expected undiscounted future net cash flows to the carrying amount of the assets. 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.
Previous wording
During the years ended December 31, 2024 and 2023, we recognized impairment expense of $36.4 million and $26.5 million, respectively. As of December 31, 2024, as a result of widening differentials and higher production cost assumptions, it was determined that the carrying amount of proved oil and gas properties in the Bakken exceeded undiscounted future net cash flows. As a result, an impairment of $35.6 million was recorded to write-down the carrying value to the estimated fair value of the proved oil and gas properties. Additionally, for the year ended December 31, 2024, an impairment of $0.7 million to the Company's unproved properties in the Permian Basin as the operator of those properties no longer intends to drill certain locations.
Current wording
During the year ended December 31, 2024, as a result of widening differentials and higher production cost assumptions, it was determined that the carrying amount of proved oil and gas properties in the Bakken exceeded undiscounted future net cash flows. As a result, an impairment of $35.6 million was recorded to write-down the carrying value to the estimated fair value of the proved oil and gas properties. Additionally, for the year ended December 31, 2024, an impairment of 0.7 million to the Company's unproved properties in the Permian Basin as the operator of those properties no longer intends to drill certain locations.
Previous wording
Total general and administrative expenses were $24.6 million ($2.70 per Boe) for the year ended December 31, 2024, a decrease of 12% from $27.9 million ($3.15 per Boe) in 2023. The decrease was primarily due to $2.5 million of costs directly related to the Warrant Exchange in 2023.
Current wording
Total general and administrative expenses were $31.0 million ($2.66 per Boe) for the year ended December 31, 2025, a increase of 26% from $24.6 million ($2.70 per Boe) in 2024. The increase was primarily due to severance expense incurred during the period as a result of a management transition as well as expenses related to capital market activities.
Previous wording
Interest expense was $18.5 million for the year ended December 31, 2024 compared to $5.3 million for 2023. The increase in interest expense was primarily due to the increase in interest rates and higher average outstanding balance on the revolving credit facility.
Current wording
Interest expense was $25.5 million for the year ended December 31, 2025 compared to $18.5 million for 2024. The increase in interest expense was primarily due to a higher average outstanding balance on the revolving credit facility, as well as the issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes in November 2025. See the section entitled“Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources"for more information.
Previous wording
For the year ended December 31, 2024, we recorded income tax expense of $6.2 million, which included current income tax expense of $0.2 million and deferred income tax expense of $6.0 million. Our effective income tax rate of 24.9% for the year ended December 31, 2024 differs from the federal statutory rate due primarily to the impact of certain discrete items, state income taxes and changes in state tax rates. For the year ended December 31, 2023, we recorded income tax expense of $24.5 million, which included current income tax expense of $0.2 million and deferred income tax expense of $24.3 million. Our effective income tax rate of 23.2% for the year ended December 31, 2023 differed from the federal statutory rate of 21% primarily due to the impact of certain discrete items and state income taxes.
Current wording
For the year ended December 31, 2025, we recorded income tax expense of $7.8 million, which included current income tax expense of $0.4 million and deferred income tax expense of $7.4 million. Our effective income tax rate of 24.2% for the year ended December 31, 2025 differs from the federal statutory rate of 21% due primarily to the impact of certain discrete items, state income taxes, and certain nontaxable or nondeductible items. For the year ended December 31, 2024, we recorded income tax expense of $6.2 million, which included current income tax expense of $0.2 million and deferred income tax expense of $6.0 million. Our effective income tax rate of 24.9% for the year ended December 31, 2024 differed from the federal statutory rate of 21% primarily due to the impact of certain discrete items and state income taxes.
Previous wording
Our main sources of liquidity and capital resources as of the periods covered by this report have been internally generated cash flow from operations and credit facility borrowings. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
Current wording
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.
Previous wording
As of December 31, 2024, we had $205.0 million of debt outstanding under our Credit Agreement. We had $129.1 million of liquidity as of December 31, 2024, consisting of $119.7 million of committed borrowing availability under the Credit Agreement and $9.4 million of cash on hand. On November 1, 2024, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which amended the Credit Agreement to, among other things, increase the borrowing base and aggregate elected commitments from $300 million to $325 million. See Note 8 to the Notes to the Consolidated Financial Statements for additional information.
Current wording
As of December 31, 2025, the Company had $350.0 million of principal debt outstanding on 8.875% senior unsecured notes (the “2029 Senior Notes”) and $50.0 million of debt outstanding under our senior secured revolving credit agreement (as amended, the “Credit Agreement”). We had $339.5 million of liquidity as of December 31, 2025, consisting of $324.7 million of committed borrowing availability under the Credit Agreement and $14.8 million of cash on hand.
Previous wording
We paid dividends of $57.5 million, or $0.44 per share, and $58.6 million, or $0.44 per share, during the years ended December 31, 2024 and 2023, respectively. On February 14, 2025, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2025 that will be paid on March 14, 2025 to stockholders of record as of February 28, 2025. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.
Current wording
We paid dividends of $57.7 million, or $0.44 per share, and $57.5 million, or $0.44 per share, during the years ended December 31, 2025 and 2024, respectively. On February 13, 2026, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2026 that will be paid on March 13, 2026 to stockholders of record as of February 27, 2026. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.
Previous wording
The $27.1 million decrease in operating cash flows during the year ended December 31, 2024 as compared to 2023 was primarily due to the decrease in oil and natural gas sales and deferred income taxes during 2024 as compared to 2023. Our net cash provided by operating activities included a benefit of $0.9 million and a benefit of $4.6 million for the years ended December 31, 2024 and 2023, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.
Current wording
The $20.7 million increase in operating cash flows during the year ended December 31, 2025 as compared to 2024 was primarily due to the increase in oil and natural gas sales during 2025 as compared to 2024. Our net cash provided by operating activities included a benefit of $5.5 million and $0.9 million for the years ended December 31, 2025 and 2024, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.
Previous wording
For the year ended December 31, 2023, our net cash used in investing activities was $356.7 million, which consisted primarily of $282.4 million of capital expenditures for oil and natural gas properties and $76.8 million of acquisitions of oil and natural gas properties. These cash flows used in investing activities are partially offset by cash proceeds from refund of advances from operators of $2.5 million.
Current wording
For the year ended December 31, 2025, our net cash used in investing activities was $409.8 million, which consisted primarily of $300.8 million of capital expenditures for oil and natural gas properties and $118.5 million of acquisitions of oil and natural gas properties. These cash flows used in investing activities are partially offset by cash proceeds from refund of advances from operators of $4.3 million, and proceeds from the sale of equity investments of $5.0 million during 2025.
Previous wording
For the year ended December 31, 2024, our net cash used in investing activities was $310.8 million, which consisted primarily of $285.8 million of capital expenditures for oil and natural gas properties and $61.2 million of acquisitions of oil and natural gas properties. These cash flows used in investing activities are partially offset by cash proceeds from disposal of oil and natural gas properties of $14.0 million and refund of advances from operators of $19.7 million during 2024.
Current wording
For the year ended December 31, 2024, our net cash used in investing activities was $310.8 million, which consisted primarily of $285.8 million of capital expenditures for oil and natural gas properties and $61.2 million of acquisitions of oil and natural gas properties. These cash flows used in investing activities are partially offset by proceeds from the disposal of oil and natural gas properties of 14.0 million and proceeds from refund of advances from operators of $19.7 million .
Previous wording
For the year ended December 31, 2023, our net cash provided by financing activities was $13.4 million primarily due to $110.0 million of net borrowings under our Credit Agreement, partially offset by $58.6 million of dividends paid on our common stock and $35.4 million of common stock repurchases.
Current wording
For the year ended December 31, 2025, our net cash provided by financing activities was $118.8 million primarily due to proceeds from senior notes, net of discount, of $336.0 million, partially offset by $155.0 million of net repayments under our Credit Agreement and $57.7 million of dividends paid on our common stock.
Previous wording
At December 31, 2024, the Company had outstanding borrowings of $205.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $119.7 million. The 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.
Current wording
At December 31, 2025, the Company had outstanding borrowings of $50.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $324.7 million. The 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.
Previous wording
On November 1, 2024, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which amended the Credit Agreement to, among other things, (a) increase the borrowing base from $300.0 million to $325.0 million, and (b) increase the aggregate elected commitments from $300.0 million to $325.0 million.
Current wording
On April 29, 2025, the Company and its lenders entered into the Fifth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) increase the borrowing base from $325.0 million to $375.0 million, and (ii) increase the aggregate elected commitments from $325.0 million to $375.0 million.
Previous wording
•As of December 31, 2024, we had $205.0 million of debt outstanding under our Credit Agreement. See Note 8 of the Notes to the Consolidated Financial Statements for information regarding future interest payment obligations on our Credit Agreement.
Current wording
•As of December 31, 2025, we had $50.0 million of debt outstanding under our Credit Agreement. See Note 8 of the Notes to the Consolidated Financial Statements for information regarding future interest payment obligations on our Credit Agreement.
Previous wording
•We entered into the MSA with the Manager in which we pay the Manager an annual services fee of $10.0 million and reimburse the Manager for certain Granite Ridge group costs related to the operation of our oil and gas assets and other properties. See Note 10 of the Notes to the Consolidated Financial Statements.
Current wording
•We entered into the MSA with the Manager in which we pay the Manager an annual services fee for certain Granite Ridge group costs related to the operation of our oil and gas assets and other properties of $11.75 million, subject to annual CPI-based adjustments beginning January 1, 2027. 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.
Previous wording
For 2025, we are budgeting approximately $300 million to $320 million in total planned capital expenditures. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Credit Agreement.
Current wording
For 2026, we are budgeting approximately $320 million to $360 million in total planned capital 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.
Previous wording
The determination of depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. As of December 31, 2024, approximately 28% of our total proved reserves were categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves.
Current wording
The determination of depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. As of December 31, 2025, approximately 24% of our total proved reserves were categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves.
Previous wording
External petroleum engineers independently estimated all of the proved reserve quantities included in our financial statements, which were prepared in accordance with the rules promulgated by the SEC. 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.
Current wording
External petroleum engineers independently estimated all of the proved reserve quantities included in our Annual Report, which were prepared in accordance with the rules promulgated by the SEC. 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, 2025.
Previous wording
Depletion of oil and natural gas producing properties is determined using the units-of-production method. During the years ended December 31, 2024, 2023, and 2022, we recognized depletion expense of $175.7 million, $160.2 million and $105.3 million, respectively.
Current wording
Depletion of oil and natural gas producing properties is determined using the units-of-production method. During the years ended December 31, 2025, 2024, and 2023, we recognized depletion expense of $214.8 million, $175.7 million and $160.2 million, respectively.
Previous wording
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 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.
Current wording
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.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
The following table represents our net cash receipts from (payments on) derivatives for the years ended December 31, 2024 and 2023: