Granite Ridge Resources Inc.
03/06/2026 | Press release | Distributed by Public on 03/06/2026 05:03
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
Management's Discussion and Analysis of Financial Conditions and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included elsewhere in this Annual Report on Form 10-K.
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." 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.
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.
Our average daily production for the year ended December 31, 2025 was 31,984 Boe per day.
Business Combination
On October 24, 2022 (the "Closing Date"), Granite Ridge and Executive Network Partnering Corporation ("ENPC") consummated the business combination pursuant to the terms of the Business Combination Agreement, dated as of May 16, 2022 (the "Business Combination Agreement"), by and among ENPC, Granite Ridge, ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge ("ENPC Merger Sub"), GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge ("GREP Merger Sub"), and Granite Ridge Holdings, LLC, a Delaware limited liability company formerly known as GREP Holdings, LLC ("GREP").
Pursuant to the Business Combination Agreement, on the Closing Date, (i) ENPC Merger Sub merged with and into ENPC (the "ENPC Merger"), with ENPC surviving the ENPC Merger as a wholly-owned subsidiary of Granite Ridge and (ii) GREP Merger Sub merged with and into GREP (the "GREP Merger," and together with the ENPC Merger, the "Mergers"), with GREP surviving the GREP Merger as a wholly-owned subsidiary of Granite Ridge (the transactions contemplated by the foregoing clauses (i) and (ii) the "Business Combination," and together with the other transactions contemplated by the Business Combination Agreement, the "Transactions").
For additional information on the Business Combination See Note 1 in the Notes to the Consolidated Financial Statements.
Source of Our Revenues
We derive our revenues from our interests in the sale of oil and natural gas production. Revenues are a function of production, the prevailing market price at the time of sale, oil quality, and transportation costs to market. We use derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Principal Components of Our Cost Structure
Lease operating expenses
Lease operating expenses are the costs incurred in the operation of producing properties, including workover costs. Expenses for field employees' salaries, saltwater disposal, repairs and maintenance comprise the most significant portion of our lease operating expenses. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. A portion of our operating cost components are variable and change in correlation to production levels.
Production and ad valorem taxes
Production taxes are paid on produced oil and natural gas. Ad valorem taxes are paid on the value of our properties in certain states. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.
Depletion and accretion expense
Depletion and accretion include the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. As a "successful efforts" company, we capitalize all costs associated with our acquisition and successful development efforts and allocate these costs to each unit of production using the units of production method. Accretion expense relates to the passage of time of our asset retirement obligations.
Impairment expense
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.
General and administrative expenses
General and administrative expenses include overhead, including payroll and benefits for our corporate staff, management and annual service fees under the MSA, audit and other professional fees and legal compliance.
Interest expense
We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.
Gain (loss) on derivative contracts
We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and natural gas. Gain (loss) on derivative contracts is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.
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 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.
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 the 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 natural gas and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2025, 2024 and 2023.
| December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
|
Average NYMEX Prices(1)
|
|||||||||||||||||
| Oil (per Bbl) | $ | 65.39 | $ | 76.63 | $ | 77.58 | |||||||||||
| Natural gas (per Mcf) | $ | 3.52 | $ | 2.19 | $ | 2.53 | |||||||||||
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(1)Based on average NYMEX closing prices.
Results of Operations
The following tables and related discussion set forth key operating and financial data as of and for the years ended December 31, 2025 and 2024. For similar operating and financial data and discussion of our 2024 results compared to our 2023 results, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" under Part II of our annual report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on March 6, 2025. Because of normal production declines, increased or decreased drilling activities, fluctuations in
commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Net Sales (in thousands): | |||||||||||
| Oil sales | $ | 360,832 | $ | 327,491 | |||||||
| Natural gas and related product sales | 89,474 | 52,539 | |||||||||
| Revenues | 450,306 | 380,030 | |||||||||
| Net Production: | |||||||||||
| Oil (MBbl) | 5,855 | 4,483 | |||||||||
| Natural gas (MMcf) | 34,912 | 27,944 | |||||||||
|
Total (MBoe)(1)
|
11,674 | 9,140 | |||||||||
| Average Daily Production: | |||||||||||
| Oil (Bbl) | 16,041 | 12,248 | |||||||||
| Natural gas (Mcf) | 95,649 | 76,350 | |||||||||
|
Total (Boe)(1)
|
31,984 | 24,973 | |||||||||
| Average Sales Prices: | |||||||||||
| Oil (per Bbl) | $ | 61.63 | $ | 73.06 | |||||||
| Effect of gain on settled oil derivatives on average price (per Bbl) | 0.28 | 0.34 | |||||||||
|
Oil net of settled oil derivatives (per Bbl)(2)
|
$ | 61.91 | $ | 73.40 | |||||||
| Natural gas and related product sales (per Mcf) | $ | 2.56 | $ | 1.88 | |||||||
| Effect of gain on settled natural gas derivatives on average price (per Mcf) | 0.08 | 0.53 | |||||||||
|
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)(2)
|
$ | 2.64 | $ | 2.41 | |||||||
| Realized price on a Boe basis excluding settled commodity derivatives | $ | 38.57 | $ | 41.58 | |||||||
| Effect of gain on settled commodity derivatives on average price (per Boe) | 0.38 | 1.79 | |||||||||
|
Realized price on a Boe basis including settled commodity derivatives(2)
|
$ | 38.95 | $ | 43.37 | |||||||
| Operating Expenses (in thousands): | |||||||||||
| Lease operating expenses | $ | 84,903 | $ | 57,461 | |||||||
| Production and ad valorem taxes | 27,554 | 26,007 | |||||||||
| Depletion and accretion expense | 215,701 | 176,529 | |||||||||
| Impairments of long-lived assets | 44,654 | 36,369 | |||||||||
| General and administrative | 31,009 | 24,649 | |||||||||
| Costs and Expenses (per Boe): | |||||||||||
| Lease operating expenses | $ | 7.27 | $ | 6.29 | |||||||
| Production and ad valorem taxes | 2.36 | 2.85 | |||||||||
| Depletion and accretion | 18.48 | 19.31 | |||||||||
| Impairments of long-lived assets | 3.83 | 3.98 | |||||||||
| General and administrative | 2.66 | 2.70 | |||||||||
| Net Producing Wells at Period-End: | 244.74 | 202.40 | |||||||||
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(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 our consolidated statements of cash flows. 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.
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 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.
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.
The following table sets forth information regarding our oil and natural gas production by basin.
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Net Production: | |||||||||||
| Oil (MBbl) | |||||||||||
| Permian | 4,288 | 2,956 | |||||||||
| Eagle Ford | 387 | 638 | |||||||||
| Bakken | 465 | 561 | |||||||||
| Haynesville | - | - | |||||||||
| DJ | 373 | 322 | |||||||||
| Appalachian | 342 | 6 | |||||||||
| Total | 5,855 | 4,483 | |||||||||
| Natural Gas (MMcf) | |||||||||||
| Permian | 18,744 | 11,229 | |||||||||
| Eagle Ford | 3,224 | 3,847 | |||||||||
| Bakken | 1,150 | 1,235 | |||||||||
| Haynesville | 8,212 | 9,264 | |||||||||
| DJ | 2,240 | 2,345 | |||||||||
| Appalachian | 1,342 | 24 | |||||||||
| Total | 34,912 | 27,944 | |||||||||
| Total (MBoe) | |||||||||||
| Permian | 7,412 | 4,828 | |||||||||
| Eagle Ford | 924 | 1,279 | |||||||||
| Bakken | 657 | 767 | |||||||||
| Haynesville | 1,369 | 1,544 | |||||||||
| DJ | 746 | 712 | |||||||||
| Appalachian | 566 | 10 | |||||||||
| Total | 11,674 | 9,140 | |||||||||
Lease Operating Expenses
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.
Production and Ad Valorem Taxes
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.
Production taxes generally fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.
Ad valorem taxes increased during the year ended December 31, 2025 as compared to 2024, primarily due to additional wells drilled and completed and new wells acquired.
Depletion and Accretion
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.
Impairment of Long-Lived Assets
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.
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.
General and Administrative
The following table provides components of our general and administrative expenses for the years ended December 31, 2025 and 2024:
| Year Ended December 31, | |||||||||||
| (in thousands) | 2025 | 2024 | |||||||||
| General and administrative expenses | $ | 27,253 | $ | 22,351 | |||||||
| Non-cash stock-based compensation | 3,756 | 2,298 | |||||||||
| Total general and administrative expenses | $ | 31,009 | $ | 24,649 | |||||||
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.
Gain/(Loss) on Derivatives - Commodity Derivatives
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:
| Year Ended December 31, | |||||||||||
| (in thousands) | 2025 | 2024 | |||||||||
| Net cash receipts from commodity derivatives | |||||||||||
| Oil derivatives | $ | 1,624 | $ | 1,503 | |||||||
| Natural gas derivatives | 2,835 | 14,860 | |||||||||
| Total net cash receipts from commodity derivatives | $ | 4,459 | $ | 16,363 | |||||||
| Unrealized gain (loss) on commodity derivatives | |||||||||||
| Oil derivatives | $ | 15,084 | $ | (5,508) | |||||||
| Natural gas derivatives | 6,726 | (11,763) | |||||||||
| Power capacity contract | 852 | - | |||||||||
| Total unrealized gain (loss) on commodity derivatives | $ | 22,662 | $ | (17,271) | |||||||
| Total gain (loss) on derivatives - commodity derivatives | $ | 27,121 | $ | (908) | |||||||
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 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 $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.
Income Tax Expense (Benefit)
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.
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 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.
With our cash on hand, cash flow from operations, and borrowing capacity under the Credit Agreement, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at
least the next twelve months. However, we may seek additional access to capital and liquidity. 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.
Common stock dividends
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.
Stock repurchase program
In December 2022, we announced that our Board of Directors approved a stock repurchase program for up to $50.0 million of our common stock through December 31, 2023. The stock repurchase program terminated on December 31, 2023. During the year ended December 31, 2023, the Company repurchased 5,651,707 shares under the program at an aggregate cost of $36.1 million. As of December 31, 2023, the Company had repurchased a total of 5,677,627 shares since the inception of the program at an aggregate cost of $36.3 million.
Cash Flows
Our cash flows for the years ended December 31, 2025, 2024 and 2023 are presented below:
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2025 | 2024 | 2023 | ||||||||||||||
| Net cash provided by operating activities | $ | 296,414 | $ | 275,733 | $ | 302,867 | |||||||||||
| Net cash used in investing activities | (409,808) | (310,768) | (356,676) | ||||||||||||||
| Net cash provided by financing activities | 118,821 | 33,724 | 13,406 | ||||||||||||||
| Net change in cash | $ | 5,427 | $ | (1,311) | $ | (40,403) | |||||||||||
Cash Flows Provided by Operating Activities
The primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our commodity derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes.
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.
Cash Flows Used in Investing Activities
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.
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 .
Cash Flows Provided by (Used in) Financing Activities
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.
For the year ended December 31, 2024, our net cash provided by financing activities was $33.7 million primarily due to $95.0 million of net borrowings under our Credit Agreement, partially offset by $57.5 million of dividends paid on our common stock.
Granite Ridge Credit Agreement
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.
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.
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.
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 (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.
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
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.
Known Contractual and Other Obligations; Planned Capital Expenditures
Contractual and Other Obligations
•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.
•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.
•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.
•We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 of the Notes to the Consolidated Financial Statements.
•We have future obligations related to the abandonment of our oil and natural gas properties. See Note 6 of the Notes to the Consolidated Financial Statements.
•With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments.
Planned Capital Expenditures
For 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.
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.
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 oil field 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, 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 significant adverse impact to the financial condition, results of operations and cash flows of the Company.
Use of Estimates
The preparation of financial statements under U.S. GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period.
Oil and Natural Gas Reserves
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.
The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Such information includes revisions of certain reserve estimates attributable to the properties included in the prior year's estimates. These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices.
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.
Oil and Natural Gas Properties
Oil and natural gas producing activities are accounted for under the successful efforts method of accounting.
The successful efforts method inherently relies on the estimation of proved oil and natural gas reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.
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.
Any reduction in proved reserves could result in an acceleration of future depletion expense. Such a decline may result from lower commodity prices which may make it uneconomical to drill certain proved undeveloped locations. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of proved properties for impairment.
Holding all other factors constant, if proved reserves are revised downward, the rate at which we record depletion and accretion expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record depletion and accretion expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.
Impairment of Oil and Natural Gas Properties
All of our long-lived assets are monitored for potential impairment annually, or when circumstances indicate that the carrying value of an asset may be greater than management's estimates of its future net cash flows, including cash flows from proved reserves and risk-adjusted probable and possible reserves. 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.
Unproved oil and natural gas properties are assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects.
Derivative Instruments - Commodity Derivatives
In order to reduce uncertainty around commodity prices received for our oil and natural gas operators' production, we enter into commodity price derivative contracts from time to time. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties' creditworthiness.
We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and fair value is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty
and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.
Revenue Recognition
The Company's revenues are derived from its interests in the sale of oil and natural gas production. As we do not operate any of our wells, we have limited visibility into the timing of when new wells start producing and production statements may not be received for one to three months or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that we will receive for the sale of the product. Engineering estimates are typically used to calculate expected volumes. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the basis differential from market on a basin-by-basin basis. The expected sales volumes and prices for these properties are estimated and recorded within the revenue receivable line item in the accompanying consolidated balance sheets. Differences between our estimates and the actual amounts received for oil and natural gas sales are recorded in the month that payment is received from the third party.
Recently Issued or Adopted Accounting Pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Note 2 of the Notes to the 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.
Granite Ridge Resources Inc. published this content on March 06, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on March 06, 2026 at 11:03 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]