Granite Ridge Resources Inc
For the period ended Dec 31, 2024. Filed Mar 6, 2025.
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.
FY2024 · Filed Mar 6, 2025
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 2023-12-31; filed 2024-03-08.
0001928446-24-000009
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent 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 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 167 previous paragraphs and 151 current paragraphs.
105 unchanged; 37 reworded; 7 added; 21 removed; 4 previous and 2 current paragraphs rearranged.
Tables are not compared: 7 previous and 7 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
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.
Current report
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 report
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 report
Cash Flows Used in Investing Activities
Current report
Cash Flows Provided by (Used in) Financing Activities
Current 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.
Current report
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.
Removed paragraphs (21)
Previous report
The information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the following: (1) as it pertains to periods prior to the completion of the Business Combination, the accounts of each of the Funds (as defined below) and all related wholly owned subsidiaries, and Granite Ridge Resources, Inc. For these periods, the Funds have been presented on a combined historical basis due to their prior common ownership and control; and (2) as it pertains to the periods subsequent to the completion of the Business Combination, the accounts of Granite Ridge Resources, Inc. as well as its wholly owned subsidiaries which include, Granite Ridge Holdings, LLC (formerly known as GREP Holdings, LLC) and Executive Network Partnership Corporation (“ENPC”), and all other subsidiaries created in connection with the Business Combination.
Previous report
Granite Ridge is a scaled, non-operated oil and gas exploration and production company. We own a portfolio of wells and top-tier acreage across the Permian and four other prolific unconventional basins across the United States. Rather than drill wells ourselves, we increase asset diversity and decrease overhead by investing in a smaller piece of a larger number of high-graded wells drilled by proven public and private operators. As a non-operating partner, we pay our pro rata share of expenses, but we are not burdened by long-term contracts and drilling obligations common to operators.
Previous report
The financial results presented in this section consist of the historical results of the combined Funds (as defined below), which at the closing of the Business Combination effectively became the historical results of Granite Ridge. Annual information related to the Results of Operations for Granite Ridge as of and for the years ended December 31, 2021 and 2020 were derived from the audited consolidated financial statements of Grey Rock Energy Fund, L.P., a Delaware limited partnership (“Fund I”), and the related notes, and the audited combined financial statements of Grey Rock Energy Fund II, L.P., a Delaware limited partnership (“Fund II-A”), Grey Rock Energy Fund II-B, L.P., a Delaware limited partnership (“Fund II-B”) and Grey Rock Energy Fund II-B Holdings, L.P., a Delaware limited partnership (“Fund II-B Holdings”, and together with Fund II-A and Fund II-B, collectively, “Fund II”), and Grey Rock Energy Fund III-A, L.P., a Delaware limited partnership (“Fund III-A”), Grey Rock Energy Partners Fund III-B ,L.P., a Delaware limited partnership (“Fund III-B”), and Grey Rock Energy Fund III-B Holdings, L.P., a Delaware limited partnership (“Fund III-B Holdings” and together with Fund III-A and Fund III-B, collectively, “Fund III” or “Predecessor”) and the related notes included in the Company’s amended registration statement on Form S-4 (File No. 333-264986) filed with the SEC on September 12, 2022. Fund I, Fund II and Fund III are collectively referred to herein as, the “Funds.”
Previous report
2023 Significant Events
Previous report
Warrant Exchange
Previous report
On June 22, 2023, we completed an exchange offer to holders of our outstanding warrants, which provided such holders the opportunity to receive 0.25 shares of our common stock in exchange for each warrant tendered by such holders (the “Offer”). This Offer coincided with a solicitation of consents from holders of the warrants to amend that certain Warrant Agreement, dated as of September 15, 2020, by and between Executive Network Partnering Corporation, a Delaware corporation ("ENPC"), and Continental Stock Transfer & Trust Company, as warrant agent ("Continental"), as amended on March 24, 2021, by and between ENPC and Continental, and as assigned pursuant to the Assignment, Assumption and Amendment Agreement, dated as of October 24, 2022, by and between Granite Ridge, ENPC and Continental (as amended and assigned, the "Warrant Agreement") to permit the Company to require that each warrant that remained outstanding upon the closing of the Offer be exchanged for 0.225 shares of our common stock (together with the Offer, the “Warrant Exchange”). On June 22, 2023, we issued 2,471,738 shares of common stock in exchange for 9,887,035 warrants tendered in the Offer, with a minimal cash settlement in lieu of partial shares. We also received the necessary approval from the holders of our outstanding warrants to amend the Warrant Agreement and accordingly, in July 2023, each remaining outstanding warrant was converted into 0.225 shares of the Company’s common stock, and subsequently, no warrants remained outstanding. See Note 9 in the Notes to Consolidated Financial Statements for further discussion of the Warrant Exchange.
Previous report
Distribution and Voting Agreement
Previous report
On August 25, 2023, Fund III, which collectively owned a majority of the voting shares of our common stock, distributed an aggregate of 31,649,616 shares of our common stock, pro rata to its limited partners (the “Distribution”). As a result of the Distribution, Fund III’s aggregate ownership of shares of our common stock was reduced from approximately 71% to approximately 47% as of the date of the Distribution.
Previous report
Also on August 25, 2023, Grey Rock Energy Partners GP III, L.P., a Delaware limited partnership (who has voting and dispositive power over Granite Ridge common stock owned by Fund III and certain of its affiliates) (“GREP GP III”), Grey Rock Energy Partners GP II, L.P., a Delaware limited partnership (who has voting and dispositive power over Granite Ridge common stock owned by Fund II) (“GREP GP II”), and Matthew Miller, Griffin Perry, Thaddeus Darden and Kirk Lazarine (collectively, the “Voting Agreement Parties”), entered into a Stockholder Voting Agreement (the “Voting Agreement”).
Previous report
Pursuant to the Voting Agreement, the Voting Agreement Parties irrevocably and unconditionally agreed to vote the 75,957,927 shares of our common stock which the Voting Agreement Parties then held (and any other shares of our common stock obtained by Voting Agreement Parties in the future) at any annual or special meeting of our stockholders or in connection with any written consent of our stockholders. The 75,957,927 shares held by the Voting Agreement Parties as of the date of the Voting Agreement constituted approximately 56.3% of the total outstanding shares of our common stock as of such date. The Voting Agreement continues indefinitely, but can be terminated on 30 days’ prior written notice by Voting Agreement Parties holding a majority of the shares of Granite Ridge common stock subject to the Voting Agreement. In connection with their entry into the Voting Agreement, the Voting Agreement Parties provided GREP GP III an irrevocable voting proxy to vote the shares subject to the Voting Agreement. Additionally, during the term of such agreement, the Voting Agreement Parties agreed not to transfer the shares covered by the Voting Agreement without the consent of GREP GP III, except pursuant to certain limited exceptions. Due to the Voting Agreement, GREP GP III, LLC, a Delaware limited liability company, the sole general partner of GREP GP III, has voting and dispositive power over a majority of the shares of the Company due to its ability to vote the outstanding shares of Granite Ridge common stock held by the Voting Agreement Parties.
Previous report
Secondary Offering
Previous report
On September 15, 2023, we consummated an underwritten registered secondary offering (the “Secondary Offering”) of an aggregate of 8,165,000 shares of our common stock owned by GREP Holdco III-A, LLC and GREP Holdco III-B Holdings, LLC, each a Delaware limited liability company, at a price of $5.00 per share, pursuant to that certain Underwriting Agreement, dated September 12, 2023, among the Company, GREP Holdco III-A, LLC, GREP Holdco III-B Holdings, LLC, BofA Securities, Inc. and Evercore Group L.L.C. We did not sell any shares of our common stock in the Secondary Offering and did not receive any proceeds from the Secondary Offering.
Previous report
We recorded an income tax expense of $24.5 million and $12.9 million in 2023 and 2022, respectively. The increase in income tax expense during the year ended December 31, 2023, compared with 2022, was due to the fact that the Funds were treated as partnerships for U.S. federal income tax purposes prior to the Business Combination and, as such, the partners of the Funds reported their share of the Fund’s income or loss on their respective income tax returns for the applicable tax year (or portion thereof). In contrast, Granite Ridge is a corporation for U.S. federal income tax purposes and is subject to U.S. federal income taxes on any income or loss from the operation of the Company’s assets following the Business Combination on October 24, 2022. The effective income tax rate differs from the statutory rate in 2023 primarily due to the impact of certain discrete items and state income taxes. The effective income tax rate differs from the statutory rate in 2022 primarily due to the allocation of profits and losses to the partners of the Funds for the period prior to the Business Combination. See Note 7 to the Notes to the Consolidated Financial Statements for additional discussion of income taxes.
Previous report
Cash Flows from Operating Activities
Previous report
Cash Flows from Investing Activities
Previous report
Cash Flows from Financing Activities
Previous report
For the year ended December 31, 2022, our net cash used in financing activities was $76.8 million. We made net payments of $51.1 million on our credit facilities and paid $10.7 million of dividends during 2022. In addition, we paid $18.5 million of expenses related to the formation of Granite Ridge and $3.2 million of deferred financing cost related to the Credit Agreement. This was partially offset by the aggregate investment received by ENPC of $6.8 million in connection with the Business Combination, which represents total risk capital contributed by ENPC, including working capital loans that were forgiven.
Previous report
The Credit Agreement provided for aggregate elected commitments of $150.0 million, an initial borrowing base of $325.0 million and an aggregate maximum revolving credit amount of $1.0 billion. The borrowing base is scheduled to be redetermined semiannually on or about April 1 and October 1 of each calendar year, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. On November 7, 2023, we entered into a First Amendment to the Credit Agreement (the "First Amendment") which, among other things, decreased the borrowing base from $325.0 million to $275.0 million and increased the aggregate elected commitments from $150.0 million to $240.0 million.
Previous report
The Company and the Required Lenders (as defined in the Credit Agreement) may each 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 we are 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.
Previous report
Asset Retirement Obligations
Previous report
There are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and the normal operation of a long-lived asset. The primary impact of this relates to oil and natural gas wells on which we have a legal obligation to plug and abandon. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and, generally, a corresponding increase in the carrying amount of the related long-lived asset. The determination of the fair value of the liability requires us to make numerous judgments and estimates, including judgments and estimates related to future costs to plug and abandon wells, future inflation rates and estimated lives of the related assets. When the judgments used to estimate the initial fair value of the asset retirement obligation change, an adjustment is recorded to both the obligation and the carrying amount of the related long-lived asset. Historically, there have been no significant revisions to our initial estimates once future results became known. See Note 6 of the Notes to the Consolidated Financial Statements for additional information regarding our asset retirement obligations.
Reworded paragraphs (37)
Previous wording
As of December 31, 2023, we owned an interest in 2,826 gross (176.50 net) producing wells, 309,472 gross (30,728 net) developed acres, and 22,335 gross (6,749 net) undeveloped acres, all located in the United States.
Current 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.
Previous wording
Our average daily production for the year ended December 31, 2023 was 24,311 Boe per day.
Current wording
Our average daily production for the year ended December 31, 2024 was 24,973 Boe per day.
Previous wording
On October 24, 2022 (the “Closing Date”), Granite Ridge and 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”).
Current wording
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”).
Previous wording
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 and Denver-Julesburg 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.
Current wording
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.
Previous wording
Our oil price differential to the NYMEX benchmark price during 2023, 2022 and 2021 was $(1.40) per barrel, $(1.89) per barrel and $(5.00) per barrel, respectively. Our natural gas price differential during 2023, 2022 and 2021 was $0.19 per Mcf, $0.91 per Mcf and $1.32 per Mcf, respectively.
Current 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.
Previous wording
Our revenues vary from year to year primarily due to changes in realized commodity prices and production volumes. In 2023, our oil and natural gas sales decreased 21% from 2022, driven by the decrease in realized prices, excluding the effect of settled commodity derivatives, partially offset by the increase in production. The lower average realized prices were driven by lower average NYMEX oil and natural gas prices.
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, 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.
Previous wording
Production from oil and gas properties increased because of drilling success and the acquisition of additional net revenue interests. This increase in 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 132.88 net wells in 2022 to 176.50 net wells in 2023.
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 176.50 net wells in 2023 to 202.40 net wells in 2024.
Previous wording
Lease operating expenses were $60.5 million ($6.82 per Boe) for the year ended December 31, 2023, an increase of 35% from $44.7 million ($6.19 per Boe) for 2022. The increase was primarily due to an increase in well count due to acquisitions and additional wells successfully drilled and completed, higher repair and maintenance costs and overall increased cost of services. The increase in lease operating expenses per Boe was primarily due to higher saltwater disposal costs, repair and maintenance costs and workover activity, partially offset by the increase in production.
Current 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.
Previous wording
We generally pay production taxes based on realized oil and natural gas sales. Production taxes were $24.9 million ($2.81 per Boe) for the year ended December 31, 2023 compared to $26.9 million ($3.73 per Boe) for 2022. As a percentage of oil and natural gas sales, our production taxes were 6% and 5% in 2023 and 2022, respectively.
Current 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.
Previous wording
Ad valorem taxes decreased during the year ended December 31, 2023 as compared to 2022, primarily due to additional wells drilled and completed and new wells acquired.
Current wording
Ad valorem taxes increased during the year ended December 31, 2024 as compared to 2023, primarily due to additional wells drilled and completed and new wells acquired.
Previous wording
Depletion and accretion was $160.7 million ($18.11 per Boe) for the year ended December 31, 2023, an increase of 52% from $105.8 million ($14.66 per Boe) in 2022. 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 $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.
Previous wording
Total general and administrative expenses were $27.9 million ($3.15 per Boe) for the year ended December 31, 2023, an increase of 96% from $14.2 million ($1.97 per Boe) in 2022. The increase was primarily due to $2.5 million of costs directly related to the Warrant Exchange, stock-based compensation of $2.2 million, annual compensation accruals related to the Company’s officers and higher professional services and legal costs. The increase in stock-based compensation was due to the issuance of restricted stock awards, stock awards, stock options and PSUs. See Note 13 in the Notes to the Consolidated Financial Statements for additional information on stock-based compensation.
Current 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.
Previous wording
Interest expense was $5.3 million for the year ended December 31, 2023 compared to $2.0 million for 2022. The increase in interest expense was primarily due to the increase in interest rates and amortization of deferred financings costs, and higher average outstanding balance on the revolving credit facility.
Current 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.
Previous wording
We recognized a loss of $5.7 million and a gain of $0.4 million during 2023 and 2022, respectively, 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.
Current wording
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 wording
As of December 31, 2023, we had $110.0 million of debt outstanding under our Credit Agreement. We had $140.1 million of liquidity as of December 31, 2023, consisting of $129.7 million of committed borrowing availability under the Credit Agreement and $10.4 million of cash on hand. On November 7, 2023, Granite Ridge amended the Credit Agreement which, among other things, decreased the borrowing base from $325.0 million to $275.0 million and provided for aggregate elected commitments of $240.0 million, and amended the applicable margin charged on the loans and other obligations under the Credit Agreement. See Note 8 to the Notes to the Consolidated Financial Statements for additional information.
Current 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.
Previous wording
We paid dividends of $58.6 million, or $0.44 per share, and $10.7 million, or $0.08 per share during the years ended December 31, 2023 and 2022, respectively. On February 15, 2024, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2024 that will be paid on March 15, 2024 to stockholders of record as of March 1, 2024. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.
Current 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.
Previous wording
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. 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.
Current wording
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.
Previous wording
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)
Current wording
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.
Previous wording
Our net cash provided by operating activities included a benefit of $4.6 million and a reduction of $17.2 million for the years ended December 31, 2023 and 2022, 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 $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.
Previous wording
For the year ended December 31, 2022, our net cash used in investing activities was $230.6 million, which consisted primarily of $185.5 million of capital expenditures for oil and natural gas properties and $49.2 million of acquisitions of oil and natural gas properties.
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 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.
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.
Current 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.
Previous wording
At December 31, 2023, we had $110.0 million of outstanding debt and $0.3 million of letters of credit issued and outstanding under our Credit Agreement, resulting in committed borrowing availability of $129.7 million. The Credit
Current 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.
Previous wording
On October 24, 2022, the Funds terminated their revolving credit facilities, and we entered into the Credit Agreement among us, as borrower, Texas Capital Bank, as administrative agent, and the lenders from time to time party thereto. The Credit Agreement has a maturity of five years from the effective date thereof.
Current wording
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 wording
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. Prior to the effectiveness of the First Amendment, SOFR loans accrued interest at SOFR plus an applicable margin ranging from 250 to 350 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 accrued 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 150 to 250 basis points, depending on the percentage of the borrowing base utilized.
Current wording
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 wording
We also pay a commitment fee on unused elected commitment amounts under our facility of 50 basis points. We may repay any amounts borrowed under the Credit Agreement prior to the maturity date without any premium or penalty.
Current wording
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 wording
The Credit Agreement also contains certain financial covenants, including the maintenance of the following financial ratios:
Current wording
The Credit Agreement contains certain financial covenants, including the maintenance of the following financial ratios:
Previous wording
(ii)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.
Current wording
(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 wording
(i)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
Current wording
(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 wording
•As of December 31, 2023, we had $110.0 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, 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.
Previous wording
•We entered into the MSA with the Manager in which we will pay the Manager an annual services fee of $10.0 million and will 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 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.
Previous wording
For 2024, we are budgeting approximately $265 million to $285 million in total planned capital expenditures, including approximately $35 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.
Current 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.
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, 2023, approximately 42% 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, 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.
Previous wording
Depletion of oil and natural gas producing properties is determined using the units-of-production method. During the years ended December 31, 2023, 2022, and 2021, we recognized depletion expense of $160.2 million, $105.3 million and $94.2 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, 2024, 2023, and 2022, we recognized depletion expense of $175.7 million, $160.2 million and $105.3 million, respectively.
Previous wording
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 for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our proved properties for impairment.
Current wording
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.
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, risk-adjusted probable and possible reserves, and integrated assets. 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 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, cash flows from integrated assets 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. At December 31, 2023, our estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2024 price of $71.68 per barrel of oil decreasing to a 2028 price of $62.02 per barrel of oil. Natural gas prices ranged from a 2024 price of $2.67 per Mcf of natural gas increasing to a 2028 price of $3.80 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2028. During the year ended December 31, 2023, we recognized an impairment expense of $26.5 million. We did not incur any impairment expense related to our proved oil and natural gas properties during the years ended December 31, 2022 or 2021.
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 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.
Previous wording
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. The Company did not recognize an impairment expense for the years ended December 31, 2023, 2022 and 2021 related to its unproved oil and natural gas properties.
Current wording
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.
Previous wording
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 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.
Current wording
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.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
Cash Flows Provided by Operating Activities
Current report — wording carried from elsewhere
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.
Rearranged previous paragraphs (4)
Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
The $43.5 million decrease in operating cash flows during the year ended December 31, 2023 as compared to 2022 was primarily due to the decrease in oil and natural gas sales and higher operating costs, partially offset by $22.9 million of settlements received from commodity derivatives during 2023, as compared to $42.4 million of settlements paid on commodity derivatives during 2022.
Previous report — wording carried elsewhere
Agreement is guaranteed by our restricted subsidiaries and is secured by a first priority mortgage and security interest in substantially all of our assets and of our restricted subsidiaries.
Previous report — wording carried elsewhere
As a result of the First Amendment, SOFR loans now 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 now 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.