Granite Ridge Resources, Inc. (GRNT)

Item 7. 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

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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, 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.

Our average daily production for the year ended December 31, 2024 was 24,973 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.

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

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.

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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 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.

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, 2024, 2023 and 2022.

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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, 2024 and 2023. For similar operating and financial data and discussion of our 2023 results compared to our 2022 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, 2023, which was filed with the SEC on March 8, 2024. Because of normal production declines, increased or decreased drilling activities, fluctuations in

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commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.

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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.

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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, 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.

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.

The following table sets forth information regarding our oil and natural gas production by basin.

Lease Operating Expenses

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

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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.

Production and Ad Valorem Taxes

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.

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, 2024 as compared to 2023, primarily due to additional wells drilled and completed and new wells acquired.

Depletion and Accretion

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.

Impairment of Long-Lived Assets

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.

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

General and Administrative

The following table provides components of our general and administrative expenses for the years ended December 31, 2024 and 2023:

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.

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Gain/(Loss) on Derivatives – Commodity Derivatives

The following table sets forth the gain (loss) on derivatives for the years ended December 31, 2024 and 2023:

The following table represents our net cash receipts from (payments on) derivatives for the years ended December 31, 2024 and 2023:

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 $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.

Gain (Loss) on Derivatives – Common Stock Warrants

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.

Income Tax Expense (Benefit)

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.

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 and credit facility borrowings. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

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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.

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 $57.5 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.

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, 2024, 2023 and 2022 are presented below:

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 $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

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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.

Cash Flows Used in Investing Activities

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.

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.

Cash Flows Provided by (Used in) Financing Activities

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.

For the year ended December 31, 2023, our net cash provided by financing activities was $13.4 million primarily due to $110.0 million of net borrowings under our Credit Agreement, partially offset by $58.6 million of dividends paid on our common stock and $35.4 million of common stock repurchases.

Granite Ridge Credit Agreement

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.

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.

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.

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.

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.

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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.

The Credit Agreement contains certain financial covenants, including the maintenance of the following financial ratios:

(i)a leverage ratio, which is the ratio of Consolidated Total Debt to EBITDAX (each as defined in the Credit Agreement), of not greater than 3.00 to 1.00 as of the last day of each fiscal quarter, and

(ii)a Current Ratio (as defined in the Credit Agreement), of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.

The Credit Agreement contains additional restrictive covenants that limit our ability and our restricted subsidiaries to, among other things, incur additional indebtedness, incur additional liens, enter into mergers and acquisitions, make or declare dividends, repurchase or redeem junior debt, make investments and loans, engage in transactions with affiliates, sell assets and enter into certain hedging transactions. In addition, the Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the administrative agent may, with the consent of majority lenders, or shall, at the direction of the majority lenders, accelerate any amounts outstanding and terminate lender commitments.

As of December 31, 2024, we were in compliance with all covenants required by the Credit Agreement.

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

•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.

•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.

•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 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.

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,

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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, 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.

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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 financial statements, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we provided them our historical information, such as oil and natural gas production, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. The third-party independent reserve engineers, NSAI, evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2024.

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, 2024, 2023, and 2022, we recognized depletion expense of $175.7 million, $160.2 million and $105.3 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 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.

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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.

Item 7. 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 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.

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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, 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.

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.

Our average daily production for the year ended December 31, 2023 was 24,311 Boe per day.

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.”

Business Combination

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”).

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.

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

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.

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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 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.

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 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.

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.

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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, 2023, 2022 and 2021.

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(1)Based on average NYMEX closing prices.

2023 Significant Events

Warrant Exchange

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.

Distribution and Voting Agreement

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.

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”).

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

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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.

Secondary Offering

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.

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, 2023 and 2022. For similar operating and financial data and discussion of our 2022 results compared to our 2021 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, 2022, which was filed with the SEC on March 27, 2023. Because of normal production declines, increased or decreased drilling activities, fluctuations in

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commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.

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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.

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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. 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.

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.

The following table sets forth information regarding our oil and natural gas production by basin.

Lease Operating Expenses

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.

Production and Ad Valorem Taxes

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.

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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 decreased during the year ended December 31, 2023 as compared to 2022, primarily due to additional wells drilled and completed and new wells acquired.

Depletion and Accretion

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.

Impairment of long-lived assets

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

General and Administrative

The following table provides components of our general and administrative expenses for the years ended December 31, 2023 and 2022:

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.

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Gain/(Loss) on Derivatives – Commodity Derivatives

The following table sets forth the gain (loss) on derivatives for the years ended December 31, 2023 and 2022:

The following table represents our net cash receipts from (payments on) derivatives for the years ended December 31, 2023 and 2022:

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 $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.

Gain (Loss) on Derivatives – Common Stock Warrants

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.

Income Tax Expense (Benefit)

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.

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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 and credit facility borrowings. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

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.

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 $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.

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. 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, 2023, 2022 and 2021 are presented below:

Cash Flows from Operating Activities

The primary factors impacting our cash flows from operating activities generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from sales of oil and natural gas production, including settlement proceeds or payments related to our commodity derivatives, (iii) operating costs of our oil and natural gas properties, (iv)

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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 $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.

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.

Cash Flows from Investing Activities

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.

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.

Cash Flows from Financing Activities

For the year ended December 31, 2023, our net cash provided by financing activities was $13.4 million primarily due to $110.0 million of net borrowings under our Credit Agreement, partially offset by $58.6 million of dividends paid on our common stock and $35.4 million of common stock repurchases.

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.

Granite Ridge Credit Agreement

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.

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.

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.

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

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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.

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.

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.

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.

The Credit Agreement also contains certain financial covenants, including the maintenance of the following financial ratios:

(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

(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.

The Credit Agreement contains additional restrictive covenants that limit our ability and our restricted subsidiaries to, among other things, incur additional indebtedness, incur additional liens, enter into mergers and acquisitions, make or declare dividends, repurchase or redeem junior debt, make investments and loans, engage in transactions with affiliates, sell assets and enter into certain hedging transactions. In addition, the Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the administrative agent may, with the consent of majority lenders, or shall, at the direction of the majority lenders, accelerate any amounts outstanding and terminate lender commitments.

As of December 31, 2023, we were in compliance with all covenants required by the Credit Agreement

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

•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.

•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.

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•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 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.

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.

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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, 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.

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 financial statements, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we provided them our historical information, such as oil and natural gas production, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. The third-party independent reserve engineers, NSAI, evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2023.

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, 2023, 2022, and 2021, we recognized depletion expense of $160.2 million, $105.3 million and $94.2 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 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.

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

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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, 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.

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.

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.

Asset Retirement Obligations

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

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known. See Note 6 of the Notes to the Consolidated Financial Statements for additional information regarding our asset retirement obligations.

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 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.

Item 7. 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 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.

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, 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.

As of December 31, 2022, we owned an interest in 2,357 gross (132.88 net) producing wells, 258,694 gross (26,414 net) developed acres, and 17,907 gross (7,896 net) undeveloped acres, all located in the United States.

Our average daily production for the year ended December 31, 2022 was 19,765 Boe per day.

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.”

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Business Combination

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”).

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.

Impacts of COVID-19 Pandemic and Geopolitical Factors

The global spread of COVID-19 since early 2020 has created significant market volatility and economic uncertainty and disruption. The virus created unprecedented challenges for our industry, including a drastic decline in demand for crude oil and natural gas. This, combined with OPEC actions in early 2020, led to spot and future prices of crude oil falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Conditions have significantly improved with the increase in domestic vaccination programs and reduced spread of the COVID-19 virus overall, which have contributed to an improvement in the economy and higher realized prices for commodities since the beginning of 2021.

On February 24, 2022, a large-scale military invasion of Ukraine by Russian troops was reported. Although the length and impact of the ongoing military conflict is highly unpredictable, the conflict in Ukraine has led and could lead to significant market and other disruptions, including significant volatility in commodity prices, and supply of energy resources, instability in credit and capital markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increase in cyberattacks and espionages. Various of Russia’s actions have led to sanctions and other penalties being levied by the U.S., the European Union, and other countries, as well as other public and private actors and companies, against Russia and certain other geographic areas, including agreement to remove certain Russian financial institutions from the SWIFT payment system, expansive bans on imports and exports of products to and from Russia (including imports of Russian oil, liquefied natural gas and coal) and a ban on exportation of U.S. denominated banknotes to Russia or persons located therein. These disruptions in the oil and gas markets have caused, and could continue to cause, significant volatility in energy prices, which could have a material effect on our business. Additional potential sanctions and penalties have also been proposed and/or threatened.

While we use derivative instruments to partially mitigate the impact of commodity price volatility on revenues, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. In addition, because our property interests are not operated by us, we have limited ability to influence or control the future development of such properties. In light of the current price and economic environment, we continue to be proactive with third-party operators to review spending and alter plans as appropriate. We expect that our cash flow from operations and borrowing availability under our credit facilities will allow us to meet our liquidity needs for at least the next 12 months.

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

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

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

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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:

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.

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 2022, 2021 and 2020 was $(1.89) per barrel, $(5.00) per barrel and $(1.94) per barrel, respectively. Our natural gas price differential during 2022, 2021 and 2020 was $0.91 per Mcf, $1.32 per Mcf and $(0.55) per Mcf, respectively.

Market Conditions

The price that we receive for the oil and natural gas our operators produce is largely a function of market supply and demand. Because our oil and natural gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide 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

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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.

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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, 2022, 2021 and 2020.

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The average 2022 NYMEX oil pricing was $94.39 per barrel of oil or 39% higher than the average NYMEX price per barrel in 2021. Our settled derivatives decreased our realized oil price per barrel by $6.48 in 2022 and by $5.58 in 2021. Our average 2022 realized oil price per barrel after reflecting settled derivatives was $86.02 compared to $57.49 in 2021. The average 2022 NYMEX natural gas pricing was $6.55 per Mcf, or 76% higher than the average NYMEX price per Mcf in 2021. Our settled derivatives decreased our realized natural gas price per Mcf by $0.88 in 2022 and by $0.42 in 2021. Our average 2022 realized gas price per Mcf after reflecting settled derivatives was $6.58 compared to $4.62 in 2021.

The average 2021 NYMEX oil pricing was $68.07 per barrel of oil or 73% higher than the average NYMEX price per barrel in 2020. Our settled derivatives decreased our realized oil price per barrel by $5.58 in 2021 and increased our realized oil price per barrel by $5.37 in 2020. Our average 2021 realized oil price per barrel after reflecting settled derivatives was $57.49 compared to $42.77 in 2020. The average 2021 NYMEX natural gas pricing was $3.72 per Mcf, or 75% higher than the average NYMEX price per Mcf in 2020. Our settled derivatives decreased our realized natural gas price per Mcf by $0.42 in 2021 and increased it by $0.17 in 2020. Our average 2021 realized gas price per Mcf after reflecting settled derivatives was $4.62 compared to $1.75 in 2020.

Results of Operations

Year ended December 31, 2022 compared to year ended December 31, 2021

The following table sets forth summary production and operating data for the periods indicated. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.

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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. In 2022, our oil and natural gas sales increased 71% from 2021, driven by an increase in realized prices, excluding the effect of settled commodity derivatives, and an increase in production volumes. The higher average price in 2022 as compared to 2021 was driven by higher average NYMEX oil and natural gas prices.

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Realized 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 108.64 net wells in 2021 to 132.88 net wells in 2022.

The following table sets forth information regarding our oil and natural gas production by basin.

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Lease Operating Expenses

Lease operating expenses were $44.7 million in 2022 compared to $26.3 million in 2021. On a per unit basis, lease operating expenses increased 38% from $4.47 per Boe in 2021 to $6.19 per Boe in 2022. On an absolute dollar basis, the increase in our lease operating expenses in 2022 compared to 2021 was primarily due to an increase in well count due to acquisitions and additional wells successfully drilled and completed, higher transportation and gathering expenses related to certain take-in kind arrangements and overall increased cost of services. Transportation and gathering expenses related to certain take-in kind arrangements increased from $0.9 million in 2021 to $5.6 million in 2022. The increase in lease operating expenses per Boe was primarily due to the increase in lease operating expenses noted above, partially offset by an increase in production.

Production and Ad Valorem Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $26.9 million in 2022 compared to $17.1 million in 2021. As a percentage of oil and natural gas sales, our production taxes were 5% and 6% in 2022 and 2021, respectively. The fluctuation in our average production tax rate from year to year is primarily due to

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changes in our oil sales as a percentage of our total oil and natural gas sales and the mix of our production volumes by basin. However, production taxes as a percent of total oil and natural gas sales are consistent with historical trends.

Ad valorem taxes increased by $2.7 million during the year ended December 31, 2022 as compared to the year ended December 31, 2021, primarily due to additional wells drilled and completed and new wells acquired.

Depletion and Accretion

Depletion and accretion was $105.8 million in 2022 compared to $94.7 million in 2021. Depletion and accretion was $14.66 per Boe in 2022 compared to $16.07 per Boe in 2021. The aggregate increase in depletion and accretion expense for 2022 compared to 2021 was driven by the increase in depletion expense primarily due to the increase in production, partially offset by the decrease in the depletion rate per Boe.

General and Administrative

General and administrative expenses were $14.2 million in 2022 compared to $10.2 million in 2021. The increase was primarily due to higher management fees and higher professional services and legal costs. Management fees were $7.9 million in 2022 compared to $6.2 million in 2021. See Note 10 in the Notes to the Consolidated Financial Statements for additional information on management fees.

Gain on Disposal of Oil and Natural Gas Properties

We did not recognize a gain on disposal of oil and natural gas properties in 2022. We recognized a gain on disposal of oil and natural gas properties of $2.3 million in 2021, primarily due to the sale of certain Permian Basin assets, the sale of a partial unit in the Bakken Basin and the sale of a unit in the SCOOP/STACK Basin.

Gain/(Loss) on Derivatives – Commodity Derivatives

The following table sets forth the loss on derivatives for the years ended December 31, 2022 and 2021:

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The following table represents our net cash payments on derivatives for the years ended December 31, 2022 and 2021:

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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.

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Interest Expense

Interest expense was $2.0 million in 2022 compared to $2.4 million in 2021. The decrease in interest expense was primarily due to lower average outstanding balance on the revolving credit facilities during 2022 as compared to 2021.

Gain on Derivatives – Common Stock Warrants

We recognized a gain of $0.4 million during 2022 from the change in fair value of the warrant liability. See Note 3 in the Notes to the Consolidated Financial Statements for additional information on the common stock warrants.

Income Tax Expense (Benefit)

We recognized an income tax expense of $12.9 million in 2022. There was no income tax expense (benefit) in 2021. The change in income tax expense during the year ended December 31, 2022, compared with 2021, was due to the fact that the Funds were treated as partnerships for U.S. federal income tax purposes and, as such, the partners of the Funds reported their share of the Fund’s income or loss on their respective income tax returns. 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 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.

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Year ended December 31, 2021 compared to year ended December 31, 2020

The following table sets forth selected operating data for the periods indicated. Average sales prices are derived from accrued accounting data for the relevant period indicated.

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Oil, Natural Gas and Related Product Sales

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. In 2021, our oil and natural gas sales increased 233% from 2020, driven by an 104% increase in realized prices, excluding the effect of settled commodity derivatives, and a 63% increase in production volumes. The higher average price in 2021 as compared to 2020 was driven by higher average NYMEX oil and natural gas prices.

Realized production from oil and gas properties increases through drilling success and 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 increased from 83.67 net wells in 2020 to 108.64 net wells in 2021.

The following table sets forth information regarding our oil and natural gas production by basin and realized prices for the periods indicated.

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Lease Operating Expenses

Lease operating expenses were $26.3 million in 2021 compared to $20.4 million in 2020. On a per unit basis, lease operating expenses decreased 26% from $5.65 per Boe in 2020 to $4.47 per Boe in 2021 due primarily to higher production volumes over which fixed costs can be spread. On an absolute dollar basis, the 29% increase in our lease operating expenses in 2021 compared to 2020 was primarily due to an increase in well count due to acquisitions and additional wells successfully drilled and completed.

Production and Ad Valorem Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $17.1 million in 2021 compared to $6.0 million in 2020. As a percentage of oil and natural gas sales, our production taxes were 6% and 7% in 2021 and 2020, respectively. The fluctuation in our average production tax rate from year to year is primarily due to

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changes in our oil sales as a percentage of our total oil and natural gas sales and the mix of our production volumes by basin. However, production taxes as a percent of total oil and natural gas sales are consistent with historical trend.

Ad valorem taxes increased by $0.3 million during the year ended December 31, 2021 as compared to the year ended December 31, 2020, primarily due to additional wells drilled and completed and new wells acquired.

Depletion and Accretion

Depletion and accretion was $94.7 million in 2021 compared to $79.9 million in 2020. Depletion and accretion was $16.07 per Boe in 2021 compared to $22.14 per Boe in 2020. The aggregate increase in depletion and accretion expense for 2021 compared to 2020 was driven by a 63% increase in production levels, partially offset by the decrease in the depletion rate per Boe.

Impairments of long-lived assets

We did not record any impairments of oil and natural gas properties in 2021. In 2020, as a result of low commodity prices and their effect on the proved reserve values of our properties, we recorded an impairment of $5.7 million to our proved oil and natural gas properties.

General and Administrative

General and administrative expenses were $10.2 million in 2021 compared to $10.1 million in 2020. General and administrative expense remained materially consistent in 2021 compared to 2020. General and administrative fees include management fees which were $6.2 million in 2021 compared to $6.6 million in 2020.

Gain on Disposal of Oil and Natural Gas Properties

We recognized a gain on disposal of oil and natural gas properties of $2.3 million in 2021 compared to $0.6 million in 2020. The increase in 2021 was primarily driven by the sale of Permian Basin assets, the sale of a partial unit in the Bakken Basin and the sale of a complete unit in our SCOOP/STACK Basin.

Gain/(Loss) on Derivatives

The following table sets forth the (loss) gain on derivatives for the years ended December 31, 2021 and 2020:

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The following table represents our net cash (payments on) receipts from derivatives for the years ended December 31, 2021 and 2020:

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Our earnings are affected by the changes in 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 $2.4 million in 2021 compared to $1.8 million in 2020. The increase in interest expense for 2021 as compared to 2020 was primarily due to an increase in the outstanding balance on the revolving credit facility.

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 and credit facility borrowings. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

As of December 31, 2022, we had no outstanding debt under our Credit Agreement. We had $200.8 million of liquidity as of December 31, 2022, consisting of $150.0 million of committed borrowing availability under the Credit Agreement and $50.8 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 $10.7 million, or $0.08 per share during the fourth quarter of 2022. On February 21, 2023, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2023 that was paid on March 15, 2023 to stockholders of record as of March 1, 2023. 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 million of our common stock through December 31, 2023. Under the stock repurchase program, we will repurchase shares of our common stock from time to time in open market transactions or in privately negotiated transactions as permitted under applicable rules and regulations. The Board of Directors of the Company may limit or terminate the stock repurchase program at any time without prior notice, but, with no further action of the Board of Directors of the Company, the stock repurchase program will terminate on December 31, 2023.

As of December 31, 2022, we had repurchased 25,920 shares under the program at an aggregate cost of $0.2 million. The extent to which we repurchase our shares of common stock, and the timing of such repurchases, will depend upon market conditions and other considerations as may be considered in our sole discretion.

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Cash Flows

Our cash flows for the years ended December 31, 2022, 2021 and 2020 are presented below:

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Cash Flows from Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volume of oil and natural gas sold by our producers. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Credit Agreement.

Net cash provided by operating activities in 2022 was $346.4 million, compared to $181.2 million in 2021. The increase in net cash provided by operating activities was primarily due to an increase in total operating revenues attributable to an increase in production and higher realized oil and natural gas prices. The increase was partially offset by higher settlements paid on commodity derivatives and higher operating expense. We paid $42.4 million of settlements on commodity derivatives during 2022 as compared to $25.2 million during 2021.

Our net cash provided by operating activities included a reduction of $17.2 million and $26.9 million for the years ended December 31, 2022 and 2021, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Net cash provided by operating activities in 2021 was $181.2 million, compared to $66.8 million in 2020. The increase in net cash provided by operating activities was primarily due to an increase in total operating revenues attributable to an increase in production and higher realized oil and natural gas prices. The increase was partially offset by $25.2 million of settlements paid on commodity derivatives during 2021 as compared to $11.9 million of cash receipts during 2020.

Our net cash provided by operating activities included a reduction of $26.9 million and a benefit of $6.7 million for the years ended December 31, 2021 and 2020, respectively, associated with changes in working capital items.

Cash Flows from Investing Activities

For the year ended December 31, 2022, our net cash used in investing activities was $230.6 million, which consisted primarily of our investment of $185.5 million for additions to oil and natural gas properties and $49.2 million of acquisitions of oil and natural gas properties.

For the year ended December 31, 2021, our net cash used in investing activities was $186.0 million, which consisted primarily of our investment of $136.1 million of additions to oil and natural gas properties and $83.2 million of acquisitions of oil and natural gas properties, partially offset by $29.4 million of proceeds received from the disposition of certain oil and natural gas assets.

For the year ended December 31, 2020, our net cash used in investing activities was $116.7 million, which consisted primarily of our investment of $99.5 million of additions to oil and natural gas properties and $17.9 million of acquisitions of oil and natural gas properties.

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Cash Flows from Financing Activities

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.

For the years ended December 31, 2021 and 2020, our net cash provided from financing activities was $8.5 million and $52.1 million, respectively. Net cash provided from financing activities in these years was primarily related to partners’ contributions and proceeds from borrowings on our credit facilities, partially offset by repayments of borrowings and partners’ distributions.

Granite Ridge Credit Agreement

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.

The Credit Agreement provides for aggregate elected commitments of $150.0 million, an initial borrowing base of $325.0 million and an aggregate maximum revolving credit amount of $1,000.0 million. The borrowing base is scheduled to be redetermined semiannually on or about April 1 and October 1 of each calendar year, commencing April 1, 2023, 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. Additionally, each of the Company and the Required Lenders (as defined in the Credit Agreement) may request one unscheduled redetermination of the borrowing base between each scheduled redetermination. The amount of the borrowing base is determined by the lenders in their sole discretion and consistent with the oil and gas lending criteria of the lenders at the time of the relevant redetermination. The amount 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.

As of December 31, 2022, we did not have any borrowings or letters of credit outstanding under the Credit Agreement, resulting in availability of $150.0 million. The Credit 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 our restricted subsidiaries.

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 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 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 an applicable margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized. We also pay a commitment fee on unused elected commitment amounts under its 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.

The Credit Agreement also contains certain financial covenants, including the maintenance of the following financial ratios:

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The Credit Agreement contains additional restrictive covenants that limit our ability and our restricted subsidiaries to, among other things, incur additional indebtedness, incur additional liens, enter into mergers and acquisitions, make or declare dividends, repurchase or redeem junior debt, make investments and loans, engage in transactions with affiliates, sell assets and enter into certain hedging transactions. In addition, the Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the administrative agent may, with the consent of majority lenders, or shall, at the direction of the majority lenders, accelerate any amounts outstanding and terminate lender commitments.

As of December 31, 2022, we were in compliance with all covenants required by the Credit Agreement

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

On October 24, 2022, the Funds terminated their revolving credit facilities, and we entered into a new credit agreement. As of December 31, 2022, there was no outstanding balance on the Credit Agreement. See Note 8 of the Notes to the Consolidated Financial Statements. 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. 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 2023, we are budgeting approximately $260 million to $270 million in total planned capital expenditures, including approximately $46 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.

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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, 2022, approximately 39% 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 financial statements, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external

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petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests. 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, 2022.

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 and accretion of oil and natural gas producing properties is determined using the units-of-production method. During the years ended December 31, 2022, 2021 and 2020, we recognized depletion and accretion expense of $105.8 million, $94.7 million and $79.9 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 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.

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, 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, 2022, our estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2023 price of $79.12 per barrel of oil decreasing to a 2027 price of $64.14 per barrel of oil. Natural gas prices ranged from a 2023 price of $4.26 per Mcf of natural gas increasing to a 2027 price of $4.50 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2027.

In March 2020, crude oil demand experienced significant declines due to the COVID-19 pandemic and resulting governmental led shut-downs in economic activity. During 2020, as it became apparent that the pandemic would continue with sustained significant decline in crude oil prices, we assessed our proved oil and natural gas properties for impairment and recorded impairment expense of $5.7 million during the year ended December 31, 2020. We did not incur any

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impairment expense related to our proved oil and natural gas properties during the years ended December 31, 2022 and 2021.

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, 2022, 2021 and 2020 related to its unproved oil and natural gas properties.

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.

Asset Retirement Obligations

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.

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 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.

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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.

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