As it pertains to the periods prior to completion of the Business Combination, the financial statements have been presented on a combined historical basis due to the Funds' prior common ownership and control. Prior to the Business Combination, the financial statements include the accounts of the Funds, all of which were commonly owned and controlled. All inter-entity balances and transactions have been eliminated in combination.

As it pertains to the period subsequent to completion of the Business Combination, the accompanying consolidated financial statements also include the accounts of the Company, and all other wholly owned subsidiaries created in connection with the Business Combination. References to the “Company” prior to October 24, 2022 refer to the combined business of the Funds and references after October 24, 2022 refer to the consolidated business of Granite Ridge Resources, Inc.

As a result of the Business Combination, periods prior to October 24, 2022 reflect Funds as limited partnerships, not as corporations. The primary financial impacts of the Transactions to the consolidated financial statements were (i) reclassification of partnership capital accounts to equity accounts reflective of a corporation and (ii) income tax effects. Since the Funds were identified as entities under common control, the consolidated financial statements for periods prior to the GREP Formation Transaction have been adjusted to retrospectively combine the previously separate entities for presentation purposes. All intercompany transactions within the consolidated businesses of the Company have been eliminated.

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The Company operates in one operating segment, which is oil and natural gas development, exploration and production. All of our operations are conducted in the geographic area of the United States. The Company’s chief operating decision maker manages operations on a consolidated basis for purposes of evaluating operations and allocating resources.

The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates of reserves are used to determine depletion and to conduct impairment analysis. Estimating reserves is inherently uncertain, including the projection of future rates of production and the timing of development expenditures.

The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and natural gas prices, future operating costs, severance taxes, development costs and work over costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.

During the fourth quarter of 2023, the Company determined that the prior year consolidated financial statements had a misstatement caused by an error in determining the tax basis of oil and natural gas properties. Management concluded that the impact of this error on the prior year consolidated financial statements period is immaterial. However, given that the adjustment to correct the error in the current year consolidated financial statements would have a material impact on 2023, the Company has corrected the prior period consolidated financial statements in this Annual Report on Form 10-K in accordance with SEC guidance. The adjustment had no effect on the Company's net income, cash flows, total assets or total liabilities and stockholders' equity, and the information included in this Annual Report on Form 10-K sets forth the effects of this correction on the previously reported consolidated balance sheet as of December 31, 2022.

Due to transactions that were completed immediately prior to the Business Combination, the tax basis of oil and natural gas properties transferred to the Company was higher than initially recognized in 2022. As a result, the Company has corrected the deferred tax liability and additional paid-in capital in the accompanying consolidated balance sheet to properly reflect the increased tax basis upon the completion of the Business Combination. As shown below, the previously reported deferred tax liability as of December 31, 2022 has decreased and additional paid-in capital as of December 31, 2022 has

Cash represents liquid cash and investments with an original maturity of 90 days or less. The Company places its cash with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. The Company has not incurred any losses related to amounts in excess of FDIC limits.

As of December 31, 2023 and 2022, the Company had $0.3 million of cash classified as restricted. This balance relates to a cash deposit for two standby letters of credit associated with oil and natural gas mining lease agreements. Restricted cash consists of cash that is stated at cost, which approximates fair market value. Classification of restricted cash is based on the nature of the restrictions associated with the underlying assets.

Revenue receivable is comprised of accrued oil and natural gas sales. The operators remit payment for production directly to the Company. In the event of complete non-performance by the Company’s customers, the maximum exposure to the Company is the outstanding revenue receivable balance at the date of non-performance. The Company monitors this exposure primarily by reviewing credit ratings, financial statements and payment history. Revenue receivables are generally unsecured and typically received from the operator one to three months after production. The Company had an allowance for expected credit losses of $0.2 million at December 31, 2023 and $0.2 million at January 1, 2023, which was based on a historical loss rate. For the years ended December 31, 2022 and 2021, the Company’s bad debt expense and allowance for doubtful accounts was immaterial.

The Company participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital-intensive nature of oil and natural gas drilling activities, our partner operators may request advance payments from working interest partners for their share of the costs. The Company expects such advances to be applied by these operators against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Changes in advances to operators are presented as an investing outflow within capital expenditures for oil and gas properties on the statement of cash flows.

The Company uses the successful efforts method of accounting for oil and gas producing activities, as further defined under ASC 932, Extractive Activities - Oil and Gas (“ASC 932”). Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory leases that find proved reserves, and to drill and equip development leases and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determinations of whether the wells have proved reserves. If the Company determines that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determinations of whether the wells have proved reserves as of December 31, 2023 or 2022.

Capitalized leasehold costs relating to proved properties are depleted using the unit-of-production method based on proved reserves. The depletion of capitalized drilling and development costs and integrated assets is based on the unit-of-production method using proved developed reserves. The Company recognized depletion expense of $160.2 million, $105.3 million and $94.2 million for the years ended December 31, 2023, 2022, and 2021, respectively. As a result of the Business Combination, the Company aggregated certain proved properties for amortization and impairment purposes.

Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the year ended December 31, 2023, the Company capitalized $1.0 million of interest costs. For the years ended December 31, 2022 and 2021, no interest costs were capitalized. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Effective January 1, 2019, the Company adopted ASU 2017-1, Business Combinations: Clarifying the Definition of Business (“ASU 2017-1”), with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. See discussions of the Company’s oil and natural gas asset acquisitions and business combinations in Note 5. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. See Note 5 for additional information on our divestitures. Ordinary maintenance and repair costs are expensed as incurred.

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair market value as determined by discounted future cash flows using a discount rate similar to that used by market participants, or comparable market value if available, is recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company recorded proved property impairment of $26.5 million for the year ended December 31, 2023 related to its Haynesville properties. There were no proved property impairment indicators for the years ended December 31, 2022 or 2021.

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. 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.

Prior to the Warrant Exchange, the Company accounted for warrants as liability-classified instruments based on an assessment of the warrant’s specific terms and applicable authoritative guidance in Accounting Standards Codification (“ASC”) Topic 480, “Distinguishing Liabilities from Equity” (“ASC 480”) and ASC Topic 815, “Derivatives and Hedging” (“ASC 815”). The warrants were required to be recorded at their initial fair value on the date of issuance, and each balance sheet date thereafter. Changes in the estimated fair value of the warrants were recognized as a non-operating gain or loss on the consolidated statements of operations. For the period during which the Company’s common stock was publicly traded, the fair value of the warrants was based on quoted prices in an active market. Refer to Note 4 for further discussion on fair value considerations.

On June 22, 2023, the Company 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. 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 for further discussion of the Warrant Exchange.

The Company follows the guidance in ASC 321, "Investments - Equity Securities" (“ASC 321”) for its investment in the common and preferred stock of Vital Energy. ASC 321 requires equity investments with readily determinable fair values to be measured at fair value, with unrealized holding gains and losses recorded as a gain or loss on the consolidated statements of operations. For the preferred stock that does not have a readily determinable fair value, the Company has not elected the measurement alternative in ASC 321 and instead will account for the preferred stock at fair value with unrealized gains and losses recorded through net income. For the year ended December 31, 2023, an unrealized gain of $0.5 million on the change in fair value of the common and preferred stock is included in the consolidated statements of operations.

The Company follows the provisions of ASC 410-20, "Asset Retirement Obligations" ("ASC 410-20"). ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The Company’s asset retirement obligation relates to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related oil and natural gas property asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. Based on certain factors, including commodity prices and costs, the Company may revise its previous estimates of the liability, which would also increase or decrease the related oil and natural gas property asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss for the difference of the settled amount and recorded liability.

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Due to the subjectivity of assumptions and the relatively long lives of the Company’s leases, the costs to ultimately retire the Company’s leases may vary significantly from prior estimates.

The Company receives payment from the sale of oil and natural gas production from one to three months after delivery. The transaction price is variable as it is based on market prices for oil and natural gas, less revenue deductions such as gathering, transportation and compression costs. Management has determined that the variable revenue constraint is overcome at the date control passes to the customer since the variable consideration to be received can be reasonably estimated based on daily market prices and historical transportation charges. Revenue is presented net of these costs within the consolidated statements of operations. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in revenue receivable in the balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received; however, differences have been and are insignificant.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company’s proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of transportation and production tax costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within one to three months after the month in which production occurs.

Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream customer’s processing plant in lieu of receiving a net payment from the operator representing its proportionate share of its natural gas production. The Company currently takes certain processed gas volumes in kind in lieu of monetary settlement but does not currently take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, gathering and processing costs and transportation expenses the Company incurs to transport the processed products to downstream customers are recorded in lease operating expenses on the consolidated statements of operations.

The Company’s disaggregated revenue has two primary sources: oil sales and natural gas sales. Substantially all of the Company’s oil and natural gas sales come from five geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Haynesville Basin (Texas/Louisiana), the Denver-Julesburg “DJ” Basin (Colorado), and the Bakken Basin (Montana/North Dakota). The Company previously owned oil and natural gas assets in the SCOOP/STACK Basin in Oklahoma, which were sold during the year ended December 31, 2022. The following tables present the


	Year Ended December 31,
(in thousands)	2023		2022		2021
Oil	$	317,099	$	338,163	$	215,250
Natural gas	76,970		159,254		74,943
Total	$	394,069	$	497,417	$	290,193


Permian	$	237,730	$	266,856	$	151,179
Eagle Ford	46,410		64,879		40,898
Bakken	51,128		64,999		56,055
Haynesville	24,833		62,743		12,039
DJ	33,968		37,880		29,191
SCOOP/STACK	—		60		831
Total	$	394,069	$	497,417	$	290,193

Prior to the Business Combination, GREP and the associated activities held by the Funds were treated as partnerships for U.S. federal income tax purposes and were not subject to U.S. federal income tax. As a result of the Business Combination, the Company became a C corporation and is subject to U.S. federal income tax and state and local income taxes, and accounts for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rate on deferred income tax assets and liabilities is recognized in income in the period that includes the enactment date.

A valuation allowance is provided for deferred income taxes if it is more likely than not these items will either expire before the Company is able to realize their benefits or if future deductibility is uncertain. Additionally, the Company evaluates tax positions under a more likely than not recognition threshold and measurement analysis before the positions are recognized for financial statement reporting. For further discussion, see Note 7.

Stock-based compensation expense is recognized in the Company's consolidated financial statements on an accelerated basis over the awards' vesting periods based on their grant date fair values. Restricted stock awards are valued at the closing price of the Company's common stock on the date of grant. The Company utilizes the Monte Carlo simulation method to determine the fair value of certain performance stock units ("PSUs"), the Black-Scholes model for options issued at-the-money and a binomial lattice model for other stock options. The Company recognizes forfeitures on stock-based compensation awards as they occur.

In June 2022, the FASB issued ASU No. 2022-03, "Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions," ("ASU 2022-03") which clarifies that a contractual restriction on the sale of an equity security is not considered part of the unit of account of the equity security and, therefore, is not considered in measuring fair value. ASU 2022-03 also clarifies that an entity cannot, as a separate unit of account, recognize and measure a contractual sale restriction and requires specific disclosures for equity securities subject to contractual sale restrictions such as the fair value of equity securities subject to contractual sale restrictions, the nature and remaining duration of the restrictions and the circumstances that could cause a lapse in the restriction. ASU 2022-03 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2023, with early application permitted. The Company does not expect the adoption of ASU 2022-03 to have a significant impact on its consolidated financial statements.

In November 2023, the FASB issued ASU No. 2023-07, "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures," ("ASU 2023-07") which requires public entities, including public entities with a single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and to provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. ASU 2023-07 is effective beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Company is currently assessing the effect that ASU 2023-07 will have on its disclosures.

In December 2023, the FASB issued ASU No. 2023-09, "Improvements to Income Tax Disclosures," ("ASU 2023-09") which requires disaggregated information about a reporting entity’s effective tax rate reconciliation as well as information on income taxes paid. The standard is intended to benefit investors by providing more detailed income tax disclosures that would be useful in making capital allocation decisions. ASU 2023-09 is effective for annual periods beginning after December 15, 2024. Early adoption is permitted. The Company has not early adopted the standard and is currently assessing the effect that ASU 2023-09 will have on its disclosures.

The FASB issued ASU No. 2016-13, “Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” which replaced the “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. The adoption of this guidance on January 1, 2023 did not have a material impact on the Company’s consolidated financial statements or related disclosures. Revenue receivables is the primary financial asset that is within the scope of the new guidance. A loss-rate method is applied to the receivables to estimate credit losses. The Company recognized a tax effected $0.1 million non-cash cumulative effect adjustment to retained earnings on its opening consolidated balance sheet at January 1, 2023 to record an allowance for expected credit losses associated with the Company’s revenue receivables.