Granite Ridge Resources, Inc.

1. Organization and Nature of Operations

Granite Ridge Resources, Inc. (together with its consolidated subsidiaries, “Granite Ridge” or the “Company”), a Delaware corporation, 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 in multiple basins throughout North America. The Company was initially formed in May 2022 for the purpose of the Business Combination (as defined below), and following the Business Combination, for the purpose of purchasing oil and natural gas assets in multiple basins in North America and realizing profits through participation in oil and natural gas wells.

On October 24, 2022, the Business Combination closed and was accounted for as a reverse recapitalization and Grey Rock Energy Fund III (as defined below) was determined to be the accounting acquirer and Predecessor (as defined below).

On October 24, 2022 (the “Closing Date”), Granite Ridge and Executive Network Partnering Corporation, a Delaware 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”).

Immediately prior to the closing of the Transactions, the net assets of Grey Rock Energy Fund, L.P., a Delaware limited partnership (“Fund I”), 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”) were transferred (through various intermediary entities) to GREP (the “GREP Formation Transaction”). Fund I, Fund II and Fund III are collectively referred to herein as the “Funds”.

At the special meeting of ENPC stockholders held in connection with the Business Combination, of the 41,400,000 shares of ENPC Class A common stock, public stockholders of 39,343,496 shares of ENPC Class A common stock exercised their rights to have those shares redeemed for cash at a redemption price of approximately $10.07 per share, or an aggregate of approximately $396.1 million. The holders of membership interests in GREP (the “Existing GREP Members”) and their direct and indirect members were issued 130.0 million shares of Granite Ridge common stock at the closing. Upon consummation of the Business Combination, each public stockholder’s ENPC common stock and ENPC warrants were automatically converted into an equivalent number of shares of Granite Ridge common stock and Granite Ridge warrants as a result of the Transactions. At the effective time of the Mergers, (i)495,357 shares of ENPC Class F common stock were converted to 1,238,393 shares of ENPC Class A common stock (of which an aggregate of 220,348 shares were subsequently forfeited pursuant to the terms of the Sponsor Agreement, dated as of May 16, 2022, by and among ENPC, Granite Ridge, and certain other parties thereto (the "Sponsor Agreement")) and the remaining shares of ENPC Class F common stock outstanding were automatically cancelled for no consideration (the “ENPC Class F Conversion”) (ii) all other remaining shares of ENPC Class A common stock automatically cancelled without any conversion, payment or distribution (the “Sponsor Share Cancellation”) and (iii) all shares of ENPC Class B common stock outstanding were deemed transferred to ENPC and surrendered and forfeited for no consideration (the “ENPC Class B Contribution”). In

January 2023,220,348 of the 371,518 shares subject to vesting and forfeiture provisions under the terms of the Sponsor Agreement were forfeited.

Following the ENPC Class F Conversion, the Sponsor Share Cancellation, the ENPC Class B Contribution and the separation of the securities offered in ENPC’s initial public offering, which consisted ofone share of Class A common stock and one-quarter of one ENPC warrant (“CAPSTM Separation”), each share of ENPC Class A common stock outstanding was automatically converted intoone share of Granite Ridge common stock. Total aggregate investment by ENPC was $6.8 million, which amount represents total risk capital contributed by ENPC, including working capital loans that were forgiven.

Fund III, Fund I and Fund II were identified as entities under common control, in which all entities are ultimately controlled by the same party before and after the GREP Formation Transaction and therefore resulted in a change in reporting entity. In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805-50-45-5, for transactions between entities under common control, the consolidated financial statements for periods prior to the GREP Formation Transaction were adjusted to retrospectively combine the previously separate entities for presentation purposes.

Warrant Exchange

On October 24, 2022, in connection with the Business Combination, the Company issued 10,349,975 common stock warrants. On June 22, 2023, the Company completed an offer to holders of its outstanding warrants which provided such holders the opportunity to receive 0.25 shares of the Company’s 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 the warrant agreement governing such warrants 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 the Company’s common stock (together with the Offer, the “Warrant Exchange”). 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.

2. Summary of Significant Accounting Policies

Basis of Presentation, Principles of Consolidation and Reclassifications

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The accompanying consolidated financial statements include the accounts of the Company and all of its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to prior years' reported amounts to conform to the current year presentation.

Segment Reporting

The Company operates inone reporting segment, which is oil and natural gas development, exploration and production. All of the Company's operations are conducted in the geographic area of the United States. The reporting segment generates revenue through the sale of oil and natural gas. The Company’s chief operating decision maker (“CODM”), who is the Company’s Chief Executive Officer, manages operations on a consolidated basis for purposes of evaluating operational performance and allocating resources. Net income, as reported within the Company’s consolidated statements of operations, is used by the CODM to assess performance for the oil and natural gas development, exploration and production segment. Significant segment expenses are the same as those reported in the consolidated statements of operations. Total assets, as reported within the Company’s consolidated balance sheets, is the measure of segment assets.

Use of Estimates

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 workover 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.

Additional significant estimates include, but are not limited to, fair value of derivative financial instruments, fair value of assets acquired and liabilities assumed for business combinations, fair value of oil and natural gas properties for impairment, asset retirement obligations, revenue receivable and income taxes. Actual results could differ from those estimates.

Cash and Restricted Cash

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.

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. During 2024, the standby letters of credit associated with oil and natural gas lease agreements were terminated and, as a result, the Company hadno restricted cash at December 31, 2025 or 2024.

Revenue Receivable

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 are typically received from the operatorone tothree months after production. As of December 31, 2025 and 2024, the Company had an allowance for expected credit losses of $0.1 million and $0.2 million, which was based on a historical loss rate.

The Company considers forecasts of future economic conditions in the estimate of its expected credit losses, in particular whether there is an increase in the probability that the Company’s counterparties are unable to pay their obligations when due, and adjusts its allowance for expected credit losses when necessary.

Advances to Operators

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 natural gas properties on the consolidated statements of cash flows.

Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for oil and natural 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 wereno exploratory wells capitalized pending determinations of whether the wells have proved reserves as of December 31, 2025 or 2024.

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 $214.8 million, $175.7 million and $160.2 million for the years ended December 31, 2025, 2024, and 2023, respectively.

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. Costs incurred to maintain wells and related equipment are charged to expense as incurred. 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. The Company capitalized $1.3 million and $1.0 million of interest costs for the years ended December 31, 2025 and 2023, respectively. No interest costs were capitalized for the year ended December 31, 2024.

Gains or losses are recorded for sales or dispositions of proved oil and gas properties which constitute an entire depletion base or 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. Dispositions of individual properties that do not significantly alter the depletion rates are generally accounted for as adjustments to capitalized costs with no gain or loss recorded.

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 is recognized at that time. The fair value of impaired assets is determined using the market or income valuation approach. The income approach is calculated using a discounted cash flow model. Discounted future cash flows use a discount rate similar to that used by market participants, or comparable market value if available. 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. The Company recorded proved property impairment of $44.7 million, $35.6 million, and $26.5 million for the years ended December 31, 2025, 2024, and 2023, respectively.

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. There wereno impairments to unproved oil and gas properties for the years ended December 31, 2025 and 2023. The Company recorded unproved oil and gas properties impairment of $0.7 million for the year ended December 31, 2024.

Derivative Instruments- Commodity Derivatives

The Company recognizes its derivative instruments as either assets or liabilities measured at fair value. The Company nets the fair value of the derivative instruments by counterparty in the accompanying consolidated balance sheets when the right of offset exists. The Company does not have any derivatives designated as fair value or cash flow hedges.

Derivative Instruments- Common Stock Warrants

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 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 in 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.

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. 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.

Equity Investments

In December 2023, the Company completed the sale of certain of its Permian Basin assets to Vital Energy, Inc. ("Vital Energy") for consideration of 561,752 shares of Vital Energy's common stock and 541,155 shares of Vital Energy's 2.0% cumulative mandatorily convertible preferred securities. On June 4, 2024, the 2.0% cumulative mandatorily convertible preferred securities were converted into the equivalent number of shares of Vital Energy’s common stock.

On December 15, 2025, Crescent Energy Company (“Crescent Energy”) completed its previously announced merger with Vital Energy. Under the merger agreement, each issued and outstanding share of Vital Energy common stock was converted into 1.9062 shares of Crescent Energy Class A common stock. As a result of the transaction, the Company’s 685,271 shares of Vital Energy common stock at the time of the merger were converted into 1,306,263 shares of Crescent Energy Class A common stock.

The Company follows the guidance in ASC 321, "Investments - Equity Securities" (“ASC 321”) for its investment in the common and preferred stock. 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 in the consolidated statements of operations. Unrealized gain (loss) resulting from the changes in fair value of equity investments is included in gain (loss) on equity investments within the Company’s consolidated statements of operations. For the preferred stock that did not have a readily determinable fair value, the Company did not elect the measurement alternative in ASC 321 and instead accounted for the preferred stock at fair value with unrealized gains and losses recorded through net income for the periods until the preferred stock was converted into common stock. The Company divested of certain shares of common stock and recognized a realized gain (loss) included in gain (loss) on equity investments within the Company’s consolidated statements of operations.

The following table summarizes the amounts reported as gain (loss) on equity investments in the consolidated statements of operations for the years ended December 31, 2025, 2024 and 2023:

Asset Retirement Obligations

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 obligations relate 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.

Revenue Recognition

The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. The Company recognizes revenue from its interests in the sales of oil and natural gas in the period that its performance obligations are satisfied.

Performance obligations are satisfied when the customer obtains control of the product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined, and when collectability is probable.

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 consolidated 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.

Non-operated Crude Oil and Natural Gas Revenues

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 revenue deductions such as gathering, transportation and compression costs incurred by the operator. 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.

Take in Kind Oil and Natural Gas Revenues

Under certain arrangements, the Company has the right to take a volume of unprocessed gas in kind at the operator's wellhead, representing its proportionate share of its natural gas production, in lieu of receiving a net payment from the operator. The Company currently takes certain natural gas volumes in kind in lieu of monetary settlement. When the Company elects to take volumes in kind, it pays third parties to transport the natural gas 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 volumes to downstream customers are recorded in lease operating expenses in the consolidated statements of operations.

Disaggregated Oil and Natural Gas Revenues

The Company’s disaggregated revenue hastwo primary sources: oil sales and natural gas sales. Substantially all of the Company’s oil and natural gas sales come fromsix geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas/New Mexico), the Haynesville Basin (Texas/Louisiana), the Denver-Julesburg “DJ” Basin (Colorado), the Bakken Basin (Montana/North Dakota), and the Appalachian Basin (Ohio). The following tables present the disaggregation of the Company’s oil and natural gas revenues by basin for the years ended December 31, 2025, 2024 and 2023.

Lease Operating Expenses

Lease operating expenses represents field employees’ salaries, saltwater disposal, repairs and maintenance, expensed workovers and other operating expenses. Lease operating expenses are expensed as incurred.

Production and Ad Valorem Taxes

The Company incurs production taxes on the sale of its production. These taxes are reported on a gross basis. Production taxes for the years ended December 31, 2025, 2024 and 2023 were approximately $22.4 million, $21.0 million and $24.9 million, respectively.

The Company incurs ad valorem tax on the value of its properties in certain states. Ad valorem taxes for the years ended December 31, 2025, 2024 and 2023 were approximately $5.2 million, $5.0 million and $2.8 million, respectively.

Income Taxes

The Company is a C corporation and subject to U.S. federal, 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 enacted 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 recorded against deferred tax assets when, based on the weight of available evidence, it is more likely than not that some or all of the deferred tax assets will not be realized. 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.

Stock-Based Compensation

The Company grants various types of stock-based awards, including restricted stock awards, performance stock units ("PSUs"), and stock options. Stock-based compensation awards are measured at fair value on the date of grant and are expensed over the requisite service period. The Company records expense associated with the fair value of stock-based compensation under the fair value recognition provisions of ASC Topic 718, "Compensation-Stock Compensation" and that expense is included within "General and administrative" expense in the accompanying consolidated statements of operations. The Company recognizes forfeitures of stock-based compensation awards as they occur. The Company's stock incentive plan and related accounting policies are defined and described more fully in Note 13.

Debt Issuance Costs and Discounts

Debt issuance costs related to the Company’s revolving credit facility are recorded as deferred financing costs within "Other long-term assets" in the consolidated balance sheets and are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs and original issuance discount associated with the Company’s senior unsecured notes are deferred and amortized to interest expense over the contractual term of the notes. Such amounts are presented as a reduction of the carrying amount of the related debt within long-term debt, net, in the consolidated balance sheets.

Recently Issued and Applicable Accounting Pronouncements (Issued and Not Yet Adopted)

In November 2024, the FASB issued ASU 2024-03, "Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses" ("ASU 2024-03"), which requires enhanced disclosure about specific types of expenses included in the expense captions presented on the face of the consolidated statement of operations as well as disclosures about selling expenses. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods beginning after December 15, 2027, with early adoption permitted. The Company is currently assessing the effect that ASU 2024-03 will have on its disclosures.

Recently Issued and Applicable Accounting Pronouncements (Issued and Adopted)

The FASB issued ASU 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 receivable 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 receivable.

In December 2023, the FASB issued ASU 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 was effective for annual periods beginning after December 15, 2024, with early adoption permitted. The Company adopted this accounting standard beginning in this Annual Report on Form 10-K. See Note 7 for enhanced income tax disclosures resulting from the adoption of ASU 2023-09.

3. Derivative Financial Instruments

The Company uses derivative financial instruments in connection with its oil and natural gas operations to provide an economic hedge of the Company’s exposure to commodity price risk associated with anticipated future oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative trading purposes.

The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its consolidated statements of operations as they occur.

Commodity Derivatives Collar Option Contracts and Swaps

The Company’s commodity derivative financial instruments consist of collar option contracts and swaps. A collar option is established with the sale of a short call option (ceiling price) and the purchase of a long put option (floor price) set to expire at a predetermined date in the future. The options give the owner the right but not the obligation to exercise the option at the expiration date.

When the settlement price is below the established floor price, the Company receives an amount from its counterparty equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is above the established ceiling price, the Company pays its counterparty an amount equal to the difference between the settlement price and the ceiling price multiplied by the hedged contract volume. When the settlement price is between the established floor and the ceiling, no amounts are due to or from the counterparty.

A swap contract allows the Company to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.

The Company has master netting agreements on individual derivative instruments with its counterparties and therefore certain amounts may be presented on a net basis in the consolidated balance sheets.

Volume of Commodity Derivative Collar Option Contracts and Swap Activities

The following table sets forth the Company’s outstanding commodity derivative contracts as of December 31, 2025.

Power Capacity Contract

On December 12, 2025, the Company entered into a power capacity contract ("Power Capacity Contract") as part of its strategy to enhance the value of its natural gas production. The arrangement is intended to economically hedge exposure to weak regional gas pricing and negative basis differentials by providing participation in power market revenues derived from converting natural gas into electricity.

The counterparty is constructing a fleet of distributed power generation facilities with an aggregate capacity of 200 megawatts, which are expected to begin commercial operations in late 2026. The Company’s agreement covers a portion of the total expected capacity and has aseven-year settlement term commencing upon the first facility achieving commercial operations.

Under the arrangement, the Company is obligated to make fixed monthly payments based on operating generation capacity multiplied by its participation interest. In return, the Company receives variable payments representing its share of the facilities’ operating profit. Operating profit is generally defined as revenue from the sale of power, less gas feedstock costs and a fixed operating and maintenance charge.

The structure allows the Company to benefit when power prices are favorable relative to gas prices, helping offset periods of depressed gas realizations. Conversely, when gas prices are strong and power generation is less economical, the Company may make net payments under the arrangement but benefits from improved cash flows on its physical gas sales. Overall, the arrangement is intended to stabilize and potentially enhance cash flows by diversifying the Company’s overall commodity price exposure.

The following table summarizes the amounts reported as gain (loss) on derivatives - commodity derivatives in the consolidated statements of operations for the years ended December 31, 2025, 2024 and 2023:

Common Stock Warrants

On October 24, 2022, in connection with the Business Combination, the Company issued 10,349,975 common stock warrants. Each warrant entitled the holder to purchaseone share of Granite Ridge’s common stock at an exercise price of $11.50 per share. The common stock warrants became exercisable 30 days after the completion of the Business Combination and 461 common stock warrants were exercised during the period they were outstanding.

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.

The Company recognized a loss of $5.7 million during 2023 from the change in fair value of the warrant liability in the consolidated statements of operations. The warrants exchanged in the Offer were marked to fair value on the date of settlement, and the liability of $17.0 million and $0.7 million related to the exchanged common stock warrants was removed from the consolidated balance sheet in June 2023 and July 2023, respectively, and the issuance of shares of the Company’s common stock was reflected in stockholders’ equity. See Note 9 for further discussion of the Warrant Exchange.

4. Fair Value Measurements

The Company has adopted and follows ASC 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in U.S. GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:

Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.

As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of December 31, 2025 and 2024:

Revolving credit facilities — The carrying amounts of the revolving credit facilities approximate their fair values, as the applicable interest rates are variable and reflective of market rates and are classified as Level 2 in the fair value hierarchy.

2029 Senior Notes -The carrying value reported for the Senior Notes is shown net of unamortized discount and unamortized deferred financing costs. The fair value of the Senior Notes was determined utilizing a discounted cash flow approach, discounted using market rates, and is classified as Level 3 in the fair value hierarchy.

Other financial assets and liabilities — The carrying amounts of the Company’s other financial assets and liabilities, such as revenue receivable and accrued expenses due to sellers, approximate their fair values because of the short maturity of these instruments.

Derivative instruments -commodity derivatives - collar option contracts and swaps — The fair value of the Company’s collar option contracts and swap commodity derivative instruments are estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. The fair value of the Company’s commodity derivative instruments is considered to be a Level 2 measurement. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) current market and contractual prices for the underlying instruments, (iii) applicable credit-adjusted risk-free rate curves, as well as other relevant economic measures.

Derivative instruments - commodity derivatives - power capacity contract— The fair value of the Company’s power capacity contract is estimated by management using a valuation model that incorporates both observable and unobservable inputs, as well as the time value of the underlying contractual cash flows. The fair value measurement is classified within Level 3 of the fair value hierarchy because significant inputs, including hourly forward power prices over the term of the agreement, are not observable for the term of the arrangement.

The Company utilizes a Monte Carlo simulation model to estimate fair value. Key inputs include: (i) forecasted hourly forward power prices at the applicable delivery nodes of the generation facilities, (ii) forward natural gas prices, (iii) long-term power and natural gas price volatilities and correlations, (iv) expected commercial operation dates of the facilities, (v) assumed operating efficiencies of the facilities, (vi) credit-adjusted discount rates, (vii) risk-free interest rate curves, and (viii) other relevant economic assumptions.

Because the valuation incorporates significant unobservable inputs, changes in these assumptions could materially impact the estimated fair value of the arrangement.

Equity investments — The fair value of the Company’s equity investment in common stock was valued using the instrument's publicly listed trading price, which is considered to be a Level 1 measurement due to the use of an observable market quote in an active market.

As of December 31, 2024, the Company held 1,027,907 shares of Vital Energy’s common stock, for which the fair value is a Level 1 measurement. On December 15, 2025, Crescent Energy completed its previously announced merger with Vital Energy. Under the merger agreement, each issued and outstanding share of Vital Energy common stock was converted into 1.9062 shares of Crescent Energy Class A common stock. As a result of the transaction, the Company’s 685,271 outstanding shares at the time of the merger closing in Vital Energy common stock were converted into 1,306,263 shares of Crescent Class A common stock, which remained held by the Company as of December 31, 2025, for which the fair value is a Level 1 measurement.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets as of December 31, 2025 and 2024. The Company nets the fair value of commodity derivative instruments by counterparty in the Company’s consolidated balance sheets.

The following table presents the significant unobservable inputs used in the valuation of the Level 3 Power Capacity Contract as of December 31, 2025. There were no Level 3 assets or liabilities as of December 31, 2024.

(1)The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount.

(2)Based on the Electric Reliability Council of Texas ("ERCOT") West Load Zone monthly forward around the clock swap prices shaped by historical hourly nodal prices in relation to ERCOT West Load Zone.

(3)Based on the Waha forward monthly gas prices.

Fair Values – Nonrecurring

Impairments of long-lived assets — The Company periodically 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. The Company reviews its oil and natural gas properties by depletion base. 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. If the estimated undiscounted future net cash flows are less than the carrying amount of the Company’s assets, it recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

The Company calculates the estimated fair values of its long-lived assets using the market and income valuation approaches. The income approach is calculated using a discounted future cash flow model. Fair value assumptions associated with the calculation of discounted future net cash flows include (i) market estimates of commodity prices, which are based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii) production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated proved and unproved reserves and (vii) discount rate. The expected future net cash flows are generally discounted using a market-based rate for proved developed producing reserves and an appropriate market discount rate based on risk for other reserve categories. The Company has historically also used the market approach by identifying market comparisons of recent transactions of oil and gas properties that share geographical and reserve characteristics to assess the fair value of the Company's assets. These are classified as Level 3 fair value assumptions.

As of December 31, 2025, the Company’s estimates of commodity prices for purposes of determining discounted future cash flows, which are based on the NYMEX strip, ranged from a 2026 price of $57.13 per barrel of oil increasing to a 2030 price of $60.77 per barrel of oil. Natural gas prices ranged from a 2026 price of $3.72 per Mcf of natural gas decreasing to a 2030 price of $3.61 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2030. The resulting cash flows were discounted using a market-based discount rate of 9% then further risked based on the reserve category.

As of December 31, 2024, the Company’s estimates of commodity prices for purposes of determining discounted future cash flows, which are based on the NYMEX strip, ranged from a 2025 price of $69.87 per barrel of oil decreasing to a 2029 price of $63.07 per barrel of oil. Natural gas prices ranged from a 2025 price of $3.53 per Mcf of natural gas increasing to a 2029 price of $3.58 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2029. The resulting cash flows were discounted using a market-based discount rate of 10% then further risked based on the reserve category.

As of December 31, 2023, the Company’s estimates of commodity prices for purposes of determining discounted 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 2025 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. The resulting cash flows were discounted using a market-based discount rate of 10% then further risked based on the reserve category.

Eagle Ford Impairment

In the fourth quarter of 2025, there were indicators that the carrying value of the Company's Eagle Ford proved oil and gas properties may be impaired due to a decline in oil prices. As a result of the impairment evaluation, where the income approach was utilized to assess fair value, the Company recorded impairment of $44.7 million, which is included in impairment of long-lived assets within the consolidated statements of operations.

Bakken Impairment

During 2024, there were indicators that the carrying value of the Company's Bakken proved oil and gas properties may be impaired due to widening differentials and higher production cost assumptions. As a result of the impairment evaluation, where the market and income approach were utilized to assess fair value, the Company recorded impairment of $35.6 million, which is included in impairment of long-lived assets within the consolidated statements of operations.

Haynesville Impairment

During 2023, there were indicators that the carrying value of the Company's Haynesville proved oil and gas properties may be impaired due to a decline in natural gas prices and negative reserve revisions for certain wells that had recently begun production as well as certain proved undeveloped wells. As a result of the impairment evaluation, where the income approach was utilized to assess fair value, the Company recorded impairment of $26.5 million, which is included in impairment of long-lived assets within the consolidated statements of operations.

Asset retirement obligations — The fair value measurements of asset retirement obligations are measured on a nonrecurring basis when a well is drilled or acquired or when production equipment and facilities are installed or acquired using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and natural gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and natural gas wells and future inflation rates.

5. Acquisitions and Divestitures

Asset Acquisitions

During the years ended December 31, 2025 and 2024, the Company acquired various oil and natural gas properties. The following table presents the cumulative adjusted purchase price of transactions accounted for as asset acquisitions in accordance with ASC Topic 805, Business Combinations(“ASC 805”) by basin included in oil and gas properties on the Company’s consolidated balance sheets:

Divestitures

During the years ended December 31, 2025 and 2024, the Company divested certain proved and unproved properties for total proceeds of $0.2 million and $14.9 million, respectively. The Company recorded a gain on sale from the divested unproved properties of $0.1 million and $0.5 million for the years ended December 31, 2025 and 2024, respectively, which is included in other, net in the consolidated statements of operations.

In December 2023, the Company completed the sale of certain of its Permian Basin assets to Vital Energy in exchange for consideration of 561,752 shares of Vital Energy's common stock and 541,155 shares of Vital Energy's 2.0% cumulative mandatorily convertible preferred securities (the "Preferred Stock"). As the sale of oil and natural gas properties did not significantly affect the unit-of-production amortization rate of the Permian Basin depletion aggregation, the Company accounted for the divestiture as a normal retirement withno gain or loss recorded on the sale.

6. Asset Retirement Obligations

The Company recognizes the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties at the times the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related oil and natural gas properties and allocated to expense over the useful life of the asset. The Company's asset retirement obligations primarily represent the present value of the estimated amounts that will be incurred to plug, abandon and remediate proved producing properties at the end of their productive lives, in accordance with applicable state laws.

The following table presents the changes in the asset retirement obligations during the years ended December 31, 2025, 2024 and 2023:

(1)Revisions in estimated liabilities during 2023 relate primarily to changes in estimated well lives

7. Income Taxes

The Company is a C corporation and subject to U.S. federal income tax and state and local income taxes. In 2025, the Company adopted ASU 2023-09, Improvements to Income Tax Disclosures, on a retrospective basis.

The Components of income tax expense were as follows for the periods indicated:

The Company's effective tax rate was 24.2%,24.9% and 23.2% for the years ended December 31, 2025, 2024 and 2023, respectively. For 2025, the effective tax rate differs from the enacted statutory rate of 21% primarily due to the impact of state income taxes. For 2024, the effective tax rate differed from the enacted statutory rate of 21% primarily due to the impact of certain discrete items and state income taxes.

The following reconciles the income tax expense included in the consolidated statements of operations with the income tax expense that would result from the application of the statutory federal tax rate:

(1)The majority of the state income tax, net of federal benefit, is attributable to activities in Texas, Louisiana and North Dakota.

Significant components of deferred tax assets and liabilities are included in the table below:

As of December 31, 2025, the Company had accumulated federal net operating loss carryforwards of $73.4 million, none of which are expected to expire, and state net operating loss carryforwards of approximately $73.4 million in states that allow net operating loss carryforward, some of which begin to expire in 2042. Utilization of these net operating losses may be limited if there were to be an ownership change as defined by Section 382 of the U.S. Internal Revenue Code. As of December 31, 2025, the Company does not believe any of its net operating losses were limited under these rules.

Income taxes paid, net of refunds, are listed below by the jurisdiction in which the taxes relate:

The Company is subject to the various taxing jurisdictions in the United States, including federal and certain state jurisdictions. As of December 31, 2025, the Company has no current tax years under audit. The Company remains subject to examination for federal income taxes for tax years 2022 through 2025 and state income taxes for tax years 2020 through 2025.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained upon examination. Therefore, as of December 31, 2025 and 2024, the Company hadno unrecognized tax benefits and didnot recognize any interest or penalties during those respective periods related to unrecognized tax benefits.

On July 4, 2025, President Trump signed the One Big Beautiful Bill Act ("OBBBA") into law. The OBBBA includes, among other things, a permanent extension of 100% bonus depreciation for certain capital expenditures and modifications to the interest expense limitation under Section 163(j). In accordance with ASC Topic 740, Income Taxes, the effects of the law are recognized in the period of enactment and, as a result, the Company recognized the impacts of the OBBBA legislation in 2025. The effective income tax rates and total income tax provision were not materially impacted by the enactment of OBBBA.

8. Debt

The Company’s long-term debt is comprised of the following:

(1)As of December 31, 2025, the current portion of long-term debt reflects $17.5 million due on the Senior Notes over the next twelve months.

Granite Ridge Credit Agreement

On October 24, 2022, Granite Ridge entered into a senior secured revolving credit agreement (as amended, the "Credit Agreement") with a syndicate of banks, currently led by Bank of America, N.A., as administrative agent.

The borrowing base is 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 April 29, 2025, the Company and its lenders entered into the Fifth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) increase the borrowing base from $325.0 million to $375.0 million, and (ii) increase the aggregate elected commitments from $325.0 million to $375.0 million.

On November 5, 2025, the Company and its lenders entered into the Sixth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things, (i) reaffirm the borrowing base and aggregate elected commitment amounts at $375.0 million, (ii) permit the issuance of the 2029 Senior Notes (as defined below), (iii) extend the maturity date to the earliest to occur of (A) November 5, 2029 or (B) the date that is ninety-one days prior to the stated maturity date of the 2029 Senior Notes if any 2029 Senior Notes remain outstanding on such date, and (iv) adjust the interest payable on (A) SOFR loans to interest at a rate per annum equal to SOFR plus an applicable margin ranging from 275 to 375 basis points, depending on the percentage of the borrowing base utilized and (B) base rate loans to interest at a rate per annum equal to the greatest of: (a) the U.S. prime rate as publicly announced from time to time by Bank of America, N.A.; (b) the federal funds effective rate plus 50 basis points; (c) the adjusted SOFR rate for aone-month interest period plus 100 basis points; and (d)100 basis points, plus, in the case of any base rate loan, an applicable margin ranging from 175 to 275 basis points, depending on the percentage of the borrowing base utilized.

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 the Company is 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.

Deferred financing costs were $5.9 million at December 31, 2025, and these costs are being amortized over the term of the Credit Agreement. At December 31, 2025, the Company had outstanding borrowings of $50.0 million and $0.3 million of letters of credit issued and outstanding under the Credit Agreement, resulting in availability of $324.7 million. The Credit Agreement is guaranteed by the restricted subsidiaries of Granite Ridge and is secured by a first priority mortgage and security interest in substantially all of the Company's and its restricted subsidiaries' assets. The Company's weighted average effective interest rate under the Credit Agreement as of December 31, 2025 and 2024 was 7.86% and 8.12%, respectively.

The Company also pays a commitment fee on unused elected commitment amounts under its facility ranging from 37.5 to 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 any 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, and

(iii)an Asset Coverage Ratio (as defined in the Credit Agreement), commencing with the fiscal quarter ending June 30, 2026, of not less than (a) for each such fiscal quarter ending prior to December 31, 2026,1.25 to 1.00 and (b) for each such fiscal quarter ending on or after December 31, 2026,1.50 to 1.00.

At December 31, 2025, the Company was in compliance with all financial covenants required by the Credit Agreement.

2029 Senior Notes

On November 5, 2025, the Company, as issuer, completed an issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes at 96.0% of par with stated maturity on November 5, 2029 (the "2029 Senior Notes") pursuant to the Note Purchase Agreement. The Company used the net proceeds from issuance of the 2029 Senior Notes to repay certain amounts under the Credit Agreement and to pay related fees and expenses. The Note Purchase Agreement allows the ability for the Company to incur up to $100.0 million of incremental notes for purposes of acquisition financing, subject to, among other things, the willingness of holders to provide such incremental notes and a pro forma net leverage ratio not greater than 2.00 to 1.00.

Interest is due to be paid at the end of each quarter, commencing December 31, 2025. In addition, the Company will repay quarterly 2.5% of the original principal amount of the notes issued on the closing date beginning on September 30, 2026. If quarterly scheduled repayments are missed, the coupon increases to 11.875% and the Company is restricted from making any dividend payments until all delinquent scheduled repayments have been fulfilled. The Company has $17.5 million included in current liabilities in the consolidated balance sheets related to quarterly principal repayments due within the next 12 months. On or after May 5, 2027 and on or prior to May 5, 2028, the Company may, at its option, redeem, at any time some or all of the 2029 Senior Notes at 103.0% of par, as set forth in the Note Purchase Agreement, plus accrued and unpaid interest, if any. Any redemption of the 2029 Senior Notes prior to May 5, 2027 is subject to payment of a make-whole amount. After May 5, 2028, the Company may redeem some or all of the Senior Notes at 100.0% of the principal amount thereof plus accrued and unpaid interest, if any. The principal remaining outstanding at the time of maturity is required to be paid in full by the Issuer.

The 2029 Senior Notes include certain covenants, which, among other things, requires the maintenance of (i) a net leverage ratio not greater than 3.25 to 1.00 and an (ii) asset coverage ratio greater than or equal to (A) for each Fiscal Quarter ending prior to December 31, 2026,1.25 to 1.00 and (B) for each Fiscal Quarter ending on or after December 31, 2026,1.50 to 1.00. The 2029 Senior Notes also contain a total leverage ratio and asset coverage ratio basket for Restricted Payments (as defined in the 2029 Senior Notes), which permits Restricted Payments in the form of cash distributions so long as, subject to certain other conditions, the leverage ratio, after giving pro forma effect to such Restricted Payments, cannot exceed 1.75 to 1.00, and the asset coverage ratio, after giving effect to such Restricted Payments, must be greater than or equal to 1.50 to 1.00. Upon issuance of the 2029 Senior Notes, the Company must maintain a minimum hedging requirement included within the Senior Notes for oil and natural gas based on our proved developed producing projected volumes for each commodity on a rolling 18-month basis.

The Senior Notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Note Purchase Agreement contains customary terms and covenants and events of default, including limitations on the Company’s ability to incur additional secured and unsecured indebtedness.

At December 31, 2025, the Company was in compliance with all financial covenants required by the Note Purchase Agreement.

9. Equity

Warrant Exchange

On June 22, 2023, the Company completed an Offer to holders of its outstanding warrants which provided such holders the opportunity to receive 0.25 shares of the Company’s common stock in exchange for each warrant tendered by such holders. This Offer coincided with a solicitation of consents from holders of the warrants to amend 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 the Company’s common stock. 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.

The warrants exchanged in the Offer were marked to fair value on the date of settlement, which was recorded in "Gain (loss) on derivatives - common stock warrants" on the consolidated statements of operations. Upon exchange, the liability of $17.0 million and $0.7 million related to the exchanged common stock warrants in June 2023 and July 2023, respectively, was removed from the consolidated balance sheet and the issuance of shares of the Company’s common stock was reflected in stockholders’ equity.

The Company incurred $2.5 million of costs directly related to the Warrant Exchange, consisting primarily of professional, legal, printing, filing, regulatory, and other costs. The costs were recorded in general and administrative expenses on the consolidated statements of operations for the year ended December 31, 2023.

Common stock dividends

The Company paid dividends of $57.7 million, or $0.44 per share, $57.5 million, or $0.44 per share, and $58.6 million, or $0.44 per share during the years ended December 31, 2025, 2024 and 2023, respectively. Any payment of future dividends will be at the discretion of the Company’s Board of Directors.

Share repurchase program

In December 2022, the Company announced that its Board of Directors approved a share repurchase program for up to $50.0 million. 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.

10. Related Party Transactions

On the Closing Date of the Business Combination, Grey Rock Administration, LLC (the “Manager”) entered into a Management Services Agreement with Granite Ridge (the “MSA”). Under the MSA, the Manager provides general management, administrative, and operating services covering the oil and gas assets and other properties of the Company and other day-to-day business and affairs of the Company. In accordance with the MSA, the Company pays the Manager an annual services fee of $10.0 million and reimburses the Manager for certain Granite Ridge group costs related to the operation of the Company’s assets (including for third party costs allocated or attributable to the assets of the Company). The initial term of the MSA expires on April 30, 2028; however, the MSA will automatically renew for additional consecutiveone-year renewal terms until terminated in accordance with its terms. Upon any termination of the MSA, the Manager shall provide transition services for a period of up to 90 days. For each of the years ended December 31, 2025, 2024 and 2023, service fees for the Company under the MSA were approximately $10.0 million.

On December 10, 2025, the Company entered into Amendment No. 1 to the Management Services Agreement, which amended the Company’s existing MSA with the Manager ("Amendment No. 1"). Amendment No. 1, among other things, (a) extended the initial term from April 30, 2028 to April 30, 2031 and (b) increased the Services Fee (as defined in MSA) from $10.0 million to $11.75 million effective January 1, 2026, provided for annual CPI-based adjustments beginning January 1, 2027 and delegated to management the authority to increase the Services Fee up to a maximum total of $12.5 million. Other than the foregoing, the material terms of the existing MSA remain unchanged.

On December 12, 2025, Granite Ridge Ventures, LLC, a Delaware limited liability company and wholly owned subsidiary of the Company, entered into a power capacity contract with a portfolio company of funds managed by affiliates of Grey Rock Investment Partners ("Conduit Bravo"). A third party entered into a transaction with Conduit Bravo on substantially similar terms and at a substantially similar time to this transaction.

During the year ended December 31, 2024, the Company divested of partial interests in certain unproved oil and natural gas properties to an affiliate of the Manager for consideration of $7.5 million. No gain or loss was recognized on the sale.

11. Commitments and Contingencies

The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.

On the Closing Date of the Business Combination, the Company entered into the MSA agreement between Granite Ridge and the Manager whereby the Company pays the Manager an annual services fee of $10.0 million and reimburses the Manager for certain Granite Ridge group costs. The initial term of the MSA expires on April 30, 2028; however, the MSA automatically renews for additional consecutiveone-year renewal terms until terminated in accordance with its terms. As described in Note 10, Amendment No. 1 to the MSA extended the initial term to April 30, 2031, increased the annual Services Fee to $11.75 million effective January 1, 2026, provided for annual CPI-based adjustments beginning January 1, 2027 and delegated to management the authority to increase the Services Fee up to a maximum total of $12.5 million annually.

12. Risk Concentrations

As a non-operator,100% of the Company’s wells are operated by third-party operating partners. As a result, the Company is highly dependent on the success of these third-party operators. If they are not successful in the development, exploitation, production and exploration activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the Company’s financial condition and results of operations could be adversely affected. These risks are heightened in a low commodity price environment, which may present significant challenges to these third-party operators. The Company’s third-party operators will make decisions in connection with their operations that may not be in the Company’s best interests, and the Company may have little or no ability to exercise influence over the operational decisions of its third-party operators.

The following table sets forth the percentage of revenues attributable to third-party operating partners who have accounted for 10% or more of revenues attributable to the Company’s assets during the years ended December 31, 2025, 2024 and 2023.

*Less than 10%

No other operator accounted for 10% or more of revenue attributable to the Company’s assets on a combined basis in the years ended December 31, 2025, 2024, or 2023. The loss of any such operator could adversely affect revenues attributable to the Company’s assets in the short term.

In the normal course of business, the Company maintains its cash balances in financial institutions, which at times may exceed federally insured limits. The Company is subject to credit risk to the extent any financial institution with which it conducts business is unable to fulfill contractual obligations on its behalf. Management monitors the financial condition of such financial institutions and does not anticipate any losses from these counterparties.

Derivative counterparties - The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”). All collar option contracts and swap derivatives entered into are with parties that are also lenders under the Company’s Credit Agreement. The Company’s obligations under the derivative instruments, with the exception of the Power Capacity Contract, are secured pursuant to the Credit Agreement, and no additional collateral has been posted by the Company.

13. Stock Incentive Plan

The Granite Ridge Resources, Inc. 2022 Omnibus Incentive Plan (the “Plan”) provides the Company the ability to grant, among other award types, stock options, restricted stock awards, and PSUs to directors, officers, employees and consultants or advisors employed by or providing service to the Company. The maximum number of shares of common stock that may be issued under the Plan is 6.5 million shares. As of December 31, 2025, the Company had 3.8 million shares of common stock remaining available for future awards under the Plan. Shares issued as a result of awards granted under the Plan are generally new common shares.

Stock-based compensation expense is recognized net of forfeitures within general and administrative expenses on the consolidated statements of operations. The Company has elected to account for forfeitures of stock-based compensation awards as they occur in determining compensation expense. The stock-based compensation expense is presented below for the indicated periods:

Restricted Stock Awards - The Company grants service-based restricted stock awards to certain of its employees and consultants, which generally vest ratably over a period ofthree years or cliff vest at the end offive years, and to non-employee directors, which vest in full afterone year. Restricted stock awards are valued at the closing price of the Company's common stock on the date of grant. All restricted shares are legally issued and outstanding. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. For restricted stock awards granted prior to March 2025, the holders of such unvested restricted stock awards have voting rights and the right to receive dividends. For restricted stock awards granted in March 2025 and thereafter, the holders of such unvested restricted stock awards do not have voting rights but do have the right to receive dividends. The Company recognizes compensation expense utilizing graded vesting whereby compensation expense is recognized over the service period for each separately vesting tranche.

The following table presents the Company's restricted stock award activity during the year ended December 31, 2025.

The weighted average grant date fair values of the restricted stock awards granted during the years ended December 31, 2024 and 2023 were $6.07 and $5.72 per share, respectively. The aggregate fair value of restricted stock awards that vested was $1.5 million and $1.0 million during the years ended December 31, 2025 and 2024, respectively. There wereno restricted stock awards that vested during the year ended December 31, 2023. As of December 31, 2025, the Company's unrecognized compensation cost related to unvested restricted stock was $2.1 million, which is expected to be recognized over a weighted average period of 1.6 years.

PSUs - The Company grants PSUs to certain of its officers under the Plan. PSUs represent the contingent right to receive shares of the Company's common stock once the PSU is vested and earned. PSUs, other than those granted during the three months ended June 30, 2025, cliff vest at the end ofthree years, generally subject to continued employment through the performance period. The total number of shares eligible to be earned may range from zero to 200% of the target number of PSUs granted, determined based upon achievement of certain “financial performance” and “market performance” criteria for the Company and individual performance criteria for the officers awarded PSUs. Financial performance is based on the Company’s financial performance at the end of the applicable performance period, while market performance is based on the relative standing of total shareholder return ("TSR") achieved by the Company compared to the TSR achieved by a predetermined group of peer companies at the end of the applicable performance period. Individual performance criteria is based on the officer's performance relative to individual performance goals at the end of the performance period. The Company utilizes the Monte Carlo simulation method to determine the fair value of the PSUs based on market performance, while PSUs based on financial performance are valued using the closing price of the Company's common stock on the date of grant.

During the second quarter of 2025, the Company granted 644,330 PSUs to certain of its officers under the Plan. These PSUs are eligible to vest, generally subject to continued employment, upon the satisfaction of certain stock price thresholds during the performance period, which ends on December 31, 2032. Each such PSU is earned based on whether the Company's stock price achieves a target average stock price for any 20 consecutive trading days during the performance period. If the stock price thresholds are not met by the end of the performance period, the PSUs will be forfeited and no shares of common stock will be issued. Compensation expense for these awards is based on the grant date fair market value of the award, calculated using a Monte Carlo simulation, and such costs are recorded on a straight-line basis over the derived requisite service period for each separately vesting portion of the award, as if the award was, in-substance, multiple awards, as applicable.

The following table presents the Company's PSU activity for the year ended December 31, 2025.

As of December 31, 2025, the Company's unrecognized compensation cost related to unvested performance stock units was $2.0 million, which is expected to be recognized over a weighted average period of 0.6 years.

The following table presents a summary of the assumptions utilized to estimate the fair value of the PSUs based on market performance granted during the periods presented.

Stock Options - The Company grants stock options to certain of its officers under the Plan. The Company’s outstanding stock options expire 10 years following the date of grant. Pursuant to the stock options granted under the Plan,33% of the options vest immediately with an additional 33% to vest on each of the nexttwo anniversaries of the date of the grant, generally subject to continued employment through each such vesting date.

The following table presents the Company's stock option activity for the year ended December 31, 2025.

The fair value of each stock option award is estimated on the date of grant. For stock options granted at-the-money, grant date fair value is estimated using the Black-Scholes pricing model. As these options represent plain vanilla options and the Company did not have historical exercise detail, the expected term for these options was estimated using the simplified method allowed under Staff Accounting Bulletin Topic 14.D.2, which is the average of the weighted average vesting term and time to expiration as of the grant date. For stock options granted with an exercise price higher than the stock price at the date of grant, grant date fair value is estimated using a lattice-based option valuation model that incorporates a range of assumptions. Expected volatilities were based on historical volatilities of the Company's stock and other factors. The expected term was derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The weighted average fair value of stock options on the date of the grant during the years ended December 31, 2025, 2024 and 2023 was $1.21, $1.38, and $0.82 per share, respectively. As of December 31, 2025, the weighted average remaining terms on the outstanding options and the exercisable options was 7.8 years and 7.5 years, respectively.

The following table presents a summary of the assumptions utilized to estimate the fair value of the stock option awards granted during the periods presented.

Other Awards - During the year ended December 31, 2025, the Company issued 13,482 common shares to a director in lieu of cash compensation. During 2023, the Company issued 94,007 fully vested stock awards to certain of its employees and consultants under the Plan. The weighted average grant date fair value of these awards in 2023 was $8.51.

Future stock-based compensation expense-The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at December 31, 2025:

14. Earnings Per Share

The Company uses the two-class method of calculating earnings per share because certain of the Company’s unvested stock-based awards qualify as participating securities.

The Company’s basic earnings per share attributable to common stockholders is computed as (i) net income as reported, (ii) less participating basic earnings, (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings per share attributable to common stockholders is computed as (i) basic earnings attributable to common stockholders, (ii) plus reallocation of participating earnings, (iii) divided by weighted average diluted common shares outstanding.

The computation of diluted net income per share excludes contingently issuable shares related to certain market-based equity awards as the required market price conditions had not been satisfied as of the end of the reporting period. These awards represent 644,330 shares of common stock that may be issued if specified market price targets are achieved. Because the market conditions were not met as of December 31, 2025, the shares were not included in the diluted weighted average share count. If the market conditions are satisfied in future periods, these shares could have a dilutive effect on earnings per share.

The following table presents the basic and diluted earnings per share computations for the years ended December 31, 2025, 2024 and 2023:

The following table is a summary of the PSUs and stock options, which were not included in the computation of diluted earnings per share, as inclusion of these items would be antidilutive.

15. Accounts Payable and Accrued Liabilities

The following table provides the components of the Company’s accounts payable and accrued liabilities at December 31, 2025 and December 31, 2024:

16. Subsequent Events

Dividend

On February 13, 2026, the Company's Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2026. The dividend will be paid on March 13, 2026 to stockholders of record as of February 27, 2026.

New Commodity Derivative Contracts

Subsequent to December 31, 2025, the Company entered into the following oil and natural gas derivative contracts to hedge additional amounts of estimated future production.

Stock-Based Compensation

In January and February 2026, the Company granted a total of 209,648 restricted stock awards. In addition, in February 2026, the Company granted 292,398 PSUs to an officer, which will be eligible to vest upon the satisfaction of certain stock price thresholds during the performance period, which ends on December 31, 2032.

Capitalized Costs

Costs Incurred for Oil and Natural Gas Producing Activities

Oil and Natural Gas Reserves and Related Financial Data

Information with respect to the Company’s oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by independent third-party reserve engineers, based on information provided by the Company.

Prices presented in the table below are the trailing 12 month simple average spot price at the first of the month for natural gas at Henry Hub and West Texas Intermediate crude oil at Cushing, Oklahoma, prior to adjustments for location, grade and quality.

The following tables present the Company’s third-party independent reserve engineers' estimates of its proved developed and undeveloped oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of the available data and of engineering and geological interpretation and judgment.

Notable changes in proved reserves for the year ended December 31, 2025 included the following:

•Revisions of previous estimates. In 2025, revisions of previous estimates decreased proved developed and undeveloped reserves by approximately 840 MBoe. The decrease was driven in part by lower oil prices. The Company’s proved reserves at December 31, 2025 were determined using the SEC price of $66.01 per Bbl of oil as compared to corresponding price of $76.32 per Bbl of oil at December 31, 2024. This decrease was partially offset by higher natural gas pricing. Proved natural gas reserves at December 31, 2025 were determined using the

SEC price of $3.39 per Mcf of natural gas as compared to corresponding price of $2.13 per Mcf of natural gas at December 31, 2024.

•Extensions and discoveries. In 2025, total extensions and discoveries of 11,996 MBoe were primarily attributable to successful drilling in the Permian Basin, which added 8,518 MBoe. Proved developed reserves increased approximately 8,746 MBoe due to the Company’s drilling activity in 2025, and 3,250 MBoe as a result of new proved undeveloped locations added.

•Acquisitions of reserves. In 2025, total acquisitions of reserves of 8,550 MBoe were attributable to the acquisitions of oil and natural gas properties primarily in the Permian Basin. The Permian Basin accounted for 6,739 MBoe of acquisitions during 2025. See Note 5 for additional discussion regarding acquisitions.

Notable changes in proved reserves for the year ended December 31, 2024 included the following:

•Revisions of previous estimates. In 2024, revisions of previous estimates decreased proved developed and undeveloped reserves by approximately 2,302 MBoe. The decrease was driven in part by lower oil and natural gas prices. The Company’s proved reserves at December 31, 2024 were determined using the SEC prices of $76.32 per Bbl of oil and $2.13 per MMBtu of natural gas, as compared to corresponding prices of $78.21 per Bbl of oil and $2.64 per MMBtu of natural gas at December 31, 2023. In addition to price revisions, there were negative revisions of 2,013 MBoe related to the removal of undeveloped drilling locations as they were no longer expected to be developed within five years of their initial recognition.

•Extensions and discoveries. In 2024, total extensions and discoveries of 6,885 MBoe were primarily attributable to successful drilling in the Permian Basin, which added 5,760 MBoe. Proved developed reserves increased approximately 2,120 MBoe due to the Company’s drilling activity in 2024, and 4,765 MBoe as a result of new proved undeveloped locations added.

•Divestiture of reserves. In 2024, the Company divested 3,525 MBoe of proved reserves primarily in the Permian Basin (see Note 5).

•Acquisitions of reserves. In 2024, total acquisitions of reserves of 8,925 MBoe were attributable to the acquisitions of oil and natural gas properties primarily in the Permian Basin. The Permian Basin accounted for 7,233 MBoe of acquisitions during 2024. See Note 5 for additional discussion regarding acquisitions.

Notable changes in proved reserves for the year ended December 31, 2023, included the following:

•Revisions of previous estimates. In 2023, revisions of previous estimates decreased proved developed and undeveloped reserves by approximately 6,662 MBoe. The decrease was primarily driven by lower oil and natural gas prices. The Company’s proved reserves at December 31, 2023 were determined using the SEC prices of $78.21 per Bbl of oil and $2.64 per MMBtu of natural gas, as compared to corresponding prices of $94.14 per Bbl of oil and $6.36 per MMBtu of natural gas at December 31, 2022. In addition to price revisions, there were negative revisions of 1,477 MBoe related to the removal of undeveloped drilling locations as they were no longer expected to be developed within five years of their initial recognition.

•Extensions and discoveries. In 2023, total extensions and discoveries of 13,116 MBoe were primarily attributable to successful drilling in the Permian Basin, which added 10,643 MBoe, and the Eagle Ford Basin, which added 1,835 MBoe. Proved developed reserves increased approximately 1,972 MBoe due to the Company’s drilling activity in 2023, and 11,144 MBoe as a result of new proved undeveloped locations added.

•Divestiture of reserves. In 2023, the Company divested 2,213 MBoe of proved reserves in the Permian Basin.

•Acquisitions of reserves. In 2023, total acquisitions of reserves of 7,570 MBoe were primarily attributable to the acquisitions of oil and natural gas properties in the Permian Basin and DJ Basin. The Permian Basin accounted for 5,342 MBoe of acquisitions and the DJ Basin accounted for 1,197 MBoe.

Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years.

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

Future oil and natural gas sales, production and development costs have been estimated using prices and costs in effect at the end of the years included, as required by ASC 932. ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our oil and natural gas reserves and for asset retirement obligations, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company’s proved oil and natural gas reserves.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of reserves may not occur in the period assumed; actual prices realized are expected to vary significantly from those used and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves at the periods indicated:

A summary of the changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: