Granite Ridge Resources (GRNT) 10-K 27 Mar 23 2022 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Mar. 22, 2023	Jun. 30, 2022
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2022
Entity File Number	001-41537
Entity Registrant Name	GRANITE RIDGE RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	88-2227812
Entity Address State Or Province	TX
Entity Address, Address Line One	5217 McKinney Ave
Entity Address, Adress Line Two	Suite 400
Entity Address, City or Town	Dallas
Entity Address, Postal Zip Code	75205
City Area Code	214
Local Phone Number	396-2850
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Ex Transition Period	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		133,212,500
Entity Central Index Key	0001928446
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false
Auditor Name	FORVIS, LLP
Auditor Location	Dallas, Texas
Auditor Firm ID	686
Common Stock
Document Information [Line Items]
Title of 12(b) Security	Common Stock, par value $0.0001 per share
Trading Symbol	GRNT
Security Exchange Name	NYSE
Warrants
Document Information [Line Items]
Title of 12(b) Security	Warrants to purchase Common Stock, each whole warrantexercisable for one share of common stock at an exerciseprice of $11.50 per share
Trading Symbol	GRNT WS
Security Exchange Name	NYSE

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash	$ 50,833	$ 11,854
Revenue receivable	72,287	47,298
Advances to operators	8,908	37,817
Prepaid and other expenses	4,203	676
Derivative assets - commodity derivatives	10,089	434
Total current assets	146,320	98,079
Property and equipment:
Oil and gas properties, successful efforts method	1,028,662	727,547
Accumulated depletion	(383,673)	(278,773)
Total property and equipment, net	644,989	448,774
Long-term assets:
Derivative assets - commodity derivatives		31
Other long-term assets	3,468	362
Total long-term assets	3,468	393
TOTAL ASSETS	794,777	547,246
Current liabilities:
Accrued expenses	62,180	10,321
Other liabilities	1,523	13
Derivative liabilities - commodity derivatives	431	7,263
Current portion of long-term debt		50,000
Total current liabilities	64,134	67,597
Long-term liabilities:
Long-term debt		1,100
Derivative liabilities - commodity derivatives		657
Derivative liabilities - common stock warrants	11,902
Asset retirement obligations	4,745	2,962
Deferred tax liability	91,592
Total long-term liabilities	108,239	4,719
TOTAL LIABILITIES	172,373	72,316
Commitments and contingencies (Note 11)
EQUITY:
Partnerships' capital		474,930
Common stock, $0.0001 par value, 431,000,000 shares authorized, 133,294,897 issued at December 31, 2022.	13
Additional paid-in capital	590,232
Retained earnings	32,388
Treasury stock, at cost, 25,920 shares at December 31, 2022	(229)
Total equity	622,404	474,930
TOTAL LIABILITIES AND EQUITY	$ 794,777	$ 547,246

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2022 $ / shares shares
CONSOLIDATED BALANCE SHEETS
Common stock, par value | $ / shares	$ 0.0001
Common stock, shares authorized	431,000,000
Common stock, shares issued	133,294,897
Treasury stock, common shares	25,920

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
REVENUES
Oil, natural gas and related product sales	$ 497,417	$ 290,193	$ 87,098
EXPENSES
Lease operating expenses	44,678	26,333	20,398
Production and ad valorem taxes	30,619	18,066	6,663
Depletion and accretion expense	105,752	94,661	79,947
Impairments of long-lived assets			5,725
General and administrative	14,223	10,179	10,108
Gain on disposal of oil and natural gas properties		(2,279)	(648)
Total operating costs and expenses	195,272	146,960	122,193
Net operating income (loss)	302,145	143,233	(35,095)
OTHER (EXPENSE) INCOME
(Loss) gain on derivatives - commodity derivatives	(25,324)	(32,389)	13,006
Interest expense	(1,989)	(2,385)	(1,841)
Gain on derivatives - common stock warrants	362
Total other (expense) income	(26,951)	(34,774)	11,165
INCOME (LOSS) BEFORE INCOME TAXES	275,194	108,459	(23,930)
Income tax expense	12,850
NET INCOME (LOSS)	$ 262,344	$ 108,459	$ (23,930)
NET INCOME (LOSS) PER SHARE:
Basic	$ 1.97	$ 0.82	$ (0.18)
Diluted	$ 1.97	$ 0.82	$ (0.18)
WEIGHTED-AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	132,923	132,923	132,923
Diluted	133,074	132,923	132,923

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) shares in Thousands, $ in Thousands	Partner Capital - Prior to Recapitalization	Common Stock	Additional Paid-in Capital	Retained Earnings	Treasury Stock	Total
Equity, Beginning Balance at Dec. 31, 2019	$ 324,369					$ 324,369
CHANGES IN EQUITY ROLL FORWARD
Cash distributions	(12,883)					(12,883)
Net income (loss)	(23,930)					(23,930)
Equity, Ending Balance at Dec. 31, 2020	370,556					370,556
CHANGES IN EQUITY ROLL FORWARD
Contributed capital	83,000					83,000
Cash distributions	(51,085)					(51,085)
Net income (loss)	108,459					108,459
Equity, Ending Balance at Dec. 31, 2021	474,930					474,930
CHANGES IN EQUITY ROLL FORWARD
Contributed capital	47,000					47,000
Net Income prior to Business Combination	219,292					219,292
Contribution of Funds' assets in exchange for common stock	$ (694,222)	$ 13	$ 694,209
Contribution of Funds' assets in exchange for common stock (Shares)		130,000
Recapitalization			6,825			6,825
Recapitalization (Shares)		2,923
Issuance costs			(18,508)			(18,508)
Issuance of common stock warrants			(12,265)			(12,265)
Issuance of vesting shares			(1,287)			(1,287)
Issuance of vesting shares (Shares)		372
Deferred income tax liability at Business Combination			(78,742)			(78,742)
Purchase of treasury stock					$ (229)	(229)
Purchase of treasury stock (Shares)					(26)
Common stock dividend declared ($0.08 per share)				$ (10,664)		(10,664)
Net income subsequent to the Business Combination				43,052		43,052
Net income (loss)						262,344
Equity, Ending Balance at Dec. 31, 2022		$ 13	$ 590,232	$ 32,388	$ (229)	$ 622,404
Equity, Ending Balance (Shares) at Dec. 31, 2022		133,295			(26)

CONSOLIDATED STATEMENTS OF CH_2

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical)	12 Months Ended
	Dec. 31, 2022 $ / shares
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Common stock dividend declared	$ 0.08

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating activities:
Net income (loss)	$ 262,344	$ 108,459	$ (23,930)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion and accretion expense	105,752	94,661	79,947
Impairments of long-lived assets			5,725
Loss (gain) on derivatives - commodity derivatives	25,324	32,389	(13,006)
Net cash (payments on) receipts from derivatives	(42,437)	(25,219)	11,913
Gain on disposal of oil and natural gas properties		(2,279)	(648)
Amortization of loan origination costs	159	48	108
Gain on derivatives - common stock warrants	(362)
Deferred income taxes	12,850
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Revenue receivable	(24,989)	(28,603)	5,532
Accrued expenses	9,838	1,840	(194)
Prepaid and other expenses	(2,095)	(125)	1,355
Other payable	5	10	4
Net cash provided by operating activities	346,389	181,181	66,806
Investing activities:
Additions to oil and natural gas properties	(185,497)	(136,077)	(99,487)
Acquisition of oil and natural gas properties	(49,191)	(83,209)	(17,903)
Deposit on acquisition	(1,899)
Refund of advances to operators	1,180	3,819
Proceeds from the disposal of oil and natural gas properties	4,845	29,443	647
Net cash used in investing activities	(230,562)	(186,024)	(116,743)
Financing activities:
Proceeds from borrowing on credit facilities	21,000	62,000	36,500
Repayments of borrowing on credit facilities	(72,100)	(49,400)	(54,500)
Cash distributions		(51,091)	(12,876)
Cash contributions		46,980	82,947
Deferred financing costs	(3,237)
Payment of expenses related to formation of Granite Ridge Resources, Inc.	(18,456)
Purchase of treasury shares	(216)
Payment of dividends	(10,664)
Proceeds from issuance of common stock	6,825
Net cash (used in) provided by financing activities	(76,848)	8,489	52,071
Net increase in cash and restricted cash	38,979	3,646	2,134
Cash and restricted cash at beginning of year	12,154	8,508	6,374
Cash and restricted cash at end of year	51,133	12,154	8,508
Supplemental disclosure of cash flow information:
Cash paid during the year for interest	(2,286)	(1,636)	(1,263)
Cash (paid) received during the year for income taxes	(98)	(79)	65
Supplemental disclosure of non-cash investing activities:
Oil and natural gas property development costs in accrued expenses	48,187	6,251	5,746
Advances to operators applied to development of oil and natural gas properties	103,535	48,387	38,311
Cash and restricted cash:
Cash	50,833	11,854	8,208
Restricted cash included in other long-term assets	300	300	300
Cash and restricted cash	$ 51,133	$ 12,154	$ 8,508

Organization and nature of oper

Organization and nature of operations	12 Months Ended
	Dec. 31, 2022
Organization and nature of operations
Organization and nature of operations	1. Organization and nature of operations Granite Ridge Resources, Inc. (together with its consolidated subsidiaries, “Granite Ridge” the “Company” or the “Successor”) is a Delaware corporation, initially formed in May 2022, whose common stock and warrants are listed and traded on the New York Stock Exchange (“NYSE”). The Company was created for the purpose of the Business Combination (as defined below), and following the Business Combination, for the purpose of purchasing non-operated 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). Unless otherwise indicated, for the periods prior to October 24, 2022, (i) the historical financial data in this Annual Report on Form 10-K and (ii) the operating and other non-financial data, disclosed in “Part II – Management’s Discussion and Analysis of Financial Condition and Results of Operations” (collectively the “Financial Statement Sections”) reflect the combined business and operations of the Funds (as defined below). Business Combination 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 (“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) 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”). 220,348 of the 371,518 shares subject to vesting and forfeiture provisions were forfeited in January 2023. 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 of one share of Class A common stock and one-quarter of one ENPC warrant (“CAPS TM 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 have been adjusted to retrospectively combine the previously separate entities for presentation purposes.

Summary of significant accounti

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2022
Summary of significant accounting policies
Summary of significant accounting policies	2. Summary of significant accounting policies Principles of Consolidation As it pertains to the periods prior to completion of the Business Combination, the financial statements have been presented on a combined historical basis due to their prior common ownership and control. Prior to the Business Combination, the financial statements include the accounts of the Funds, all of which were commonly owned and controlled. All inter-entity balances and transactions have been eliminated in combination. As it pertains to the period subsequent to completion of the Business Combination, the accompanying consolidated financial statements also include the accounts of the Company, and all other wholly owned subsidiaries created in connection with the Business Combination. References to the “Company” prior to October 24, 2022 refer to the combined business of the Funds and references after October 24, 2022 refer to the consolidated business of Granite Ridge Resources, Inc. Basis of Presentation As a result of the Business Combination, periods prior to October 24, 2022 reflect Funds as limited partnerships, not as corporations. The primary financial impacts of the Transactions to the consolidated financial statements were (i) reclassification of partnership capital accounts to equity accounts reflective of a corporation and (ii) income tax effects. Since Funds were identified as entities under common control, the consolidated financial statements for periods prior to the GREP Formation Transaction have been adjusted to retrospectively combine the previously separate entities for presentation purposes. All intercompany transactions within the consolidated businesses of the Company have been eliminated. The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The Company operates in a one operating segment, which is oil and natural gas development, exploration and production. All of our operations are conducted in the geographic area of the United States. The Company’s chief operating decision maker, manages operations on a consolidated basis for purposes of evaluating operations and allocating resources. 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 work over costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties. Additional significant estimates include, but are not limited to, fair value of derivative financial instrument, fair value of business combinations, asset retirement obligations, revenue receivable and income taxes. Actual results could differ from those estimates. Reclassifications Certain reclassifications have been made to prior period amounts to conform to the current period presentation. 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. As of December 31, 2022 and 2021, the Company had $0.3 million of cash classified as restricted. This balance relates to a cash deposit for two standby letters of credit associated with oil and natural gas mining lease agreements. Restricted cash consists of cash that is stated at cost, which approximates fair market value. Classification of restricted cash is based on the nature of the restrictions associated with the underlying assets. Revenue Receivable 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 writes off specific accounts receivable when they become uncollectible. For the years ended December 31, 2022, 2021 and 2020, the Company’s bad debt expense and allowance for doubtful accounts was immaterial. Advance 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 gas properties, net on the statement of cash flows. Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for oil and gas producing activities, as further defined under ASC 932, Extractive Activities - Oil and Gas There were no exploratory wells capitalized pending determinations of whether the wells have proved reserves as of December 31, 2022 and 2021. 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 $105.3 million, $94.2 million and $79.5 million for the years ended December 31, 2022, 2021, and 2020, respectively. As a result of the Business Combination, the Company aggregated certain proved properties for amortization and impairment purposes. Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the years ended December 31, 2022, 2021 and 2020, no interest costs were capitalized because its exploration and development projects generally last less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred. Effective January 1, 2019, the Company adopted ASU 2017-1, Business Combinations: Clarifying the Definition of Business (“ASU 2017-1”), with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. See discussions of the Company’s oil and natural gas asset acquisitions and business combinations in Note 5. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. See Note 5 for additional information on our divestitures. Ordinary maintenance and repair costs are expensed as incurred. The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company did not recognize an impairment expense for the years ended December 31, 2022 and 2021 related to its proved oil and natural gas properties. During the year ended December 31, 2020, the Company recognized an impairment expense of $5.7 million related to its proved oil and natural gas properties. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. The Company did not recognize an impairment expense for the years ended December 31, 2022, 2021 and 2020 related to its unproved oil and natural gas properties. 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 The Company accounts for warrants as liability-classified instruments based on an assessment of the warrant’s specific terms and applicable authoritative guidance in Accounting Standards Codification (“ASC”) Topic 480, “Distinguishing Liabilities from Equity” (“ASC 480”) and ASC Topic 815, “Derivatives and Hedging” (“ASC 815”). The warrants are 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 are recognized as a non-operating gain or loss on the consolidated statements of operations. For the period during which the Company’s common stock was publicly traded, the fair value of the warrants was based on quoted prices in an active market. Refer to Note 4 for further discussion on fair value considerations. Asset Retirement Obligation The Company follows the provisions of ASC 410-20, Asset Retirement Obligations 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 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 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 transportation and production tax costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within one to three months after the month in which production occurs. Take-in Kind Oil and Natural Gas Revenues Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer’s processing plant in lieu of receiving a net payment from the operator representing its proportionate share of its natural gas production. The Company currently takes certain processed gas volumes in kind in lieu of monetary settlement but does not currently take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, gathering and processing costs and transportation expenses the Company incurs to transport the processed products to downstream customers are recorded in Lease Operating Expenses on the Consolidated Statements of Operations. The Company’s disaggregated revenue has two primary sources: oil sales and natural gas sales. Substantially all of the Company’s oil and natural gas sales come from six geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Haynesville Basin (Texas/Louisiana), the Denver-Julesburg “DJ” Basin (Colorado), the Bakken Basin (Montana/North Dakota) and the SCOOP/STACK Basin (Oklahoma). The following tables present the disaggregation of the Company’s oil revenues and natural gas revenues by basin for the years ended December 31, 2022, 2021 and 2020. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 Oil ​ $ 338,163 ​ $ 215,250 ​ $ 70,870 Natural gas ​ 159,254 ​ 74,943 ​ 16,228 Total ​ $ 497,417 ​ $ 290,193 ​ $ 87,098 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Permian ​ $ 266,856 ​ $ 151,179 ​ $ 37,205 Eagle Ford ​ ​ 64,879 ​ ​ 40,898 ​ ​ 12,554 Bakken ​ 64,999 ​ 56,055 ​ 27,769 Haynesville ​ 62,743 ​ 12,039 ​ 9,110 DJ ​ 37,880 ​ 29,191 ​ — SCOOP/STACK ​ 60 ​ 831 ​ 460 Total ​ $ 497,417 ​ $ 290,193 ​ $ 87,098 ​ Lease Operating Expenses Lease operating expenses represents field employees’ salaries, saltwater disposal, repairs and maintenance, expensed work overs 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, 2022, 2021 and 2020 were approximately $26.9 million, $17.1 million and $6.0 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, 2022, 2021 and 2020 were approximately $3.7 million, $1.0 million and $0.7 million, respectively. Income Taxes Prior to the Business Combination, GREP and the associated activities held by Funds were treated as partnerships for U.S. federal income tax purposes and were not subject to U.S. federal income tax. As a result of the Business Combination, the Company became a C corporation and is subject to U.S. federal income tax and state and local income taxes, and accounts for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rate on deferred income tax assets and liabilities is recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred income taxes if it is more likely than not these items will either expire before the Company is able to realize their benefits or if future deductibility is uncertain. Additionally, the Company evaluates tax positions under a more likely than not recognition threshold and measurement analysis before the positions are recognized for financial statement reporting. For further discussion, see Note 7. Recently Issued and Applicable Accounting Pronouncements The FASB issued ASU No. 2016-02, “Leases (Topic 842)” which requires all leases greater than one year to be recognized as assets and liabilities. This ASU also expands the required quantitative and qualitative disclosures surrounding leases. Oil and gas leases are excluded from the guidance. We adopted this ASU on January 1, 2022 and there was no material impacts to our consolidated financial statements. The FASB issued ASU No. 2016-13, “Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” which replaces the current “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. This guidance becomes effective for fiscal years beginning after December 15, 2022, however, the impact is not expected to be material.

Derivative financial instrument

Derivative financial instruments	12 Months Ended
	Dec. 31, 2022
Derivative financial instruments
Derivative financial instruments	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 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. Collar and Producer 3-way Option Contracts The Company’s derivative financial instruments consist of collar and producer 3-way option contracts. A collar option is established with the sale of a short call option and the purchase of a long put option 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. A producer 3-way contract is established with the sale of a short call option and the purchase of a long put option set to expire at a predetermined date in the future. However, the producer 3-way contract also includes the sale of a short put option 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. The Company has master netting agreements on individual derivative instruments with certain counterparties and therefore certain amounts may be presented on a net basis in the consolidated balance sheets. Volume of Derivative Activities The following table sets forth the Company’s outstanding commodity derivative contracts as of December 31, 2022. All of the Company’s commodity derivative contracts as of December 31, 2022 are expected to settle by December 31, 2023. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First Quarter Second Quarter Third Quarter Fourth Quarter Total Producer 3-way (oil) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Volume (Bbl) ​ 431,160 ​ 340,263 ​ 228,659 ​ 208,488 ​ 1,208,570 Weighted-average sub-floor price ($/Bbl) ​ $ 57.22 ​ $ 62.22 ​ $ 60.42 ​ $ 60.43 ​ $ 59.79 Weighted-average floor price ($/Bbl) ​ $ 70.62 ​ $ 77.89 ​ $ 79.25 ​ $ 80.00 ​ $ 75.92 Weighted-average ceiling price ($/Bbl) ​ $ 96.04 ​ $ 99.23 ​ $ 100.61 ​ $ 101.92 ​ $ 98.82 Producer 3-way (natural gas) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Volume (Mcf) ​ 2,634,993 ​ — ​ — ​ — ​ 2,634,993 Weighted-average sub-floor price ($/Mcf) ​ $ 4.41 ​ $ — ​ $ — ​ $ — ​ $ 4.41 Weighted-average floor price ($/Mcf) ​ $ 5.51 ​ $ — ​ $ — ​ $ — ​ $ 5.51 Weighted-average ceiling price ($/Mcf) ​ $ 11.28 ​ $ — ​ $ — ​ $ — ​ $ 11.28 Collar (natural gas) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Volume (Mcf) ​ 774,634 ​ 3,051,421 ​ 2,530,000 ​ 2,070,000 ​ 8,426,055 Weighted-average floor price ($/Mcf) ​ $ 5.96 ​ $ 4.12 ​ $ 4.25 ​ $ 4.50 ​ $ 4.42 Weighted-average ceiling price ($/Mcf) ​ $ 9.15 ​ $ 5.63 ​ $ 5.90 ​ $ 6.35 ​ $ 6.21 ​ The following table summarizes the amounts reported in the consolidated statements of operations related to the commodity derivative instruments for the years ended December 31, 2022, 2021 and 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 (Loss) gain on commodity derivatives ​ ​ ​ Oil derivatives ​ $ (14,985) ​ $ (24,885) ​ $ 11,604 Natural gas derivatives ​ (10,339) ​ (7,504) ​ 1,402 Total ​ $ (25,324) ​ $ (32,389) ​ $ 13,006 ​ The following table represents the Company’s net cash receipts (payments on) commodity derivatives for the years ended December 31, 2022, 2021 and 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 Net cash (payments on) receipts from commodity derivatives ​ ​ ​ Oil derivatives ​ $ (23,695) ​ $ (19,034) ​ $ 10,180 Natural gas derivatives ​ (18,742) ​ (6,185) ​ 1,733 Total ​ $ (42,437) ​ $ (25,219) ​ $ 11,913 ​ Common stock warrants On October 24, 2022, in connection with the Business Combination, the Company issued 10,349,975 common stock warrants. Each warrant entitles the holder to purchase one 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 will expire five-years after the completion of the Business Combination. The Company has the right to redeem the common stock warrants at a price of $0.01 per warrant when the price of Granite Ridge’s common stock equals or exceeds $ 18.00 for 20 days within a 30-day trading period. The common stock warrants were initially recognized as a liability with a fair value of $12.3 million and were remeasured to a fair value of $11.9 million as of December 31, 2022. We recognized a gain of $0.4 million during 2022 from the change in fair value of the warrant liability in the consolidated statements of operations. No common stock warrants were exercised during 2022.

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2022
Fair value measurements
Fair value measurements	4. Fair value measurements The Company has adopted and follows ASC 820, Fair Value Measurements and Disclosures 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, 2022 and 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 ​ ​ December 31, 2021 ( in thousands) Carrying Value Fair Value Carrying Value Fair Value Assets: ​ ​ ​ ​ Derivative instruments - commodity derivatives ​ $ 10,089 ​ $ 10,089 ​ $ 465 ​ $ 465 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: ​ ​ ​ ​ Derivative instruments - common stock warrants ​ $ 11,902 ​ $ 11,902 ​ $ — ​ $ — Revolving credit facilities ​ $ — ​ $ — ​ $ 51,100 ​ $ 51,100 Derivative instruments - commodity derivatives ​ $ 431 ​ $ 431 ​ $ 7,920 ​ $ 7,920 ​ Revolving credit facilities Other financial assets and liabilities Derivative instruments - commodity derivatives — The fair value of the Company’s derivative instruments is 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. S ubstantially 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 - common stock warrants 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, 2022 and 2021. The Company nets the fair value of commodity derivative instruments by counterparty in the Company’s consolidated balance sheets. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2022 ​ ​ Fair Value Measurement Using ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Amounts ​ Net Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Offset in the ​ Presented in the ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Fair ​ Consolidated ​ Consolidated (in thousands) Level 1 Level 2 Level 3 Value Balance Sheet Balance Sheet Assets (at fair value): ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ $ — ​ $ 20,197 ​ $ — ​ $ 20,197 ​ $ (10,108) ​ $ 10,089 Liabilities (at fair value): ​ ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ — ​ (10,539) ​ — ​ (10,539) ​ 10,108 ​ (431) Warrant liability – noncurrent portion ​ (11,902) ​ — ​ — ​ (11,902) ​ — ​ — Net derivative instruments ​ $ (11,902) ​ $ 9,658 ​ $ — ​ $ (2,244) ​ $ — ​ $ 9,658 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2021 ​ ​ Fair Value Measurement Using ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Amounts ​ Net Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Offset in the ​ Presented in the ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Fair ​ Consolidated ​ Consolidated (in thousands) Level 1 Level 2 Level 3 Value Balance Sheet Balance Sheet Assets (at fair value): ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ $ — ​ $ 4,821 ​ $ — ​ $ 4,821 ​ $ (4,387) ​ $ 434 Commodity derivatives – noncurrent portion ​ — ​ 2,147 ​ — ​ 2,147 ​ (2,116) ​ 31 Liabilities (at fair value): ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ — ​ (11,649) ​ — ​ (11,649) ​ 4,386 ​ (7,263) Commodity derivatives – noncurrent portion ​ — ​ (2,774) ​ — ​ (2,774) ​ 2,117 ​ (657) Net derivative instruments ​ $ — ​ $ (7,455) ​ $ — ​ $ (7,455) ​ $ — ​ $ (7,455) ​ Fair Values – Non Recurring Impairments of long-lived assets The Company calculates the expected undiscounted future net cash flows of its long-lived assets and their integrated assets using management’s assumptions and expectations of (i) 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 reserves, and (vii) prevailing market rates of income and expenses from integrated assets. As of December 31, 2022, the Company’s estimates of commodity prices for purposes of determining undiscounted future cash flows, which are based on the NYMEX strip, ranged from a 2023 price of $79.12 per barrel of oil decreasing to a 2027 price of $64.14 per barrel of oil. Natural gas prices ranged from a 2023 price of $4.26 per Mcf of natural gas increasing to a 2027 price of $4.50 per Mcf. Both oil and natural gas commodity prices for this purpose were held flat after 2027. The Company calculates the estimated fair values of its long-lived assets and their integrated assets 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 reserves, (vii) prevailing market rates of income and expenses from integrated assets and (viii) discount rate. The expected future net cash flows are discounted using an annual rate of 10 percent to determine fair value. These are classified as Level 3 fair value assumptions. The Company did no t recognize any impairment loss during the years ended December 31, 2022 or 2021. During the year ended December 31, 2020, the carrying value of oil and natural gas properties were impaired to an estimated fair value. The fair value of oil and natural gas assets impaired, based on the grouping of the oil and natural gas assets by basin, was approximately $4.9 million at December 31, 2020, resulting in impairment losses of approximately $5.7 million for the year ended December 31, 2020. The grouping of oil and natural gas assets impaired included the SCOOP/STACK and Bakken basins, whose fair values were approximately $1.8 million and $3.1 million, respectively, at December 31, 2020. Asset retirement obligations

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2022
Acquisitions and Divestitures
Acquisitions and Divestitures	5. Acquisitions and Divestitures The Company follows ASU 2017-1 in evaluating whether acquisitions of oil and natural gas properties are accounted for as asset acquisitions or as business combinations. The majority of the Company’s acquisitions during 2022, 2021 and 2020 qualified as asset acquisitions. Acquisitions that qualified as business combinations, as discussed below, were accounted for in accordance with ASC Topic 805, Business Combinations 2022 Acquisitions During the year ended December 31, 2022, the Company acquired various oil and natural gas properties, which included working interests ranging from 0.11% to 40%, and net revenue interests ranging from 0.09% to 29%. These included the following transactions: Bakken Basin – During the year ended December 31, 2022, the Company acquired proved oil and natural gas properties in the Bakken Basin for $1.6 million. Permian Basin — During the year ended December 31, 2022, the Company closed on various asset acquisitions of unproved oil and natural gas properties for $18.0 million and proved oil and natural gas properties for $8.2 million in the Permian Basin. During the year ended December 31, 2022, the Company completed an acquisition of proved and unproved oil and natural gas properties in the Permian Basin for $13.2 million. This acquisition met the definition of a business combination. The fair value allocated to proved and unproved oil and natural gas properties was $11.2 million $2.0 million, respectively. Asset retirement obligations were immaterial. DJ Basin — During the year ended December 31, 2022, the Company acquired unproved oil and natural gas properties in the DJ Basin for $2.9 million. In addition, the Company acquired proved oil and natural gas properties in the DJ Basin for $2.3 million. Haynesville — During the year ended December 31, 2022, the Company acquired proved oil and natural gas properties in the Haynesville Basin for $3.0 million. 2022 Divestitures Permian Basin - During the year ended December 31, 2022, the Company sold a partial unit of oil and natural gas properties in the Permian Basin for approximately $3.0 million, eliminating equivalent amounts from the oil and natural gas property accounts. No gain or loss was recorded. Eagle Ford Basin — During the year ended December 31, 2022, the Company sold a partial unit of oil and natural gas properties in the Eagle Ford Basin for approximately $1.3 million, eliminating equivalent amounts from the oil and natural gas property accounts. No gain or loss was recorded. 2021 Acquisitions For the year ended December 31, 2021, the Company acquired various oil and natural gas properties, which included working interests ranging from 0.01%-34.79% and net revenue interests ranging from 0.01%-25.61%. Bakken Basin - During the year ended December 31, 2021, the Company acquired proved undeveloped oil and natural gas properties in the Bakken Basin of approximately $0.2 million. Permian Basin – During the year ended December 31, 2021, the Company acquired various proved and unproved oil and natural gas properties in the Permian Basin of approximately $43.8 million. DJ Basin - During the year ended December 31, 2021, the Company acquired various proved oil and natural gas properties of approximately $40.4 million. Customary post close adjustments were made during the year end December 31, 2021 which resulted in cash inflow of approximately $1.1 million. 2021 Divestitures Bakken Basin - During the year ended December 31, 2021, the Company sold a partial unit of oil and natural gas properties in the Bakken Basin for $0.9 million recognizing the full amount as a gain. Permian Basin - During the year ended December 31, 2021, the Company sold a complete unit of mineral interest assets in Texas for $22.5 million. The Company recorded a gain of $1.2 million associated with the sale. The Company also sold a partial unit of oil and natural gas properties in the Permian Basin for approximately $1.0 million eliminating equivalent amounts from the property accounts. SCOOP/STACK Basin - During the year ended December 31, 2021, the Company sold a complete unit of mineral interest assets in Oklahoma for approximately $1.9 million. The Company recorded a gain of $0.1 million associated with the sale. Eagle Ford Basin- During the year ended December 31, 2021, the Company sold a partial unit of oil and natural gas properties in the Eagle Ford Basin for $3.0 million, eliminating equivalent amounts from the property accounts. 2020 Acquisitions For the year ended December 31, 2020, the Company acquired various proved oil and natural gas properties, which included working interests ranging from 0.37%-50.00% and net revenue interests ranging from 0.01%-37.50%. These included the following transactions: Bakken Basin – During the year ended December 31, 2020, the Company acquired various proved oil and natural gas properties in the Bakken Basin for $0.7 million, consisting of proved developed nonproducing oil and natural gas properties and proved undeveloped oil and natural gas properties. Permian Basin - During the year ended December 31, 2020, the Company acquired various proved oil and natural gas properties in the Permian Basin for $11.6 million, consisting of proved undeveloped oil and natural gas properties and proved developed nonproducing oil and natural gas properties. In addition, the Company acquired proved oil and natural gas properties in the Permian Basin for $1.8 million that included proved developed producing properties. This acquisition met the definition of a business combination. The fair value of assets acquired and liabilities assumed is outlined in the table below. Eagle Ford - During the year ended December 31, 2020, the Company acquired proved oil and natural gas properties in the Eagle Ford Basin for $3.0 million that included proved developed producing properties. This acquisition met the definition of a business combination. The fair value of assets acquired and liabilities assumed is outlined in the table below. The following table presents a summary of the fair values of the assets acquired and the liabilities assumed in acquisitions that met the definition of a business combination: ​ ​ ​ ​ ​ ​ December 31, (in thousands) 2020 Fair value of proved assets acquired and liabilities assumed ​ Proved oil and gas properties (1) ​ $ 4,943 Less: Asset retirement obligations ​ (130) Net asset acquired ​ 4,813 Consideration transferred (including liabilities assumed) ​ $ 4,813 (1) Amount includes asset retirement costs of $0.1 million for 2020.

Asset retirement obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2022
Asset retirement obligations
Asset retirement obligations	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. Our asset retirement obligations primarily represent the present value of the estimated amount we will incur to plug, abandon and remediate our 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, 2022, 2021 and 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 Asset retirement obligations, beginning of year ​ $ 2,962 ​ $ 3,114 ​ $ 1,561 Liabilities incurred during the period ​ 1,012 ​ 465 ​ 329 Revision of estimates (1) ​ 490 ​ (868) ​ 814 Accretion of discount during the period ​ 499 ​ 447 ​ 410 Disposals or settlements ​ — ​ (196) ​ — Asset retirement obligations, end of year ​ $ 4,963 ​ $ 2,962 ​ $ 3,114 (1) Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2022
Income taxes
Income taxes	7. In 2022, the Company became the sole owner of GREP. GREP is a disregarded entity for U.S. federal income tax purposes. Prior to the Business Combination, GREP and the associated activities held by Funds were treated as partnerships for U.S. federal income tax purposes and were not subject to U.S. federal income tax. Any taxable income or loss generated prior to the Business Combination was passed through to and included in the taxable income or loss of its members. As a result of the Business Combination, the Funds' net assets were transferred to the Company resulting in carryover tax basis of those assets. The Company is a C corporation and subject to U.S. federal income tax and state and local income taxes. The Components of income tax expense were as follows for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) ​ 2022 ​ 2021 ​ 2020 Current ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ — ​ $ — ​ $ — State ​ ​ — ​ ​ — ​ ​ — ​ ​ ​ — ​ ​ — ​ ​ — Deferred ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ 11,444 ​ $ — ​ $ — State ​ ​ 1,406 ​ ​ — ​ ​ — ​ ​ ​ 12,850 ​ ​ — ​ ​ — Income tax expense ​ $ 12,850 ​ $ — ​ $ — ​ The Company's effective tax rate was 4.7%, 0% 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: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) ​ 2022 ​ 2021 ​ 2020 Income (loss) before income taxes ​ $ 275,194 ​ $ 108,459 ​ $ (23,930) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income tax expense (benefit) at federal statutory rate ​ ​ 57,791 ​ ​ 22,776 ​ (5,025) ​ Net (income) loss prior to Business Combination - non taxable ​ ​ (46,051) ​ ​ (22,776) ​ ​ 5,025 ​ State income taxes, net of federal benefit ​ ​ 1,110 ​ ​ — ​ ​ — ​ Income tax expense ​ $ 12,850 ​ $ — ​ $ — ​ Effective tax rate ​ ​ 4.7% ​ ​ 0.0% ​ ​ 0.0% ​ ​ Significant components of deferred tax assets and liabilities are included in the table below: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) ​ 2022 ​ 2021 Deferred tax assets ​ ​ ​ ​ Net operating loss carryforwards ​ $ 11,500 ​ $ — Asset retirement obligation ​ ​ 1,128 ​ — Other deductible temporary differences ​ ​ 88 ​ ​ — Total deferred tax assets ​ ​ 12,716 ​ — Less: valuation allowance ​ ​ — ​ — Net deferred tax assets ​ $ 12,716 ​ $ — ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities ​ ​ ​ ​ Property, plant and equipment ​ $ (102,112) ​ $ — Unrealized derivatives ​ ​ (2,196) ​ ​ — Total deferred tax liabilities ​ ​ (104,308) ​ ​ — Net deferred tax liability ​ $ (91,592) ​ $ — ​ As of December 31, 2022, the Company had accumulated federal net operating loss carryforward of $51.6 million, none of which are expected to expire, and state net operating loss carryforwards of approximately $51.6 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 Internal Revenue Code. As of December 31, 2022, the Company does not believe any of its net operating losses were limited under these rules. The Company is subject to the various taxing jurisdictions in the United States, including federal and certain state jurisdictions. As of December 31, 2022, the Company has no current tax years under audit. The Company remains subject to examination for federal income taxes for tax years 2019 through 2022 and state income taxes for tax years 2018 through 2022. 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, 2022 and 2021, the Company had no unrecognized tax benefits and did not recognize any interest or penalties during those respective periods related to unrecognized tax benefits. ​ On August 16, 2022, the Inflation Reduction Act (the "IRA") was enacted into law and includes significant changes related to tax, climate change, energy and health care. The provisions within IRA, among other things, include (i) a new 15% corporate alternative minimum tax on certain large corporations, (ii) a new nondeductible 1% excise tax on the value of certain stock that a company repurchases, and (iii) various tax incentives for energy and climate initiatives. Each of these provisions are effective for tax years beginning after December 31, 2022. The Department of Treasury is expected to publish regulations relevant to many aspects of the IRA. The Company is currently awaiting such guidance and continues to evaluate the effect of the new law to its future cash flows and financial results. The Company is currently evaluating the impact of the IRA on its cash taxes and income tax expense for the 2023 tax year.

Debt

Debt	12 Months Ended
	Dec. 31, 2022
Debt
Debt	8. Debt The carrying value of total debt is summarized at December 31, 2022 and 2021 as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, (in thousands) 2022 2021 Fund I Facility ​ $ — ​ $ 1,100 Fund II Facility ​ — ​ 20,000 Fund III Facility ​ — ​ 30,000 Granite Ridge Credit Agreement ​ ​ — ​ ​ ​ Total debt ​ — ​ 51,100 Less: Current portion of outstanding debt ​ — ​ (50,000) Total long-term debt ​ $ — ​ $ 1,100 ​ The Funds’ Credit Facilities The Funds maintained three revolving credit facilities prior to the Business Combination, with an aggregate outstanding balance of $51.1 million as of December 31, 2021. The Funds repaid all amounts outstanding under these credit facilities and terminated these credit facilities on October 24, 2022 in connection with the closing of the Business Combination and Granite Ridge’s entry into a new credit facility. Granite Ridge Credit Agreement On October 24, 2022, Granite Ridge entered into a senior secured revolving credit agreement (the “Credit Agreement”) among Granite Ridge, as borrower, Texas Capital Bank, as administrative agent, and the lenders from time to time party thereto. The Credit Agreement has a maturity date of five The Credit Agreement provides for aggregate elected commitments of $150.0 million, an initial borrowing base of $325.0 million and an aggregate maximum revolving credit amount of $1.0 billion. The borrowing base is scheduled to be redetermined semiannually on or about April 1 and October 1 of each calendar year, commencing April 1, 2023, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the borrower and each of 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 Granite Ridge 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. Granite Ridge does not have any borrowings or letters of credit outstanding under the Credit Agreement at December 31, 2022, resulting in availability of $150.0 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 assets of the Company and its restricted subsidiaries. Borrowings under the Credit Agreement may be base rate loans or secured overnight financing rate (“SOFR”) loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at SOFR plus an applicable margin ranging from 250 to 350 basis points, depending on the percentage of the borrowing base utilized, plus an additional 10, 15 or 20 basis point credit spread adjustment for a one three six one 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), subject to certain adjustments, of not greater than 3.00 to 1.00 as of the last day of any fiscal quarter (commencing with the fiscal quarter ending December 31, 2022), and (ii) a current ratio (as defined in the Credit Agreement), subject to certain adjustments, of not less than 1.00 to 1.00 as of the last day of any fiscal quarter (commencing with the fiscal quarter ending December 31, 2022). At December 31, 2022, the Company, was in compliance with all covenants required by the Credit Agreement.

Equity

Equity	12 Months Ended
	Dec. 31, 2022
Equity
Equity	9. Equity As a result of the Business Combination, periods prior to December 31, 2022 reflect Granite Ridge as a limited partnership, not a corporation. On the date of the Transactions, the capital of the Funds consisted of general partner interests and limited partner interests. The general partner interest was a non-economic, management interest. The general partner was granted full and complete power and authority to manage and conduct the business and affairs of the Funds and to take all such actions as it deemed necessary or appropriate to accomplish the purpose of the Funds. In connection with the Business Combination, the net assets of the Funds were transferred to GREP, which became a wholly-owned subsidiary of Granite Ridge. For additional information regarding the Business Combination, see Note 1. At December 31, 2022, the Company had 431,000,000 authorized shares of capital stock, each with a par value of $0.0001 per share, and had issued 133,294,897 shares of common stock. In connection with the closing of the Transaction, the Company’s Board of Directors adopted the Granite Ridge 2022 Omnibus Incentive Plan (“the Plan”), which provides for granting, among others, stock options, restricted stock awards and other awards 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 will not exceed 6,500,000 shares. No shares were issued under the Plan as of December 31, 2022 Common stock dividends Share repurchase program Directors of the Company may limit or terminate the stock repurchase program at any time without prior notice, but, with no further action of the Board of Directors of the Company, the stock repurchase program will terminate on December 31, 2023. At December 31, 2022, the Company had repurchased 25,920 shares under the program at an aggregate cost of $0.2 million. The extent to which the Company repurchases its shares of common stock, and the timing of such repurchases, will depend upon market conditions and other considerations as may be considered in the Company’s sole discretion. Previous Capitalization Prior to the Business Combination, the partners’ capital attributable to the Funds was divided into two classifications: (1) General Partner and (2) Limited Partners. On the date of the Business Combination, the General Partner and Limited Partner’s capital was exchanged for 130 million shares of common stock. See Note 1 for additional information on these and other transactions related to the Business Combination. Vesting Shares ​ As discussed in Note 1, 495,357 shares of Class F common stock of ENPC were converted into 1,238,393 shares of Class A common stock of ENPC, 371,518 of which became subject to certain vesting and forfeiture provisions upon their conversion to the Company’s common stock in accordance with the Business Combination Agreement (the “Vesting Shares”). Based on an assessment of the Vesting Shares, the Company considered ASC 480 and accounted for the Vesting Shares as a liability. On the date of the Business Combination, the Company recorded a liability related to the Vesting Shares of $1.3 million. In January 2023, 151,170 of these shares vested and the remaining shares were forfeited.

Related party transactions

Related party transactions	12 Months Ended
	Dec. 31, 2022
Related party transactions
Related party transactions	10. Related party transactions On the Closing Date of the Business Combination, the Grey Rock Administration, LLC (the “Manager”) entered into a Management Services Agreement with Granite Ridge (the “MSA”). Under the MSA, the Manager will provide 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 shall pay the Manager an annual services fee of $10.0 million and shall reimburse 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). The initial term of the MSA expires on April 30, 2028; however, the MSA will automatically renew for additional consecutive one-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. At December 31, 2022, service fees for the Company under the MSA were approximately $1.9 million. Prior to the Transaction, the Company paid an annual management fee to an entity under common control as compensation for providing managerial services to the Company. For the periods ended December 31, 2022, December 31, 2021 and December 31, 2020, total management fees for the Company were approximately $7.9 million, $6.2 million and $6.6 million, respectively, and are included in general and administrative expenses within the accompanying consolidated statements of operations.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and contingencies
Commitments and contingencies	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 shall pay the Manager an annual services fee of $10.0 million and shall reimburse the Manager for certain Granite Ridge group costs. The initial term of the MSA expires on April 30, 2028; however, the MSA will automatically renew for additional consecutive one-year renewal terms until terminated in accordance with its terms.

Risk concentrations

Risk concentrations	12 Months Ended
	Dec. 31, 2022
Risk concentrations
Risk concentrations	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 operation 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, 2022, 2021 and 2020. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Major Operators 2022 ​ 2021 ​ 2020 Operator A * ​ * ​ 11 % ​ Operator B * ​ * ​ 13 % ​ Operator C 12 % ​ 12 % ​ 17 % ​ Operator D * ​ 15 % ​ * ​ ​ Operator E ​ 10 % ​ * ​ ​ * ​ ​ Operator F ​ 10 % ​ * ​ ​ * ​ ​ *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, 2022, 2021, or 2020. 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 All of the Company’s outstanding derivative instruments are covered by either International Swap Dealers Association Master Agreements (“ISDAs”) entered into with parties that are also lenders under the Company’s revolving credit facility or parties under the Hedge Intercreditor Agreement. The Company’s obligation under the derivative instruments are secured pursuant to the Credit Agreement, and no additional collateral had been posted by the Company

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2022
Earnings per share
Earnings per share	13. Earnings Per Share The Company’s basic earnings (loss) per share are computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted EPS is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. ​ The following table presents the basic and diluted earnings per share computations for the years ended December 31, 2022, 2021 and 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, (in thousands) 2022 2021 2020 Net income (loss) ​ $ 262,344 ​ $ 108,459 ​ $ (23,930) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average common shares outstanding: ​ ​ ​ Weighted average common shares outstanding – basic ​ 132,923 ​ 132,923 ​ 132,923 Weighted average common shares outstanding – diluted ​ 133,074 ​ 132,923 ​ 132,923 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) per common share: ​ ​ ​ Basic ​ $ 1.97 ​ $ 0.82 ​ $ (0.18) Diluted ​ $ 1.97 ​ $ 0.82 ​ $ (0.18) ​ Diluted weighted average common shares outstanding include certain Vesting Shares, as defined in Note 9, that are expected to vest in January 2023. There were no dilutive securities outstanding for the years ended December 31, 2021 and 2020. Diluted net earnings per share for the year ended December 31, 2022 excluded 10,349,975 common stock warrants outstanding as inclusion of these items would be antidilutive.

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2022
Subsequent events
Subsequent events	14. Subsequent Events On February 21, 2023, our Board of Directors declared a cash dividend of $0.11 per share for the first quarter of 2023. Dividend payment of $14.6 million was paid on March 15, 2023 to stockholders of record as of March 1, 2023. During the first quarter of 2023, the Company acquired oil and natural gas properties in the DJ Basin and Permian Basin for $17.9 million and $6.9 million, respectively. From January 1, 2023 to March 22, 2023, the Company repurchased 222,498 shares under the share repurchase program at an aggregate cost of $1.4 million.

Summary of significant accoun_2

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2022
Summary of significant accounting policies
Principles of Consolidation	Principles of Consolidation As it pertains to the periods prior to completion of the Business Combination, the financial statements have been presented on a combined historical basis due to their prior common ownership and control. Prior to the Business Combination, the financial statements include the accounts of the Funds, all of which were commonly owned and controlled. All inter-entity balances and transactions have been eliminated in combination. As it pertains to the period subsequent to completion of the Business Combination, the accompanying consolidated financial statements also include the accounts of the Company, and all other wholly owned subsidiaries created in connection with the Business Combination. References to the “Company” prior to October 24, 2022 refer to the combined business of the Funds and references after October 24, 2022 refer to the consolidated business of Granite Ridge Resources, Inc.
Basis of Presentation	Basis of Presentation As a result of the Business Combination, periods prior to October 24, 2022 reflect Funds as limited partnerships, not as corporations. The primary financial impacts of the Transactions to the consolidated financial statements were (i) reclassification of partnership capital accounts to equity accounts reflective of a corporation and (ii) income tax effects. Since Funds were identified as entities under common control, the consolidated financial statements for periods prior to the GREP Formation Transaction have been adjusted to retrospectively combine the previously separate entities for presentation purposes. All intercompany transactions within the consolidated businesses of the Company have been eliminated. The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The Company operates in a one operating segment, which is oil and natural gas development, exploration and production. All of our operations are conducted in the geographic area of the United States. The Company’s chief operating decision maker, manages operations on a consolidated basis for purposes of evaluating operations and allocating resources.
Use of Estimates	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 work over costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties. Additional significant estimates include, but are not limited to, fair value of derivative financial instrument, fair value of business combinations, asset retirement obligations, revenue receivable and income taxes. Actual results could differ from those estimates.
Reclassifications	Reclassifications Certain reclassifications have been made to prior period amounts to conform to the current period presentation.
Cash and Restricted Cash	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. As of December 31, 2022 and 2021, the Company had $0.3 million of cash classified as restricted. This balance relates to a cash deposit for two standby letters of credit associated with oil and natural gas mining lease agreements. Restricted cash consists of cash that is stated at cost, which approximates fair market value. Classification of restricted cash is based on the nature of the restrictions associated with the underlying assets.
Revenue Receivable	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 writes off specific accounts receivable when they become uncollectible. For the years ended December 31, 2022, 2021 and 2020, the Company’s bad debt expense and allowance for doubtful accounts was immaterial.
Advance to operators	Advance 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 gas properties, net on the statement of cash flows.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for oil and gas producing activities, as further defined under ASC 932, Extractive Activities - Oil and Gas There were no exploratory wells capitalized pending determinations of whether the wells have proved reserves as of December 31, 2022 and 2021. 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 $105.3 million, $94.2 million and $79.5 million for the years ended December 31, 2022, 2021, and 2020, respectively. As a result of the Business Combination, the Company aggregated certain proved properties for amortization and impairment purposes. Costs of significant nonproducing properties, wells in the process of being drilled and completed and development projects are excluded from depletion until the related project is completed. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the years ended December 31, 2022, 2021 and 2020, no interest costs were capitalized because its exploration and development projects generally last less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred. Effective January 1, 2019, the Company adopted ASU 2017-1, Business Combinations: Clarifying the Definition of Business (“ASU 2017-1”), with the objective of adding guidance to assist in evaluating whether transactions should be accounted for as asset acquisitions or as business combinations. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and a substantive process that together significantly contribute to the ability to create output. See discussions of the Company’s oil and natural gas asset acquisitions and business combinations in Note 5. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion. Generally, no gain or loss is recognized until the entire depletion base is sold. However, gain or loss is recognized from the sale of less than an entire depletion base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. See Note 5 for additional information on our divestitures. Ordinary maintenance and repair costs are expensed as incurred. The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties and integrated assets would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved and risk-adjusted unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs and cash flows from integrated assets. The Company did not recognize an impairment expense for the years ended December 31, 2022 and 2021 related to its proved oil and natural gas properties. During the year ended December 31, 2020, the Company recognized an impairment expense of $5.7 million related to its proved oil and natural gas properties. Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the projects. The Company did not recognize an impairment expense for the years ended December 31, 2022, 2021 and 2020 related to its unproved oil and natural gas properties.
Derivative Instruments - Commodity Derivatives	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	Derivative Instruments- Common Stock Warrants The Company accounts for warrants as liability-classified instruments based on an assessment of the warrant’s specific terms and applicable authoritative guidance in Accounting Standards Codification (“ASC”) Topic 480, “Distinguishing Liabilities from Equity” (“ASC 480”) and ASC Topic 815, “Derivatives and Hedging” (“ASC 815”). The warrants are 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 are recognized as a non-operating gain or loss on the consolidated statements of operations. For the period during which the Company’s common stock was publicly traded, the fair value of the warrants was based on quoted prices in an active market. Refer to Note 4 for further discussion on fair value considerations.
Asset Retirement Obligation	Asset Retirement Obligation The Company follows the provisions of ASC 410-20, Asset Retirement Obligations 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	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 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 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 Reserves	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 transportation and production tax costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within one to three months after the month in which production occurs.
Take-in Kind Oil and Natural Gas Reserves	Take-in Kind Oil and Natural Gas Revenues Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer’s processing plant in lieu of receiving a net payment from the operator representing its proportionate share of its natural gas production. The Company currently takes certain processed gas volumes in kind in lieu of monetary settlement but does not currently take NGL volumes. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, gathering and processing costs and transportation expenses the Company incurs to transport the processed products to downstream customers are recorded in Lease Operating Expenses on the Consolidated Statements of Operations. The Company’s disaggregated revenue has two primary sources: oil sales and natural gas sales. Substantially all of the Company’s oil and natural gas sales come from six geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Haynesville Basin (Texas/Louisiana), the Denver-Julesburg “DJ” Basin (Colorado), the Bakken Basin (Montana/North Dakota) and the SCOOP/STACK Basin (Oklahoma). The following tables present the disaggregation of the Company’s oil revenues and natural gas revenues by basin for the years ended December 31, 2022, 2021 and 2020. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 Oil ​ $ 338,163 ​ $ 215,250 ​ $ 70,870 Natural gas ​ 159,254 ​ 74,943 ​ 16,228 Total ​ $ 497,417 ​ $ 290,193 ​ $ 87,098 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Permian ​ $ 266,856 ​ $ 151,179 ​ $ 37,205 Eagle Ford ​ ​ 64,879 ​ ​ 40,898 ​ ​ 12,554 Bakken ​ 64,999 ​ 56,055 ​ 27,769 Haynesville ​ 62,743 ​ 12,039 ​ 9,110 DJ ​ 37,880 ​ 29,191 ​ — SCOOP/STACK ​ 60 ​ 831 ​ 460 Total ​ $ 497,417 ​ $ 290,193 ​ $ 87,098 ​
Lease Operating Expenses	Lease Operating Expenses Lease operating expenses represents field employees’ salaries, saltwater disposal, repairs and maintenance, expensed work overs and other operating expenses. Lease operating expenses are expensed as incurred.
Production and Ad Valorem Taxes	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, 2022, 2021 and 2020 were approximately $26.9 million, $17.1 million and $6.0 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, 2022, 2021 and 2020 were approximately $3.7 million, $1.0 million and $0.7 million, respectively.
Income Taxes	Income Taxes Prior to the Business Combination, GREP and the associated activities held by Funds were treated as partnerships for U.S. federal income tax purposes and were not subject to U.S. federal income tax. As a result of the Business Combination, the Company became a C corporation and is subject to U.S. federal income tax and state and local income taxes, and accounts for income taxes under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rate on deferred income tax assets and liabilities is recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred income taxes if it is more likely than not these items will either expire before the Company is able to realize their benefits or if future deductibility is uncertain. Additionally, the Company evaluates tax positions under a more likely than not recognition threshold and measurement analysis before the positions are recognized for financial statement reporting. For further discussion, see Note 7.
Recently Issued and Applicable Accounting Pronouncements	Recently Issued and Applicable Accounting Pronouncements The FASB issued ASU No. 2016-02, “Leases (Topic 842)” which requires all leases greater than one year to be recognized as assets and liabilities. This ASU also expands the required quantitative and qualitative disclosures surrounding leases. Oil and gas leases are excluded from the guidance. We adopted this ASU on January 1, 2022 and there was no material impacts to our consolidated financial statements. The FASB issued ASU No. 2016-13, “Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” which replaces the current “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. This guidance becomes effective for fiscal years beginning after December 15, 2022, however, the impact is not expected to be material.

Summary of significant accoun_3

Summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2022
Summary of significant accounting policies
Schedule of disaggregated revenues by operation and geographic location	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 Oil ​ $ 338,163 ​ $ 215,250 ​ $ 70,870 Natural gas ​ 159,254 ​ 74,943 ​ 16,228 Total ​ $ 497,417 ​ $ 290,193 ​ $ 87,098 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Permian ​ $ 266,856 ​ $ 151,179 ​ $ 37,205 Eagle Ford ​ ​ 64,879 ​ ​ 40,898 ​ ​ 12,554 Bakken ​ 64,999 ​ 56,055 ​ 27,769 Haynesville ​ 62,743 ​ 12,039 ​ 9,110 DJ ​ 37,880 ​ 29,191 ​ — SCOOP/STACK ​ 60 ​ 831 ​ 460 Total ​ $ 497,417 ​ $ 290,193 ​ $ 87,098 ​

Derivative financial instrume_2

Derivative financial instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative financial instruments
Schedule of derivative activity by volume	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First Quarter Second Quarter Third Quarter Fourth Quarter Total Producer 3-way (oil) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Volume (Bbl) ​ 431,160 ​ 340,263 ​ 228,659 ​ 208,488 ​ 1,208,570 Weighted-average sub-floor price ($/Bbl) ​ $ 57.22 ​ $ 62.22 ​ $ 60.42 ​ $ 60.43 ​ $ 59.79 Weighted-average floor price ($/Bbl) ​ $ 70.62 ​ $ 77.89 ​ $ 79.25 ​ $ 80.00 ​ $ 75.92 Weighted-average ceiling price ($/Bbl) ​ $ 96.04 ​ $ 99.23 ​ $ 100.61 ​ $ 101.92 ​ $ 98.82 Producer 3-way (natural gas) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Volume (Mcf) ​ 2,634,993 ​ — ​ — ​ — ​ 2,634,993 Weighted-average sub-floor price ($/Mcf) ​ $ 4.41 ​ $ — ​ $ — ​ $ — ​ $ 4.41 Weighted-average floor price ($/Mcf) ​ $ 5.51 ​ $ — ​ $ — ​ $ — ​ $ 5.51 Weighted-average ceiling price ($/Mcf) ​ $ 11.28 ​ $ — ​ $ — ​ $ — ​ $ 11.28 Collar (natural gas) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Volume (Mcf) ​ 774,634 ​ 3,051,421 ​ 2,530,000 ​ 2,070,000 ​ 8,426,055 Weighted-average floor price ($/Mcf) ​ $ 5.96 ​ $ 4.12 ​ $ 4.25 ​ $ 4.50 ​ $ 4.42 Weighted-average ceiling price ($/Mcf) ​ $ 9.15 ​ $ 5.63 ​ $ 5.90 ​ $ 6.35 ​ $ 6.21 ​
Schedule of commodity derivatives reported in earnings	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 (Loss) gain on commodity derivatives ​ ​ ​ Oil derivatives ​ $ (14,985) ​ $ (24,885) ​ $ 11,604 Natural gas derivatives ​ (10,339) ​ (7,504) ​ 1,402 Total ​ $ (25,324) ​ $ (32,389) ​ $ 13,006 ​
Schedule of net cash receipts (payments on) commodity derivatives	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 Net cash (payments on) receipts from commodity derivatives ​ ​ ​ Oil derivatives ​ $ (23,695) ​ $ (19,034) ​ $ 10,180 Natural gas derivatives ​ (18,742) ​ (6,185) ​ 1,733 Total ​ $ (42,437) ​ $ (25,219) ​ $ 11,913 ​

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2022
Fair value measurements
Summary of carrying amounts and fair values of financial instruments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 ​ ​ December 31, 2021 ( in thousands) Carrying Value Fair Value Carrying Value Fair Value Assets: ​ ​ ​ ​ Derivative instruments - commodity derivatives ​ $ 10,089 ​ $ 10,089 ​ $ 465 ​ $ 465 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: ​ ​ ​ ​ Derivative instruments - common stock warrants ​ $ 11,902 ​ $ 11,902 ​ $ — ​ $ — Revolving credit facilities ​ $ — ​ $ — ​ $ 51,100 ​ $ 51,100 Derivative instruments - commodity derivatives ​ $ 431 ​ $ 431 ​ $ 7,920 ​ $ 7,920 ​
Summary of net derivative asset (liability) measured at fair value	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2022 ​ ​ Fair Value Measurement Using ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Amounts ​ Net Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Offset in the ​ Presented in the ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Fair ​ Consolidated ​ Consolidated (in thousands) Level 1 Level 2 Level 3 Value Balance Sheet Balance Sheet Assets (at fair value): ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ $ — ​ $ 20,197 ​ $ — ​ $ 20,197 ​ $ (10,108) ​ $ 10,089 Liabilities (at fair value): ​ ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ — ​ (10,539) ​ — ​ (10,539) ​ 10,108 ​ (431) Warrant liability – noncurrent portion ​ (11,902) ​ — ​ — ​ (11,902) ​ — ​ — Net derivative instruments ​ $ (11,902) ​ $ 9,658 ​ $ — ​ $ (2,244) ​ $ — ​ $ 9,658 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2021 ​ ​ Fair Value Measurement Using ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Amounts ​ Net Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Offset in the ​ Presented in the ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Fair ​ Consolidated ​ Consolidated (in thousands) Level 1 Level 2 Level 3 Value Balance Sheet Balance Sheet Assets (at fair value): ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ $ — ​ $ 4,821 ​ $ — ​ $ 4,821 ​ $ (4,387) ​ $ 434 Commodity derivatives – noncurrent portion ​ — ​ 2,147 ​ — ​ 2,147 ​ (2,116) ​ 31 Liabilities (at fair value): ​ ​ ​ ​ ​ ​ Commodity derivatives – current portion ​ — ​ (11,649) ​ — ​ (11,649) ​ 4,386 ​ (7,263) Commodity derivatives – noncurrent portion ​ — ​ (2,774) ​ — ​ (2,774) ​ 2,117 ​ (657) Net derivative instruments ​ $ — ​ $ (7,455) ​ $ — ​ $ (7,455) ​ $ — ​ $ (7,455) ​

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2022
Acquisitions and Divestitures
Summary of the fair value of the assets acquired and the liabilities assumed in the Permian Basin acquisition that met the definition of a business combination	The following table presents a summary of the fair values of the assets acquired and the liabilities assumed in acquisitions that met the definition of a business combination: ​ ​ ​ ​ ​ ​ December 31, (in thousands) 2020 Fair value of proved assets acquired and liabilities assumed ​ Proved oil and gas properties (1) ​ $ 4,943 Less: Asset retirement obligations ​ (130) Net asset acquired ​ 4,813 Consideration transferred (including liabilities assumed) ​ $ 4,813 (1) Amount includes asset retirement costs of $0.1 million for 2020.

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Asset retirement obligations
Schedule of changes in the asset retirement obligations	The following table presents the changes in the asset retirement obligations during the years ended December 31, 2022, 2021 and 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) 2022 2021 2020 Asset retirement obligations, beginning of year ​ $ 2,962 ​ $ 3,114 ​ $ 1,561 Liabilities incurred during the period ​ 1,012 ​ 465 ​ 329 Revision of estimates (1) ​ 490 ​ (868) ​ 814 Accretion of discount during the period ​ 499 ​ 447 ​ 410 Disposals or settlements ​ — ​ (196) ​ — Asset retirement obligations, end of year ​ $ 4,963 ​ $ 2,962 ​ $ 3,114 (1) Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income taxes
Schedule of components of income tax expense	The Components of income tax expense were as follows for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) ​ 2022 ​ 2021 ​ 2020 Current ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ — ​ $ — ​ $ — State ​ ​ — ​ ​ — ​ ​ — ​ ​ ​ — ​ ​ — ​ ​ — Deferred ​ ​ ​ ​ ​ ​ ​ ​ ​ Federal ​ $ 11,444 ​ $ — ​ $ — State ​ ​ 1,406 ​ ​ — ​ ​ — ​ ​ ​ 12,850 ​ ​ — ​ ​ — Income tax expense ​ $ 12,850 ​ $ — ​ $ — ​
Schedule of effective tax rate	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) ​ 2022 ​ 2021 ​ 2020 Income (loss) before income taxes ​ $ 275,194 ​ $ 108,459 ​ $ (23,930) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Income tax expense (benefit) at federal statutory rate ​ ​ 57,791 ​ ​ 22,776 ​ (5,025) ​ Net (income) loss prior to Business Combination - non taxable ​ ​ (46,051) ​ ​ (22,776) ​ ​ 5,025 ​ State income taxes, net of federal benefit ​ ​ 1,110 ​ ​ — ​ ​ — ​ Income tax expense ​ $ 12,850 ​ $ — ​ $ — ​ Effective tax rate ​ ​ 4.7% ​ ​ 0.0% ​ ​ 0.0% ​ ​
Schedule of significant components of deferred tax assets and liabilities	Significant components of deferred tax assets and liabilities are included in the table below: ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (in thousands) ​ 2022 ​ 2021 Deferred tax assets ​ ​ ​ ​ Net operating loss carryforwards ​ $ 11,500 ​ $ — Asset retirement obligation ​ ​ 1,128 ​ — Other deductible temporary differences ​ ​ 88 ​ ​ — Total deferred tax assets ​ ​ 12,716 ​ — Less: valuation allowance ​ ​ — ​ — Net deferred tax assets ​ $ 12,716 ​ $ — ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities ​ ​ ​ ​ Property, plant and equipment ​ $ (102,112) ​ $ — Unrealized derivatives ​ ​ (2,196) ​ ​ — Total deferred tax liabilities ​ ​ (104,308) ​ ​ — Net deferred tax liability ​ $ (91,592) ​ $ — ​

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2022
Debt
Schedule of long-term debt at carrying value	The carrying value of total debt is summarized at December 31, 2022 and 2021 as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, (in thousands) 2022 2021 Fund I Facility ​ $ — ​ $ 1,100 Fund II Facility ​ — ​ 20,000 Fund III Facility ​ — ​ 30,000 Granite Ridge Credit Agreement ​ ​ — ​ ​ ​ Total debt ​ — ​ 51,100 Less: Current portion of outstanding debt ​ — ​ (50,000) Total long-term debt ​ $ — ​ $ 1,100 ​

Risk Concentrations (Tables)

Risk Concentrations (Tables)	12 Months Ended
	Dec. 31, 2022
Risk concentrations
Schedule of third-party operating partners who have accounted for 10% or more of revenues	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, 2022, 2021 and 2020. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Major Operators 2022 ​ 2021 ​ 2020 Operator A * ​ * ​ 11 % ​ Operator B * ​ * ​ 13 % ​ Operator C 12 % ​ 12 % ​ 17 % ​ Operator D * ​ 15 % ​ * ​ ​ Operator E ​ 10 % ​ * ​ ​ * ​ ​ Operator F ​ 10 % ​ * ​ ​ * ​ ​ *Less than 10%

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings per share
Schedule of basic and diluted earnings per share	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, (in thousands) 2022 2021 2020 Net income (loss) ​ $ 262,344 ​ $ 108,459 ​ $ (23,930) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average common shares outstanding: ​ ​ ​ Weighted average common shares outstanding – basic ​ 132,923 ​ 132,923 ​ 132,923 Weighted average common shares outstanding – diluted ​ 133,074 ​ 132,923 ​ 132,923 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) per common share: ​ ​ ​ Basic ​ $ 1.97 ​ $ 0.82 ​ $ (0.18) Diluted ​ $ 1.97 ​ $ 0.82 ​ $ (0.18) ​

Organization and Nature of op_2

Organization and Nature of operations (Details) - USD ($)	Oct. 24, 2022	Dec. 31, 2022
Business Acquisition
Common stock, shares authorized		431,000,000
Granite Ridge Common Stock
Business Acquisition
Common stock, shares authorized		431,000,000
Shares issues to existing GREP members upon business combination closing	130,000,000
ENPC Common Class A
Business Acquisition
Common stock shares converted	1
ENPC Common Class F
Business Acquisition
Common stock to be converted	1
Executive Network Partnering Corporation
Business Acquisition
Business acquisition, cash consideration transferred	$ 396,100,000
Warrants to be converted	1
Total aggregate investment by ENPC	$ 6,800,000
Executive Network Partnering Corporation | Granite Ridge Common Stock
Business Acquisition
Shares issues to existing GREP members upon business combination closing	130,000,000
Executive Network Partnering Corporation | ENPC Common Class A
Business Acquisition
Common stock, shares authorized	41,400,000
Common stock, shares outstanding	39,343,496
Business acquisition, redemption price per share	$ 10.07
Executive Network Partnering Corporation | ENPC Common Class A | ENPC Conversion Activity, Effective Time of Merger
Business Acquisition
Shares converted during merger	1,238,393
Converted shares subject to certain vesting provisions	371,518
Converted shares subject to certain vesting provisions, forfeitures	$ 220,348
Executive Network Partnering Corporation | ENPC Common Class F | ENPC Conversion Activity, Effective Time of Merger
Business Acquisition
Shares to-be converted during merger	495,357
Shares forfeited	220,348

Summary of significant accoun_4

Summary of significant accounting policies - Basis of presentation (Details)	12 Months Ended
	Dec. 31, 2022 $ / shares
Common stock, par value	$ 0.0001
Operating segments	1
Granite Ridge Common Stock
Common stock, par value	$ 0.0001

Summary of significant accoun_5

Summary of significant accounting policies - Cash and restricted cash (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) item	Dec. 31, 2021 USD ($) item	Dec. 31, 2020 USD ($)
Cash classified as restricted | $	$ 300	$ 300	$ 300
Number of standby letters of credit | item	2	2
Maximum
Cash investment term	90 days

Summary of significant accoun_6

Summary of significant accounting policies - Advance to operators (Details)	12 Months Ended
	Dec. 31, 2022
Maximum
Advance payments to operators, term	90 days

Summary of significant accoun_7

Summary of significant accounting policies - Oil and natural gas properties (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Summary of significant accounting policies
Exploratory wells capitalized whose proved reserves are yet to be determined	$ 0	$ 0
Interest costs capitalized	0	0	$ 0
Depletion and accretion recognized	$ 105,300,000	$ 94,200,000	79,500,000
Impairments of long-lived assets			$ 5,725,000

Summary of significant accoun_8

Summary of significant accounting policies - Revenue recognition (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Disaggregation of Revenue
Number of revenue sources	2
Operating regions	6
Revenue	$ 497,417	$ 290,193	$ 87,098
Permian
Disaggregation of Revenue
Revenue	266,856	151,179	37,205
Eagle Ford
Disaggregation of Revenue
Revenue	64,879	40,898	12,554
Bakken
Disaggregation of Revenue
Revenue	64,999	56,055	27,769
Haynesville
Disaggregation of Revenue
Revenue	62,743	12,039	9,110
Denver-Julesburg
Disaggregation of Revenue
Revenue	37,880	29,191
SCOOP/STACK
Disaggregation of Revenue
Revenue	60	831	460
Oil
Disaggregation of Revenue
Revenue	338,163	215,250	70,870
Natural Gas
Disaggregation of Revenue
Revenue	$ 159,254	$ 74,943	$ 16,228

Summary of significant accoun_9

Summary of significant accounting policies - Production and Ad Valorem taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Production Tax
Production taxes	$ 26.9	$ 17.1	$ 6
Ad Valorem Tax
AD VALOREM taxes	$ 3.7	$ 1	$ 0.7

Derivative instruments - Volume

Derivative instruments - Volume of derivative activities (Details)	Dec. 31, 2022 $ / bbl $ / Mcf Mcf bbl
Producer 3-way (crude oil) | 2023
Derivative instruments
Derivative volume activity | bbl	1,208,570
Producer 3-way (crude oil) | First Quarter (2023)
Derivative instruments
Derivative volume activity | bbl	431,160
Producer 3-way (crude oil) | Second Quarter (2023)
Derivative instruments
Derivative volume activity | bbl	340,263
Producer 3-way (crude oil) | Third Quarter (2023)
Derivative instruments
Derivative volume activity | bbl	228,659
Producer 3-way (crude oil) | Fourth Quarter (2023)
Derivative instruments
Derivative volume activity | bbl	208,488
Producer 3-way (crude oil) | Weighted-average sub-floor price | 2023
Derivative instruments
Derivative contract prices | $ / bbl	59.79
Producer 3-way (crude oil) | Weighted-average sub-floor price | First Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	57.22
Producer 3-way (crude oil) | Weighted-average sub-floor price | Second Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	62.22
Producer 3-way (crude oil) | Weighted-average sub-floor price | Third Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	60.42
Producer 3-way (crude oil) | Weighted-average sub-floor price | Fourth Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	60.43
Producer 3-way (crude oil) | Weighted-average floor price | 2023
Derivative instruments
Derivative contract prices | $ / bbl	75.92
Producer 3-way (crude oil) | Weighted-average floor price | First Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	70.62
Producer 3-way (crude oil) | Weighted-average floor price | Second Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	77.89
Producer 3-way (crude oil) | Weighted-average floor price | Third Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	79.25
Producer 3-way (crude oil) | Weighted-average floor price | Fourth Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	80
Producer 3-way (crude oil) | Weighted-average ceiling price | 2023
Derivative instruments
Derivative contract prices | $ / bbl	98.82
Producer 3-way (crude oil) | Weighted-average ceiling price | First Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	96.04
Producer 3-way (crude oil) | Weighted-average ceiling price | Second Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	99.23
Producer 3-way (crude oil) | Weighted-average ceiling price | Third Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	100.61
Producer 3-way (crude oil) | Weighted-average ceiling price | Fourth Quarter (2023)
Derivative instruments
Derivative contract prices | $ / bbl	101.92
Producer 3-way (natural gas) | 2023
Derivative instruments
Derivative volume activity | Mcf	2,634,993
Producer 3-way (natural gas) | First Quarter (2023)
Derivative instruments
Derivative volume activity | Mcf	2,634,993
Producer 3-way (natural gas) | Weighted-average sub-floor price | 2023
Derivative instruments
Derivative contract prices	4.41
Producer 3-way (natural gas) | Weighted-average sub-floor price | First Quarter (2023)
Derivative instruments
Derivative contract prices	4.41
Producer 3-way (natural gas) | Weighted-average floor price | 2023
Derivative instruments
Derivative contract prices	5.51
Producer 3-way (natural gas) | Weighted-average floor price | First Quarter (2023)
Derivative instruments
Derivative contract prices	5.51
Producer 3-way (natural gas) | Weighted-average ceiling price | 2023
Derivative instruments
Derivative contract prices	11.28
Producer 3-way (natural gas) | Weighted-average ceiling price | First Quarter (2023)
Derivative instruments
Derivative contract prices	11.28
Collar (natural gas) | 2023
Derivative instruments
Derivative volume activity | Mcf	8,426,055
Collar (natural gas) | First Quarter (2023)
Derivative instruments
Derivative volume activity | Mcf	774,634
Collar (natural gas) | Second Quarter (2023)
Derivative instruments
Derivative volume activity | Mcf	3,051,421
Collar (natural gas) | Third Quarter (2023)
Derivative instruments
Derivative volume activity | Mcf	2,530,000
Collar (natural gas) | Fourth Quarter (2023)
Derivative instruments
Derivative volume activity | Mcf	2,070,000
Collar (natural gas) | Weighted-average floor price | 2023
Derivative instruments
Derivative contract prices	4.42
Collar (natural gas) | Weighted-average floor price | First Quarter (2023)
Derivative instruments
Derivative contract prices	5.96
Collar (natural gas) | Weighted-average floor price | Second Quarter (2023)
Derivative instruments
Derivative contract prices	4.12
Collar (natural gas) | Weighted-average floor price | Third Quarter (2023)
Derivative instruments
Derivative contract prices	4.25
Collar (natural gas) | Weighted-average floor price | Fourth Quarter (2023)
Derivative instruments
Derivative contract prices	4.50
Collar (natural gas) | Weighted-average ceiling price | 2023
Derivative instruments
Derivative contract prices	6.21
Collar (natural gas) | Weighted-average ceiling price | First Quarter (2023)
Derivative instruments
Derivative contract prices	9.15
Collar (natural gas) | Weighted-average ceiling price | Second Quarter (2023)
Derivative instruments
Derivative contract prices	5.63
Collar (natural gas) | Weighted-average ceiling price | Third Quarter (2023)
Derivative instruments
Derivative contract prices	5.90
Collar (natural gas) | Weighted-average ceiling price | Fourth Quarter (2023)
Derivative instruments
Derivative contract prices	6.35

Derivative instruments - Impact

Derivative instruments - Impact of commodity derivatives on earnings (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative instruments
(Loss) gain on derivatives - commodity derivatives	$ (25,324)	$ (32,389)	$ 13,006
Net cash (payments on) receipts from derivatives	(42,437)	(25,219)	11,913
Crude oil derivatives
Derivative instruments
(Loss) gain on derivatives - commodity derivatives	(14,985)	(24,885)	11,604
Net cash (payments on) receipts from derivatives	(23,695)	(19,034)	10,180
Natural gas derivatives
Derivative instruments
(Loss) gain on derivatives - commodity derivatives	(10,339)	(7,504)	1,402
Net cash (payments on) receipts from derivatives	$ (18,742)	$ (6,185)	$ 1,733

Derivative instruments - Common

Derivative instruments - Common stock warrants (Details)		12 Months Ended
	Oct. 24, 2022 $ / shares shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Derivative instruments
Derivative liabilities - common stock warrants		$ 11,902,000
Gain on derivatives - common stock warrants		362,000
Warrants
Derivative instruments
Common stock issued | shares	10,349,975
Exercise price of warrants | $ / shares	$ 11.50
Shares of common stock underlying each warrant	1
Period after business combination close in which warrants become exercisable	30 days
Period after business combination close in which warrants expire	5 years
Derivative liabilities - common stock warrants		11,900,000	$ 12,300,000
Gain on derivatives - common stock warrants		400,000
Proceeds from warrant exercises		$ 0
Warrants | Granite Ridge common stock equal to or exceeding $18.00 for 20 days within a 30-day trading period
Derivative instruments
Redemption price per warrant | $ / shares	$ 0.01
Common stock redemption price trigger | $ / shares	$ 18
Days inside a 30-day trading period common stock must equal or exceed $18.00	20 days
Trading period threshold for redemption of warrants	30 days

Fair value measurements - Carry

Fair value measurements - Carrying amounts and fair values of financial instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Assets:
Derivative instruments - commodity derivatives	$ 10,089	$ 434
Liabilities:
Derivative instruments - common stock warrants	11,902
Derivative instruments - commodity derivatives	431	7,263
Carrying Value
Assets:
Derivative instruments - commodity derivatives	10,089	465
Liabilities:
Derivative instruments - common stock warrants	11,902
Revolving credit facilities		51,100
Derivative instruments - commodity derivatives	431	7,920
Total Fair Value
Assets:
Derivative instruments - commodity derivatives	10,089	465
Liabilities:
Derivative instruments - common stock warrants	11,902
Revolving credit facilities		51,100
Derivative instruments - commodity derivatives	431	7,920
Fair Value, Recurring | Total Fair Value
Assets:
Derivative instruments - commodity derivatives	20,197	4,821
Liabilities:
Derivative instruments - common stock warrants	11,902
Derivative instruments - commodity derivatives	$ 10,539	$ 11,649

Fair value measurements - Fair

Fair value measurements - Fair value of net derivative instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Assets (at fair value):
Commodity derivatives - current portion	$ 10,089	$ 434
Commodity derivatives - noncurrent portion		31
Liabilities (at fair value):
Commodity derivatives - current portion	(431)	(7,263)
Warrant liability - noncurrent position	(11,902)
Commodity derivatives - noncurrent portion		(657)
Total Fair Value
Assets (at fair value):
Commodity derivatives - current portion	10,089	465
Liabilities (at fair value):
Commodity derivatives - current portion	(431)	(7,920)
Warrant liability - noncurrent position	(11,902)
Fair Value, Recurring
Assets (at fair value):
Commodity derivatives - current portion - Net of fair value presented in CBS	10,089	434
Commodity derivatives - noncurrent portion - Net of fair value presented in CBS		31
Liabilities (at fair value):
Commodity derivatives - current portion - Net fair value presented in CBS	(431)	(7,263)
Warrant liability - noncurrent portion - Net fair value presented in CBS		(657)
Net derivative instruments	9,658	(7,455)
Fair Value, Recurring | Total Fair Value
Assets (at fair value):
Commodity derivatives - current portion	20,197	4,821
Commodity derivatives - current portion offset in the Consolidated Balance Sheet	(10,108)	(4,387)
Commodity derivatives - noncurrent portion		2,147
Commodity derivatives - noncurrent portion offset in the Consolidated Balance Sheet		(2,116)
Liabilities (at fair value):
Commodity derivatives - current portion	(10,539)	(11,649)
Commodity derivatives - current portion - Offset in Consolidated Balance Sheet	10,108	4,386
Warrant liability - noncurrent position	(11,902)
Commodity derivatives - noncurrent portion		(2,774)
Warrant liability - noncurrent portion- Offset in the Consolidated Balance Sheet		2,117
Net derivative instruments	(2,244)	(7,455)
Fair Value, Recurring | Level 1 | Total Fair Value
Liabilities (at fair value):
Warrant liability - noncurrent position	(11,902)
Net derivative instruments	(11,902)
Fair Value, Recurring | Level 2 | Total Fair Value
Assets (at fair value):
Commodity derivatives - current portion	20,197	4,821
Commodity derivatives - noncurrent portion		2,147
Liabilities (at fair value):
Commodity derivatives - current portion	(10,539)	(11,649)
Commodity derivatives - noncurrent portion		(2,774)
Net derivative instruments	$ 9,658	$ (7,455)

Fair value measurements - Fai_2

Fair value measurements - Fair value nonrecurring (Details) - Fair Value, Nonrecurring - Level 3	Dec. 31, 2022 $ / Mcf $ / bbl
Oil commodity prices per barrel 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contract prices | $ / bbl	79.12
Oil commodity prices per barrel 2027
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contract prices | $ / bbl	64.14
Natural gas commodity prices per Mcf 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contract prices | $ / Mcf	4.26
Natural gas commodity prices per Mcf 2027
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative contract prices | $ / Mcf	4.50

Fair value measurements - Fai_3

Fair value measurements - Fair values nonrecurring - Additional information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairments of long-lived assets			$ 5,725,000
Fair Value, Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of oil and natural gas assets			4,900,000
Impairments of long-lived assets	$ 0	$ 0	5,700,000
Fair Value, Nonrecurring | Level 3 | SCOOP/STACK
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of oil and natural gas assets			1,800,000
Fair Value, Nonrecurring | Level 3 | Bakken
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of oil and natural gas assets			$ 3,100,000
Fair Value, Nonrecurring | Level 3 | Discount Rate, Future Net Cash Flows
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate (percentage)	10%

Acquisitions and Divestitures_2

Acquisitions and Divestitures (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and natural gas properties
Oil and natural gas properties sold		$ 4,845,000	$ 29,443,000	$ 647,000
Denver-Julesburg
Oil and natural gas properties
Acquisitions of oil and natural gas properties	$ 17,900,000
2020 Acquisitions | Bakken | Proved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties				$ 700,000
2020 Acquisitions | Permian | Proved oil and natural gas properties
Oil and natural gas properties
Oil and natural gas properties qualified as purchases of a business				1,800,000
Acquisitions of oil and natural gas properties				$ 11,600,000
2020 Acquisitions | Eagle Ford | Proved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties				$ 3,000,000
2021 Acquisitions | Bakken | Proved undeveloped oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties			200,000
2021 Acquisitions | Permian | Proved and unproved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties			43,800,000
2021 Acquisitions | Denver-Julesburg | Proved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties			40,400,000
Cash inflow (outflow) for customary post close adjustments			1,100,000
2021 Divestitures | Bakken
Oil and natural gas properties
Oil and natural gas properties sold			900,000
2021 Divestitures | Permian | Mineral interest assets
Oil and natural gas properties
Oil and natural gas properties sold			22,500,000
Gain (loss) on oil and gas property divestitures			1,200,000
2021 Divestitures | Permian | Mineral interest assets, partial unit
Oil and natural gas properties
Gain (loss) on oil and gas property divestitures			1,000,000
2021 Divestitures | SCOOP/STACK | Mineral interest assets
Oil and natural gas properties
Oil and natural gas properties sold			1,900,000
Gain (loss) on oil and gas property divestitures			100,000
2021 Divestitures | Eagle Ford | Mineral interest assets, partial unit
Oil and natural gas properties
Oil and natural gas properties sold			$ 3,000,000
2022 Acquisitions | Bakken | Proved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties		$ 1,600,000
2022 Acquisitions | Permian | Proved oil and natural gas properties
Oil and natural gas properties
Oil and natural gas properties qualified as purchases of a business		11,200,000
Acquisitions of oil and natural gas properties		$ 8,200,000
2022 Acquisitions | Permian | Unproved oil and natural gas properties
Oil and natural gas properties
Oil and natural gas properties qualified as purchases of a business		2,000,000
Acquisitions of oil and natural gas properties		$ 18,000,000
2022 Acquisitions | Permian | Proved and unproved oil and natural gas properties
Oil and natural gas properties
Oil and natural gas properties qualified as purchases of a business		13,200,000
2022 Acquisitions | Denver-Julesburg | Proved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties		$ 2,300,000
2022 Acquisitions | Denver-Julesburg | Unproved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties		2,900,000
2022 Acquisitions | Haynesville | Proved oil and natural gas properties
Oil and natural gas properties
Acquisitions of oil and natural gas properties		3,000,000
2022 Divestitures | Permian | Mineral interest assets, partial unit
Oil and natural gas properties
Oil and natural gas properties sold		3,000,000
Gain (loss) on oil and gas property divestitures		0
2022 Divestitures | Eagle Ford | Mineral interest assets, partial unit
Oil and natural gas properties
Oil and natural gas properties sold		1,300,000
Gain (loss) on oil and gas property divestitures		$ 0
Minimum | 2020 Acquisitions
Oil and natural gas properties
Working interests in proved oil and natural gas properties				0.37%
Net revenue interests in proved oil and natural gas properties				0.01%
Minimum | 2021 Acquisitions
Oil and natural gas properties
Working interests in proved oil and natural gas properties			0.01%
Net revenue interests in proved oil and natural gas properties			0.01%
Minimum | 2022 Acquisitions
Oil and natural gas properties
Working interests in proved oil and natural gas properties		0.11%
Net revenue interests in proved oil and natural gas properties		0.09%
Maximum | 2020 Acquisitions
Oil and natural gas properties
Working interests in proved oil and natural gas properties				50%
Net revenue interests in proved oil and natural gas properties				37.50%
Maximum | 2021 Acquisitions
Oil and natural gas properties
Working interests in proved oil and natural gas properties			34.79%
Net revenue interests in proved oil and natural gas properties			25.61%
Maximum | 2022 Acquisitions
Oil and natural gas properties
Working interests in proved oil and natural gas properties		40%
Net revenue interests in proved oil and natural gas properties		29%

Acquisitions and Divestitures -

Acquisitions and Divestitures - Fair value of assets acquired and liabilities assumed in Permian Basin acquisition (Details) - 2020 Acquisitions $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($)
Fair value of proved assets acquired and liabilities assumed
Proved oil and gas properties (1)	$ 4,943
Less: Asset retirement obligations	(130)
Net assets acquired	4,813
Consideration transferred (including liabilities assumed)	4,813
Asset retirement costs	$ 130

Asset retirement obligations (D

Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset retirement obligations
Asset retirement obligations, beginning of year	$ 2,962	$ 3,114	$ 1,561
Liabilities incurred during the period	1,012	465	329
Revision of estimates (1)	490	(868)	814
Accretion of discount during the period	499	447	410
Disposals or settlements		(196)
Asset retirement obligations, end of year	$ 4,963	$ 2,962	$ 3,114

Income taxes (Details)

Income taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Deferred
Federal	$ 11,444
State	1,406
Deferred income taxes	12,850
Income tax expense	12,850
Reconciliation of income tax expense (benefit)
Income (loss) before income taxes	275,194	$ 108,459	$ (23,930)
Income tax expense (benefit) at federal statutory rate	57,791	22,776	(5,025)
Net (income) loss prior to Business Combination - non taxable	(46,051)	$ (22,776)	$ 5,025
State income taxes, net of federal benefit	1,110
Income tax expense	$ 12,850
Effective tax rate	4.70%	0%	0%
Deferred tax assets
Net operating loss carryforwards	$ 11,500
Asset retirement obligation	1,128
Other deductible temporary difference	88
Total deferred tax assets	12,716
Net deferred tax assets	12,716
Deferred tax liabilities
Property, plant and equipment	(102,112)
Unrealized derivatives	(2,196)
Total deferred tax liabilities	(104,308)
Net deferred tax liabilities	$ (91,592)

Income taxes - Narratives (Deta

Income taxes - Narratives (Details) - USD ($)	12 Months Ended			24 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2022
Income taxes
Effective tax rate	4.70%	0%	0%
Enacted statutory rate	21%
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration	$ 51,600,000			$ 51,600,000
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	$ 51,600,000			51,600,000
Unrecognized tax benefits, interest or penalties				$ 0
Inflation Reduction Act, excise tax percentage	1%
Inflation Reduction Act, corporate alternative minimum tax percentage	15%

Debt - Carrying value of debt (

Debt - Carrying value of debt (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Debt Instrument [Line Items]
Total debt	$ 51,100
Less: Current portion of outstanding debt	(50,000)
Total long-term debt	1,100
Fund I Facility
Debt Instrument [Line Items]
Total debt	1,100
Fund II Facility
Debt Instrument [Line Items]
Total debt	20,000
Fund III Facility
Debt Instrument [Line Items]
Total debt	$ 30,000

Debt - Additional information (

Debt - Additional information (Details) $ in Thousands		12 Months Ended
	Oct. 24, 2022 USD ($)	Dec. 31, 2021 USD ($) item
Credit facility
Total debt		$ 51,100
The Funds' Credit Facilities
Credit facility
No. of revolving credit facilities | item		3
Line of credit		$ 51,100
Granite Ridge Credit Facility
Credit facility
Debt instrument term	5 years
Capacity for aggregate elected commitments	$ 150,000
Initial borrowing capacity	325,000
Maximum borrowing capacity	$ 1,000,000
Frequency of payments	quarterly
Commitment fee percentage	0.50%
Granite Ridge Credit Facility | Minimum
Credit facility
Current ratio	100%
Granite Ridge Credit Facility | Maximum
Credit facility
Leverage ratio	300%
Granite Ridge Credit Facility | Secured Overnight Financing Rate (SOFR) | Credit Spread Adjustment Scenario 1
Credit facility
Variable interest rate adjustment term	1 month
Interest rate increase	0.10%
Granite Ridge Credit Facility | Secured Overnight Financing Rate (SOFR) | Credit Spread Adjustment Scenario 2
Credit facility
Variable interest rate adjustment term	3 months
Interest rate increase	0.15%
Granite Ridge Credit Facility | Secured Overnight Financing Rate (SOFR) | Credit Spread Adjustment Scenario 3
Credit facility
Variable interest rate adjustment term	6 months
Interest rate increase	0.20%
Granite Ridge Credit Facility | Secured Overnight Financing Rate (SOFR) | Minimum
Credit facility
Variable interest rate	2.50%
Granite Ridge Credit Facility | Secured Overnight Financing Rate (SOFR) | Maximum
Credit facility
Variable interest rate	3.50%
Granite Ridge Credit Facility | U.S. Prime Rate
Credit facility
Interest rate increase	0.50%
Granite Ridge Credit Facility | U.S. Prime Rate | Credit Spread Adjustment Scenario 1
Credit facility
Variable interest rate adjustment term	1 month
Interest rate increase	1%
Granite Ridge Credit Facility | U.S. Prime Rate | Minimum | Credit Spread Adjustment Scenario 1
Credit facility
Additional to margin added to interest rate	1.50%
Granite Ridge Credit Facility | U.S. Prime Rate | Maximum | Credit Spread Adjustment Scenario 1
Credit facility
Additional to margin added to interest rate	2.50%

Equity (Details)

Equity (Details) - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 24, 2022	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2022
Class of Stock [Line Items]
Common stock, shares authorized		431,000,000	431,000,000	431,000,000
Common stock, par value		$ 0.0001	$ 0.0001	$ 0.0001
Common stock, shares issued		133,294,897	133,294,897	133,294,897
Dividends, Common Stock, Cash			$ 10,700
Common Stock, Dividends, Per Share, Cash Paid			$ 0.08
Treasury Stock, Value, Acquired, Cost Method				$ 229
Omnibus Incentive Plan
Class of Stock [Line Items]
Share-based awards authorized		6,500,000	6,500,000	6,500,000
Common stock, shares issued		0	0	0
ENPC Common Class A | ENPC Conversion Activity, Effective Time of Merger
Class of Stock [Line Items]
Shares converted during merger	1,238,393
Converted shares subject to certain vesting provisions	371,518
Vesting shares liability	$ 1,300
Shares vested		151,170	151,170	151,170
ENPC Common Class F | ENPC Conversion Activity, Effective Time of Merger
Class of Stock [Line Items]
Shares to-be converted during merger	495,357
Granite Ridge Common Stock
Class of Stock [Line Items]
Common stock, shares authorized		431,000,000	431,000,000	431,000,000
Common stock, par value		$ 0.0001	$ 0.0001	$ 0.0001
Common stock, shares issued		133,294,897	133,294,897	133,294,897
Shares issues to existing GREP members upon business combination closing	130,000,000
Granite Ridge Common Stock | Common Stock Repurchase Program
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount		$ 50,000	$ 50,000	$ 50,000
Treasury Stock, Shares, Acquired		25,920
Treasury Stock, Value, Acquired, Cost Method		$ 200

Related party transactions (Det

Related party transactions (Details) - Management Company (MSA) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related party transactions
Annual management fees payable	$ 10
Oil and gas management agreement, renewal term	1 year
Oil and gas management agreement, transition services term	90 days
Management fees paid	$ 1.9
Due to management company	$ 7.9	$ 6.2	$ 6.6

Commitments and contingencies (

Commitments and contingencies (Details) - Management Company (MSA) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Related party transactions
Annual management fees payable	$ 10
Oil and gas management agreement, renewal term	1 year

Risk concentrations (Details)

Risk concentrations (Details) - item	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Risk concentrations
Percentage of wells operated by third-party operating partners	100%
Number of operators	0	0	0
Sales revenue | Oil and natural gas
Risk concentrations
Benchmark percentage of revenues contributed by major operators	10%	10%	10%
Benchmark used to determine the disclosure of revenues contributed by major operators	10%	10%	10%
Sales revenue | Oil and natural gas | Operator A
Risk concentrations
Concentration risk (as a percent)			11%
Sales revenue | Oil and natural gas | Operator B
Risk concentrations
Concentration risk (as a percent)			13%
Sales revenue | Oil and natural gas | Operator C
Risk concentrations
Concentration risk (as a percent)	12%	12%	17%
Sales revenue | Oil and natural gas | Operator D
Risk concentrations
Concentration risk (as a percent)		15%
Sales revenue | Oil and natural gas | Operator E
Risk concentrations
Concentration risk (as a percent)	10%
Sales revenue | Oil and natural gas | Operator F
Risk concentrations
Concentration risk (as a percent)	10%

Earnings per share (Details)

Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2021
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) as reported	$ 262,344	$ 108,459	$ (23,930)
Weighted average common shares outstanding:
Basic	132,923,000	132,923,000	132,923,000
Diluted	133,074,000	132,923,000	132,923,000
Net income (loss) per common share:
Basic	$ 1.97	$ 0.82	$ (0.18)
Diluted	$ 1.97	$ 0.82	$ (0.18)
Warrants
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive shares excluded from EPS	10,349,975			0

Subsequent events (Details)

Subsequent events (Details) - USD ($) $ / shares in Units, $ in Thousands				3 Months Ended	12 Months Ended
	Mar. 15, 2023	Feb. 21, 2023	Jan. 01, 2023	Mar. 31, 2023	Dec. 31, 2022
Subsequent events
Common stock dividend declared					$ 0.08
Payments of dividend					$ 10,664
Repurchase of treasury shares					$ 229
Denver-Julesburg
Subsequent events
Property Plant and Equipment, Additions				$ 17,900
Subsequent Events
Subsequent events
Common stock dividend declared		$ 0.11
Payments of dividend	$ 14,600
Repurchase of treasury shares			$ 1,400
Repurchase of treasury shares (Shares)			222,498
Subsequent Events | Permian
Subsequent events
Property Plant and Equipment, Additions				$ 6,900