0001558370-22-017579 | 10-Q | XBRL Viewer | Granite Ridge Resources INC

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Document and Entity Information - $ / shares	9 Months Ended
Document and Entity Information - $ / shares	Sep. 30, 2022	Nov. 10, 2022
Document And Entity Information
Document Type	10-Q
Document Quarterly Report	true
Document Transition Report	false
Document Period End Date	Sep. 30, 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 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
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		133,294,897
Entity Central Index Key	0001928446
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q3
Amendment Flag	false
Common Stock
Document And Entity Information
Title of 12(b) Security	Common Stock, par value $0.0001 per share
Trading Symbol	GRNT
Security Exchange Name	NYSE
Warrants
Document And Entity Information
Title of 12(b) Security	Warrants to purchase Common Stock, each whole warrant exercisable for one share of common stock at an exercise price of $11.50 per share
Trading Symbol	GRNT WS
Security Exchange Name	NYSE
Exercise price of warrants	$ 11.50
Number of securities called by each warrant or right	1

CONDENSED COMBINED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Current assets:
Cash	$ 6,410	$ 7,319
Revenue receivable	54,324	32,697
Advances to operators	26,230	37,150
Other assets	4,098	70
Other Receivable		469
Derivative assets	4,376
Contributions receivable	10	94
Total current assets	95,448	77,799
Property and equipment:
Oil and gas properties, successful efforts method	550,163	376,657
Accumulated depletion	(168,302)	(98,266)
Total property and equipment, net	381,861	278,391
Long-term assets:
Derivative assets	812
TOTAL ASSETS	478,121	356,190
Current liabilities:
Accrued expenses	20,595	6,640
Derivative liabilities	3,941	3,953
Credit facilities		29,938
Total current liabilities	24,536	40,531
Long-term liabilities:
Derivative liabilities		400
Asset retirement obligations	2,243	963
Total long-term liabilities	2,243	1,363
Total Liabilities	26,779	41,894
Commitments and contingencies
Partners' capital:
General partner	41,614	15,462
Limited partners	409,728	298,834
Total partners' capital	451,342	314,296
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 478,121	$ 356,190

CONDENSED COMBINED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
REVENUES
Oil, natural gas, and related product sales, net	$ 90,194	$ 55,717	$ 263,263	$ 142,632
EXPENSES
Lease operating expenses	6,368	3,621	15,840	8,407
Production taxes	5,053	2,506	14,628	7,737
Depletion and accretion expense	39,868	15,794	70,529	45,798
General and administrative	1,776	1,764	4,880	4,978
Total expenses	53,065	23,685	105,877	66,920
Net operating income (loss)	37,129	32,032	157,386	75,712
OTHER INCOME/(EXPENSE)
Gain/(loss) on derivative contracts	6,082	(6,558)	(19,147)	(18,115)
Interest expense	476	353	1,193	926
Total other income (expense)	5,606	(6,911)	(20,340)	(19,041)
NET INCOME/(LOSS)	$ 42,735	$ 25,121	$ 137,046	$ 56,671

CONDENSED COMBINED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Thousands	General Partner	Limited Partner	Total
Balance at period beginning at Dec. 31, 2020	$ 657	$ 177,772	$ 178,429
Net income/(loss)	51	15,459	15,510
Balance at period end at Mar. 31, 2021	708	193,231	193,939
Balance at period beginning at Dec. 31, 2020	657	177,772	178,429
Net income/(loss)			56,671
Balance at period end at Sep. 30, 2021	13,334	241,766	255,100
Balance at period beginning at Mar. 31, 2021	708	193,231	193,939
Net income/(loss)	(219)	16,259	16,040
Partners' contributions	62	19,938	20,000
Balance at period end at Jun. 30, 2021	551	229,428	229,979
Net income/(loss)	(73)	25,194	25,121
Carried interest reallocation	12,856	(12,856)
Balance at period end at Sep. 30, 2021	13,334	241,766	255,100
Balance at period beginning at Dec. 31, 2021	15,462	298,834	314,296
Net income/(loss)	(29)	27,874	27,845
Carried interest reallocation	7,168	(7,168)
Balance at period end at Mar. 31, 2022	22,601	319,540	342,141
Balance at period beginning at Dec. 31, 2021	15,462	298,834	314,296
Net income/(loss)			137,046
Balance at period end at Sep. 30, 2022	41,614	409,728	451,342
Balance at period beginning at Mar. 31, 2022	22,601	319,540	342,141
Net income/(loss)	218	66,248	66,466
Carried interest reallocation	11,801	(11,801)
Balance at period end at Jun. 30, 2022	34,620	373,987	408,607
Net income/(loss)	340	42,395	42,735
Carried interest reallocation	6,654	(6,654)
Balance at period end at Sep. 30, 2022	$ 41,614	$ 409,728	$ 451,342

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

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+ Details

CONDENSED COMBINED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Operating activities:
Net income/(loss)	$ 137,046	$ 56,671
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Depletion and accretion expense	70,529	45,798
Change in unrealized (gain) loss on derivative contracts	(5,600)	11,010
Amortization of loan origination costs	62	31
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Revenue receivable	(21,627)	(22,941)
Prepaid expenses	(4,028)
Other assets	469	(469)
Accrued expenses	(2,811)	(1,800)
Net cash provided by operating activities	179,662	91,900
Investing activities:
Acquisition of proved oil and gas properties	(31,258)	(67,012)
Proceeds from the disposal of oil and gas properties	741	3,041
Refund of advances to operators	971	2,298
Development of oil and gas properties	(121,109)	(63,113)
Net cash used in investing activities	(150,655)	(124,786)
Financing activities:
Proceed from borrowing	16,000	46,000
Repayments of borrowing	(46,000)	(22,000)
Partners' contributions, net of change in contributions receivable	84	20,074
Net cash provided by financing activities	(29,916)	44,074
Net increase/(decrease) in cash	(909)	11,188
Cash at beginning of period	7,319	2,638
Cash at end of period	6,410	13,826
Supplemental disclosure of cash flow information
Cash paid during the year for interest	317	392
Supplemental disclosure of non cash investing activities
Oil and natural gas property development costs in accrued expenses	15,757	561
Acquired and assumed asset retirement obligations	633
Revision of asset retirement costs	507
Advances to operators applied to development of oil and natural gas properties	$ 54,147	$ 24,880

Organization and nature of operations

9 Months Ended

Sep. 30, 2022

Organization and nature of operations

Organization and nature of operations

1.Organization and nature of operations

Organization

Granite Ridge Resources, Inc. (“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) has been determined to be the accounting acquirer and predecessor (as defined below). The information provided in this Quarterly Report on Form 10-Q only reflects the financial condition and results of operations of the Predecessor.

The financial information for the Predecessor for such periods does not reflect the material changes to the business as a result of the Business Combination. Accordingly, the financial information for the Predecessor is not necessarily indicative of Granite Ridge’s results of operations, cash flows or financial position following the completion of the Business Combination.

Nature of operations

Grey Rock Energy Fund III-A, LP (“Grey Rock III-A”) was formed on March 14, 2018 as a Delaware limited partnership and commenced operations on April 19, 2018. Grey Rock III-A was created 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.

Grey Rock Energy Fund III-B Holdings, LP (“Grey Rock III-B Holdings”) was formed on March 14, 2018, as a Delaware limited partnership and commenced operations on April 19, 2018. Grey Rock III-B Holdings was created for the purpose of purchasing non-operated oil and natural gas assets in multiple basins in North America, realizing profits through participation in oil and natural gas wells, and granting net profits interest in oil and natural gas assets to Grey Rock III-B (as defined below), a related party, in accordance with its limited partnership agreement.

Grey Rock Energy Fund III-B, LP (the “Grey Rock III-B”) was formed on March 14, 2018 as a Delaware limited partnership and commenced operations on April 19, 2018. Grey Rock III-B was created for the purpose of acquiring net profits interests in oil and natural gas assets from Grey Rock III-B Holdings, a related party, in multiple basins in North America, in accordance with its limited partnership agreement.

Grey Rock Preferred Limited Partner III, LP (“Grey Rock PLP III”) was formed on March 14, 2018, as a Delaware limited partnership and commenced operations on April 19, 2018. Grey Rock PLP III was created for the purpose of holding limited partnership interests in Grey Rock III-B, a related party.

Collectively, Grey Rock III-A, Grey Rock III-B Holdings, Grey Rock III-B and Grey Rock PLP III are known as the “Partnership”, “Grey Rock Energy Fund III”, “Fund III”, or “Predecessor”.

Grey Rock Energy Partners GP III-A, LP, a Delaware limited partnership (the “Fund III-A General Partner”), acts as general partner of Grey Rock III-A. Grey Rock Energy Partners GP III-B, LP, a Delaware limited partnership (the “Fund III-B General Partner”), acts as general partner of Grey Rock III-B Holdings and Grey Rock III-B. Grey Rock Energy Management, LLC, a Delaware limited liability company (the “Management Company”), serves as investment manager to the Partnership.

The term of the Partnership is up to nine years. The investment term is three years and may be extended by the General Partner, in its sole discretion, for an additional one-year term. The harvest period is four years and may be extended by the General Partner, in its sole discretion, for an additional one-year term, and thereafter, by the General Partner, with the consent of a majority-in- interest of the limited partners, for additional, successive one-year terms to allow for an orderly dissolution and liquidation of the Partnership.

The Partnership and certain other funds affiliated with Grey Rock formed GREP Holdings, LLC, a Delaware limited liability company (“GREP”), who entered into a business combination agreement (“BCA”) on May 16, 2022 with Executive Network Partnering Corporation (“ENPC”), a Delaware corporation and NYSE publicly traded special purpose acquisition company, Granite Ridge Resources, Inc., a Delaware corporation (“Granite Ridge”), ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), and GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub”), pursuant to which (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”), 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”). The BCA provided that in connection with the Business Combination, the members of GREP would receive common stock of Granite Ridge in the business combination, valued at approximately $1.3 billion on May 16, 2022, upon the execution of the BCA. The Business Combination closed on October 24, 2022.

Summary of significant accounting policies

9 Months Ended

Sep. 30, 2022

Summary of significant accounting policies

Summary of significant accounting policies

2.Summary of significant accounting policies

Principles of Combination

The accompanying condensed combined financial statements include the accounts of Grey Rock III-A, Grey Rock III-B Holdings, Grey Rock III-B and Grey Rock PLP III all of which share common ownership and management. All inter-entity balances and transactions have been eliminated in combination.

Basis of Presentation

The condensed combined balance sheet as of December 31, 2021 was derived from the audited combined financial statements, and the unaudited interim condensed combined financial statements as of September 30, 2022 and for the three and nine month periods ended September 30, 2022 and 2021, provided herein have been prepared in accordance with the instructions for the Securities and Exchange Commission’s (“SEC’s”) Form 10-Q and Article 10 of Regulation S-X.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted pursuant to rules and regulations of the SEC. However, in the Partnership’s opinion, the disclosures made therein are adequate to make the information presented not misleading. The Partnership believes these condensed combined financial statements include all normal recurring adjustments necessary to fairly present the results of the interim periods. The condensed combined statements of income for the three and nine months ended September 30, 2022 and the condensed

combined results of cash flows for the nine months ended September 30, 2022 are not necessarily indicative of the combined statements of income and results of cash flows that might be expected for the entire year. These condensed combined financial statements and the accompanying notes should be read in conjunction with the audited combined financial statements and the notes thereto for the year ended December 31, 2021. The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information at the Partnership level.

Fair Value

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

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

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

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

As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Partnership’s financial assets and liabilities, such as due from related parties, revenue receivable, related party payable, accounts payable and accrued expenses, approximate their fair values because of the short maturity of these instruments.

Revenue Receivable

Revenue receivable is comprised of accrued natural gas and crude oil sales. The operators remit payment for production directly to the Partnership. There have been no credit losses to date. In the event of complete non-performance by the Partnership’s customers, the maximum exposure to the Partnership is the outstanding revenue receivable balance at the date of non-performance. The Partnership writes off specific accounts receivable when they become uncollectible. For the three and nine months ended September 30, 2022 and 2021, the Partnership had no bad debt expense, and did not record an allowance for doubtful accounts.

Other Assets

Other assets are comprised of payments made in advance for services deemed to have future value to the Partnership and fees that were capitalized in connection to the Business Combination. Capitalized fees were $4,098 thousand and zero as of September 30, 2022 and December 31, 2021, respectively. Prepaid expenses were zero and $70 thousand as of September 30, 2022 and December 31, 2021, respectively.

Revenue Recognition

The Partnership’s revenues are primarily derived from its interests in the sale of oil and natural gas production. The Partnership 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 and when the Partnership has no further obligations to perform related to the sale. The Partnership 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. At the end of each month, amounts due from customers are accrued in revenue receivable in the balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; however, differences have been and are insignificant.

The Partnership 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.

A wellhead imbalance liability equal to the Partnership’s share is recorded to the extent that the Partnership’s well operators have sold volumes in excess of its share of remaining reserves in an underlying property. However, in each of the three and nine months ended September 30, 2022 and 2021, the Partnership’s oil and natural gas production was in balance, meaning its cumulative portion of oil and natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in oil and natural gas production from those wells.

Non-operated crude oil and natural gas revenues – The Partnership’s proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Partnership 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 of transportation costs which is the amount of proceeds to be received by the Partnership during the month in which production occurs and it is probable the Partnership will collect the consideration it is entitled to receive. Proceeds are generally received by the Partnership within one to three months after the month in which production occurs. The Partnership’s disaggregated revenue has two revenue sources, which are oil sales, and natural gas and NGL sales. Oil sales for the three months ended September 30, 2022 and 2021 were approximately $61,607 thousand and $40,376 thousand, respectively. Natural gas and NGL sales for the three months ended September 30, 2022 and 2021 were approximately $28,587 thousand and $15,341 thousand, respectively. Oil sales for the nine months ended September 30, 2022 and 2021 were approximately $197,332

thousand and $104,700 thousand, respectively. Natural gas and NGL sales for the nine months ended September 30, 2022 and 2021 were approximately $65,931 thousand and $37,932 thousand, respectively.

Substantially all of the Partnership’s oil and natural gas sales currently come from four geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Denver-Julesburg “DJ” Basin (Colorado) and the Bakken Basin (Montana/North Dakota). The following tables present the disaggregation of the Partnership’s oil revenues and natural gas and NGL revenues by basin for the three and nine months ended September 30, 2022 and 2021.


	Three months ended September 30, 2022
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	11,891	$	65,997	$	8,271	$	4,035


	Three months ended September 30, 2021
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	4,575	$	39,252	$	10,726	$	1,164


	Nine months ended September 30, 2022
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	35,978	$	186,853	$	30,370	$	10,062


	Nine months ended September 30, 2021
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	22,002	$	97,926	$	19,801	$	2,903

Income Taxes

Because the Partnership is a limited partnership, the income or loss of the Partnership for federal and state income tax purposes is generally allocated to the partners in accordance with the Partnership’s formation documents, and it is the responsibility of the partners to report their share of taxable income or loss on their separate income tax returns. Accordingly, no recognition has been given to federal or state income taxes in the accompanying condensed combined financial statements.

The Partnership is required to determine whether its tax positions are more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit recognized is measured as the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement with the relevant taxing authority. De-recognition of a tax benefit previously recognized results in the Partnership recording a tax liability that reduces ending partners’ capital. Based on its analysis, the Partnership has determined that it has not incurred any liability for unrecognized tax benefits as of September 30, 2022 and December 31, 2021. However, the Partnership’s conclusions may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof.

The Partnership recognizes interest and penalties related to unrecognized tax benefits in interest expense and other expenses, respectively. No interest or penalties were recognized for the three and nine months ended September 30, 2022 and 2021.

The Partnership files an income tax return in the U.S. federal jurisdiction, and may file income tax returns in various U.S. states and foreign jurisdictions. Generally, the Partnership is subject to income tax examinations by major taxing authorities during the period since inception.

The Partnership may be subject to potential examination by U.S. federal, U.S. states or foreign jurisdiction authorities in the areas of income taxes. These potential examinations may include questioning the timing and amount of deductions, the nexus of income among various tax jurisdictions and compliance with U.S. federal, U.S. state and foreign tax laws. The Partnership’s management does not expect that the total amount of unrecognized tax benefits will materially change over the next twelve months.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation.

Use of Estimates

The preparation of the condensed combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the condensed combined 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. Additional significant estimates include impairment testing, derivative instruments and hedging activity, and asset retirement obligations. Actual results could differ from those estimates.

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. The Partnership adopted this ASU on January 1, 2022, and there was no material impacts to the condensed combined financial statements.

The FASB issued ASU No. 2016-13, “Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” which introduces guidance for estimating credit losses on certain types of financial instruments based on expected losses and the timing of the recognition of such losses. This guidance becomes effective beginning on January 1, 2023, however, the impact is not expected to be material.

Derivative instruments

9 Months Ended

Sep. 30, 2022

Derivative instruments

Derivative instruments

3.Derivative instruments

From time to time, the Partnership may utilize derivative contracts in connection with its oil and natural gas operations to provide an economic hedge of the Partnership’s exposure to commodity price risk associated with anticipated future oil and natural gas production. The Partnership does not hold or issue derivative financial instruments for trading purposes. These derivative contracts consist of fixed price collar options and producer 3-way option contracts. The Partnership typically hedges approximately 50% to 75% of expected oil and natural gas production from the underlying entities for 12 to 24 months in the future. The Partnership’s derivative activities and exposure to derivative contracts are classified by the following primary underlying risk of commodity prices. In addition to its primary underlying risk, the Partnership is also subject to additional counterparty risk due to the inability of its counterparties to meet the terms of their contracts.

Derivative Contracts

The Partnership has not designated its derivative instruments as hedges for accounting purposes. Cash and non-cash changes in fair value are included in gain or loss on derivative contracts in the condensed combined statements of income. Derivative assets are included within current and noncurrent assets in the condensed combined balance sheets as of September 30, 2022. Derivative liabilities are included within current liabilities in the condensed combined balance sheets as of September 30, 2022. Derivative assets and liabilities are included within current and noncurrent liabilities in the condensed combined balance sheets as of December 31, 2021.

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, like 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. 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 fair value of open collar options and producer 3-way contracts reported in the condensed combined balance sheets may differ from that which would be realized in the event the Partnership terminated its position in the contract. Risks may arise as a result of the failure of the counterparty to the option contract to comply with the terms of the option contract. The loss incurred by the failure of counterparties is generally limited to the aggregate fair value of option contracts in an unrealized gain position as well as any collateral posted with the counterparty.

The Partnership considers the creditworthiness of each counterparty to an option contract in evaluating potential credit risk. Additionally, risks may arise from unanticipated movements in the fair value of the underlying investments.

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

Volume of Derivative Activities

At September 30, 2022, the volume of the Partnership’s derivative activities based on their volume (crude oil is presented in Bbl and natural gas is presented in Mcf) and contract prices, categorized by primary underlying risk, are as follows:


			Contract Prices
Period	Type of Contract	(Volume/Month)	Range	Weighted Average
Oct 2022 – Dec 2023	Producer 3-way (crude oil)	34,413 – 612	$113.10 – $40.00		$75.16
Oct 2022 – Dec 2022	Collar (crude oil)	33,886 – 5,448	$112.75 – $85.00		$97.24
Nov 2022 – Mar 2023	Producer 3-way (natural gas)	128,912 – 3,813	$8.44 – $3.00		$5.13
Nov 2022 – Jun 2023	Collar (natural gas)	90,941 – 11,036	$9.05 – $2.90		$5.48

Impact of Derivatives on the Condensed Combined Balance Sheets and Condensed Combined Statements of Income.

The following table identifies the fair value amounts of derivative instruments included in the accompanying condensed combined balance sheets as derivative assets and liabilities categorized by primary underlying risk, at September 30, 2022.


	September 30, 2022				September 30, 2022
	Derivative assets				Derivative liabilities
(in thousands)	Current portion		Noncurrent portion		Current portion		Noncurrent portion
Primary underlying risk
Commodity price
Crude oil	$	4,581	$	812	$	(1,865)	$	—
Natural gas		(205)		—		(2,076)		—
Total	$	4,376	$	812	$	(3,941)	$	—

The following tables identify the net gain/(loss) amounts included in the accompanying condensed combined statements of income as gain/(loss) on derivative contracts for the three and nine months ended September 30, 2022.


	Three months ended September 30, 2022
(in thousands)	Realized loss		Change in unrealized gain/(loss)		Total
Primary underlying risk
Commodity price
Crude oil	$	(4,971)	$	16,571	$	11,600
Natural gas		(4,360)		(1,158)		(5,518)
Total	$	(9,331)	$	15,413	$	6,082


	Nine months ended September 30, 2022
(in thousands)	Realized loss		Change in unrealized gain/(loss)		Total
Primary underlying risk
Commodity price
Crude oil	$	(15,388)	$	7,404	$	(7,984)
Natural gas		(9,359)		(1,804)		(11,163)
Total	$	(24,747)	$	5,600	$	(19,147)

The following table identifies the fair value amounts of derivative instruments included in the accompanying condensed combined balance sheets as derivative liabilities categorized by primary underlying risk, at December 31, 2021.


	December 31, 2021				December 31, 2021
	Derivative assets					Derivative liabilities
(in thousands)	Current portion		Noncurrent portion		Current portion		Noncurrent portion
Primary underlying risk
Commodity price
Crude oil	$	—	$	—	$	(3,465)	$	(411)
Natural gas		—		—		(488)		11
Total	$	—	$	—	$	(3,953)	$	(400)


	Three months ended September 30, 2021
(in thousands)	Realized loss		Change in unrealized gain/(loss)		Total
Primary underlying risk
Commodity price
Crude oil	$	(2,324)	$	721	$	(1,603)
Natural gas		(1,635)		(3,320)		(4,955)
Total	$	(3,959)	$	(2,599)	$	(6,558)


	Nine months ended September 30, 2021
(in thousands)	Realized loss		Change in unrealized loss		Total
Primary underlying risk
Commodity price
Crude oil	$	(2,583)	$	(6,775)	$	(9,358)
Natural gas		(4,522)		(4,235)		(8,757)
Total	$	(7,105)	$	(11,010)	$	(18,115)

Fair value measurements

9 Months Ended

Sep. 30, 2022

Fair value measurements

Fair value measurements

4.Fair value measurements

Fair Values – Recurring

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 Partnership’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 information about the Partnership’s recurring assets and liabilities measured at fair value as of September 30, 2022:


							September 30,
(in thousands)	Level 1		Level 2		Level 3		2022
Assets (at fair value):
Derivative contracts	$	—	$	5,188	$	—	$	5,188
Liabilities (at fair value):
Derivative contracts	$	—	$	(3,941)	$	—	$	(3,941)

The following table presents information about the Partnership’s recurring liabilities measured at fair value as of December 31, 2021:


							December 31,
(in thousands)	Level 1		Level 2		Level 3		2021
Liabilities (at fair value):
Derivative contracts	$	—	$	(4,353)	$	—	$	(4,353)

The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed combined balance sheets:


	September 30, 2022				December 31, 2021
(in thousands)	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities (at fair value):
Revolving Credit Facility	$	—	$	—	$	29,938	$	29,938

The recorded value of the revolving credit facility approximates its fair value because of its floating rate structure based on the Prime Rate spread. The fair value measurement for the revolving credit facility represents Level 2 inputs.

Fair Values - Non Recurring

The fair value measurements of asset retirement obligations are measured on a nonrecurring basis when a well is drilled or acquired or when production equipment and facilities are installed or acquired using a discounted cash flow model based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and natural gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and natural gas wells and future inflation rates. Asset retirement obligations incurred and acquired during the nine months ended September 30, 2022 were approximately $633 thousand.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Oil and natural gas properties

9 Months Ended

Sep. 30, 2022

Oil and natural gas properties

Oil and natural gas properties

5.Oil and natural gas properties

Oil and natural gas properties consisted of only proved properties as of September 30, 2022 and December 31, 2021. The book value of the Partnership’s oil and natural gas properties consists of all acquisition costs, drilling costs and other associated capitalized costs.

2022 Acquisitions

Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of income from the closing date of the acquisition. For the three and nine months ended September 30, 2022, the Partnership acquired various proved oil and natural gas properties, which included working interests ranging from 2% to 30% and 0.51% to 43%, respectively, and net revenue interests ranging from 1% to 23% and 0.38% to 33%, respectively, in Texas and New Mexico.

Permian Basin – The Partnership acquired proved undeveloped oil and natural gas properties in the Permian Basin of approximately $6,290 thousand and $25,328 thousand during the three and nine months ended September 30, 2022, respectively.

DJ Basin – The Partnership acquired proved undeveloped oil and natural gas properties in the DJ Basin of approximately $2,833 thousand and $2,938 thousand during the three and nine months ended September 30, 2022, respectively.

Haynesville – The Partnership acquired proved undeveloped oil and natural gas properties in the Haynesville Basin of approximately $2,992 thousand during the three and nine months ended September 30, 2022.

2022 Divestitures

The Partnership made no divestitures of oil and natural gas properties for the three months ended September 30, 2022.

Eagle Ford Basin – For the nine months ended September 30, 2022, the Partnership sold a partial unit of oil and natural gas properties in the Eagle Ford Basin for approximately $741 thousand, eliminating equivalent amounts from the oil and natural gas property accounts. No gain or loss was recorded.

2021 Acquisitions

For the three and nine months ended September 30, 2021, the Partnership acquired various proved oil and natural gas properties, which included working interests ranging from 5% to 41.2% and 0.01% to 41.2%, respectively, and net revenue interests ranging from 4% and 30.3% and 0.01% to 31%, respectively, in Colorado, Texas, New Mexico and North Dakota.

Bakken Basin – The Partnership did not acquire proved undeveloped oil and natural gas properties in the Bakken Basin during the three months ended September 30, 2021. During the nine months ended September 30, 2021, the Partnership acquired proved undeveloped oil and natural gas properties in the Bakken Basin of approximately $190 thousand.

Permian Basin – The Partnership acquired proved undeveloped and proved developed oil and natural gas properties in the Permian Basin of approximately $17,444 thousand and $26,456 thousand during the three and nine months ended September 30, 2021, respectively.

DJ Basin – The Partnership did not acquire proved developed producing oil and natural gas properties in the DJ Basin during the three months ended September 30, 2021. The Partnership acquired proved developed producing oil and natural gas properties in the DJ Basin of approximately $40,366 thousand during the nine months ended September 30, 2021.

2021 Divestitures

Eagle Ford Basin – For the three and nine months ended September 30, 2021, the Partnership sold a partial unit of oil and natural gas properties in the Eagle Ford Basin for approximately $3,041 thousand, eliminating equivalent amounts from the oil and natural gas property accounts. No gain or loss was recorded.

Partners' capital

9 Months Ended

Sep. 30, 2022

Partners' capital:

Partners' capital

6.Partners’ capital

Commitments and Contributions

As of September 30, 2022, there were no contributions receivable from the General Partner. As of December 31, 2021, contributions receivable was approximately $84 thousand from the General Partner. As of September 30, 2022 and December 31, 2021, contributions receivable was approximately $10 thousand from the Limited Partners.

All limited partners of Grey Rock III-B Holdings are considered affiliates of the General Partner.

Allocation of Net Profits and Losses

The Partnership’s net profits or losses for any fiscal period shall be allocated among the partners in such manner that, as of the end of such fiscal period and to the greatest extent possible, the capital account of each partner shall be equal to the respective net amount, positive or negative, that would be distributed to such partner from the Partnership or for which such partner would be liable to the Partnership, determined as if, on the last day of such fiscal period, the Partnership were to (a) liquidate the assets of the Partnership for an amount equal to their book value and (b) distribute the proceeds in liquidation.

(a)

First, 100% to such partner until such partner has received cumulative distributions equal to such partner’s aggregate capital contributions to the Partnership for any purpose;

(b)

Second, 100% to such partner until the aggregate distributions to such partner equal the preferred return amount of 8% per annum on the partner’s capital contributions;

(c)

Third, 80% to the General Partner and 20% to such partner until the General Partner has received cumulative distributions equal to 20% of the cumulative amount of distributions made pursuant to (c) and previously made pursuant to (b); and

(d)

Thereafter, 20% to the General Partner and 80% to such partner.

The reallocation to the general partner from the limited partners was approximately $6,654 thousand and $25,623 thousand for the three and nine months ended September 30, 2022, respectively. The reallocation to the general partner from the limited partners was approximately $12,856 thousand for the three and nine months ended September 30, 2021. The allocation of carried interest will remain provisional until the final liquidation of the Partnership.

Distributions

In accordance with the Limited Partnership Agreement (“LPA”), all distributions shall be made, at such times and in such amounts as determined in the sole discretion of the General Partner, to the partners in proportion to their Partnership percentage interests. For the three and nine months ended September 30, 2022 and 2021, the Partnership did not make any distributions.

Related party transactions

9 Months Ended

Sep. 30, 2022

Related party transactions

Related party transactions

7.Related party transactions

The Partnership pays an annual management fee to the Management Company, an entity under common control, as compensation for providing managerial services to the Partnership. The management fee will accrue beginning on the initial closing date of the Partnership and will be payable to the Management Company quarterly, in advance, calculated as of the first day of each fiscal quarter and prorated appropriately for partial quarters. Limited partners will be assessed one and one-half (1.5%) per annum of such limited partner’s aggregate capital commitment. For the three months ended September 30, 2022 and 2021, management fees were $919 thousand and $969 thousand, respectively. For the nine months ended September 30, 2022 and 2021, management fees were $2,808 thousand and $2,908 thousand, respectively. Management fees are included in general and administrative fees on the accompanying condensed combined statements of income.

As of September 30, 2022, the Partnership did not have any related party payables with the Management Company. As of December 31, 2021, the Partnership had a related party payable with the Management Company for organizational expenses incurred on behalf of the Partnership of $8 thousand, respectively, that was included in accrued expenses on the accompanying condensed combined balance sheets.

Commitments and contingencies

9 Months Ended

Sep. 30, 2022

Commitments and contingencies.

Commitments and contingencies

8.Commitments and contingencies

The Partnership is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural 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. The Partnership is currently not a party to any material pending legal proceedings that would give rise to potential loss contingencies.

As of September 30, 2022, the Partnership had incurred approximately $15,757 thousand in capital expenditures that were included in accounts payable, and the Partnership estimates that it is committed to an additional approximately $50,000 thousand in development capital expenditures not yet incurred for wells the Partnership elected to participate in.

Credit facility

9 Months Ended

Sep. 30, 2022

Credit facility

Credit facility

9.Credit facility

Since 2018, the Partnership has maintained a revolving credit facility (the “Facility”) with a borrowing capacity of $100,000 thousand, of which, as of September 30, 2022 and December 31, 2021, $0 and $30,000 thousand was outstanding, respectively.

The Facility is collateralized by all of the Partnership’s oil and natural gas properties and requires compliance with certain financial covenants. As of September 30, 2022, the Partnership, was in compliance with all covenants required by the Facility. Further, the Partnership did not have any unamortized loan origination costs as of September 30, 2022. As of December 31, 2021, the Partnership had unamortized loan origination costs of $62 thousand.

Additionally, the Facility bears interest at an annual base rate of the Prime Rate minus an acceptable margin of 0.50%. As of September 30, 2022 and December 31 2021, the weighted average interest rate on borrowed amounts was approximately 4.47% and 3.35%, respectively. As of September 30, 2022, the Partnership repaid amounts outstanding under the Facility and the Facility was terminated on October 24, 2022 in connection with the closing of the Business Combination and Granite Ridge’s entry into a new credit facility.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-URI https://asc.fasb.org/topic&trid=2208564

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (h)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (d)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (g)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1C
-Subparagraph (a)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495334-112611

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1E
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495348-112611

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1I
-Subparagraph (b)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495371-112611

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 50
-Paragraph 1B
-Subparagraph (i)
-URI https://asc.fasb.org/extlink&oid=123466505&loc=SL123495323-112611

+ Details

Risk concentrations

9 Months Ended

Sep. 30, 2022

Risk concentrations

Risk concentrations

10.Risk concentrations

As a non-operator, 100% of the Partnership’s wells are operated by third-party operating partners. As a result, the Partnership 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 Partnership’s leasehold interests, or are unable or unwilling to perform, the Partnership’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 Partnership’s third-party operators will make decisions in connection with their operations that may not be in the Partnership’s best interests, and the Partnership may have little or no ability to exercise influence over the operational decisions of its third-party operators.

In the normal course of business, the Partnership maintains its cash balances in financial institutions, which at times may exceed federally insured limits. The Partnership 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. The outbreak of the novel coronavirus and the military conflict between Russia and Ukraine continue to significantly impact the worldwide economy and specific economic sectors. As a result, commodity prices remain volatile, which may impact the Partnership’s performance and may lead to future losses.

Subsequent events

9 Months Ended

Sep. 30, 2022

Subsequent events

Subsequent events

11.Subsequent events

In connection with preparing the condensed combined financial statements for the three and nine months ended September 30, 2022, management has evaluated subsequent events for potential recognition and disclosure through the date November 14, 2022, which is the date the condensed combined financial statements were available to be issued.

As discussed in Note 1—Nature of Operations, on May 16, 2022, GREP entered into a business combination agreement with ENPC, a NYSE publicly traded special purpose acquisition company and Granite Ridge. The Business Combination closed on October 24, 2022 as a result of which GREP and ENPC became wholly-owned subsidiaries of Granite Ridge. Granite Ridge’s common stock and warrants are listed on the NYSE. Refer to Note 1 for additional information.

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 years from the effective date thereof.

The Credit Agreement provides for aggregate elected commitments of $150.0 million, an initial borrowing base of $325.0 million and an aggregate maximum revolving credit amount of $1,000.0 million. The borrowing base is scheduled to be redetermined semiannually on or about April 1 and October 1 of each calendar year, commencing April 1, 2023, and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, 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, 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.

In conjunction with the Credit Agreement, on October 24, 2022, all derivative contracts outstanding with GREP were novated to Granite Ridge.

Granite Ridge’s board of directors recently declared a dividend of $0.08 per share of Granite Ridge’s common stock. The dividend is payable on December 15, 2022 to stockholders of record on December 1, 2022. This dividend payout is aligned with Granite Ridge’s intent to pay a minimum dividend of $60 million per year to its shareholders, which would currently equate to $0.45 per share annually or an approximate five percent dividend yield. The initial common dividend was prorated to October 24, 2022, the effective date of Granite Ridge’s business combination, which equaled $0.08 per common share for the quarter.

Summary of significant accounting policies (Policies)

9 Months Ended

Sep. 30, 2022

Summary of significant accounting policies

Principles of Combination

Basis of Presentation

Fair Value

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

Revenue Receivable

Other Assets

Other Assets

Revenue Recognition

thousand and $104,700 thousand, respectively. Natural gas and NGL sales for the nine months ended September 30, 2022 and 2021 were approximately $65,931 thousand and $37,932 thousand, respectively.


	Three months ended September 30, 2022
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	11,891	$	65,997	$	8,271	$	4,035


	Three months ended September 30, 2021
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	4,575	$	39,252	$	10,726	$	1,164


	Nine months ended September 30, 2022
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	35,978	$	186,853	$	30,370	$	10,062


	Nine months ended September 30, 2021
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	22,002	$	97,926	$	19,801	$	2,903

Income Taxes

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation.

Use of Estimates

Recently Issued and Applicable Accounting Pronouncements

Summary of significant accounting policies (Tables)

9 Months Ended

Sep. 30, 2022

Summary of significant accounting policies

Schedule of disaggregation of the Partnership's oil revenues and natural gas and NGL revenues by basin


	Three months ended September 30, 2022
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	11,891	$	65,997	$	8,271	$	4,035


	Three months ended September 30, 2021
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	4,575	$	39,252	$	10,726	$	1,164


	Nine months ended September 30, 2022
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	35,978	$	186,853	$	30,370	$	10,062


	Nine months ended September 30, 2021
(in thousands)	Eagle Ford		Permian		Denver-Julesberg		Bakken

Revenues	$	22,002	$	97,926	$	19,801	$	2,903

Derivative instruments (Tables)

9 Months Ended

Sep. 30, 2022

Derivative instruments

Schedule of volume-based derivative activity subject to price risk


			Contract Prices
Period	Type of Contract	(Volume/Month)	Range	Weighted Average
Oct 2022 – Dec 2023	Producer 3-way (crude oil)	34,413 – 612	$113.10 – $40.00		$75.16
Oct 2022 – Dec 2022	Collar (crude oil)	33,886 – 5,448	$112.75 – $85.00		$97.24
Nov 2022 – Mar 2023	Producer 3-way (natural gas)	128,912 – 3,813	$8.44 – $3.00		$5.13
Nov 2022 – Jun 2023	Collar (natural gas)	90,941 – 11,036	$9.05 – $2.90		$5.48

Schedule of derivative liabilities categorized by primary underlying risk


	September 30, 2022				September 30, 2022
	Derivative assets				Derivative liabilities
(in thousands)	Current portion		Noncurrent portion		Current portion		Noncurrent portion
Primary underlying risk
Commodity price
Crude oil	$	4,581	$	812	$	(1,865)	$	—
Natural gas		(205)		—		(2,076)		—
Total	$	4,376	$	812	$	(3,941)	$	—


	December 31, 2021				December 31, 2021
	Derivative assets					Derivative liabilities
(in thousands)	Current portion		Noncurrent portion		Current portion		Noncurrent portion
Primary underlying risk
Commodity price
Crude oil	$	—	$	—	$	(3,465)	$	(411)
Natural gas		—		—		(488)		11
Total	$	—	$	—	$	(3,953)	$	(400)

Schedule of income as gain/(loss) on derivative contracts


	Three months ended September 30, 2022
(in thousands)	Realized loss		Change in unrealized gain/(loss)		Total
Primary underlying risk
Commodity price
Crude oil	$	(4,971)	$	16,571	$	11,600
Natural gas		(4,360)		(1,158)		(5,518)
Total	$	(9,331)	$	15,413	$	6,082


	Nine months ended September 30, 2022
(in thousands)	Realized loss		Change in unrealized gain/(loss)		Total
Primary underlying risk
Commodity price
Crude oil	$	(15,388)	$	7,404	$	(7,984)
Natural gas		(9,359)		(1,804)		(11,163)
Total	$	(24,747)	$	5,600	$	(19,147)


	Three months ended September 30, 2021
(in thousands)	Realized loss		Change in unrealized gain/(loss)		Total
Primary underlying risk
Commodity price
Crude oil	$	(2,324)	$	721	$	(1,603)
Natural gas		(1,635)		(3,320)		(4,955)
Total	$	(3,959)	$	(2,599)	$	(6,558)


	Nine months ended September 30, 2021
(in thousands)	Realized loss		Change in unrealized loss		Total
Primary underlying risk
Commodity price
Crude oil	$	(2,583)	$	(6,775)	$	(9,358)
Natural gas		(4,522)		(4,235)		(8,757)
Total	$	(7,105)	$	(11,010)	$	(18,115)

Fair value measurements (Tables)

9 Months Ended

Sep. 30, 2022

Fair value measurements

Schedule of partnership's recurring liabilities measured at fair value


							September 30,
(in thousands)	Level 1		Level 2		Level 3		2022
Assets (at fair value):
Derivative contracts	$	—	$	5,188	$	—	$	5,188
Liabilities (at fair value):
Derivative contracts	$	—	$	(3,941)	$	—	$	(3,941)


							December 31,
(in thousands)	Level 1		Level 2		Level 3		2021
Liabilities (at fair value):
Derivative contracts	$	—	$	(4,353)	$	—	$	(4,353)

Schedule of fair value of financial instruments that are not recorded at fair value in the condensed combined balance sheets


	September 30, 2022				December 31, 2021
(in thousands)	Carrying Value		Fair Value		Carrying Value		Fair Value
Liabilities (at fair value):
Revolving Credit Facility	$	—	$	—	$	29,938	$	29,938

Organization and nature of operations (Details) - USD ($) $ in Billions		9 Months Ended
	May 16, 2022	Sep. 30, 2022
Nature of operations
Term of the partnership		9 years
Investment term		3 years
Extension term of investment		1 year
Harvest period		4 years
Extension of harvest period		1 year
Additional term for for dissolution and liquidation of partnership		1 year
Business Combination Agreement
Nature of operations
Amount paid to acquire interest in oil and natural gas property	$ 1.3

Summary of significant accounting policies - Revenue Receivable (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Summary of significant accounting policies
Credit losses	$ 0		$ 0
Bad debt expense	$ 0	$ 0	$ 0	$ 0

Summary of significant accounting policies - Other Assets (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2022	Dec. 31, 2021
Summary of significant accounting policies
Capitalized fees, business combination	$ 4,098,000	$ 0
Prepaid expenses, business combination	$ 0	$ 70,000

Summary of significant accounting policies - Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Summary of significant accounting policies
Revenues	$ 90,194	$ 55,717	$ 263,263	$ 142,632
Minimum
Summary of significant accounting policies
Payment Receivable Term, After Delivery			1 month
Payment Receivable Term, After Production			1 month
Maximum
Summary of significant accounting policies
Payment Receivable Term, After Delivery			3 months
Payment Receivable Term, After Production			3 months
Eagle Ford
Summary of significant accounting policies
Revenues	11,891	4,575	$ 35,978	22,002
Permian
Summary of significant accounting policies
Revenues	65,997	39,252	186,853	97,926
Denver Julesberg
Summary of significant accounting policies
Revenues	8,271	10,726	30,370	19,801
Bakken
Summary of significant accounting policies
Revenues	4,035	1,164	10,062	2,903
Oil and Condensate [Member]
Summary of significant accounting policies
Revenues	61,607	40,376	197,332	104,700
Natural gas and NGL sales
Summary of significant accounting policies
Revenues	$ 28,587	$ 15,341	$ 65,931	$ 37,932

Summary of significant accounting policies - Income Taxes (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Summary of significant accounting policies
Interest or penalties related to unrecognized tax benefits	$ 0	$ 0	$ 0	$ 0

Derivative instruments (Details) - Commodity futures	9 Months Ended
Derivative instruments (Details) - Commodity futures	Sep. 30, 2022
Minimum
Derivative instruments
Percentage of hedging	50.00%
Expected hedging term	12 months
Maximum
Derivative instruments
Percentage of hedging	75.00%
Expected hedging term	24 months

Derivative instruments - Volume of Derivative Activities (Details)	9 Months Ended
	Sep. 30, 2022 $ / Mcf $ / bbl Mcf bbl
Oct 2022 - Dec 2023 \| Producer 3-way (crude oil)
Derivative [Line Items]
Contractual Weighted Average Price/Unit \| $ / bbl	75.16
Oct 2022 - Dec 2023 \| Producer 3-way (crude oil) \| Maximum
Derivative [Line Items]
Contractual Volume/Month \| bbl	34,413
Contractual Price/Unit \| $ / bbl	113.10
Oct 2022 - Dec 2023 \| Producer 3-way (crude oil) \| Minimum
Derivative [Line Items]
Contractual Volume/Month \| bbl	612
Contractual Price/Unit \| $ / bbl	40.00
Oct 2022 - Dec 2022 \| Collar (crude oil)
Derivative [Line Items]
Contractual Weighted Average Price/Unit \| $ / bbl	97.24
Oct 2022 - Dec 2022 \| Collar (crude oil) \| Maximum
Derivative [Line Items]
Contractual Volume/Month \| bbl	33,886
Contractual Price/Unit \| $ / bbl	112.75
Oct 2022 - Dec 2022 \| Collar (crude oil) \| Minimum
Derivative [Line Items]
Contractual Volume/Month \| bbl	5,448
Contractual Price/Unit \| $ / bbl	85.00
Nov 2022 - Mar 2023 \| Producer 3-way (natural gas)
Derivative [Line Items]
Contractual Weighted Average Price/Unit \| $ / Mcf	5.13
Nov 2022 - Mar 2023 \| Producer 3-way (natural gas) \| Maximum
Derivative [Line Items]
Contractual Volume/Month \| Mcf	128,912
Contractual Price/Unit \| $ / Mcf	8.44
Nov 2022 - Mar 2023 \| Producer 3-way (natural gas) \| Minimum
Derivative [Line Items]
Contractual Volume/Month \| Mcf	3,813
Contractual Price/Unit \| $ / Mcf	3.00
Nov 2022 - Jun 2023 \| Collar (natural gas)
Derivative [Line Items]
Contractual Weighted Average Price/Unit \| $ / Mcf	5.48
Nov 2022 - Jun 2023 \| Collar (natural gas) \| Maximum
Derivative [Line Items]
Contractual Volume/Month \| Mcf	90,941
Contractual Price/Unit \| $ / Mcf	9.05
Nov 2022 - Jun 2023 \| Collar (natural gas) \| Minimum
Derivative [Line Items]
Contractual Volume/Month \| Mcf	11,036
Contractual Price/Unit \| $ / Mcf	2.90

Derivative instruments - Impact of Derivatives on the Balance Sheet and Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Derivative instruments
Derivative assets, current portion	$ 4,376		$ 4,376
Derivative assets, noncurrent portion	812		812
Derivative liabilities, current portion	(3,941)		(3,941)		$ (3,953)
Derivative liabilities, noncurrent portion					(400)
Change in unrealized gain/(loss) on derivatives			5,600	$ (11,010)
Total gain/(loss) on derivative contracts	6,082	$ (6,558)	(19,147)	(18,115)
Primary underlying risk, Commodity Price \| Non-hedging derivative instruments
Derivative instruments
Derivative assets, current portion	4,376		4,376
Derivative assets, noncurrent portion	812		812
Derivative liabilities, current portion	(3,941)		(3,941)		(3,953)
Derivative liabilities, noncurrent portion					(400)
Realized loss on derivatives	(9,331)	(3,959)	(24,747)	(7,105)
Change in unrealized gain/(loss) on derivatives	15,413	(2,599)	5,600	(11,010)
Total gain/(loss) on derivative contracts	6,082	(6,558)	(19,147)	(18,115)
Crude oil \| Primary underlying risk, Commodity Price \| Non-hedging derivative instruments
Derivative instruments
Derivative assets, current portion	4,581		4,581
Derivative assets, noncurrent portion	812		812
Derivative liabilities, current portion	(1,865)		(1,865)		(3,465)
Derivative liabilities, noncurrent portion					(411)
Realized loss on derivatives	(4,971)	(2,324)	(15,388)	(2,583)
Change in unrealized gain/(loss) on derivatives	16,571	721	7,404	(6,775)
Total gain/(loss) on derivative contracts	11,600	(1,603)	(7,984)	(9,358)
Natural gas \| Primary underlying risk, Commodity Price \| Non-hedging derivative instruments
Derivative instruments
Derivative assets, current portion	(205)		(205)
Derivative liabilities, current portion	(2,076)		(2,076)		(488)
Derivative liabilities, noncurrent portion					$ 11
Realized loss on derivatives	(4,360)	(1,635)	(9,359)	(4,522)
Change in unrealized gain/(loss) on derivatives	(1,158)	(3,320)	(1,804)	(4,235)
Total gain/(loss) on derivative contracts	$ (5,518)	$ (4,955)	$ (11,163)	$ (8,757)

Fair value measurements (Details) - USD ($) $ in Thousands	9 Months Ended
Fair value measurements (Details) - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Fair value measurements
Acquired and assumed asset retirement obligations	$ 633
Fair Value, Recurring
Fair value measurements
Derivative contract assets	5,188
Derivative contract liabilities	(3,941)	$ (4,353)
Fair Value, Recurring \| Level 2
Fair value measurements
Derivative contract assets	5,188
Derivative contract liabilities	(3,941)	$ (4,353)
Fair Value, Nonrecurring
Fair value measurements
Acquired and assumed asset retirement obligations	$ 633

Fair value measurements - Carrying and Fair Value (Details) - Fair Value, Recurring $ in Thousands	Dec. 31, 2021 USD ($)
Carrying Value
Fair value measurements
Revolving Credit Facility	$ 29,938
Fair Value
Fair value measurements
Revolving Credit Facility	$ 29,938

Oil and natural gas properties (Details) - USD ($)	3 Months Ended		9 Months Ended
Oil and natural gas properties (Details) - USD ($)	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
2022 Acquisitions \| Minimum
Oil and natural gas properties
Working interests acquired	2.00%		0.51%
Net revenue interests acquired	1.00%		0.38%
2022 Acquisitions \| Maximum
Oil and natural gas properties
Working interests acquired	30.00%		43.00%
Net revenue interests acquired	23.00%		33.00%
2022 Acquisitions \| Permian Basin
Oil and natural gas properties
Amount paid to acquire interest in oil and natural gas property	$ 6,290,000		$ 25,328,000
2022 Acquisitions \| Denver Julesberg Basin
Oil and natural gas properties
Amount paid to acquire interest in oil and natural gas property	$ 2,833,000		2,938,000
2022 Acquisitions \| Haynesville Basin
Oil and natural gas properties
Amount paid to acquire interest in oil and natural gas property			2,992,000
2022 Divestitures
Oil and natural gas properties
Divestitures of oil and natural gas properties during period	0
2022 Divestitures \| Eagle Ford Basin \| Partial sale of ownership interest
Oil and natural gas properties
Amount received from sale of interest in oil and natural gas property			$ 741,000
2021 Acquisitions \| Minimum
Oil and natural gas properties
Working interests acquired		5.00%		0.01%
Net revenue interests acquired		4.00%		0.01%
2021 Acquisitions \| Maximum
Oil and natural gas properties
Working interests acquired		41.20%		41.20%
Net revenue interests acquired		30.30%		31.00%
2021 Acquisitions \| Permian Basin
Oil and natural gas properties
Amount paid to acquire interest in oil and natural gas property		$ 17,444,000		$ 26,456,000
2021 Acquisitions \| Denver Julesberg Basin
Oil and natural gas properties
Amount paid to acquire interest in oil and natural gas property		0		40,366,000
2021 Acquisitions \| Bakken Basin
Oil and natural gas properties
Amount paid to acquire interest in oil and natural gas property		$ 0		190,000
2021 Divestitures \| Eagle Ford Basin \| Partial sale of ownership interest
Oil and natural gas properties
Amount received from sale of interest in oil and natural gas property				3,041,000
Recorded gain on divestiture				0
Recorded loss on divestiture				$ 0

Partners' capital (Details) - USD ($)	3 Months Ended		9 Months Ended
Partners' capital (Details) - USD ($)	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Partners' capital
Reallocation of distributions from Limited Partner to General Partner	$ 6,654		$ 25,623	$ 12,856,000
LPA distributions	0	$ 0	$ 0	$ 0
Scenario III
Partners' capital
Percentage of cumulative distributions received by distributions			20.00%
General Partner
Partners' capital
Contributions receivable	0		$ 0		$ 84,000
General Partner \| Scenario III
Partners' capital
Percentage of cumulative distributions received by partner			80.00%
General Partner \| Scenario IV
Partners' capital
Percentage of cumulative distributions received by partner			20.00%
Limited Partner
Partners' capital
Contributions receivable	$ 10,000		$ 10,000
Limited Partner \| Scenario I
Partners' capital
Percentage of allocation of net profit and losses to partners			100.00%
Limited Partner \| Scenario II
Partners' capital
Percentage of allocation of net profit and losses to partners			100.00%
Preferred return (as a percent)			8.00%
Limited Partner \| Scenario III
Partners' capital
Percentage of cumulative distributions received by partner			20.00%
Limited Partner \| Scenario IV
Partners' capital
Percentage of cumulative distributions received by partner			80.00%

Related party transactions (Details) - Management Company - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Related party transactions
Management fees, related party	$ 919,000	$ 969,000	$ 2,808,000	$ 2,908,000
Related party payable	$ 0		$ 0		$ 8,000
Limited Partner
Related party transactions
Percentage of limited partner's aggregate capital commitment			1.50%

- Definition

Carrying amount as of the balance sheet date of obligations due all related parties. For classified balance sheets, represents the current portion of such liabilities (due within one year or within the normal operating cycle if longer).

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 10
-Section S99
-Paragraph 1B
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+ Details

Commitments and Contingencies (Details) $ in Thousands	9 Months Ended
Commitments and Contingencies (Details) $ in Thousands	Sep. 30, 2022 USD ($)
Commitments and contingencies.
Capital expenditures included in accounts payable	$ 15,757
Additional development capital expenditures, INP	$ 50,000

Credit facility (Details) - Revolving Credit Facility - USD ($)	9 Months Ended
	Sep. 30, 2022	Dec. 31, 2021
Credit facility
Borrowing capacity	$ 100,000,000
Outstanding amount	0	$ 30,000,000
Unamortized loan origination costs	$ 0	$ 62,000
Margin rate (as a percent)	0.50%
Prime Rate
Credit facility
Weighted average interest rate (as a percent)	4.47%	3.35%

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Risk concentrations (Details)	9 Months Ended
Risk concentrations (Details)	Sep. 30, 2022
Risk concentrations
Percentage of partnership wells operated by third party operating partners	100.00%

Subsequent events (Details) - Subsequent Event [Member] $ / shares in Units, $ in Millions	Oct. 24, 2022 USD ($) $ / shares
Subsequent Event [Line Items]
Dividends declared per share \| $ / shares	$ 0.08
Dividends Payable	$ 60.0
Annual dividends per share, year to date \| $ / shares	$ 0.45
Annual cumulative dividend yield	5.00%
Credit agreement with Texas Capital Bank
Subsequent Event [Line Items]
Aggregate elected commitments	$ 150.0
Initial borrowing base	325.0
Aggregate maximum borrowing capacity	1,000.0
Current borrowing capacity	$ 150.0