10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2022

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to _______

Commission File Number: 001-41537

GRANITE RIDGE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 1311
(Primary Standard Industrial
Classification Code Number) 88-2227812
(I.R.S. Employer
Identification Number)

5217 McKinney Ave, Suite 400,

Dallas, TX 75205

(Address of principal executive offices)

(214) 396-2850

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, par value $0.0001 per share	GRNT	New York Stock Exchange
Warrants to purchase Common Stock, each whole warrant exercisable for one share of common stock at an exercise price of $11.50 per share	GRNT WS	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ◻ No ⌧

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ⌧ No ◻

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

			⌧
Large accelerated filer ◻	Accelerated filer ◻	Non-accelerated filer ⌧	Smaller reporting company ☒ Emerging growth company ☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ⌧

At November 10, 2022, there were 133,294,897 shares of our common stock, par value $0.0001, outstanding.

EXPLANATORY NOTE

The financial statements covered in this Quarterly Report on Form 10-Q of Granite Ridge Resources, Inc. (“Granite Ridge”) present the financial condition and results of operations of Granite Ridge’s predecessor, Grey Rock Energy Fund III-A, LP and its subsidiaries, Grey Rock Energy Fund III-B, LP, Grey Rock Energy Fund III-B Holdings, L.P. and its subsidiaries, and Grey Rock Preferred Limited Partner III, L.P. (collectively, “Grey Rock Energy Fund III” or the “Predecessor”), which operated the majority of the historical business and was identified as the acquirer and predecessor upon consummation of the business combination on October 24, 2022.

Granite Ridge did not conduct any activity prior to the business combination and the Predecessor became a subsidiary of Granite Ridge upon closing of the various formation transactions completed concurrently with the business combination. The information provided in this Quarterly Report on Form 10-Q only reflects the financial condition and results of operations of the Predecessor as of September 30, 2022 and December 31, 2021 and for the three and nine months ended September 30, 2022 and 2021. Because the business combination was completed subsequent to the end of the period covered by this Quarterly Report on Form 10-Q, the information provided herein regarding the Predecessor does not include financial or other information regarding the other entities who were parties to the business combination or whose assets became part of the business combination, including Executive Network Partnering Corporation, Grey Rock Energy Fund, LP and its subsidiaries, Grey Rock Energy Fund II, L.P. and its subsidiaries, Grey Rock Energy Fund II-B, LP, Grey Rock Energy Fund II-B Holdings, L.P. and its subsidiaries, and Grey Rock Preferred Limited Partner II, L.P. The condensed combined financial data 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 and related formation transactions.

i

TABLE OF CONTENTS

		PAGE
PART I - FINANCIAL INFORMATION
Item 1.	Condensed Combined Financial Statements (Unaudited) (Predecessor)	1
	Condensed Combined Balance Sheets (Unaudited)	1
	Condensed Combined Statements of Income (Unaudited)	2
	Condensed Combined Statements of Changes in Partners’ Capital (Unaudited)	3
	Condensed Combined Statements of Cash Flows (Unaudited)	4
	Notes to Condensed Combined Financial Statements (Unaudited)	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	35
PART II - OTHER INFORMATION		37
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	Mine Safety Disclosures	37
Item 5.	Other Information	37
Item 6.	Exhibits	37
Signatures		40

ii

PART I – FINANCIAL INFORMATION

Item 1. Condensed Combined Financial Statements.

GREY ROCK ENERGY FUND III

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

CONDENSED COMBINED BALANCE SHEETS

	(Unaudited)
	As of September 30,		As of December 31,
(in thousands)	2022		2021
ASSETS
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 long-term assets		812		—
TOTAL ASSETS	$	478,121	$	356,190
LIABILITIES AND PARTNERS' CAPITAL
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 (Note 8)
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

The accompanying notes are an integral part to these condensed combined financial statements

1

GREY ROCK ENERGY FUND III

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

CONDENSED COMBINED STATEMENTS OF INCOME

(UNAUDITED)

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2022		2021		2022		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		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	$	42,735	$	25,121	$	137,046	$	56,671

The accompanying notes are an integral part to these condensed combined financial statements

2

GREY ROCK ENERGY FUND III

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

CONDENSED COMBINED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(UNAUDITED)

(in thousands)	General Partner		Limited Partners		Total
Balance at December 31, 2021	$	15,462	$	298,834	$	314,296
Net (loss)/income		(29)		27,874		27,845
Carried interest reallocation		7,168		(7,168)		—
Balance at March 31, 2022		22,601		319,540		342,141
Net income		218		66,248		66,466
Carried interest reallocation		11,801		(11,801)		—
Balance at June 30, 2022		34,620		373,987		408,607
Net income		340		42,395		42,735
Carried interest reallocation		6,654		(6,654)		—
Balance at September 30, 2022	$	41,614	$	409,728	$	451,342

(in thousands)	General Partner		Limited Partners		Total
Balance at December 31, 2020	$	657	$	177,772	$	178,429
Net income		51		15,459		15,510
Balance at March 31, 2021		708		193,231		193,939
Net (loss)/income		(219)		16,259		16,040
Partners' contributions		62		19,938		20,000
Balance at June 30, 2021		551		229,428		229,979
Net (loss)/income		(73)		25,194		25,121
Carried interest reallocation		12,856		(12,856)		—
Balance at September 30, 2021	$	13,334	$	241,766	$	255,100

The accompanying notes are an integral part to these condensed combined financial statements

3

GREY ROCK ENERGY FUND III

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

CONDENSED COMBINED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine months ended September 30,
(in thousands)	2022		2021
Operating activities:
Net income	$	137,046	$	56,671
Adjustments to reconcile net income 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:
Proceeds from borrowings on credit facilities		16,000		46,000
Repayments of borrowings on credit facilities		(46,000)		(22,000)
Partners’ contributions, net of change in contributions receivable		84		20,074
Net cash (used in)/provided by financing activities		(29,916)		44,074
Net (decrease)/increase 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

The accompanying notes are an integral part to these condensed combined financial statements

4

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED)

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”.

5

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

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

6

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

7

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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

8

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

9

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

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.

10

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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

11

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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)

12

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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)

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, 2021.

	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)

13

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

14

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

15

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

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.

16

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

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.

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.

17

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

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.

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.

18

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

SEPTEMBER 30, 2022

(UNAUDITED) Continued

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.

19

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In this Quarterly Report on Form 10-Q, unless otherwise specified or the context otherwise requires, “Grey Rock,” “we,” “us,” and “our” refer to Grey Rock Energy Fund III. Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the historical financial results of our Predecessor, Grey Rock Energy Fund III, on an individual basis unless otherwise noted.

Cautionary Statement Concerning Forward-Looking Statements

This report contains forward-looking statements regarding future events and our future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production, cash flow, borrowing base under our revolving credit facility, and impairment are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following:

● the ability to recognize the anticipated benefits of the Business Combination;

● Granite Ridge’s financial performance following the Business Combination;

● changes in Granite Ridge’s strategy, future operations, financial position, estimated revenues and losses, projected costs, prospectus and plans;

● changes in current or future commodity prices and interest rates;

● supply chain disruptions;

● infrastructure constraints and related factors affecting our properties;

● expansion plans and opportunities;

● operational risks including, but not limited to, the pace of drilling and completions activity on our properties;

● changes in the markets in which Granite Ridge competes;

● geopolitical risk and changes in applicable laws, legislation, or regulations, including those relating to environmental matters;

● cyber-related risks;

20

● the fact that reserve estimates depend on many assumptions that may turn out to be inaccurate and that any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of the Company’s reserves;

● the outcome of any known and unknown litigation and regulatory proceedings;

● limited liquidity and trading of Granite Ridge’s securities;

● acts of war or terrorism; and

● market conditions and global, regulatory, technical, and economic factors beyond Granite Ridge’s control, including the potential adverse effects of the COVID-19 pandemic, or another major disease, affecting capital markets, general economic conditions, global supply chains and Granite Ridge’s business and operations.

We have based any forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results achieved may differ materially from expected results described in these statements. You should consider carefully the statements in the section entitled “Risk Factors” and other sections of our Registration Statement on Form S-4/A filed with the SEC on September 12, 2022, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Forward-looking statements speak only as of the date they are made. We do not undertake, and specifically disclaim, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.

The following discussion should be read in conjunction with the unaudited condensed combined financial statements and accompanying notes to condensed combined financial statements appearing elsewhere in this report.

Overview

We hold strategic investments in non-operated working interests in diversified upstream oil and natural gas assets in North America. As a non-operator, we have been able to diversify our investment exposure by participating in a large number of gross wells, as well as entering into additional project areas by partnering with numerous experienced operating partners that utilize the latest completion techniques in core unconventional basins across the United States.

We have achieved capital appreciation through our assets and earned income through investments, directly or indirectly, through our special purpose subsidiaries, in non-operated working interests in diversified upstream oil and natural gas assets in North America.

Pursuant to our investment strategies, Fund III collectively participated in 977 gross (58 net) producing wells as of September 30, 2022 with a core focus in the premier basins within the United States. As of December 31, 2021, Fund III collectively participated in 862 gross (46 net) producing wells. As of September 30, 2022 and December 31, 2021, Fund III leased approximately 43,857 gross (8,903 net) and 35,378 gross (7,039 net) developed acres, and 16,083 gross (6,109 net) and 18,488 gross (6,272 net) undeveloped acres, respectively, all located in the United States.

Fund III’s average daily production for the three and nine months ended September 30, 2022 was 12,259 Boe and 11,615 Boe per day, respectively. The increase in production is consistent with our increase in net producing wells which increased to 58 wells as of September 30, 2022, up from 46 as of the end of 2021. During 2021, our wells increased from 17 net wells at the beginning of 2021 to 46 net wells at the end of 2021. The increase in wells was primarily driven by Fund III’s acquisition of additional wells during the first nine months of 2022 and throughout 2021.

21

Business Combination

Fund III 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 New York Stock Exchange (“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 execution of the BCA. The Business Combination closed on October 24, 2022. Granite Ridge is listed on the NYSE under the ticker symbol “GRNT”.  To the extent any of the financial data included in this Quarterly Report on Form 10-Q is as of a date or from a period prior to the consummation of our Business Combination, such financial data is that of Fund III, the Predecessor. The financial data 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 data for the Predecessor is not necessarily indicative of our results of operations, cash flows or financial position following the completion of the Business Combination.

Impacts of COVID-19 Pandemic and Geopolitical Factors

The global spread of COVID-19 since early 2020 has created significant market volatility and economic uncertainty and disruption. The virus created unprecedented challenges for our industry, including a drastic decline in demand for crude oil and natural gas. This, combined with OPEC actions in early 2020, led to spot and future prices of crude oil falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Conditions have significantly improved with the increase in domestic vaccination programs and reduced spread of the COVID-19 virus overall, which have contributed to an improvement in the economy and higher realized prices for commodities since the beginning of 2021. However, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue evolve, as do operators’ production decisions in response to these macroeconomic factors. It remains difficult to predict how long the COVID-19 pandemic and related market conditions will persist and the resulting future effects on our business. While we use derivative instruments to partially mitigate the impact of commodity price volatility on revenues, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. In addition, because our property interests are not operated by us, we have limited ability to influence or control the future development of such properties. In light of the current price and economic environment, we continue to be proactive with third-party operators to review spending and alter plans as appropriate. We currently expect that our cash flow from operations and borrowing availability under our credit facilities will allow us to meet our liquidity needs for at least the next 12 months.

In addition to the global COVID-19 pandemic, U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions and the start of the military conflict between Russia and Ukraine. On February 24, 2022, a full-scale military invasion of Ukraine by Russian troops began. Although the length and impact of the ongoing military conflict is highly unpredictable, the conflict in Ukraine has led to market disruptions, including significant volatility in commodity prices, credit and capital markets, as well as supply chain disruptions. Various of Russia’s actions have led to sanctions and other penalties being levied by the U.S., the European Union, and other countries, as well as other public and private actors and companies, against Russia and certain other geographic areas, including restrictions on imports of Russian oil, liquefied natural gas and coal. Additional potential sanctions and penalties have also been proposed and/or threatened. These disruptions in the oil and gas markets have caused, and could continue to cause, significant volatility in energy prices, which could have a material effect on our business.

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In addition, the United States and other countries have imposed sanctions on Russia which increases the risk that Russia, as a retaliatory action, may launch cyberattacks against the United States, its government, infrastructure and businesses. On March 21, 2022, the Biden Administration issued warnings about the potential for Russia to engage in malicious cyber activity against the United States in response to the economic sanctions that have been imposed. Prolonged unfavorable economic conditions or uncertainty as a result of the military conflict between Russia and Ukraine, may adversely affect our business, financial condition, and results of operations.

Environmental, Social and Corporate Governance Initiatives

We are committed to developing industry-leading ESG programs and continually improving our ESG performance. We view exceptional ESG performance as an opportunity to differentiate us from our peers, provide for increased access to capital markets, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate.

Source of Our Revenues

We derive our revenues from our interests in the sale of oil and natural gas production. Revenues are a function of production, the prevailing market price at the time of sale, oil quality, and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

Lease operating expenses

Lease operating expenses are the costs incurred in the operation of producing properties, including workover costs. Expenses for field employees’ salaries, saltwater disposal, ad valorem taxes, repairs and maintenance comprise the most significant portion of our lease operating expenses. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. A portion of our operating cost components are variable and change in correlation to production levels.

Production taxes

Production taxes are paid on produced oil and natural gas which is generated in Texas, Oklahoma, Montana, New Mexico, North Dakota, Louisiana and Colorado. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

Depletion and accretion expense

Depletion and accretion include the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and successful development efforts and allocate these costs to each unit of production using the units of production method. Accretion expense relates to the passage of time of our asset retirement obligations.

Impairment expense

We evaluate capitalized costs related to proved oil properties, including wells and related oil sales support equipment and facilities, for impairment on an annual basis. If undiscounted cash flows are insufficient to recover the net capitalized

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costs, we recognize an impairment charge for the difference between the net capitalized cost of proved properties and their estimated fair values.

General and administrative expenses

General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, management fees, audit and other professional fees and legal compliance.

Interest expense

We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

Gain (loss) on derivative contracts

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on derivative contracts is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon;

● the timing and success of drilling and production activities by our operating partners;

● the prices and the supply and demand for oil and natural gas;

● the quantity of oil and natural gas production from the wells in which we participate;

● changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil and natural gas;

● our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and

● the level of our operating expenses.

In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage in the Eagle Ford, Permian, Bakken, Haynesville and Denver-Julesburg Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.

The price of oil and natural gas can vary depending on the market in which it is sold and the means of transportation used to transport the oil and natural gas to market.

The price at which our oil and natural gas production are sold typically reflects either a premium or discount to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil and natural gas price differentials between the applicable benchmark and the sales prices we receive for our oil and natural gas production. Our oil price

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differential to the NYMEX benchmark price during the three and nine months ended September 30, 2022 was $(2.23) and $(1.52) per barrel, respectively, as compared to $(1.52) and $(5.14) per barrel in the three and nine months ended September 30, 2021, respectively. Our natural gas price differential during the three and nine months ended September 30, 2022 was $3.24 and $3.33 per Mcf, as compared to $2.15 and $2.43 per Mcf in the three and nine months ended September 30, 2021.

Market Conditions

The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and natural gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength of the U.S. dollar can adversely impact oil prices. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

Prices for various quantities of natural gas and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the three and nine months ended September 30, 2022 and 2021.

	Three months ended September 30,				Nine months ended September 30,
	2022		2021		2022		2021
Average NYMEX Prices (1)
Oil (per Bbl)	$	93.18	$	70.51	$	98.24	$	64.99
Natural gas (per Mcf)		7.95		4.32		6.70		3.35

(1) Based on average NYMEX closing and spot prices.

For the three months ended September 30, 2022, the average NYMEX oil pricing was $93.18 per barrel of oil or 32% higher than the average NYMEX  price per barrel for the three months ended September 30, 2021. Our settled derivatives decreased our realized oil price per barrel by $7.34 in the three months ended September 30, 2022 and $3.97 in the three months ended September 31, 2021. For the three months ended September 30, 2022, our average realized oil price per barrel after reflecting settled derivatives was $83.61 compared to $65.02 for the three months ended September 30, 2021. The average NYMEX natural gas pricing for the three months ended September 30, 2022 was $7.95 per Mcf, or 84% higher than the average NYMEX price per Mcf for the three months ended September 30, 2021. Our settled derivatives decreased our realized natural gas price per Mcf by $1.71 and $0.69 in the three months ended September 30, 2022 and 2021, respectively. For the three months ended September 30, 2022, our realized gas price per Mcf was $9.48 compared to $5.78 for the three months ended September 30, 2021, which was primarily driven by higher  NYMEX pricing for natural gas and gas realizations.

For the nine months ended September 30, 2022, the average NYMEX oil pricing was $98.24 per barrel of oil or 51% higher than the average NYMEX  price per barrel for the nine months ended September 30, 2021. Our settled derivatives decreased our realized oil price per barrel by $7.54 in the nine months ended September 30, 2022 and by $1.48 in the nine months ended September 31, 2021. For the nine months ended September 30, 2022, our average realized oil price per barrel after reflecting settled derivatives was $89.18 compared to $58.37 for the nine months ended September 30, 2021. The average NYMEX natural gas pricing for the nine months ended September 30, 2022 was $6.70 per Mcf, or 100% higher than the average NYMEX price per Mcf for the nine months ended September 30, 2021. Our settled derivatives decreased our realized natural gas price per Mcf by $1.42 and $0.69 in the nine months ended September 30, 2022 and 2021, respectively. For the nine months ended September 30, 2022, our realized gas price per Mcf was $8.61 compared to $5.09 for the nine months ended September 30, 2021, which was primarily driven by higher  NYMEX pricing for natural gas and gas realizations.

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Results of Operations — Fund III

Three months ended September 30, 2022 compared to three months ended September 30, 2021

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

	Three months ended September 30,
	2022		2021
Net Sales (in thousands):
Oil sales	$	61,607	$	40,376
Natural gas and related product sales		28,587		15,341
Revenues		90,194		55,717
Average Sales Prices:
Oil (per Bbl)	$	90.95	$	68.99
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)		(7.34)		(3.97)
Oil net of settled oil derivatives (per Bbl)		83.61		65.02
Natural gas and related product sales (per Mcf)		11.19		6.47
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)		(1.71)		(0.69)
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)		9.48		5.78
Realized price on a Boe basis excluding settled commodity derivatives		81.75		56.82
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)		(8.46)		(4.04)
Realized price on a Boe basis including settled commodity derivatives		73.29		52.78
Operating Expenses (in thousands):
Lease operating expenses	$	6,368	$	3,621
Production taxes		5,053		2,506
Depletion and accretion expense		39,868		15,794
General and administrative		1,776		1,764
Total operating expenses		53,065		23,685
Costs and Expenses (per Boe):
Lease operating expenses	$	5.77	$	3.69
Production taxes		4.58		2.56
Depletion and accretion		36.13		16.11
General and administrative		1.61		1.80
Net Producing Wells at Period-End		58.33		42.82

Oil, Natural Gas and Related Product Sales

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. For the three months ended September 30, 2022, our oil and natural gas sales increased 62% from the three months ended September 30, 2021, driven by a 13% increase in production volumes and a 44% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average price in the three months ended September 30, 2022 as compared to the three months ended September 30, 2021 was driven by higher average NYMEX oil and natural gas prices.

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Realized production from oil and natural gas properties increases through drilling success and the acquisition of additional net revenue interests. Increases in production are offset by the natural decline of the production rate of existing oil and natural gas wells.

Production for the three months ended September 30, 2022 and 2021 is set forth in the following table:

	Three months ended September 30,
	2022		2021
Production:
Oil (MBbl)		677		585
Natural gas (MMcf)		2,556		2,372
Total (MBoe)(1)		1,103		981
Average Daily Production:
Oil (Bbl)		7,526		6,503
Natural gas (Mcf)		28,398		26,354
Total (Boe)(1)		12,259		10,895

(1) Natural gas is converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Lease Operating Expenses

Lease operating expenses were approximately $6,368 thousand and $3,621 thousand for the three months ended September 30, 2022 and 2021, respectively. On a per unit basis, production expenses increased 56% from $3.69 per Boe for the three months ended September 30, 2021 to $5.77 per Boe for the three months ended September 30, 2022, due primarily to gas processing fees in the Permian Basin and an increase in commodity prices. On an absolute dollar basis, the 76% increase in our production related expenses for the three months ended September 30, 2022, compared to the three months ended September 30, 2021 was primarily due to a 56% increase in per unit costs and a 13% increase in production.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $5,053 thousand for the three months ended September 30, 2022, compared to $2,506 thousand for the three months ended September 30, 2021. As a percentage of oil and natural gas sales, our production taxes were 6% and 4% for the three months ended September 30, 2022 and 2021, respectively. Production taxes as a percent of total oil and natural gas sales are consistent with historical trend.

Depletion and Accretion

Depletion and accretion was approximately $39,868 thousand for the three months ended September 30, 2022, compared to $15,794 thousand for the three months ended September 30, 2021. Depletion and accretion was $36.13 per Boe for the three months ended September 30, 2022 compared to $16.11 per Boe for the three months ended September 30, 2021. Aggregate depletion and accretion expense increased for the three months ended September 30, 2022 compared to the three months ended September 30, 2021, which is consistent with the increase in production levels. The aggregate   increase in depletion and accretion expense for the three months ended September 30, 2022 compared to the three months ended September 30, 2021 was driven by the 124% increase in the depletion and accretion rate per Boe and a 13% increase in production levels, respectively.

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General and Administrative

General and administrative expenses were approximately $1,776 thousand for the three months ended September 30, 2022, compared to $1,764 thousand for the three months ended September 30, 2021, respectively. General and administrative fees remained materially consistent period over period. General and administrative fees include management fees which were approximately $919 thousand and $969 thousand for the three months ended September 30, 2022 and 2021, respectively. Management fees also remained materially consistent period over period.

Gain/(Loss) on Derivative Contracts

We enter into commodity derivatives instruments to manage the price risk attributable to future oil and natural gas production. We recorded a gain on derivative contracts of approximately $6,082 thousand during the three months ended September 30, 2022, compared to a loss of $6,558 thousand during the three months ended September 30, 2021. Commodity price volatility during the three months ended September 30, 2022 resulted in realized losses of $9,331 thousand in the three months ended September 30, 2022    compared to $3,959 thousand in the three months ended September 30, 2021. For the three months ended September 30, 2022, unrealized gains were $15,413 thousand, compared to unrealized losses of $2,599 thousand in the three months ended September 30, 2021. Our average three months ended September 30, 2022 realized oil price per barrel after reflecting settled derivatives was $83.61, compared to $65.02 in the three months ended September 30, 2021. Our settled derivatives decreased our realized oil price per barrel by $7.34 in the three months ended September 30, 2022, compared to $3.97 in the three months ended September 30, 2021. Our realized natural gas price per Mcf was $9.48 in the three months ended September 30, 2022, compared to $5.78 in the three months ended September 30, 2021. Our settled derivatives decreased our realized natural gas price per Mcf by $1.71 in the three months ended September 30, 2022, and $0.69 in the three months ended September 30, 2021. As of September 30, 2022, we ended the period with a $1,247 thousand net derivative asset compared to a $4,353 thousand net derivative liability as of December 31, 2021.

Interest Expense

Interest expense was approximately $476 thousand and $353 thousand for the three months ended September 30, 2022 and 2021, respectively. The increase in interest expense for the three months ended September 30, 2022 as compared to the three months ended September 30, 2021 was primarily due to an increase in the weighted average interest rate.

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Nine months ended September 30, 2022 compared to nine months ended September 30, 2021

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

	Nine months ended September 30,
	2022		2021
Net Sales (in thousands):
Oil sales	$	197,332	$	104,700
Natural gas and related product sales		65,931		37,932
Revenues		263,263		142,632
Average Sales Prices:
Oil (per Bbl)	$	96.72	$	59.85
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)		(7.54)		(1.48)
Oil net of settled oil derivatives (per Bbl)		89.18		58.37
Natural gas and related product sales (per Mcf)		10.03		5.78
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)		(1.42)		(0.69)
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)		8.61		5.09
Realized price on a Boe basis excluding settled commodity derivatives		83.95		50.16
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)		(7.89)		(2.50)
Realized price on a Boe basis including settled commodity derivatives		76.06		47.66
Operating Expenses (in thousands):
Lease operating expenses	$	15,840	$	8,407
Production taxes		14,628		7,737
Depletion and accretion expense		70,529		45,798
General and administrative		4,880		4,978
Total operating expenses		105,877		66,920
Costs and Expenses (per Boe):
Lease operating expenses	$	5.05	$	2.96
Production taxes		4.66		2.72
Depletion and accretion		22.49		16.11
General and administrative		1.56		1.75
Net Producing Wells at Period-End		58.33		42.82

Oil, Natural Gas and Related Product Sales

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. For the nine months ended September 30, 2022, our oil and natural gas sales increased 85% from the nine months ended September 30, 2021, driven by a 10% increase in production volumes and a 67% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average price in the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021 was driven by higher average NYMEX oil and natural gas prices.

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Realized production from oil and natural gas properties increases through drilling success and the acquisition of additional net revenue interests. Increases in production are offset by the natural decline of the production rate of existing oil and natural gas wells. During the nine months ended September 30, 2022, the number of wells we participated in increased by 36% as compared to the nine months ended September 30, 2021. The new well additions drove the 10% increase in production in the first nine months of 2022 as compared to the first nine months of 2021.

Production for the nine months ended September 30, 2022 and 2021 is set forth in the following table:

	Nine months ended September 30,
	2022		2021
Production:
Oil (MBbl)		2,040		1,750
Natural gas (MMcf)		6,576		6,563
Total (MBoe)(1)		3,136		2,843
Average Daily Production:
Oil (Bbl)		7,556		6,480
Natural gas (Mcf)		24,354		24,308
Total (Boe)(1)		11,615		10,531

(1) Natural gas is converted to Boe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Lease Operating Expenses

Lease operating expenses were approximately $15,840 thousand and $8,407 thousand for the nine months ended September 30, 2022 and 2021, respectively. On a per unit basis, production expenses increased 71% from $2.96 per Boe for the nine months ended September 30, 2021 to $5.05 per Boe for the nine months ended September 30, 2022, due primarily to gas processing fees in the Permian Basin and an increase in commodity prices. On an absolute dollar basis, the 88% increase in our production related expenses for the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021 was primarily due to a 71% increase in per unit costs and a 10% increase in production.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $14,628 thousand for the nine months ended September 30, 2022, compared to $7,737 thousand for the nine months ended September 30, 2021. As a percentage of oil and natural gas sales, our production taxes were 6% and 5% for the nine months ended September 30, 2022 and 2021, respectively. Production taxes as a percent of total oil and natural gas sales are consistent with historical trend.

Depletion and Accretion

Depletion and accretion was approximately $70,529 thousand for the nine months ended September 30, 2022, compared to $45,798 thousand for the nine months ended September 30, 2021. Depletion and accretion was $22.49 per Boe for the nine months ended September 30, 2022 compared to $16.11 per Boe for the nine months ended September 30, 2021. Aggregate  depletion and accretion expense increased for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021, which is consistent with production levels, which also increased period over period. The aggregate  increase in depletion and accretion expense for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 was driven by a 40% increase in the depletion and accretion rate per Boe and a 10% increase in production levels.

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General and Administrative

General and administrative expenses were approximately $4,880 thousand for the nine months ended September 30, 2022, compared to $4,978 thousand for the nine months ended September 30, 2021, respectively. General and administrative expense remained materially consistent for the nine months ended September 30, 2022, compared to the nine months ended September 30, 2021. General and administrative fees include management fees which were approximately $2,808 thousand and $2,908 thousand for the nine months ended September 30, 2022 and 2021, respectively. Management fees also remained materially consistent period over period.

Gain/(Loss) on Derivative Contracts

We enter into commodity derivatives instruments to manage the price risk attributable to future oil and natural gas production. We recorded a loss on derivative contracts of approximately $19,147 thousand during the nine months ended September 30, 2022, compared to $18,115 thousand during the nine months ended September 30, 2021. Volatility in commodity prices in the nine months ended September 30, 2022 resulted in realized losses of $24,747 thousand in the nine months ended September 30, 2022 compared to $7,105 thousand in the nine months ended September 30, 2021. For the nine months ended September 30, 2022, unrealized gains were $5,600 thousand, compared to unrealized losses of $11,010 thousand in the nine months ended September 30, 2021. Our average nine months ended September 30, 2022 realized oil price per barrel after reflecting settled derivatives was $89.18, compared to $58.37 in the nine months ended September 30, 2021. Our settled derivatives decreased our realized oil price per barrel by $7.54 in the nine months ended September 30, 2022, compared to $1.48 in the nine months ended September 30, 2021. Our realized natural gas price per Mcf was $8.61 in the nine months ended September 30, 2022, compared to $5.09 in the nine months ended September 30, 2021. Our settled derivatives decreased our realized natural gas price per Mcf by $1.42 in the nine months ended September 30, 2022, and $0.69 in the nine months ended September 30, 2021. As of September 31, 2022, we ended the period with a $1,247 thousand net derivative asset compared to $4,353 thousand net derivative liability as of December 31, 2021.

Interest Expense

Interest expense was approximately $1,193 thousand and $926 thousand for the nine months ended September 30, 2022 and 2021, respectively. The increase in interest expense for the nine months ended September 30, 2022 as compared to the nine months ended September 30, 2021 was primarily due to an increase in the weighted average interest rate, partially offset by a larger outstanding balance on the credit facility during the nine months ended September 30, 2021.

Liquidity and Capital Resources — Fund III

Nine months ended September 30, 2022 compared to nine months ended September 30, 2021

Overview

Our main sources of liquidity and capital resources as of the periods covered by this report have been internally generated cash flow from operations. Our primary use of capital has been for the development and acquisition of oil and natural gas properties. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

As of September 30, 2022, we had no outstanding debt. We had approximately $106,410 thousand in liquidity as of September 30, 2022, consisting of approximately $100,000 thousand of committed borrowing availability under the revolving credit facility and approximately $6,410 thousand of cash on hand.

With our cash on hand, cash flow from operations, and borrowing capacity under the new revolving credit facility entered into by Granite Ridge subsequent to September 30, 2022, we believe that we will have sufficient cash flow and liquidity

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to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

Our recent capital commitments have been to fund development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash on hand, cash flows from operations and available borrowing capacity under our new revolving credit facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels.

Working Capital

Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes,  collection of receivables, expenditures related to our development operations and the impact of our outstanding derivative instruments.

At September 30, 2022, we had a working capital surplus of approximately $70,912 thousand, compared to a surplus of approximately $37,268 thousand at December 31, 2021. Current assets increased by approximately $17,649 thousand and current liabilities decreased by approximately $15,995 thousand at September 30, 2022, compared to December 31, 2021. The increase in current assets in the nine months ended September 30, 2022 as compared to December 31, 2021 is primarily due to an increase in revenue receivable, other assets and derivative assets partially offset by a decrease in cash and advances to operators. The decrease in current liabilities in the nine months ended September 30, 2022 as compared to December 31, 2021 is primarily due to the decrease in our credit facilities and derivative liabilities, partially offset by an increase in accrued expenses.

Cash Flows

Our cash flows for the months ended September 30, 2022 and 2021 are presented below:

	Nine months ended September 30,
(in thousands)	2022		2021
Net Cash Provided by Operating Activities	$	179,662	$	91,900
Net Cash Used in Investing Activities		(150,655)		(124,786)
Net Cash (Used in)/Provided by Financing Activities		(29,916)		44,074
Net Change in Cash	$	(909)	$	11,188

Cash Flows from Operating Activities

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

Net cash provided by operating activities during the nine months ended September 30, 2022 was approximately $179,662 thousand, compared to approximately $91,900 thousand during the nine months ended September 30, 2021. The increase in net cash provided by operating activities primarily relates to a 67% increase in realized prices (before the effects of derivatives) and a 10% increase in production period over period.  Working capital changes during the nine months ended September 30, 2022 included an increase of approximately $21,627 thousand in revenue receivables related to increased realized oil prices (before the effects of derivatives) and increased production from development drilling.  Working capital changes during the nine months ended September 30, 2021 included an increase of approximately $22,941 thousand in revenue receivables related to increased production, resulting from development drilling, as well as increased realized commodity prices (before the effects of derivatives), as commodity prices recovered from their historic lows in 2020 as a result of COVID-19.

32

Cash Flows from Investing Activities

We had cash flows used in investing activities of approximately $150,655 thousand and approximately $124,786 thousand during the nine months ended September 30, 2022 and 2021, respectively, primarily as a result of the development of proved oil and natural gas properties and acquisitions in the first nine months of 2022 and 2021.

Cash Flows from Financing Activities

Net cash used in financing activities was approximately $29,916 thousand for the nine months ended September 30, 2022. Net cash provided by financing activities was approximately $44,074 thousand for the nine months ended September 30, 2021. The cash used in financing activities in the nine months ended September 30, 2022 was primarily related to net borrowings, as opposed to a combination of partners’ contributions and net borrowings during the nine months ended September 30, 2021.

Revolving Credit Facility

In October 2018, we entered into a revolving credit facility with an initial borrowing capacity of $0. Through a series of amendments, as of September 30, 2022, the borrowing base was raised to $100,000 thousand with no balance outstanding. From December 31, 2021 through September 30, 2022, there were no amendments to the revolving credit facility. On October 24, 2022, the revolving credit facility was terminated and Granite Ridge entered into a new revolving credit agreement. See Note 11 to our condensed combined unaudited financial statements appearing elsewhere in this report.

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

As of September 30, 2022, we had repaid our contractual commitments under our revolving credit facility which included periodic interest payments. See Note 9 to our condensed combined unaudited financial statements appearing elsewhere in this report. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 to our condensed combined unaudited financial statements appearing elsewhere in this report. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 6 to our combined audited financial statements included in our Registration Statement on Form S-4/A filed with the SEC on September 12, 2022. With respect to all of these items, except for our commitments under our debt agreements, we cannot determine with accuracy the amount and/or timing of such payments.

Planned Capital Expenditures

For the remainder of 2022, we are budgeting approximately $50,000 thousand in total planned capital expenditures. As of September 30, 2022, we had incurred approximately $15,757 thousand in capital expenditures that were included in accounts payable, and we estimate that we were committed to an additional approximately $50,000 thousand in development capital expenditures not yet incurred for wells we had elected to participate in. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under the new revolving credit facility entered into by Granite Ridge subsequent to September 30, 2022.

The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures

33

in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see “Quantitative and Qualitative Disclosures About Market Risk.”

Capital Requirements

Development activities are discretionary, and, for the near term, we expect such activities to be maintained at levels we can fund through cash on hand, internal cash flow and borrowings under the new revolving credit facility entered into by Granite Ridge subsequent to September 30, 2022. To the extent capital requirements exceed internal cash flow and borrowing capacity under such revolving credit facility, additional financings from the capital markets may be pursued to fund these requirements. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our projects, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital. If internally generated cash flow and borrowing capacity is not available under our revolving credit facility, we may issue additional debt to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With the new revolving credit agreement entered into by Granite Ridge subsequent to September 30, 2022 and our positive cash flows from operations, we believe we will have sufficient capital to meet our drilling commitments, expected general and administrative expenses and other cash needs for the next twelve months. Nonetheless, any strategic acquisition of assets or increase in drilling activity may lead us to seek additional capital. We may also choose to seek additional capital rather than utilize our credit to fund accelerated or continued drilling at the discretion of management and depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.

Effects of Inflation and Pricing

The oil and natural gas industry is typically very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion.

Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Critical Accounting Estimates

Our critical accounting policies involving significant estimates include the estimation of proved oil and natural gas reserves, impairment testing, derivative instruments and hedging activity and asset retirement obligations. There were no material changes in our critical accounting policies involving significant estimates from those reported in our Registration Statement on Form S-4/A filed with the SEC on September 12, 2022.

34

A description of our critical accounting policies was provided in the section titled “Grey Rock’s Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Fund I, II and III” of our Registration Statement on Form S-4/A filed with the SEC on September 12, 2022.

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors. Historically, the markets for oil and natural gas have been volatile, and we believe these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil and natural gas prices.

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility. All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative contracts on the statements of operations rather than as a component of other comprehensive income or other income (expense).

We generally use derivatives to economically hedge a significant, but varying portion of our anticipated future production. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash from operations or borrowings under our new revolving credit facility.

Interest Rate Risk

At September 30, 2022, we did not have any debt outstanding. At December 31, 2021, we had approximately $29,938 thousand of debt outstanding, which bears interest at a floating rate. Based on the approximately $29,938 thousand in floating rate debt we had outstanding as of December 31, 2021, a 1% increase or decrease in the weighted average interest rate would have resulted in an increase or decrease, respectively, of approximately $299 thousand in interest expense per year. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our variable rate indebtedness but may enter into such derivative arrangements in the future. To the extent we enter into any such interest rate derivative arrangement, we would subject to risk for financial loss.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in company reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

35

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting. As discussed elsewhere in this Quarterly Report on Form 10-Q, we completed the Business Combination on October 24, 2022. Prior to the Business Combination, Granite Ridge Resources, Inc. was a privately held company with no operations, formed to be the successor following the Business Combination, and therefore its controls were not required to be designed or maintained in accordance with Exchange Act Rule 13a-15. Grey Rock Energy Fund III is the predecessor to Granite Ridge Resources, Inc. The design of public company disclosure controls and procedures and internal controls over financial reporting for the Company following the Business Combination has required and will continue to require significant time and resources from our management and other personnel. Furthermore, Executive Network Partnering Corporation, the legal acquirer in the Business Combination, was a non-operating public shell company prior to the Business Combination, and as such the disclosure controls and procedures and internal controls of Executive Network Partnering Corporation no longer exist as of the assessment date. As a result, management evaluated our disclosure controls and procedures as of September 30, 2022, but was unable, without incurring unreasonable effort or expense, to conclude whether our disclosure controls and procedures were effective as of September 30, 2022.

Changes in Internal Control over Financial Reporting

As described above, the design and implementation of internal control over financial reporting for the Company following the Business Combination has required and will continue to require significant time and resources from management and other personnel. In preparation for the Business Combination, we have been engaged in the process of the design and implementation of our internal control over financial reporting in a manner commensurate with the scale of our operations post-Business Combination. Changes that have been implemented leading up to and since the time of the Business Combination have included, among other things, the addition of entity level controls, appointment of an Audit Committee, adoption of committee charters and various governance policies, and establishment of an internal audit function. Except as described above, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

Our Company was not a party to any material legal proceedings during the quarterly period ended September 30, 2022. In the future, the Company may be subject from time to time to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.

Item 1A. Risk Factors.

In addition to the information set forth in this report, the risks that are discussed in the Registration Statement on Form S-4/A filed with the SEC on September 12, 2022 (the “Registration Statement”), under the headings “Risk Factors,” “Business of Grey Rock,” “Grey Rock’s Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk” should be carefully considered, as such risks could materially affect our business, financial condition or future results. There have been no material changes to the risk factors disclosed in the Registration Statement.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit No.	Description
2.1	Business Combination Agreement, dated May 16, 2022, by and among Executive Network Partnering Corporation, Granite Ridge Resources, Inc., ENPC Merger Sub, Inc., GREP Merger Sub, LLC, and GREP (incorporated by reference to Annex A of Granite Ridge Resources, Inc.’s Registration Statement on Form S-4, filed with the SEC on May 16, 2022).
3.1	Amended and Restated Certificate of Incorporation of Granite Ridge Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
3.2	Amended and Restated Bylaws of Granite Ridge Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).

37

Exhibit No.	Description
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Granite Ridge Resources, Inc.’s Registration Statement on Form S-4/A, filed with the SEC on September 12, 2022).
4.2	Specimen Warrant Certificate (incorporated by reference to Exhibit 4.3 to Executive Network Partnering Corporation’s Registration Statement on Form S-1, filed with the SEC on September 14, 2020).
4.3	Warrant Agreement, dated September 15, 2020 between Continental Stock Transfer & Trust Company and Executive Network Partnering Corporation (incorporated by reference to Exhibit 4.1 to Executive Network Partnering Corporation’s Current Report on Form 8-K, filed with the SEC on September 21, 2020).
4.4	Amendment No. 1 to Warrant Agreement, dated March 24, 2021 between Continental Stock Transfer & Trust Company and Executive Network Partnering Corporation (incorporated by reference to Exhibit 1.01 to Executive Network Partnering Corporation’s Current Report on Form 8-K, filed with the SEC on March, 25, 2021).
4.5	Assignment, Assumption and Amendment Agreement, dated October 24, 2022 by and among Executive Network Partnering Corporation, Granite Ridge Resources, Inc. and Continental Stock Transfer & Trust Company and Granite Ridge Resources, Inc. (incorporated by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
10.1	Registration Rights Agreement and Lock-Up Agreement, dated October 24, 2022 by and among Granite Ridge Resources, Inc., ENPC Holdings II, LLC and the other Holders (as defined therein) listed thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
10.2	Management Services Agreement, dated October 24, 2022 by and between Granite Ridge Resources, Inc. and Grey Rock Administration, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
10.3#	Granite Ridge Resources, Inc. 2022 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
10.4	Credit Agreement, dated October 24, 2022 by and among Granite Ridge Resources, Inc., as borrower, Texas Capital Bank, as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
10.5	Sponsor Agreement, dated as of May 16, 2022, by and among ENPC Holdings, LLC, ENPC Holdings II, LLC, Executive Network Partnering Corporation, Granite Ridge Resources, Inc., GREP Holdings, LLC and certain other parties thereto (incorporated by reference to Annex D of Granite Ridge Resources, Inc.’s Registration Statement on Form S-4, filed with the SEC on May 16, 2022).
F10.6	Form of Indemnity Agreement for Directors Affiliated with the Grey Rock funds (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).

38

Exhibit No.	Description
10.7	Form of Indemnity Agreement for Officers and Outside Directors (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
10.8#	Executive Employment Agreement between Luke C. Brandenberg and Granite Ridge Resources, Inc., dated October 24, 2022 (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
10.9#	Executive Employment Agreement between Tyler S. Farquharson and Granite Ridge Resources, Inc., dated October 24, 2022 (incorporated by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
21.1	Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2022).
31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
101.INS*	Inline XBRL Instance Document
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Document
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104	Cover Page Interactive Data File (embedded within the Inline XBRL document)
​ * Filed herewith # Indicates management plan or compensatory arrangement.

39

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Quarterly Report to be signed on its behalf by the undersigned thereunto duly authorized.

	GRANITE RIDGE RESOURCES, INC.
November 14, 2022	By:	/s/ LUKE C. BRANDENBERG
		Name:	Luke C. Brandenberg
		Title:	President and Chief Executive Officer
November 14, 2022	By:	/s/ TYLER S. FARQUHARSON
		Name:	Tyler S. Farquharson
		Title:	Chief Financial Officer

40

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Luke C. Brandenberg, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Granite Ridge Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

b) (Paragraph omitted pursuant to SEC Release Nos. 33-8238/34-47986 and 33-8392/34-49313);

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weakness in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: November 14, 2022	By: /s/	LUKE C. BRANDENBERG
		Luke C. Brandenberg
		President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Tyler S. Farquharson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Granite Ridge Resources, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

b) (Paragraph omitted pursuant to SEC Release Nos. 33-8238/34-47986 and 33-8392/34-49313);

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weakness in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: November 14, 2022	By: /s/	TYLER S. FARQUHARSON
		Tyler S. Farquharson
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Granite Ridge Resources, Inc., (the “Company”) on Form 10-Q for the quarterly period ended September 30, 2022, as filed with the United States Securities and Exchange Commission on the date hereof, (the “Report”), the undersigned officers of the Company hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: November 14, 2022	By:	/s/ LUKE C. BRANDENBERG
		Name:	Luke C. Brandenberg
		Title:	President and Chief Executive Officer
Dated: November 14, 2022	By:	/s/ TYLER S. FARQUHARSON
		Name:	Tyler S. Farquharson
		Title:	Chief Financial Officer

XML

Document and Entity Information - $ / shares	9 Months Ended
	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

XML

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

XML

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

XML

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

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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

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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.

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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.

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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)

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, 2021.

	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)

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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Summary of significant accounting policies (Policies)

9 Months Ended

Sep. 30, 2022

Summary of significant accounting policies

Principles of Combination

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

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

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

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

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

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

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

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

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.

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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

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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)

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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

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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

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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

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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

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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

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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

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Derivative instruments (Details) - Commodity futures	9 Months Ended
	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

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Derivative instruments - Volume of Derivative Activities (Details)	9 Months Ended
	Sep. 30, 2022 $ / bbl $ / Mcf bbl Mcf
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

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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)

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Fair value measurements (Details) - USD ($) $ in Thousands	9 Months Ended
	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

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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

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Oil and natural gas properties (Details) - USD ($)	3 Months Ended		9 Months Ended
	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

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Partners' capital (Details) - USD ($)	3 Months Ended		9 Months Ended
	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%

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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%

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

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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%

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

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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