Granite Ridge Resources 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)
Registration No. 333-268478

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Granite Ridge Resources, Inc.

128,233,953 Shares of Common Stock
10,349,975 Shares of Common Stock issuable
upon the exercise of Warrants

This prospectus relates to the issuance by Granite Ridge Resources, Inc. (“Granite Ridge” or the “Company”) of up to an aggregate of 10,349,975 shares of common stock, $0.0001 par value (the “Granite Ridge common stock”) that may be issued upon exercise of warrants to purchase Granite Ridge common stock at an exercise price of $11.50 per share (the “Granite Ridge warrants”).

This prospectus also relates to the offer and sale from time to time by the selling securityholders named in this prospectus (the “Selling Securityholders”), or their permitted transferees, of up to 128,233,953 shares of Granite Ridge common stock.

The shares of Granite Ridge common stock offered for resale under this prospectus were issued to the Selling Securityholders (as applicable to each) in accordance with the terms of, and transactions contemplated by, the Business Combination Agreement, dated as of May 16, 2022 (the “Business Combination Agreement”), by and among Executive Network Partnering Corporation, a Delaware corporation (“ENPC”), Granite Ridge, ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub”), and GREP Holdings, LLC, a Delaware limited liability company (“GREP”). The Granite Ridge common stock registered hereunder represents the securities issued to the Selling Securityholders pursuant to the terms of the Business Combination Agreement, as applicable to each Selling Securityholder, concurrently with the closing of the Business Combination.

The Business Combination is described in greater detail in this prospectus. See “Prospectus Summary — Business Combination.”

The 128,233,953 maximum amount of shares of Granite Ridge common stock offered for resale under this prospectus consist of (a) 1,238,393 shares of Granite Ridge common stock (the “Sponsor Shares”), of which 1,174,106 shares of Granite Ridge common stock were issued to ENPC Holdings II, LLC (“Holdco”) and 64,287 shares of Granite Ridge common stock were issued to the former independent directors of ENPC, in the Business Combination as merger consideration in connection with the exchange or forfeiture of securities of ENPC, as described below; and (b) 126,995,560‬ shares of Granite Ridge common stock issued to the other Selling Securityholders named herein in connection with the Business Combination as merger consideration based on a share value at the time the Business Combination Agreement was executed of $10.00 per share.

In connection with the initial public offering of ENPC, ENPC Holdings, LLC (“Sponsor”) acquired (and later assigned to Holdco and the former independent directors of ENPC) (i) 828,000 shares of ENPC Class F common stock (giving effect to a stock split effected by ENPC) for a capital contribution of $6,250, or for approximately $0.008 per share, (ii) 300,000 shares of Class B ENPC Common Stock (giving effect to the Forward Split (as defined herein)) for a capital contribution of $18,750, or for approximately $0.06 per share, and (iii) 614,000 CAPS™ (after giving effect to the Forward Split), each consisting of one share of Class A common stock and one-quarter of one ENPC warrant, originally purchased by the Sponsor for $6,140,000 in a private placement, or for approximately $10.00 per each ENPC CAPS™. At the effective time of the transactions contemplated by the Business Combination Agreement, (i) 495,357 shares of ENPC Class F common stock were converted to 1,238,393 shares of ENPC Class A common stock (of which 371,518 of those shares are, upon conversion to Granite Ridge common stock, subject to certain vesting and forfeiture provisions set forth in the Sponsor Agreement (as defined herein)) and the remaining shares of ENPC Class F common stock outstanding were automatically cancelled for no consideration (the “ENPC Class F Conversion”) (ii) all other remaining shares of ENPC Class A common stock held by Holdco were automatically cancelled without any conversion, payment or distribution (the “Sponsor Share Cancellation”) and (iii) all shares of ENPC Class B common stock outstanding were deemed transferred to ENPC and surrendered and forfeited for no consideration (the “ENPC Class B Contribution”). Effective immediately prior to the ENPC Class F Conversion, Sponsor Share Cancellation and ENPC Class B Contribution, any and all ENPC CAPS™, which were composed of one share of ENPC Class A common stock and one-fourth of one ENPC warrant, were automatically detached and broken into their constituent parts, such that a holder of an ENPC CAPS™ was deemed to hold one share of ENPC Class A common stock and one-fourth of one ENPC warrant (the “CAPS™ Separation”). As noted, the constituent ENPC Class A common stock was converted or canceled pursuant to the Business Combination Agreement and all ENPC warrants held by Holdco, including all of the ENPC private placement warrants were canceled. Following the ENPC Class F Conversion, the Sponsor Share Cancellation, the ENPC Class B Contribution and the

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CAPS™ Separation, each share of ENPC Class A common stock outstanding was automatically converted into one share of Granite Ridge common stock.

As a result, upon giving effect to the CAPS™ Separation, ENPC Class F Conversion, Sponsor Share Cancellation and ENPC Class B Contribution, the Sponsor’s total aggregate investment of $6.935 million (which amount represents the total risk capital contributed to ENPC by or on behalf of the Sponsor, including working capital loans that were forgiven) for 1,238,393 shares of Granite Ridge common stock held by Holdco and the former independent directors of ENPC following the Business Combination resulted in a per share purchase price of approximately $5.60 per share (assuming all 371,518 shares subject to vesting or forfeiture are fully vested) or approximately $8.00 per share (excluding all 371,518 shares subject to vesting or forfeiture).

In connection with the Business Combination, holders of 39,343,496 shares of ENPC Class A common stock, or 93.6% of the outstanding shares of ENPC Class A Common Stock, exercised their rights to have those shares redeemed for cash at a redemption price of approximately $10.07 per share, or an aggregate of approximately $396.1 million. The shares of Granite Ridge common stock being offered for resale pursuant to this prospectus by the Selling Securityholders represent approximately 96% of the outstanding shares of Granite Ridge common stock as of the date of this prospectus. Given the substantial number of shares of Granite Ridge common stock being registered for potential resale by Selling Securityholders pursuant to this prospectus, the sale of shares by the Selling Securityholders, or the perception in the market that the Selling Securityholders intend to sell shares, could increase the volatility of the market price of Granite Ridge common stock or result in a significant decline in the public trading price of Granite Ridge common stock. Even if our trading price is significantly below $10.00, the offering price for the CAPS™ offered in ENPC’s initial public offering, certain of the Selling Securityholders may still have an incentive to sell shares of Granite Ridge common stock because the purchase price or cost basis for the underlying securities were lower than the cost basis or purchase price for the public investors or the current trading price of Granite Ridge common stock (who may not experience a similar rate of return at the same trading price). For example, subject to the satisfaction of various conditions pursuant to the Sponsor Agreement and based on the closing price of Granite Ridge common stock of $9.13 as of January 9, 2023, Holdco and other holders of the Sponsor Shares could realize profits no higher than approximately $3.53 per share, or approximately $4.37 million in the aggregate (assuming, for simplicity, that all 371,518 shares subject to vesting or forfeiture are fully vested, but acknowledging fewer shares are likely to vest given a closing price of $9.13).

Pursuant to this prospectus, the Selling Securityholders are permitted to offer the securities from time to time, if and to the extent as they may determine, through public or private transactions or through other means described in the section of this prospectus entitled “Plan of Distribution” at prevailing market prices, at prices different than prevailing market prices or at privately negotiated prices. The Selling Securityholders may sell shares through agents they select or through underwriters and dealers they select. The Selling Securityholders also may sell their securities directly to investors. If the Selling Securityholders use agents, underwriters or dealers to sell their shares, we will name such agents, underwriters or dealers and describe any applicable commissions or discounts in a supplement to this prospectus if required.

We have agreed to bear all of the expenses incurred in connection with the registration of these securities. The Selling Securityholders will pay or assume underwriting fees, discounts and commissions or similar charges, if any, incurred in the sale of securities by them.

The Selling Securityholders identified in this prospectus may offer, sell or distribute all or a portion of the Granite Ridge common stock included under this prospectus (as applicable to each Selling Securityholder) in the section entitled “Selling Securityholders.” We will not receive any proceeds from the sale of securities by the Selling Securityholders. We will receive the proceeds from the exercise of any Granite Ridge warrants for cash. The exercise price of Granite Ridge warrants is $11.50 per warrant. We believe the likelihood that Granite Ridge warrant holders will exercise their Granite Ridge warrants, and therefore the amount of cash proceeds that we would receive, is dependent upon the trading price of Granite Ridge common stock. If the trading price for Granite Ridge common stock continues to be less than $11.50 per share, we believe holders of Granite Ridge warrants will be unlikely to exercise their warrants.

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required.

Granite Ridge common stock and Granite Ridge warrants are listed on the New York Stock Exchange under the symbols “GRNT” and “GRNT WS,” respectively. On January 9, 2023, the closing price of Granite Ridge common stock was $9.13 per share and the closing price of Granite Ridge warrants on January 9, 2023 was $1.09 per warrant.

We are an “emerging growth company” and a “smaller reporting company” as those terms are defined under applicable federal securities laws, and as such, are subject to certain reduced public company reporting requirements.

AN INVESTMENT IN OUR COMMON STOCK INVOLVES SIGNIFICANT RISKS. YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 15 OF THIS PROSPECTUS BEFORE YOU MAKE YOUR DECISION TO INVEST IN OUR COMMON STOCK.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is January 18, 2023

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	CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS					iii
	FREQUENTLY USED TERMS					v
	SUMMARY OF THE PROSPECTUS					1
	RISK FACTORS					15
	USE OF PROCEEDS					41
	UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION					44
	BUSINESS OF GRANITE RIDGE					55
	PROPERTIES OF GRANITE RIDGE					69
	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS					85
	MANAGEMENT					134
	EXECUTIVE COMPENSATION					141
	DESCRIPTION OF SECURITIES					148
	SELLING SECURITYHOLDERS					156
	BENEFICIAL OWNERSHIP OF SECURITIES					160
	CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS					163
	MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS					167
	PLAN OF DISTRIBUTION					173
	TRANSFER AGENT AND REGISTRAR					176
	LEGAL MATTERS					176
	EXPERTS					176
	WHERE YOU CAN FIND ADDITIONAL INFORMATION					176
	INDEX TO FINANCIAL STATEMENTS					F-1
	ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS					A-1
	ANNEX B: RESERVE REPORT OF FUND I AS OF DECEMBER 31, 2021					B-1
	ANNEX C: RESERVE REPORT OF FUND II AS OF DECEMBER 31, 2021					C-1
	ANNEX D: RESERVE REPORT OF FUND III AS OF DECEMBER 31, 2021					D-1

You should rely only on the information provided in this prospectus. Neither we nor the Selling Securityholders have authorized anyone to provide you with different information. Neither we nor the Selling Securityholders are making an offer of these securities in any jurisdiction where the offer is not permitted. You should not assume that the information in this prospectus is accurate as of any date other than the date hereof. Since the date of this prospectus, our business, financial condition, results of operations and prospects may have changed.

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement on Form S-1 that we filed with the Securities and Exchange Commission (the “SEC”) using the “shelf” registration process. Under this shelf registration process, the Selling Securityholders may, from time to time, sell the securities offered by them described in this prospectus. We will not receive any proceeds from the sale by such Selling Securityholders of the securities offered by them described in this prospectus. We may also use the shelf registration statement to issue 10,349,975 shares of our common stock, $0.0001 par value, that may be issued upon exercise of warrants to purchase common stock at an exercise price of $11.50 per share of common stock (the “Granite Ridge warrants”).

Neither we nor the Selling Securityholders have authorized anyone to provide you with any information or to make any representations other than those contained in this prospectus or any applicable prospectus

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supplement or any free writing prospectuses prepared by or on behalf of us or to which we have referred you. Neither we nor the Selling Securityholders take responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. Neither we nor the Selling Securityholders will make an offer to sell these securities in any jurisdiction where the offer or sale is not permitted.

We may also provide a prospectus supplement or post-effective amendment to the registration statement to add information to, or update or change information contained in, this prospectus. You should read both this prospectus and any applicable prospectus supplement or post-effective amendment to the registration statement together with the additional information to which we refer you in the sections of this prospectus entitled “Where You Can Find Additional Information.”

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements made in this prospectus are “forward looking statements.” Statements regarding our expectations regarding the business are “forward looking statements.” In addition, words such as “estimates,” “projected,” “expects,” “estimated,” “anticipates,” “forecasts,” “plans,” “intends,” “believes,” “seeks,” “may,” “will,” “would,” “future,” “propose,” “target,” “goal,” “objective,” “outlook” and variations of these words or similar expressions (or the negative versions of such words or expressions) are intended to identify forward-looking statements. These forward-looking statements are not guarantees of future performance, conditions or results, and involve a number of known and unknown risks, uncertainties, assumptions and other important factors, many of which are outside the control of the parties, that could cause actual results or outcomes to differ materially from those discussed in the forward-looking statements. Important factors, among others, that may affect actual results or outcomes include:

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

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Granite Ridge’s financial performance following the Business Combination;

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changes in Granite Ridge’s strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects and plans, or our ability to raise additional capital;

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changes in current or future commodity prices and interest rates;

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supply chain disruptions;

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infrastructure constraints and related factors affecting our properties;

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expansion plans and opportunities;

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

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changes in the markets in which Granite Ridge competes;

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

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cyber-related risks;

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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;

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

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

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acts of war or terrorism;

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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; and

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other risks and uncertainties set forth in the section entitled “Risk Factors” included elsewhere in this prospectus.

The forward-looking statements contained in this prospectus and in any document incorporated by reference herein are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, those factors described under the heading “Risk Factors.” Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We may

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face additional risks and uncertainties that are not presently known to us, or that we deem to be immaterial, which may also impair our business, financial condition or prospects. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.

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FREQUENTLY USED TERMS

Unless otherwise stated or unless the context otherwise requires, the terms “we,” “us,” “our,” “Granite Ridge” and “the Company” refer to Granite Ridge Resources, Inc., a Delaware corporation. Furthermore, in this prospectus:

“Business Combination” means the Transactions contemplated by the Business Combination Agreement and the related agreements.

“Business Combination Agreement” means the Business Combination Agreement, dated as of May 16, 2022, as amended, by and among ENPC, Granite Ridge, ENPC Merger Sub, GREP Merger Sub, and GREP.

“CAPS™” means the securities offered in ENPC’s initial public offering, which consisted of one share of Class A common stock and one-quarter of one ENPC warrant.

“closing” means the closing of the Transactions.

“Closing Date” means October 24, 2022, the date on which the Business Combination was consummated.

“Code” means the Internal Revenue Code of 1986, as amended and restated from time to time.

“Combined Company” means Granite Ridge and its consolidated subsidiaries after giving effect to the Business Combination.

“Credit Agreement” means that certain senior secured revolving credit agreement dated October 24, 2022 among the Company, as borrower, Texas Capital Bank, as administrative agent, and the lenders from time to time party thereto.

“DGCL” means the General Corporation Law of the State of Delaware.

“ENPC Class A common stock” means the Class A common stock, par value $0.0001 per share, of ENPC prior to the Business Combination.

“ENPC Class B common stock” means the Class B common stock, par value $0.0001 per share, of ENPC prior to the Business Combination.

“ENPC Class F common stock” means the Class F common stock, par value $0.0001 per share, of ENPC prior to the Business Combination.

“ENPC common stock” means the ENPC Class A common stock, ENPC Class B common stock and ENPC Class F common stock prior to the Business Combination.

“ENPC initial stockholders” or “initial holders” means the Sponsor and any other holders of Founder Shares prior to the ENPC IPO (or their permitted transferees).

“ENPC IPO” means the ENPC initial public offering, consummated on September 18, 2020, in which ENPC sold 41,400,000 CAPS™ at $10.00 per CAPS™ (after giving effect to the Forward Split).

“ENPC Merger” means the merger of ENPC Merger Sub with and into ENPC, with ENPC being the surviving corporation in the merger and a wholly-owned subsidiary of Granite Ridge.

“ENPC Merger Sub” means ENPC Merger Sub, a Delaware corporation.

“ENPC public shares” means, prior to the Business Combination, the 41,400,000 shares of ENPC Class A common stock underlying the CAPS™ issued in the ENPC IPO (after giving effect to the Forward Split).

“ENPC public stockholders” means, prior to the Business Combination, holders of ENPC public shares, including ENPC initial stockholders to the extent ENPC initial stockholders held ENPC public shares.

“ENPC Warrant Agreement” means the Warrant Agreement, dated September 15, 2020, as amended by Amendment No. 1 dated March 24, 2021, between ENPC and Continental Stock Transfer & Trust Company, as warrant agent.

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“ENPC warrants” means, prior to the Business Combination, ENPC’s warrants sold as part of the CAPS™ in the ENPC IPO (whether purchased in the ENPC IPO or thereafter in the open market) and as part of the private placement CAPS™.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Existing GREP Members” means the members of GREP as of the Closing Date.

“Forward Split” refers collectively to (i) the 2.5 for 1 forward stock split for each outstanding ENPC Class A common stock and ENPC Class B common stock, as effected by the first amendment to ENPC’s charter dated as of March 24, 2021, and (ii) the 2.5 for 1 forward warrant split for each outstanding ENPC Warrant, as effected by that certain Amendment No. 1 to Warrant Agreement, dated March 24, 2021, by and between ENPC and Continental Stock Transfer & Trust Company, a New York corporation.

“Founder Shares” means, prior to the Business Combination, the ENPC Class F common stock and the ENPC Class A common stock issued upon the automatic conversion thereof at the time of the Business Combination.

“Funds” or the “Grey Rock Funds” means, collectively, Fund I, Fund II and Fund III.

“Fund I” means Grey Rock Energy Fund, LP, a Delaware limited partnership.

“Fund II” means, collectively, Grey Rock Energy Fund II, L.P., Grey Rock Energy Fund II-B, LP, and Grey Rock Energy Fund II-B Holdings, L.P., each a Delaware limited partnership.

“Fund III” means, collectively, Grey Rock Energy Fund III-A, LP, Grey Rock Energy Fund III-B, LP, and Grey Rock Energy Fund III-B Holdings, LP, each a Delaware limited partnership.

“GAAP” means generally accepted accounting principles in the United States.

“Granite Ridge” means Granite Ridge Resources, Inc., a Delaware corporation.

“Granite Ridge Board” means the board of directors of Granite Ridge.

“Granite Ridge common stock” means the common stock, par value $0.0001 per share, of Granite Ridge.

“Granite Ridge Warrant Agreement” means the ENPC Warrant Agreement, as assigned and amended by the by that certain Assignment, Assumption and Amendment Agreement, dated October 24, 2022, by and among the Company, ENPC and Continental Stock Transfer & Trust Company.

“Granite Ridge warrants” means the ENPC warrants that were converted into warrants to purchase Granite Ridge common stock upon consummation of the Business Combination

“GREP” means GREP Holdings, LLC, a Delaware limited liability company.

“GREP Merger” means the merger of GREP Merger Sub with and into GREP with GREP being the surviving company in the merger and a wholly-owned subsidiary of Granite Ridge.

“GREP Merger Sub” means GREP Merger Sub, LLC, a Delaware limited liability company.

“Grey Rock” means Grey Rock Energy Management, LLC, a Delaware limited liability company.

“Holdco” means ENPC Holdings II, LLC, a Delaware limited liability company.

“Incentive Plan” means the Granite Ridge 2022 Omnibus Incentive Plan.

“IRS” means the U.S. Internal Revenue Service.

“Manager” means Grey Rock Administration, LLC, a Delaware limited liability company, or its permitted assignee.

“Mergers” means, collectively, the ENPC Merger and the GREP Merger.

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“MSA” means the Management Services Agreement, dated October 24, 2022 by and between Granite Ridge Resources, Inc. and Grey Rock Administration, LLC.

“NYSE” means the New York Stock Exchange.

“private placement” means the private sale of private placement CAPS™ that occurred simultaneously with the consummation of the ENPC IPO for total gross proceeds of $6,140,000.

“private placement CAPS™” means, prior to the Business Combination, the 614,000 CAPS™ purchased by the Sponsor in the private placement (after giving effect to the Forward Split), each consisting of one share of ENPC Class A common stock and one-quarter of one private placement warrant.

“private placement warrants” means, prior to the Business Combination, the 153,500 warrants underlying the private placement CAPS™ purchased by the Sponsor in the private placement (after giving effect to the Forward Split), each of which is exercisable for one share of ENPC Class A common stock in accordance with its terms.

“Securities Act” means the Securities Act of 1933, as amended.

“Selling Securityholders” means selling securityholders named in this prospectus and donees, transferees, assignees, successors, designees and others who later come to hold any of the Selling Securityholders’ interest in the Granite Ridge common stock other than through a public sale.

“Sponsor” means ENPC Holdings, LLC, a Delaware limited liability company.

“Sponsor Agreement” means that certain Sponsor Agreement, dated May 16, 2022, by and among Sponsor, Holdco, ENPC, Granite Ridge, GREP and certain other parties named therein.

“Sponsor Shares” means the 1,238,393 shares of Granite Ridge common stock offered for resale under this prospectus, of which 1,174,106 shares of Granite Ridge common stock were issued to Holdco and 64,287 shares of Granite Ridge common stock were issued to the former independent directors of ENPC in the Business Combination as merger consideration.

“Transactions” means, collectively, the Mergers, Business Combination and the other transactions contemplated by the Business Combination Agreement.

“Transfer Agent” means Continental Stock Transfer & Trust Company, a New York corporation.

“Treasury regulations” means the regulations promulgated by the U.S. Treasury Department under the Code.

“Trust Account” means the trust account into which the net proceeds of the ENPC IPO and the private placement were deposited for the benefit of the ENPC public stockholders and which held total assets of approximately $414.5 million prior to the Business Combination.

“Warrant Agreement Amendment and Assignment” means that certain Assignment, Assumption and Amendment Agreement, dated October 24, 2022, by and among the Company, ENPC and Continental Stock Transfer & Trust Company, which assigned the ENPC Warrant Agreement to the Company.

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SUMMARY OF THE PROSPECTUS

This summary highlights selected information from this prospectus and does not contain all of the information that is important to you in making an investment decision. You should read the entire prospectus carefully, including the information under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes to those financial statements appearing elsewhere in this prospectus.

Unless the context otherwise requires, with respect to descriptions of the financials and operations of the properties owned by Granite Ridge, references to “Granite Ridge”, the “Company”, “we”, “us”, or “our” relate to the assets contributed by GREP in the Business Combination, as owned or operated by the Funds prior to the Business Combination, and as owned or operated by Granite Ridge after the Business Combination.

This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in “Glossary of Oil and Natural Gas Terms” set forth in Annex A.

Business Overview

Granite Ridge holds strategic investments in non-operated working interests in diversified upstream oil and gas assets in North America. Granite Ridge primarily engages in oil and natural gas exploration and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include the Company’s acreage. As a non-operator, Granite Ridge has been able to diversify its investment exposure by participating in a large number of gross wells, as well as entering into additional project areas by partnering with numerous operating partners in core unconventional basins across the United States. Because Granite Ridge has generally been able to elect to participate on a well-by-well basis in any given well, Granite Ridge believes it has maintained increased flexibility in the timing and amount of its capital expenditures because it has not been burdened with various contractual arrangements with respect to minimum drilling obligations. Further, Granite Ridge has avoided exploratory and infrastructure costs incurred by many oil and gas producers.

Granite Ridge has achieved capital appreciation through its assets and provided income through investments, directly or indirectly, in non-operated working interests in diversified upstream oil and gas assets in North America, including by:

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purchasing working interests, net profits interests and options to acquire net profits interests in upstream oil and gas assets in multiple basins throughout the United States;

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participating in the development of assets alongside operators who have significant experience in developing and producing hydrocarbons in the Company’s core asset areas;

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generating income and capital appreciation via interests of the Company in oil and gas wells; and

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exiting investments at the appropriate time.

Granite Ridge will not receive any proceeds from the sale of Granite Ridge common stock to be offered by the Selling Securityholders pursuant to this prospectus.

Overview of the Assets of Granite Ridge

Granite Ridge currently holds interests in more than 2,000 wells in core areas of the Midland, Permian, Delaware, Bakken, Eagle Ford, and Haynesville plays (the “Properties”). Non-operated working interests constitute the central part of the Company’s investment strategy, but it has also made certain investments in minerals, operated working interests, and any other oil and gas assets that are incidental or ancillary to, preserve, protect, or enhance the Company’s assets, or are acquired as part of a package with, such non-operated working interests.

The Company’s assets are concentrated in the Eagle Ford, Permian, Bakken, Haynesville, and Denver-Julesberg basins. These basins consist primarily of oil plays, driving a higher concentration of oil production, with some exposure to dry gas in the Eagle Ford basin, in particular. The operators of the Company’s assets include basin-focused public E&P companies and large, experienced private companies.

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Corporate History and Business Combination

Granite Ridge Resources, Inc.

Granite Ridge is a Delaware corporation, formed on May 9, 2022 to consummate the Business Combination. Following the closing of the Business Combination, Granite Ridge operates and controls the business and assets previously controlled by the Funds.

Granite Ridge common stock and Granite Ridge warrants are currently listed on the New York Stock Exchange under the symbols “GRNT” and “GRNT WS,” respectively.

The mailing address of Granite Ridge’s principal executive office is 5217 McKinney Avenue, Suite 400, Dallas, Texas 75205, and its telephone number is (214) 396-2850. Granite Ridge’s website is www.graniteridge.com. Information contained on our website is not a part of this prospectus.

Business Combination

On October 24, 2022 (the “Closing Date”), Granite Ridge Resources, Inc., a Delaware corporation (“Granite Ridge” or the “Company”), and Executive Network Partnering Corporation, a Delaware corporation (“ENPC”) consummated the previously announced business combination pursuant to the terms of the Business Combination Agreement, dated as of May 16, 2022 (the “Business Combination Agreement”), by and among ENPC, Granite Ridge, ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub”), and GREP Holdings, LLC, a Delaware limited liability company (“GREP”).

Pursuant to the Business Combination Agreement, on the Closing Date, (i) ENPC Merger Sub merged with and into ENPC (the “ENPC Merger”), with ENPC surviving the ENPC Merger as a wholly-owned subsidiary of Granite Ridge and (ii) GREP Merger Sub merged with and into GREP (the “GREP Merger,” and together with the ENPC Merger, the “Mergers”), with GREP surviving the GREP Merger as a wholly-owned subsidiary of Granite Ridge (the transactions contemplated by the foregoing clauses (i) and (ii) the “Business Combination,” and together with the other transactions contemplated by the Business Combination Agreement, the “Transactions”).

At the special meeting of ENPC stockholders held in connection with the Business Combination, public stockholders of 39,343,496 shares of ENPC Class A common stock exercised their rights to have those shares redeemed for cash at a redemption price of approximately $10.07 per share, or an aggregate of approximately $396.1 million. The holders of membership interests in GREP (the “Existing GREP Members”) and their direct and indirect members were issued 130.0 million shares of Granite Ridge common stock at the closing. Upon consummation of the Business Combination, each public stockholder’s ENPC common stock and ENPC warrants were automatically converted into an equivalent number of shares of Granite Ridge common stock and Granite Ridge warrants as a result of the Transactions. At the effective time of the Mergers, (i) 495,357 shares of ENPC Class F common stock were converted to 1,238,393 shares of ENPC Class A common stock (of which 371,518 of those shares are, upon conversion to Granite Ridge common stock, subject to certain vesting and forfeiture provisions set forth in the Sponsor Agreement) and the remaining shares of ENPC Class F common stock outstanding were automatically cancelled for no consideration (the “ENPC Class F Conversion”) (ii) all other remaining shares of ENPC Class A common stock held by Holdco were automatically cancelled without any conversion, payment or distribution (the “Sponsor Share Cancellation”) and (iii) all shares of ENPC Class B common stock outstanding were deemed transferred to ENPC and surrendered and forfeited for no consideration (the “ENPC Class B Contribution”). Following the ENPC Class F Conversion, the Sponsor Share Cancellation, the ENPC Class B Contribution and the CAPSTM Separation, each share of ENPC Class A common stock outstanding was automatically converted into one share of Granite Ridge common stock. The aggregate consideration paid in the Transactions to the Existing GREP Members and their direct and indirect members consists of 130.0 million shares of Granite Ridge common stock.

Immediately after giving effect to the Transactions (including as a result of the redemptions described above), there were 133,294,897 shares of Granite Ridge common stock, and 10,349,975 Granite Ridge

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warrants issued and outstanding. Upon the closing, ENPC’s Class A common stock, CAPSTM and warrants ceased trading, and the Company’s shares of Granite Ridge common stock and Granite Ridge warrants began trading on the New York Stock Exchange under the symbols “GRNT” and “GRNT WS,” respectively. As of the closing, Existing GREP Members and their direct and indirect members beneficially owned approximately 97.5% of the Company’s outstanding shares of common stock and the former ENPC public stockholders, Holdco and the former independent directors of ENPC owned approximately 2.5% of the outstanding shares of Granite Ridge common stock.

As noted above, the per share redemption price of approximately $10.07 for holders of ENPC public shares of ENPC Class A common stock electing redemption was paid out of ENPC’s Trust Account, which had a balance immediately prior to the closing of approximately $416.8 million. Following the payment of redemptions, ENPC had approximately $20.7 million of available cash remaining. Of these funds, approximately $13.9 million was used to pay certain transaction expenses and approximately $6.8 million became available to Granite Ridge upon the consummation of the Business Combination.

The shares beneficially owned by the Existing GREP Members who are Selling Securityholders hereunder represent more than 89% of the total outstanding shares of Granite Ridge common stock and all of the shares that may be offered by the Selling Securityholders collectively represent more than 96% of the total outstanding shares of Granite Ridge common stock, and these holders will have the ability to sell or distribute all of their shares pursuant to the registration statement of which this prospectus forms a part so long as it is available for use. The sale of the securities being registered in this prospectus therefore could result in a significant decline in the public trading price of Granite Ridge common stock and potentially hinder our ability to raise capital at terms that are acceptable to us or at all.

Other Arrangements

Warrant Agreement Assignment, Assumption and Amendment

On the Closing Date of the Business Combination, the Company entered into the Assignment, Assumption and Amendment Agreement (the “Warrant Agreement Amendment and Assignment”), by and among the Company, ENPC and Continental Stock Transfer & Trust Company (“Continental”). The Warrant Agreement Amendment and Assignment assigned the existing Warrant Agreement, dated September 15, 2020, as amended on March 24, 2021 (“Amendment No. 1”), by and between ENPC and Continental (as amended, the “Existing Warrant Agreement”) to the Company, and the Company agreed to perform all applicable obligations under such agreement.

For more information about the Warrant Agreement Amendment and Assignment, see the section entitled “Certain Relationships and Related Party Transactions — Warrant Agreement Assignment, Assumption and Amendment.” The full text of the Warrant Agreement Amendment and Assignment is attached to this registration statement of which this prospectus forms a part.

Registration Rights and Lock-Up Agreement

On the Closing Date of the Business Combination, the Company entered into the Registration Rights and Lock-Up Agreement (the “RRA and Lock-Up Agreement”) with Granite Ridge, Holdco, Richard Boyce, Michael M. Calbert, Gisel Ruiz and the Existing GREP Members, with respect to the shares of Granite Ridge common stock issued as consideration under the Business Combination Agreement. The RRA and Lock-Up Agreement includes, among other things, the following provisions:

Registration Rights. Granite Ridge was required to file this resale shelf registration statement on behalf of certain Granite Ridge security holders promptly after the closing of the Business Combination to register shares of Granite Ridge common stock held by Holdco, Richard Boyce, Michael M. Calbert, Gisel Ruiz and the Existing GREP Members. The RRA and Lock-Up Agreement will also provide certain demand rights and piggyback rights to the Granite Ridge security holders, subject to certain specified underwriter cutbacks and issuer blackout periods. Granite Ridge shall bear all costs and expenses incurred in connection with this resale shelf registration statement, any demand registration statement, any underwritten takedown, any block trade, any piggyback registration statement and all

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expenses incurred in performing or complying with its other obligations under the RRA and Lock-Up Agreement, whether or not the registration statement becomes effective.

Lock-Up. Existing GREP Members will not be able to transfer any shares of Granite Ridge common stock beneficially owned or otherwise held by them for a period that is the earlier of (i) 180 days from the date of the closing of the Business Combination; (ii) the date on which the closing price of the Granite Ridge common stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and similar transactions) for any 20 trading days within any 30-trading day period or (iii) the date on which Granite Ridge completes a liquidation, merger, stock exchange or other similar transaction that results in all of Granite Ridge’s stockholders having the right to exchange their shares of Granite Ridge common stock for cash, securities or other property. In connection with and in order to facilitate the closing of the Business Combination, the Company waived the lock-up restrictions with respect to all shares that would have been issued to GREP Holdco I LLC at closing, 3,357,807 shares that would have been issued to GREP Holdco II LLC at closing and 4,967,367 shares that would have been issued to GREP Holdco II-B Holdings, LLC at closing. Subsequent to the closing, the Company waived the lock-up restrictions with respect to 9,507,742 shares of common stock owned by GREP Holdco II LLC and 14,050,471 shares of common stock owned by GREP Holdco II-B Holdings, LLC. As of the date hereof, 95,123,520 shares of Granite Ridge common stock will remain subject to these transfer restrictions.

Termination of Letter Agreement. In connection with the consummation of the Business Combination, the letter agreement, dated September 15, 2020, by and among ENPC, ENPC Holdings, LLC, a Delaware limited liability company (“Sponsor”), Holdco and the other parties thereto, was terminated at closing and Sponsor, Holdco and such parties will not be subject to contractual lock-up periods preventing them from transferring any shares of Granite Ridge common stock beneficially owned or otherwise held by them.

For more information about the RRA and Lock-Up Agreement, see the section entitled “Certain Relationships and Related Party Transactions — Registration Rights and Lock-Up Agreement.” The full text of the RRA and Lock-Up Agreement is attached to this registration statement of which this prospectus forms a part.

Management Services Agreement

On the Closing Date of the Business Combination, in connection with the consummation thereof, Grey Rock Administration, LLC, a Delaware limited liability company (“Manager”) indirectly owned by the four of the Company’s directors, Matthew Miller, Griffin Perry, Thaddeus Darden and Kirk Lazarine, entered into a Management Services Agreement with Granite Ridge (the “MSA”). Under the MSA, Manager will provide general management, administrative and operating services covering the oil and gas assets and other properties of Granite Ridge (the “Assets”) and the day-to-day business and affairs of Granite Ridge relating to the Assets. Granite Ridge shall pay Manager an annual services fee of $10 million and shall reimburse Manager for certain Granite Ridge group costs related to the operation of the Assets (including for third party costs allocated or attributable to the Assets). The initial term of the MSA expires on April 30, 2028; however, the MSA will automatically renew for additional consecutive one-year renewal terms until terminated in accordance with its terms. Upon any termination of the MSA, Manager shall provide transition services for a period of up to 90 days.

For more information about the MSA, see the section entitled “Certain Relationships and Related Party Transactions — Management Services Agreement.” The full text of the MSA is attached to this registration statement of which this prospectus forms a part.

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Granite Ridge Organizational Structure Following the Business Combination

The diagram below illustrates what the ownership of Granite Ridge looked like immediately following the closing of the Business Combination(1):

[MISSING IMAGE: tm2228428d1-fc_granitebwlr.jpg]

(1)

See diagrams above and “Frequently Used Terms” for the entities comprising the “Grey Rock Energy Funds” and “Existing GREP Members.” Shares shown as issued to Existing GREP Members includes shares issued to the direct and indirect members of the Existing GREP Members. Shares shown as issued to Holdco includes shares issued to the former independent directors of ENPC.

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SUMMARY HISTORICAL COMBINED FINANCIAL INFORMATION OF THE PREDECESSOR

The following table shows summary historical financial information of the Predecessor for the periods and as of the dates indicated because, as of the closing of the Business Combination, Granite Ridge deemed Fund III to be its “predecessor” for financial reporting purposes. The summary statement of operations for the three and nine months ended September 30, 2022 and 2021 and cash flow information for the nine months ended September 30, 2022 and 2021 of 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 Grey Rock Preferred Limited Partner III, L.P. (“Grey Rock Energy Fund III” or “Fund III”), as well as the balance sheet information as of September 30, 2022, are derived from the unaudited condensed combined financial statements of Grey Rock Energy Fund III included elsewhere in this prospectus. The summary statement of operations and of cash flow information of Fund III for the years ended December 31, 2021, 2020 and 2019, as well as the balance sheet information as of December 31, 2021 and 2020, are derived from the audited combined financial statements of Grey Rock Energy Fund III included elsewhere in this prospectus. The unaudited condensed combined financial statements were prepared on the same basis as the audited combined financial statements. In Grey Rock’s management’s opinion, such financial statements include all adjustments, consisting of normal recurring adjustments that Grey Rock’s management considers necessary for a fair presentation of the financial information for those periods.

The historical results of Fund III are not necessarily indicative of the results that may be expected in the future. You should read the following summary historical financial data together with the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Fund III (Predecessor)”, “Business of Granite Ridge” and the audited combined financial statements of Grey Rock Energy Fund III and related notes included elsewhere in this prospectus.

	Three Months Ended September 30,						Nine Months Ended September 30,						Year Ended December 31,
(in thousands)	2022			2021			2022			2021			2021			2020			2019
Statement of Operations Information:
Revenues
Oil, natural gas, and related product sales		$	90,194		$	55,717		$	263,263		$	142,632		$	197,546		$	28,290		$	23,283
Operating expenses
Lease operating expenses			6,368			3,621			15,840			8,407			12,362			5,147			2,669
Production taxes			5,053			2,506			14,628			7,737			10,808			1,815			1,369
Depletion and accretion expense			39,868			15,794			70,529			45,798			60,534			22,130			17,100
Professional fees			—			—			—			—			1,552			790			939
Management fees			—			—			—			—			3,878			3,878			3,878
General and administrative			1,776			1,764			4,880			4,978			832			498			144
Organizational expense			—			—			—			—			—			—			21
Total expenses			53,065			23,685			105,877			66,920			89,966			34,258			26,120
Net operating income (loss)			37,129			32,032			157,386			75,712			107,580			(5,968)			(2,837)
Other (expense) income
Gain (loss) on derivative contracts			6,082			(6,558)			(19,147)			(18,115)			(17,315)			2,928			137
Interest expense			(476)			(353)			(1,193)			(926)			(1,399)			(428)			(509)
Total other income (expense)			5,606			(6,911)			(20,340)			(19,041)			(18,714)			2,500			(372)
Net income (loss)		$	42,735		$	25,121		$	137,046		$	56,671		$	88,866		$	(3,468)		$	(3,209)

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	Nine Months Ended September 30,						Year Ended December 31,
	2022			2021			2021				2020			2019
Statement of Cash Flow Information;
Net cash provided by operating activities		$	179,662		$	91,900		$	131,715			$	14,085		$	8,670
Net cash used in investing activities			(150,655)			(124,786)			(194,014)				(80,868)			(83,707)
Net cash (used in) provided by financing activities			(29,916)			44,074			66,980	��			66,447			69,815

	As of September 30,			As of December 31,
	2022			2021			2020
Balance Sheet Information:
Cash		$	6,410		$	7,319		$	2,638
Property and equipment, net			381,861			278,391			172,481
Total assets			478,121			356,190			192,862
Credit facilities			—			29,938			9,897
Total partner’s capital			451,342			314,296			178,429

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SUMMARY HISTORICAL CONSOLIDATED FINANCIAL INFORMATION OF FUND I

The summary statement of operations and cash flow information of Grey Rock Energy Fund, LP and its subsidiaries (“Fund I”) for the nine months ended September 30, 2022 and 2021, as well as the balance sheet information as of September 30, 2022, are derived from the unaudited condensed consolidated financial statements of Grey Rock Energy Fund, LP included elsewhere in this prospectus. The summary statement of operations and of cash flow information of Fund I for the years ended December 31, 2021, 2020 and 2019, as well as the balance sheet information as of December 31, 2021 and 2020, are derived from the audited consolidated financial statements of Grey Rock Energy Fund, LP included elsewhere in this prospectus. The unaudited condensed consolidated financial statements were prepared on the same basis as the audited consolidated financial statements. In Grey Rock’s management’s opinion, such financial statements include all adjustments, consisting of normal recurring adjustments that Grey Rock’s management considers necessary for a fair presentation of the financial information for those periods.

The historical results of Fund I are not necessarily indicative of the results that may be expected in the future. You should read the following summary consolidated historical financial data together with the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Fund I”, “Business of Granite Ridge” and the audited consolidated financial statements of Grey Rock Energy Fund, LP and related notes included elsewhere in this prospectus.

	Nine Months Ended September 30,						Year Ended December 31,
(in thousands)	2022			2021			2021			2020			2019
Statement of Operations Information:
Revenues
Oil, natural gas, and related product sales		$	7,806		$	8,182		$	10,257		$	9,791		$	13,440
Operating expenses
Lease operating expenses			1,216			1,426			1,799			2,156			2,980
Production taxes			512			506			627			619			865
Depletion and accretion expense			1,611			2,533			3,038			9,837			7,262
Impairment expense			—			—			—			5,725			—
Professional fees			—			—			218			302			665
Management fees			—			—			—			585			700
General and administrative			158			360			171			383			202
Gain on disposal of oil and natural gas properties			—			(1,011)			(1,341)			(597)			(4,910)
Total expenses			3,497			3,814			4,512			19,010			7,764
Net operating income (loss)			4,309			4,368			5,745			(9,219)			5,676
Other (expense) income
(Loss) gain on derivative contracts			(576)			(1,832)			(1,842)			1,714			(1,371)
Interest expense			(22)			(116)			(138)			(245)			(665)
Total other (expense) income			(598)			(1,948)			(1,980)			1,469			(2,036)
Net income (loss)		$	3,711		$	2,420		$	3,765		$	(7,750)		$	3,640

	Nine Months Ended September 30,						Year Ended December 31,
	2022			2021			2021			2020			2019
Statement of Cash Flow Information:
Net cash provided by operating activities		$	3,977		$	4,544		$	5,473		$	8,152		$	6,426
Net cash (used in) provided by investing activities			(1,584)			19,454			21,280			(6,455)			8,154
Net cash used in financing activities			(1,100)			(24,300)			(27,300)			(2,500)			(13,241)

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	As of September 30,			As of December 31,
	2022			2021			2020
Balance Sheet Information:
Cash		$	2,033		$	740		$	1,287
Property and equipment, net			14,959			15,046			37,711
Total assets			19,687			16,999			40,784
Credit facilities			—			1,100			6,400
Total partner’s capital			18,685			14,974			33,209

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SUMMARY HISTORICAL COMBINED FINANCIAL INFORMATION OF FUND II

The summary statement of operations and cash flow information of Grey Rock Energy Fund II, LP 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. (“Grey Rock Energy Fund II” or “Fund II”) for the nine months ended September 30, 2022 and 2021, as well as the balance sheet information as of September 30, 2022, are derived from the unaudited condensed combined financial statements of Grey Rock Energy Fund II included elsewhere in this prospectus. The summary statement of operations and of cash flow information of Grey Rock Energy Fund II for the years ended December 31, 2021 and 2020, as well as the balance sheet information as of December 31, 2021 and 2020, are derived from the audited combined financial statements of Grey Rock Energy Fund II included elsewhere in this prospectus. The unaudited condensed combined financial statements were prepared on the same basis as the audited combined financial statements. In Grey Rock’s management’s opinion, such financial statements include all adjustments, consisting of normal recurring adjustments that Grey Rock’s management considers necessary for a fair presentation of the financial information for those periods.

The historical results of Fund II are not necessarily indicative of the results that may be expected in the future. You should read the following summary historical financial data together with the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Fund II”, “Business of Granite Ridge” and the audited combined financial statements of Grey Rock Energy Fund II and related notes included elsewhere in this prospectus.

	Nine Months Ended September 30,						Year Ended December 31,
(in thousands)	2022			2021			2021			2020
Statement of Operations Information:
Revenues
Oil, natural gas, and related product sales		$	110,013		$	59,822		$	82,391		$	49,017
Operating expenses
Lease operating expenses			13,662			8,122			13,128			13,760
Production taxes			5,171			4,505			5,675			3,564
Depletion and accretion expense			26,038			24,109			31,090			47,980
Professional fees			—			—			541			992
Management fees			—			—			2,315			2,185
General and administrative			2,709			2,904			672			495
Gain on disposal of oil and natural gas properties			—			(955)			(938)			(51)
Total expenses			47,580			38,685			52,483			68,925
Net operating income (loss)			62,433			21,137			29,908			(19,908)
Other (expense) income
(Loss) gain on derivative contracts			(11,064)			(13,713)			(13,232)			8,363
Interest expense			(489)			(611)			(848)			(1,167)
Total other (expense) income			(11,553)			(14,324)			(14,080)			7,196
Net income (loss)		$	50,880		$	6,813		$	15,828		$	(12,712)

	Nine Months Ended September 30,						Year Ended December 31,
	2022			2021			2021			2020
Statement of Cash Flow Information:
Net cash provided by operating activities		$	67,718		$	34,209		$	43,990		$	44,569
Net cash used in investing activities			(22,824)			(11,344)			(13,288)			(29,420)
Net cash used in financing activities			(20,000)			(22,084)			(31,191)			(11,876)

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	As of September 30,			As of December 31,
	2022			2021			2020
Balance Sheet Information:
Cash		$	28,688		$	3,794		$	4,283
Property and equipment, net			151,240			155,336			173,600
Total assets			204,410			173,541			186,897
Credit facilities			—			20,000			22,093
Total partners’ capital			196,541			145,661			158,918

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THE OFFERING

Issuer

Granite Ridge Resources, Inc.

Issuance of Granite Ridge Common Stock

Granite Ridge common stock to be issued upon exercise of all Granite Ridge Warrants

10,349,975

Resale of Granite Ridge Common Stock

Granite Ridge common stock offered by the Selling Securityholders

Up to 128,233,953 shares of Granite Ridge common stock owned by the Selling Securityholders.

Granite Ridge common issued and outstanding after the consummation of this offering (assuming exercise of all Granite Ridge warrants)

143,620,452 shares of Granite Ridge common stock.

Use of Proceeds

We could potentially receive up to an aggregate of approximately $119.0 million from the exercise of all Granite Ridge warrants. We believe the likelihood that Granite Ridge warrant holders will exercise their Granite Ridge warrants, and therefore the amount of cash proceeds that we would receive, is dependent upon the trading price of Granite Ridge common stock. If the trading price for Granite Ridge common stock continues to be less than $11.50 per share, we believe holders of Granite Ridge warrants will be unlikely to exercise their warrants. See the section entitled “Use of Proceeds.”

We will not receive any of the proceeds from the sale of the shares of Granite Ridge common stock by the Selling Securityholders.

Listing and trading symbol

Granite Ridge common stock is currently listed on the New York Stock Exchange under the symbol “GRNT.” Granite Ridge warrants are currently listed on the New York Stock Exchange under the symbol “GRNT WS”.

Risk Factors

Any investment in the securities offered hereby is speculative and involves a high degree of risk. You should carefully consider the information set forth under “Risk Factors” and elsewhere in this prospectus.

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SUMMARY OF RISK FACTORS

Summary of Risk Factors

Granite Ridge’s business and operations are subject to a number of risks and uncertainties, including those highlighted in the section entitled “Risk Factors” immediately following this summary. Some of these principal risks include the following:

Risks Related to Granite Ridge’s Business and Operations

•

As a non-operator, Granite Ridge’s development of successful operations relies extensively on third parties.

•

Oil and natural gas prices are volatile. Extended declines in such prices have adversely affected, and could in the future adversely affect, Granite Ridge’s business and results of operations. Geopolitical factors, including actions by OPEC and hostilities between Russia and Ukraine, as well as economic conditions, including economic downturn or recession may impact oil and natural gas prices.

•

Granite Ridge’s estimated reserves are based on many assumptions that may prove to be inaccurate.

•

Granite Ridge’s future success depends on its ability to replace reserves that its operators produce.

•

Certain of Granite Ridge’s undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established, operations are commenced or the leases are extended.

•

Deficiencies of title to Granite Ridge’s leased interests could significantly affect its financial condition.

•

Inflation could adversely impact Granite Ridge’s ability to control its costs, including its operating partners.

•

The COVID-19 pandemic has had, and may continue to have, a material adverse effect on Granite Ridge’s financial condition and results of operations.

•

Various laws and regulations govern aspects of the oil and gas business including natural resource conservation and environmental, health, and safety matters, and these laws and regulations could change and become stricter over time.

•

Fuel and energy conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.

•

Increased attention to environmental, social and governance matters may impact Granite Ridge’s business.

•

Following the Business Combination, Granite Ridge relies on the Manager for various certain key services under the MSA.

•

The relative lack of public company experience by Granite Ridge’s management team may put Granite Ridge at a competitive disadvantage.

Risks Related to Ownership of Granite Ridge Common Stock

•

Sales by the Selling Securityholders or issuances by the Company, or the perception that such sales or issuances may occur may cause the market price of Granite Ridge common stock to drop.

•

The exercise of the Granite Ridge warrants could adversely affect the market price of Granite Ridge common stock and result in dilution to holders of Granite Ridge common stock.

•

The Granite Ridge warrants may never be in the money, and they may expire worthless.

•

Granite Ridge qualifies as an “emerging growth company”, which could make its securities less attractive.

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•

If the Business Combination’s benefits do not meet the expectations of financial analysts, the market price of Granite Ridge common stock may decline.

•

Anti-takeover provisions in the Granite Ridge organizational documents could delay or prevent a change of control.

•

Granite Ridge is a “controlled company” under the corporate governance rules of the NYSE.

•

Granite Ridge could be adversely affected by changes in applicable tax laws, regulations, or administrative interpretations thereof in the United States or other jurisdictions.

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RISK FACTORS

The following risk factors apply to our business and operations. These risk factors are not exhaustive, and investors are encouraged to perform their own investigation with respect to our business, financial condition and prospects. You should carefully consider the following risk factors in addition to the other information included in this prospectus, including matters addressed in the section entitled “Cautionary Note Regarding Forward-Looking Statements” and the financial statements and notes to the financial statements included herein. We may face additional risks and uncertainties that are not presently known to us, or that we currently deem immaterial, which may also impair our business or financial condition. The following discussion should be read in conjunction with the financial statements and notes to the financial statements included herein. As used in the risks described in this subsection, references to “we,” “us” and “our” are intended to refer to Granite Ridge, unless the context clearly indicates otherwise.

Risks Related to Granite Ridge’s Business and Operations

As a non-operator, Granite Ridge’s development of successful operations relies extensively on third parties, which could have a material adverse effect on Granite Ridge’s results of operation.

Granite Ridge has only participated in wells operated by third parties. The success of Granite Ridge’s business operations depends on the timing of drilling activities and success of Granite Ridge’s third-party operators. If Granite Ridge’s operators are not successful in the development, exploitation, production, and exploration activities relating to Granite Ridge’s leasehold interests, or are unable or unwilling to perform, Granite Ridge’s financial condition and results of operation would be materially adversely affected.

Granite Ridge’s operators will make decisions in connection with their operations (subject to their contractual and legal obligations to other owners of working interests), which may not be in Granite Ridge’s best interests. The Company may have no ability to exercise influence over the operational decisions of its operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on third-party operators could prevent Granite Ridge from realizing target returns for those locations. The success and timing of development activities by Granite Ridge’s operators will depend on a number of factors that will largely be outside of the Company’s control, including oil and natural gas prices and other factors generally affecting the industry operating environment; the timing and amount of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of technology; and the rate of production of reserves, if any.

These risks are heightened in a low commodity price environment, which may present significant challenges to Granite Ridge’s operators. The challenges and risks faced by Granite Ridge’s operators may be similar to or greater than Granite Ridge’s own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital. Commodity prices and/or other conditions have in the past and may in the future cause oil and gas operators to file for bankruptcy. The insolvency of an operator of any of the Properties, the failure of an operator of any of the Properties to adequately perform operations or an operator’s breach of applicable agreements could reduce Granite Ridge’s production and revenue and result in Granite Ridge’s liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner. Finally, an operator of the Properties may have the right, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, to require Granite Ridge to pay its proportionate share of the defaulting party’s share of costs.

The inability of one or more of Granite Ridge’s operating partners to meet their obligations to Granite Ridge may adversely affect Granite Ridge’s financial results.

Granite Ridge’s exposures to credit risk, in part, are through receivables resulting from the sale of Granite Ridge’s oil and natural gas production, which operating partners market on Granite Ridge’s behalf to energy marketing companies, refineries, and their affiliates. Granite Ridge is subject to credit risk due to the relative concentration of Granite Ridge’s oil and natural gas receivables with a limited number of operating partners. This may impact Granite Ridge’s overall credit risk since these entities may be similarly affected by changes in economic and other conditions. A low commodity price environment may strain Granite

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Ridge’s operating partners, which could heighten this risk. The inability or failure of Granite Ridge’s operating partners to meet their obligations to Granite Ridge or their insolvency or liquidation may adversely affect Granite Ridge’s financial results.

Granite Ridge’s business depends on third-party transportation and processing facilities and other assets that are owned by third parties.

The marketability of Granite Ridge’s oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, adverse weather events or natural disasters, equipment malfunctions or failures, scheduled or unscheduled maintenance, legal or other reasons, could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells, or the delay or discontinuance of development plans for the Properties. In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, Granite Ridge’s wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, Granite Ridge may rely on third-party oil trucking to transport a significant portion of Granite Ridge’s production to third-party transportation pipelines, rail loading facilities, and other market access points.

In addition, the third parties on whom operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting business on the Properties. Further, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development and increased regulation of pipelines by PHMSA, and therefore less capacity to transport Granite Ridge’s products by pipeline. Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce Granite Ridge’s operating partners’ ability to market oil production and have an adverse effect on Granite Ridge. Operators’ access to transportation options and the prices they receive can also be affected by federal and state regulation — including regulation of oil production, transportation, and pipeline safety — as well by general economic conditions and changes in supply and demand.

The loss of a key member of the Manager’s management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise Granite Ridge relies, could diminish the Company’s ability to conduct its operations and harm its ability to execute its business plan.

Granite Ridge relies on continued contributions of the members of the Manager’s management team by virtue of its reliance on the MSA. Granite Ridge’s success depends heavily upon the continued contributions of those members of the Manager’s management team whose knowledge, relationships with industry participants, leadership, and technical expertise would be difficult to replace. In particular, Granite Ridge’s ability to successfully acquire additional properties, to increase its reserves, to participate in drilling opportunities, and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, Granite Ridge’s ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on the Manager’s management team’s knowledge and expertise in the industry. To continue to develop its business, Granite Ridge relies on the Manager’s management team’s knowledge and expertise in the industry and will use the Manager’s management team’s relationships with industry participants to enter into strategic relationships. The members of the Manager’s management team may terminate their employment with the Manager at any time. If the Manager were to lose key members of its management team, neither the Manager nor Granite Ridge may be able to replace the knowledge or relationships that they possess, and the Company’s ability to execute its business plan could be materially harmed. As a result, Granite Ridge’s operations and financial condition could suffer.

Oil and natural gas prices are volatile. Extended declines in such prices have adversely affected, and could in the future adversely affect, Granite Ridge’s business, financial position, results of operations and cash flow.

The oil and natural gas markets are very volatile, and the Company cannot predict future oil and natural gas prices. Oil and natural gas prices have fluctuated significantly, including periods of rapid and

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material decline, in recent years. The prices Granite Ridge receives for the oil and natural gas production associated with its working interests heavily influence Granite Ridge’s production, revenue, cash flows, profitability, reserve bookings and access to capital. Although Granite Ridge seeks to mitigate volatility and potential declines in commodity prices through derivative arrangements that hedge a portion of the expected production associated with Granite Ridge’s working interests, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks.

The prices Granite Ridge receives for the production and the levels of the production associated with its working interests depend on numerous factors beyond the Company’s control. These factors include, but are not limited to, the following:

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changes in global supply and demand for oil and natural gas;

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the actions of OPEC and other major oil producing countries;

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worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics (such as the global COVID-19 coronavirus outbreak);

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the price and quantity of imports of foreign oil and natural gas;

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political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity, particularly those in the Middle East, Russia, South America and Africa;

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the outbreak or escalation of military hostilities, including between Russia and Ukraine, and the potential destabilizing effect such conflicts may pose for the European continent or the global oil and natural gas markets;

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the level of global oil and natural gas exploration, production activity and inventories;

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changes in U.S. energy policy;

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weather conditions and outbreak of disease;

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technological advances affecting energy consumption;

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domestic and foreign governmental taxes, tariffs and/or regulations;

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proximity and capacity of processing, gathering, storage, oil and natural gas pipelines and other transportation facilities;

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the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and

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the price and availability of alternative fuels.

These factors and the volatility of the energy markets make it extremely difficult to predict oil and natural gas prices. A substantial or extended decline in oil or natural gas prices, such as the significant and rapid decline that occurred in 2020, has resulted in and could result in future impairments of Granite Ridge’s proved oil and natural gas properties and may materially and adversely affect Granite Ridge’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent commodity prices received from production are insufficient to fund planned capital expenditures, Granite Ridge may be required to reduce spending or borrow or issue additional equity to cover any such shortfall. Lower oil and natural gas prices may limit Granite Ridge’s ability to comply with the covenants under any credit facilities (or other debt instruments) and/or limit Granite Ridge’s ability to access borrowing availability thereunder, which is dependent on many factors including the value of Granite Ridge’s proved reserves.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect Granite Ridge’s financial condition or results of operations.

Granite Ridge’s operating partners’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be

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commercially viable. In addition, drilling and producing operations on Granite Ridge’s acreage may be curtailed, delayed, or canceled by the operators of the Properties as a result of other factors, including:

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declines in oil or natural gas prices, as occurred in 2020 in connection with the COVID-19 pandemic;

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infrastructure limitations, such as gas gathering and processing constraints;

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the high cost, shortages or delays of equipment, materials and services;

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unexpected operational events, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents;

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title problems;

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pipe or cement failures and casing collapses;

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lost or damaged oilfield development and service tools;

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compliance with environmental, health, safety and other governmental requirements;

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increases in severance taxes;

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regulations, restrictions, moratoria and bans on hydraulic fracturing;

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unusual or unexpected geological formations, and pressure or irregularities in formations;

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loss of drilling fluid circulation;

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environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;

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fires, blowouts, craterings and explosions;

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uncontrollable flows of oil, natural gas or well fluids; and

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pipeline capacity curtailments.

In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells, regulatory penalties and third party claims. Granite Ridge ordinarily maintains insurance against various losses and liabilities arising from its operations; however, insurance against all operational risks is not available to Granite Ridge. Additionally, Granite Ridge may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on Granite Ridge’s business activities, financial condition and results of operations.

Certain of Granite Ridge’s undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established or operations are commenced on units containing the acreage or the leases are extended.

A portion of Granite Ridge’s acreage is not currently held by production or held by operations. Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If Granite Ridge’s leases expire and it is unable to renew the leases, Granite Ridge will lose its right to participate in the development of the related Properties. Drilling plans for these areas are generally in the discretion of third-party operators and are subject to change based on various factors that are beyond the Company’s control, such as: the availability and cost of capital, equipment, services and personnel; seasonal conditions; regulatory and third-party approvals; oil and natural gas prices; results of title work; gathering system and other transportation constraints; drilling costs and results; and production costs. As of December 31, 2021, the Company estimates that the Funds, and following the Business Combination, Granite Ridge, had leases that were not developed that represented 504 net acres potentially expiring in 2022, 1,543 net acres potentially expiring in 2023, 3,040 net acres potentially expiring in 2024, and 0 net acres potentially expiring in 2025 and beyond.

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Granite Ridge could experience periods of higher costs as activity levels fluctuate or if commodity prices rise. These increases could reduce Granite Ridge’s profitability, cash flow, and ability to complete development activities as planned.

An increase in commodity prices or other factors could result in increased development activity and investment in Granite Ridge’s areas of operations, which may increase competition for and cost of equipment, labor and supplies. Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict Granite Ridge’s operating partners’ ability to conduct desired or expected operations. In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing commodity prices as producers seek to increase production in order to capitalize on higher commodity prices. In situations where cost inflation exceeds commodity price inflation, Granite Ridge’s profitability and cash flow, and Granite Ridge’s operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in the drilling of new wells or significant increase in drilling costs could reduce Granite Ridge’s revenues and cash flows.

New technologies may cause the current exploration and drilling methods of Granite Ridge’s operating partners to become obsolete, and such operators may not be able to keep pace with technological developments in the oil and gas industry.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, Granite Ridge may be placed at a competitive disadvantage, and competitive pressures may force Granite Ridge’s operating partners to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before Granite Ridge or its operating partners can. Granite Ridge cannot be certain that it or its operators will be able to implement technologies on a timely basis or at a cost that is acceptable to Granite Ridge. If Granite Ridge’s operators are unable to maintain technological advancements consistent with industry standards, Granite Ridge’s business, results of operations and financial condition may be materially adversely affected.

Due to previous declines in oil and natural gas prices, the Funds have in the past taken writedowns of the properties that constitute Granite Ridge’s oil and natural gas properties. Granite Ridge may be required to record further writedowns of its oil and natural gas properties in the future.

In 2020, the Funds were required to write down the carrying value of certain of the properties that constitute Granite Ridge’s oil and natural gas properties, and further writedowns could be required by Granite Ridge in the future. Under the successful efforts method of accounting, capitalized costs related to proved oil properties, including wells and related support equipment and facilities, are evaluated for impairment on an annual basis. If undiscounted cash flows are insufficient to recover the net capitalized costs, an impairment charge for the difference between the net capitalized cost of proved properties and their estimated fair values is recognized. A substantial or extended decline in oil or natural gas prices, could result in future impairments of Granite Ridge’s proved oil and natural gas properties.

Granite Ridge’s estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of Granite Ridge’s reserves.

Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty. No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating, exploration and development costs. Some of Granite Ridge’s reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.

Granite Ridge routinely makes estimates of oil and natural gas reserves in connection with managing its business and preparing reports to its lenders and investors, including estimates prepared by the Company’s

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independent reserve engineering firm. Although the reserve information contained herein is reviewed by the Company’s independent reserve engineers, estimates of crude oil and natural gas reserves are inherently imprecise. The process also requires economic assumptions about matters such as oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of Granite Ridge’s estimated reserves relies in part on the ability of the Manager’s reserve engineers to make accurate assumptions. Any significant variance from these assumptions by actual figures could greatly affect Granite Ridge’s estimated reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which Granite Ridge’s estimated reserves are based result in the actual quantities of oil and natural gas Granite Ridge’s operating partners ultimately recover being different from Granite Ridge’s estimated reserves. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this prospectus, subsequent reports Granite Ridge files with the SEC or other company materials.

The present value of future net cash flows from Granite Ridge’s proved reserves is not necessarily the same as the current market value of Granite Ridge’s estimated proved reserves.

The Company bases the estimated discounted future net cash flows from its proved reserves using specified pricing and cost assumptions. However, actual future net cash flows from Granite Ridge’s oil and natural gas properties will be affected by factors such as the volume, pricing and duration of Granite Ridge’s oil and natural gas hedging contracts; actual prices Granite Ridge receives for oil and natural gas; Granite Ridge’s actual operating costs in producing oil and natural gas; the amount and timing of Granite Ridge’s capital expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation. In addition, the 10% discount factor Granite Ridge uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with Granite Ridge or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of Granite Ridge’s reserves, which could adversely affect its business, results of operations and financial condition.

Granite Ridge’s future success depends on its ability to replace reserves that Granite Ridge’s operators produce.

Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, Granite Ridge’s future success depends upon its ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that Granite Ridge acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, Granite Ridge’s proved reserves will decline as Granite Ridge’s reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon Granite Ridge’s level of success in acquiring or finding additional reserves that are economically recoverable. Granite Ridge cannot assure you that it will be able to find or acquire and develop additional reserves at an acceptable cost.

Granite Ridge may acquire significant amounts of unproved property to further its development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. Granite Ridge seeks to acquire both proved and producing properties as well as undeveloped acreage that it believes will enhance growth potential and increase Granite Ridge’s earnings over time. However, Granite Ridge cannot assure you that all of these properties will contain economically viable reserves or that it will not abandon its initial investments. Additionally, the Company cannot assure you that unproved reserves or undeveloped acreage that it acquires will be profitably developed, that new wells drilled on the Properties will be productive or that the Company will recover all or any portion of its investments in the Properties and its reserves.

Extreme weather conditions could adversely affect operators’ ability to conduct drilling activities in some of the areas where the Properties are located.

Drilling and producing activities and other operations in some of Granite Ridge’s operating areas could be adversely affected by extreme weather conditions, such as floods, lightning, drought, ice and other

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storms, prolonged freeze events, and tornadoes, which may cause a loss of production from temporary cessation of activity, or lost or damaged facilities and equipment on the part of Granite Ridge’s operating partners. Such extreme weather conditions could also impact other areas of operations for Granite Ridge’s operating partners, including access to drilling and production facilities for routine operations, maintenance and repairs and the availability of, and access to, necessary third-party services, such as electrical power, water, gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt operations on the affected Properties and materially increase operation and capital costs, which could have a material adverse effect on Granite Ridge’s business, financial condition and results of operations.

The development of Granite Ridge’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than it currently anticipates. Therefore, Granite Ridge’s undeveloped reserves may not be ultimately developed or produced.

Approximately 53% of Granite Ridge’s estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2021. Development of these reserves may take longer and require higher levels of capital expenditures than the Company currently anticipates. Delays in the development of Granite Ridge’s reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of its estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause Granite Ridge to have to reclassify its proved reserves as unproved reserves.

The Company’s acquisition strategy will subject it to certain risks associated with the inherent uncertainty in evaluating properties for which the Company has limited information.

The Company intends to continue to expand its operations in part through acquisitions. The Company’s decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, Granite Ridge’s reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit the Company to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an inspection is undertaken. Any acquisition involves other potential risks, including, among other things:

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the validity of Granite Ridge’s assumptions about reserves, future production, revenues and costs;

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a decrease in Granite Ridge’s liquidity by using a significant portion of its cash from operations or borrowing capacity to finance acquisitions;

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a significant increase in Granite Ridge’s interest expense or financial leverage if it incurs additional debt to finance acquisitions;

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the ultimate value of any contingent consideration agreed to be paid in an acquisition;

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the assumption of unknown liabilities, losses or costs for which Granite Ridge is not indemnified or for which its indemnity is inadequate;

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“geological risk,” which refers to the risk that hydrocarbons may not be present or, if present, may not be recoverable economically;

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an inability to hire, train or retain qualified personnel to manage and operate Granite Ridge’s growing business and assets; and

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an increase in Granite Ridge’s costs or a decrease in its revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.

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Granite Ridge may also acquire multiple assets in a single transaction. Portfolio acquisitions via joint-venture or other structures are more complex and expensive than single project acquisitions, and the risk that a multiple-project acquisition will not close may be greater than in a single-project acquisition. An acquisition of a portfolio of projects may result in Granite Ridge’s ownership of projects in geographically dispersed markets which place additional demands on Granite Ridge’s ability to manage such operations. A seller may require that a group of projects be purchased as a package, even though one or more of the projects in the portfolio does not meet Granite Ridge’s investment criteria. In such cases, Granite Ridge may attempt to make a joint bid with another buyer, and such other buyer may default on its obligations.

Further, Granite Ridge may acquire properties subject to known or unknown liabilities and with limited or no recourse to the former owners or operators. As a result, if liability were asserted against Granite Ridge based upon such properties, Granite Ridge may have to pay substantial sums to dispute or remedy the matter, which could adversely affect Granite Ridge’s cash flow. Unknown liabilities with respect to assets acquired could include, for example: liabilities for clean-up of undiscovered or undisclosed environmental contamination; claims by developers, site owners, vendors or other persons relating to the asset or project site; liabilities incurred in the ordinary course of business; and claims for indemnification by general partners, directors, officers and others indemnified by the former owners of the asset or project sites.

Granite Ridge may not be able to successfully integrate future acquisitions or realize all of the anticipated benefits from its future acquisitions, and Granite Ridge’s future results will suffer if it does not effectively manage its expanded operations.

Granite Ridge’s growth strategy will, in part, rely on acquisitions. The Company has to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in its evolving market. Granite Ridge’s future success will depend, in part, upon its ability to manage this expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and basins and associated increased costs and complexity. Granite Ridge may also face increased scrutiny from governmental authorities as a result of increases in the size of its business. There can be no assurances that Granite Ridge will be successful or that it will realize the expected benefits currently anticipated from its acquisitions. In addition, the process of integrating Granite Ridge’s operations could cause an interruption of, or loss of momentum in, the activities of Granite Ridge’s business. Members of the Company’s and the Manager’s management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage Granite Ridge’s business. If management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, Granite Ridge’s business could suffer.

Deficiencies of title to Granite Ridge’s leased interests could significantly affect Granite Ridge’s financial condition.

Prior to drilling an oil or natural gas well, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination. Any one or more of the foregoing could require Granite Ridge to reverse revenues previously recognized and potentially negatively affect Granite Ridge’s cash flows and results of operations. While Granite Ridge typically conducts title examination prior to its acquisition of oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, any failure to obtain perfect title to Granite Ridge’s leaseholds may adversely affect its current production and reserves and its ability in the future to increase production and reserves.

Granite Ridge’s derivatives activities could adversely affect its cash flow, results of operations and financial condition.

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Granite Ridge’s expected production, which may include swaps, collars, puts and other structures. In accordance with applicable accounting principles, Granite Ridge is required to record its derivatives at fair market value, and they are included on Granite Ridge’s balance sheet as assets or liabilities and in Granite Ridge’s statements of income as gain (loss) on derivatives, net. Accordingly, Granite Ridge’s earnings may fluctuate significantly as a result of changes in the fair market value of its derivative instruments. In addition, while intended to mitigate the effects of volatile oil and natural gas prices, Granite Ridge’s derivatives transactions may limit its potential gains and increase its potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.

Granite Ridge’s actual future production may be significantly higher or lower than it estimates at the time it enters into derivative contracts for such period. If the actual amount of production is higher than the Company estimates, it will have greater commodity price exposure than it intended. If the actual amount of production is lower than the notional amount that is subject to Granite Ridge’s derivative financial instruments, Granite Ridge might be forced to satisfy all or a portion of its derivative transactions without the benefit of the cash flow from its sale of the underlying physical commodity, resulting in a substantial diminution of Granite Ridge’s liquidity. As a result of these factors, Granite Ridge’s hedging activities may not be as effective as it intends in reducing the volatility of Granite Ridge’s cash flows, and in certain circumstances may actually increase the volatility of Granite Ridge’s cash flows. In addition, such transactions may expose Granite Ridge to the risk of loss in certain circumstances, including instances in which a counterparty to its derivative contracts is unable to satisfy its obligations under the contracts; Granite Ridge’s production is less than expected; or there is a widening of price differentials between delivery points for Granite Ridge’s production and the delivery point assumed in the derivative arrangement.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

Granite Ridge may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that its operators use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” Granite Ridge accrues a liability for decommissioning costs associated with its wells, but have not established any cash reserve account for these potential costs in respect of any of the Properties. If decommissioning is required before economic depletion of the Properties or if the Company’s estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, it may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair Granite Ridge’s ability to focus capital investment in other areas of its business.

Granite Ridge is not insured against all of the operating risks to which its business is exposed.

In accordance with industry practice, Granite Ridge maintains insurance against some, but not all, of the operating risks to which its business is exposed. Granite Ridge insures some, but not all, of the Properties from operational loss-related events. Granite Ridge has insurance policies that include coverage for general liability, operational control of well, oil pollution, workers’ compensation and employers’ liability and other coverage. Granite Ridge’s insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, Granite Ridge’s insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect it against liability from all potential consequences, damages or losses.

Granite Ridge may be liable for damages from an event relating to a project in which Granite Ridge owns a non-operating working interest. Such events may also cause a significant interruption to Granite Ridge’s business, which might also severely impact Granite Ridge’s financial position. Granite Ridge may experience production interruptions for which it does not have production interruption insurance.

Granite Ridge intends to reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for Granite Ridge’s industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that the Company believes are economically acceptable. No assurance can be given that Granite Ridge will be able to maintain insurance in the future at rates that it considers reasonable, and it may elect

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to maintain minimal or no insurance coverage. Granite Ridge may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause Granite Ridge to restrict its operations, which might severely impact its financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on Granite Ridge’s financial condition and results of operations.

Granite Ridge conducts business in a highly competitive industry.

The oil and natural gas industry is highly competitive. The key areas in respect of which Granite Ridge faces competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by Granite Ridge’s operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.

Competition in Granite Ridge’s markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities.

Granite Ridge’s competitors also include entities with greater technical, physical and financial resources. Finally, companies and certain private equity firms not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect Granite Ridge’s business. If Granite Ridge is unsuccessful in competing against other companies, its business, results of operations, financial condition or prospects could be materially adversely affected.

The ongoing military conflict between Ukraine and Russia has caused unstable market and economic conditions and is expected to have additional global consequences, such as heightened risks of cyberattacks. Granite Ridge’s business, financial condition, and results of operations may be materially adversely affected by the negative global and economic impact resulting from the conflict in Ukraine or any other geopolitical tensions.

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 large-scale military invasion of Ukraine by Russian troops was reported. Although the length and impact of the ongoing military conflict is highly unpredictable, the conflict in Ukraine has led and could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in credit and capital markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increase in cyberattacks and espionage. 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 agreement to remove certain Russian financial institutions from the Society for Worldwide Interbank Financial Telecommunication (“SWIFT”) payment system, expansive bans on imports and exports of products to and from Russia (including imports of Russian oil, liquefied natural gas and coal) and a ban on exportation of U.S denominated banknotes to Russia or persons located therein. 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 Granite Ridge’s business. Additional potential sanctions and penalties have also been proposed and/or threatened.

The extent and duration of the military action, sanctions and resulting market disruptions are impossible to predict, but could be substantial. Prolonged unfavorable economic conditions or uncertainty as a result of the military conflict between Russia and Ukraine may adversely affect Granite Ridge’s business,

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financial condition, and results of operations. Any of the foregoing may also magnify the impact of other risks described in this prospectus.

Inflation could adversely impact Granite Ridge’s ability to control its costs, including the operating expenses and capital costs of its operating partners.

Although inflation in the United States has been relatively low in recent years, it has risen significantly beginning in the second half of 2021. This is believed to be the result of the economic impact from the COVID-19 pandemic, including the effects of global supply chain disruptions and government stimulus packages, among other factors. Global, industry-wide supply chain disruptions caused by the COVID-19 pandemic have resulted in shortages in labor, materials and services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could continue to cause costs to increase as well as scarcity of certain products and raw materials. To the extent elevated inflation remains, Granite Ridge’s operating partners may experience further cost increases for their operations, including oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in Granite Ridge’s operating partners’ areas of operations, as well as increased labor costs. An increase in oil and natural gas prices may cause the costs of materials and services to rise. The Company cannot predict any future trends in the rate of inflation and any continued significant increase in inflation, to the extent Granite Ridge is unable to recover higher costs through higher commodity prices and revenues, would negatively impact Granite Ridge’s business, financial condition and results of operation.

The COVID-19 pandemic has had, and may continue to have, a material adverse effect on Granite Ridge’s financial condition and results of operations.

Granite Ridge faces risks related to public health crises, including the COVID-19 pandemic. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 and had and could in the future continue to have a material adverse impact on Granite Ridge’s financial condition and results of operations.

Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, the Company continues to monitor the effects of the pandemic on its operations. As a result of the ongoing COVID-19 pandemic, Granite Ridge’s operations, and those of Granite Ridge’s operating partners, have and may continue to experience delays or disruptions and temporary suspensions of operations. In addition, Granite Ridge’s results of operations and financial condition have been and may continue to be adversely affected by the ongoing COVID-19 pandemic.

The extent to which Granite Ridge’s operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond its control, such as the emergence of more contagious and harmful variants of the COVID-19 virus, the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that the Company identifies herein. While the effects of the COVID-19 pandemic have lessened recently in the United States, the Company cannot predict the duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may materially adversely affect its results of operations and financial condition in a manner that is not currently known to the Company or that it does not currently consider to present significant risks to its operations.

Granite Ridge’s operating partners depend on computer and telecommunications systems, and failures in those systems or cybersecurity threats, attacks and other disruptions could significantly disrupt Granite Ridge’s business operations.

The Company and the Manager have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with Granite Ridge’s business.

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In addition, the Company and the Manager have developed or may develop proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible that the Company, the Manager, or these third parties, could incur interruptions from cybersecurity attacks, computer viruses or malware, or that third-party service providers could cause a breach of Granite Ridge’s data. The Company believes that it and the Manager have positive relations with their information technology vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to the Company’s or the Manager’s arrangements with third parties for their computing and communications infrastructure or any other interruptions to, or breaches of, their information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt Granite Ridge’s business operations. Although the Company and the Manager utilize various procedures and controls to monitor these threats and mitigate their exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. Furthermore, various third-party resources that Granite Ridge or the Manager rely on, directly or indirectly, in the operation of Granite Ridge’s business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyber-attacks or similar events that are entirely outside the control or Granite Ridge or the Manager, and any such events could significantly disrupt Granite Ridge’s business operations and/or have a material adverse effect on its results of operations. Granite Ridge has not, to its knowledge, experienced any material losses relating to cyber-attacks; however, there can be no assurance that Granite Ridge will not suffer material losses in the future.

In addition, Granite Ridge’s operating partners face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of their facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to Granite Ridge’s operations and could have a material adverse effect on Granite Ridge’s financial position, results of operations or cash flows. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject Granite Ridge’s operations to increased risks. Any future terrorist attack at Granite Ridge’s operating partners’ facilities, or those of their purchasers or vendors, could have a material adverse effect on Granite Ridge’s financial condition and operations.

A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business, and noncompliance with these laws and regulations could subject Granite Ridge to material administrative, civil or criminal penalties, injunctive relief, or other liabilities.

A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business. Any noncompliance with these laws and regulations could subject Granite Ridge to material administrative, civil or criminal penalties, injunctive relief, or other liabilities. Additionally, compliance with these laws and regulations may, from time to time, result in increased costs of operations, delay in operations, or decreased production, and may affect acquisition costs. Examples of laws and regulations that govern the environmental aspects of the oil and gas business include the following:

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the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-construction, operating, permitting monitoring, control, recordkeeping, and reporting requirements and is relied upon by the U.S. Environmental Protection Agency (“EPA”) as an authority for adopting climate change regulatory initiatives, including relating to GHG emissions;

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the Clean Water Act (“CWA”), which regulates discharges of pollutants and dredge and fill material to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction as protected waters of the United States;

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the Oil Pollution Act (“OPA”), which requires oil spill prevention, control, and countermeasure planning and imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;

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the Safe Drinking Water Act (“SDWA”), which protects the quality of the nation’s public drinking water sources through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;

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the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which imposes liability without regard to fault on certain categories of potentially responsible parties including generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as on present and certain past owners and operators of sites were hazardous substance releases have occurred or are threatening to occur;

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the Resource Conservation and Recovery Act (“RCRA”), which imposes requirements for the generation, treatment, storage, transport, disposal and cleanup of non-hazardous and hazardous wastes;

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the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas. Similar protections are afforded to migratory birds under the Migratory Bird Treaty Act (“MBTA”) and bald and golden eagles under the Bald and Golden Eagle Protection Act (“BGEPA”);

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the Emergency Planning and Community Right-to-Know Act (“EPCRA”), which requires certain facilities to report toxic chemical uses, inventories, and releases and to disseminate such information to local emergency planning committees and response departments; and

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the Occupational Safety and Health Act (“OSHA”) and comparable state statutes, which impose regulations related to the protection of worker health and safety, including requiring employers to implement a hazard communication program and disseminate hazard information to employees.

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict or otherwise regulate the management of hazardous substances and wastes, the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and groundwater, including through permitting requirements, monitoring and reporting requirements, limitations or prohibitions of operations on certain protected areas, requirements to install certain emissions monitoring or control equipment, spill planning and preparedness requirements, and the application of specific worker health and safety criteria. Failure to comply with applicable environmental laws and regulations by Granite Ridge or third-party operators or contractors could trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements or other corrective measures, and the issuance of orders enjoining existing or future operations. In addition, Granite Ridge or its operating partners may be strictly liable under state or federal laws for environmental damages caused by the previous owners or operators of properties they purchase, without regard to fault.

Environmental laws and regulations change frequently and tend to become more stringent over time, and the implementation of new, or the modification of existing, laws or regulations could adversely affect Granite Ridge’s business. For example, in recent years, the EPA published final rules that establish new air emission control requirements, among other requirements, for oil and natural gas production, processing, transportation, and storage activities to address emissions of methane and VOCs. Among these requirements is the reduction of methane and VOC emissions from oil and gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells subject to the rule. These New Source Performance Standards (“NSPS”), as so referred, also impose requirements for leak detection and repair at well sites and natural gas transmission compressor stations and professional engineer certifications of emission control systems installed to comply with the rule. These rules have been heavily litigated and some aspects of them continue to be subject to various challenge, rescission, and proposal actions. Accordingly, the final implementation and scope of these requirements remains uncertain, but the imposition of these requirements on certain sources of air emissions in the oil and gas industry that were constructed, reconstructed, or modified on or after August 23, 2011, will likely result in increased costs for oil and natural gas exploration and production activities. Furthermore, EPA in November 2021 proposed a suite of NSPS rules, known as Subparts OOOOb and OOOOc that, if adopted, will further impact the upstream and midstream oil and gas sectors. As proposed, Subparts OOOOb and OOOOc would impose requirements on new, modified, existing and/or reconstructed sources in the oil and natural gas sector. The proposed regulations include additional inspections, emission control requirements, additional financial

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assurance for plugged and abandoned wells, and emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources. The proposed rules for new and modified facilities are currently estimated to be finalized by the end of 2022, while any standards finalized for existing facilities will require further state rulemaking actions over the next several years before they become effective. The proposed rules and any state standards, if implemented, could further increase the cost of development and operation of the Properties.

Additionally, some states in which the Properties are located, such as Colorado and New Mexico, have adopted stringent rules and regulations to reduce methane emissions and emissions of other hydrocarbons, VOCs, and nitrogen oxides associated with oil and gas facilities. For example, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) recently adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, the development of pre-production air monitoring plans at certain oil and gas facilities, enclosed combustion device testing, a methane intensity reduction requirement based on statewide volume of production and additional measures for reducing and eliminating emissions from pneumatic devices. AQCC is expected to undertake several additional rulemaking efforts to further reduce emissions over the next several years. State rules and regulations such as these could significantly increase the costs to develop and operate the Properties, result in a delay in operations or decreased production, and may affect acquisition costs.

Granite Ridge anticipates that hydraulic fracturing will be engaged in by some or all opportunities in which it invests, which could be adversely affected by regulatory initiatives related to hydraulic fracturing.

Hydraulic fracturing is an important and commonly used process that Granite Ridge anticipates will be engaged in by some or all opportunities in which it invests. Hydraulic fracturing is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.

The EPA has asserted authority over certain hydraulic-fracturing activities that use diesel fuel under the SDWA. In addition, legislation such as the Fracturing Responsibility and Awareness of Chemicals Act and similar proposals have been repeatedly introduced before Congress to provide for federal regulation of hydraulic fracturing, such as through disclosure requirements for chemical additives used in hydraulic fracturing fluids. Certain states (including states in which the Properties are located) have adopted, and other states are considering adopting, regulations that could impose more stringent permitting and well construction requirements on hydraulic-fracturing operations or seek to ban fracturing activities altogether. For example, Colorado Senate Bill 19-181 amended state law to give municipalities and counties greater local control over siting and permitting of oil and gas facilities, and some municipalities within the state have implemented regulations within their jurisdictions. In the event federal, tribal, state, local, or municipal legal restrictions are adopted in Granite Ridge’s target areas, the investments may incur significant additional compliance costs, experience delays in exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. A number of governmental bodies, including the EPA, a committee of the U.S. House of Representatives, the U.S. Department of Energy, and a number of other federal agencies have from time to time analyzed, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. As these studies proceed, and depending on their scope and results, they could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory programs. This, in turn, could lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing, which could adversely affect the investments.

Seismicity concerns associated with injection of produced water and certain other field fluids into disposal wells has led to increased regulation of saltwater injection and disposal wells in certain areas of states in which the Properties are located, which could increase the cost of, or limit the number of facilities available for, disposal of produced water from oil and gas exploration and production operations at the Properties.

Flowback and produced water or certain other field fluids gathered from oil and natural gas exploration and production operations are often injected or disposed of in underground disposal wells. This disposal process has been linked to increased induced seismicity events in certain areas of the country. Certain states (including states in which the Properties are located) have begun to consider or adopt laws and regulations

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that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or in underground disposal wells, and state agencies implementing these requirements may issue orders directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, the Colorado Oil and Gas Conservation Commission adopted regulations in November 2020 that impose various new requirements on the underground injection of fluid wastes to further seismic safety and protection of the environment. In addition, in 2014, the Railroad Commission of Texas (“RRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Furthermore, in response to a number of earthquakes in recent years in the Midland Basin, in September 2021 the RRC announced that it will not issue any new saltwater disposal (“SWD”) well permits in an area known as the Gardendale Seismic Response Area (“SRA”), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well. In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. And in October 2021 and January 2022, respectively, the RRC identified two additional SRAs: the Northern Culberson-Reeves SRA and the Stanton SRA. Operators in the Northern Culberson-Reeves and Stanton SRAs were required to develop and implement seismic response plans, which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff. Such restrictions and requirements could limit oil and gas well exploration and production activities underlying the investments or increase the cost of those activities if wastewater disposal options become limited.

Specific climate legislation and regulation regarding emissions of carbon dioxide, methane, and other greenhouse gases may develop or be enacted, which could adversely affect the oil and gas industry and demand for the oil and gas produced from the Properties.

The energy industry is affected from time to time in varying degrees by political developments and a wide range of federal, tribal, state and local statutes, rules, orders and regulations that may, in turn, affect the operations and costs of the companies engaged in the energy industry. In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on the Properties. Further, the Inflation Reduction Act (“IRA”), which the U.S. Congress passed in August 2022, includes a charge for methane emissions from specific types of facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year, and although the IRA generally provides for a conditional exemption under certain circumstances, the change applies to emissions that exceed an established emissions threshold for each type of covered facility. The charge starts at $900 per metric ton of methane in 2025 (using 2024 data), and increases to $1,500 after two years. Additional GHG regulation could also result from the agreement crafted during the United Nations climate change conference in Paris, France in December 2015 (the “Paris Agreement”). Under the Paris Agreement, the United States committed to reducing its GHG emissions by 26 – 28% by the year 2025 as compared with 2005 levels. Moreover, in November 2021, at the U.N. Framework Convention on Climate Change 26th Conference of the Parties, the U.S. and the European Union advanced a Global Methane Pledge to reduce global methane emissions at least 30% from 2020 levels by 2030, which over 100 countries have signed. While Congress has from time to time considered legislation to reduce emissions of GHGs, comprehensive legislation aimed at reducing GHG emissions has not yet been adopted at the federal level.

In the absence of comprehensive federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These

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programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact Granite Ridge, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from the Properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas, that may be imposed in various states, as well as state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets. Finally, it should be noted that climate changes may have significant physical effects, such as increased frequency and severity of storms, freezes, floods, drought, hurricanes and other climatic events; if any of these effects were to occur, they could have an adverse effect on Granite Ridge.

In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. Environmental, social, and governance (“ESG”) goals and programs, which may include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and stakeholders across the industry, and companies without robust ESG programs may find access to capital and investors more challenging in the future. Further, while reporting on most ESG information is currently voluntary, in March 2022, the SEC issued a proposed rule that would require public companies to disclose certain climate-related information, including climate-related risks, impacts, oversight and management, financial statement metrics and emissions, targets, goals and plans. While the proposed rule is not yet effective and is expected to be subject to a lengthy comment process, compliance with the proposed rule as drafted could result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

Fuel and energy conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.

Fuel and energy conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, Granite Ridge’s revenues.

Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas exploration and production and related infrastructure projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will continue to rise in the future, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting Granite Ridge’s future financial results.

The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on Granite Ridge’s business, financial condition, results of operations and cash flows.

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Increased attention to environmental, social and governance (“ESG”) matters may impact Granite Ridge’s business.

Increasing attention to climate change, fuel conservation measures, alternative fuel requirements, incentives to conserve energy or use alternative energy sources, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices may result in increased costs, reduced demand for Granite Ridge’s products, reduced profits, increased investigations and litigation, and negative impacts on Granite Ridge’s access to capital markets. Increasing attention to climate change and any related negative public perception regarding Granite Ridge and/or its industry, for example, may result in demand shifts for our products, increased litigation risk for Granite Ridge, and increased regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state, local, tribal and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward Granite Ridge and its industry and to the diversion of investment to other industries, which could have a negative impact on Granite Ridge’s access to and costs of capital. Also, institutional lenders may, of their own accord, elect not to provide or place additional restrictions on funding for fossil fuel energy companies based on climate change related concerns, which could affect Granite Ridge’s access to capital for potential growth projects.

Granite Ridge relies on the Manager for various certain key services under the MSA, which could result in conflicts of interest and other unforeseen risks.

At the closing of the Business Combination, Granite Ridge entered into the MSA with the Manager, pursuant to which the Manager supplies land, accounting, engineering, finance, and other back-office services to Granite Ridge in connection with continued management of the Properties contributed to Granite Ridge as part of the proposed Business Combination. Under this arrangement, the success of Granite Ridge depends upon the Manager who will have overall supervision and control certain business affairs of Granite Ridge’s and its investment activities. Further, the employees of the Manager and its respective principals and managers (as applicable) will devote a portion of their time to the affairs of Granite Ridge necessary for the proper performance of their duties. However, other investment activities of the Manager are likely to require those individuals to devote substantial amounts of their time to matters unrelated to the business of Granite Ridge. Pursuant to the MSA, Granite Ridge will be offered the opportunity to participate in certain of these activities.

Subject to the provisions of the MSA that provides for the Manager to offer Granite Ridge the opportunity to participate in certain investments made by funds affiliated with the Manager and for Granite Ridge to offer such funds the opportunity to participate in certain investments made by Granite Ridge, the Manager may make investments on behalf of its funds not a part of the Business Combination or in which such funds may co-invest with Granite Ridge, any such transactions may involve conflicts of interest among Granite Ridge, the Manager, and their affiliates, some or all of which may not be thought of or taken into account in reviewing and approving such transactions. In certain events, the Manager may not be in a position unilaterally to control such investments or exercise certain rights associated with such investments. Granite Ridge may be subject to conflicts of interest involving the Manager and its affiliates, and the Manager may enter into relationships with developers, co-owners or other affiliates, some of which may give rise to conflicts of interest. To the extent not addressed by the MSA, the Manager and Granite Ridge intend to implement policies as necessary or appropriate to deal with such potential conflicts.

Investment analyses and decisions by the Manager may frequently be required to be undertaken on an expedited basis to take advantage of investment opportunities. In such cases, the information available at the time of making an investment decision may be limited, and the Manager may not have access to complete information regarding the investment. Therefore, no assurance can be given that the Manager will have knowledge of all circumstances that may adversely affect an investment. In addition, the Manager expects to rely upon specialized expert input by various third-party consultants and service providers in connection with its evaluation of proposed investments.

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Additionally, if the MSA is terminated or not renewed upon the end of its term, it may be difficult for Granite Ridge to hire the necessary personnel in a timely manner to handle the matters and services being provided by Manager, which could have a material adverse effect on Granite Ridge’s business and results of operations.

Granite Ridge relies to a large degree on the Manager to maintain an effective system of internal control over financial reporting and Granite Ridge may not be able to accurately report its financial results or prevent fraud.

Under the terms of the MSA, Granite Ridge must rely to a large extent on the internal controls and financial reporting controls of the Manager, and the Manager’s failure to maintain effective controls or comply with applicable standards may adversely affect Granite Ridge. Any failure of the Manager to maintain adequate internal controls over financial reporting or to implement required, new or improved controls, or difficulties encountered in their implementation, could cause material weaknesses or significant deficiencies in Granite Ridge’s financial reporting and could result in errors or misstatements in Granite Ridge’s consolidated financial statements that could be material. Any third-party failure to achieve and maintain effective internal controls could have a material adverse effect on Granite Ridge’s business, its ability to access capital markets and investors’ perception of Granite Ridge. Additionally, if Granite Ridge or its independent registered public accounting firm were to conclude that third-party internal controls over financial reporting were not effective, any material weaknesses in such internal controls could require significant expense and management time to remediate.

The relative lack of public company experience by Granite Ridge’s management team may put Granite Ridge at a competitive disadvantage.

As a company with a class of securities that are registered under the Exchange Act, Granite Ridge is subject to reporting and other legal, accounting, corporate governance, and regulatory requirements imposed by the Exchange Act or the Sarbanes-Oxley Act. With the exception of Granite Ridge’s Chief Financial Officer, Tyler Farquharson, Granite Ridge’s management team lacks public company experience, which could impair Granite Ridge’s ability to comply with these legal, accounting, and regulatory requirements. Such responsibilities include complying with securities laws and making required disclosures on a timely basis. Granite Ridge’s senior management may not be able to implement and effect programs and policies in an effective and timely manner that adequately respond to such increased legal and regulatory compliance and reporting requirements. Granite Ridge’s failure to do so could lead to the imposition of fines and penalties and negatively impact Granite Ridge’s business and operations.

The borrowing base under Granite Ridge’s Credit Agreement may be reduced in light of commodity price declines, which could limit Granite Ridge in the future.

At the closing of the Business Combination, Granite Ridge entered into a senior secured revolving credit agreement dated October 24, 2022 among the Company, as borrower, Texas Capital Bank, as administrative agent, and the lenders from time to time party thereto (the “Credit Agreement”), secured by a first priority mortgage and security interest in substantially all assets of Granite Ridge and its restricted subsidiaries. Availability under the Credit Agreement is limited to the aggregate commitments of the lenders, which is the least of the aggregate maximum credit amounts of the lenders, the borrowing base and the elected commitment amount chosen by Granite Ridge. Granite Ridge’s borrowing base under the Credit Agreement will depend on, among other things, the value of the proved reserves attributed to, and projected revenues from, the oil and natural gas properties securing Granite Ridge’s Credit Agreement, many of which factors are beyond Granite Ridge’s control. Accordingly, lower commodity volumes and prices may reduce the available amount of Granite Ridge’s borrowing base under the Credit Agreement. Granite Ridge’s borrowing base is determined at the discretion of the lenders party to the Credit Agreement and is subject to semi-annual redeterminations, as well as any special redeterminations described in the Credit Agreement. Granite Ridge may reset the elected commitment amount under the Credit Agreement in conjunction with each borrowing base redetermination. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, Granite Ridge would be required to repay the excess or otherwise remedy the deficiency in accordance with the terms of the Credit Agreement. Granite Ridge may not have sufficient funds to make such repayments, and may not have access to the equity or debt capital markets, at the time such repayment obligations are due. If Granite Ridge does not have sufficient

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funds and it is otherwise unable to raise sufficient funds, negotiate renewals of its borrowings or arrange new financing, Granite Ridge may have to sell significant assets. Any such sale could have a material adverse effect on Granite Ridge’s business and financial results. Please see the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources — Fund III (Predecessor), Fund I and Fund II — Credit Agreement” for more information.

Risks Relating to Ownership of Granite Ridge Common Stock

Sales of the Granite Ridge common stock by the Selling Securityholders (or the perception that such shares may be sold) or issuances by Granite Ridge may cause the market price of Granite Ridge’s securities to drop significantly, even if Granite Ridge’s business is doing well.

The sale of shares of Granite Ridge common stock in the public market or otherwise, including sales pursuant to this prospectus, or the perception that such sales could occur, could harm the prevailing market price of shares of Granite Ridge common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for Granite Ridge to sell equity securities in the future at a time and at a price that it deems appropriate.

In connection with the Business Combination, Holdco and the former independent directors of ENPC received 1,238,393 shares of Granite Ridge common stock and the Existing GREP Members and their direct and indirect members were issued 130.0 million shares of Granite Ridge common stock. Pursuant to the terms and subject to the conditions of the RRA and Lock-up Agreement, Fund III will not be able to sell any of the shares of Granite Ridge common stock that it received as a result of the Business Combination (subject to limited exceptions) until 180 days after the consummation of the Business Combination. In connection with and in order to facilitate the closing of the Business Combination and subsequent to the closing of the Business Combination, the Company granted waivers of the lock-up restriction with respect to certain shares other than shares held by Fund III. Please see the section entitled “Certain Relationships and Related Party Transactions — Registration Rights and Lock-Up Agreement” for more information.

The Selling Securityholders other than Fund III may sell, and upon expiration of the applicable lock-up periods and subject to applicable securities laws, Fund III may sell large amounts of shares of Granite Ridge common stock in the open market or in privately negotiated transactions, which could have the effect of increasing the volatility in Granite Ridge’s stock price or putting significant downward pressure on the price of Granite Ridge common stock. The shares beneficially owned by the Existing GREP Members who are Selling Securityholders hereunder represent more than 89% of the total outstanding shares of Granite Ridge common stock and all of the shares that may be offered by the Selling Securityholders collectively represent more than 96% of the total outstanding shares of Granite Ridge common stock, and these holders will have the ability to sell or distribute all of their shares pursuant to the registration statement of which this prospectus forms a part so long as it is available for use. The sale of the securities being registered in this prospectus therefore could result in a significant decline in the public trading price of Granite Ridge common stock and potentially hinder our ability to raise capital. Please see the section entitled “Selling Securityholders” for the number of shares of Granite Ridge common stock that may be sold hereunder.

As restrictions on resale end, the market price of shares of Granite Ridge common stock could drop significantly if the Selling Securityholders sell them or are perceived by the market as intending to sell them. These factors could also make it more difficult for Granite Ridge to raise additional funds through future offerings of shares of Granite Ridge common stock or other securities.

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per share, or approximately $4.37 million in the aggregate (assuming, for simplicity, that all 371,518 shares subject to vesting or forfeiture are fully vested, but acknowledging fewer shares are likely to vest given a closing price of $9.13).

In the future, Granite Ridge may also issue its securities in connection with investments or acquisitions. The amount of shares of Granite Ridge common stock issued in connection with an investment or acquisition could constitute a material portion of Granite Ridge’s then-outstanding shares of Granite Ridge common stock. Any issuance of additional securities in connection with investments or acquisitions may result in additional dilution to the Granite Ridge’s stockholders.

We expect to issue additional shares of common stock under our equity incentive plan. Any such issuances would dilute the interest of our shareholders and likely present other risks.

The shares of Granite Ridge common stock reserved for future issuance under the Incentive Plan will become eligible for sale in the public market once those shares are issued, subject to provisions relating to various vesting requirements and, in some cases, limitations on volume and manner of sale applicable to affiliates under Rule 144. The number of shares of Granite Ridge common stock expected to be reserved for future issuance under its equity incentive plans is 6,500,000, which represents approximately 4.9% of the shares of Granite Ridge common stock that are outstanding following the consummation of the Business Combination. Granite Ridge expects to file one or more registration statements on Form S-8 under the Securities Act to register shares of Granite Ridge common stock or securities convertible into or exchangeable for shares of Granite Ridge common stock issued pursuant to the Incentive Plan. Accordingly, shares registered under such registration statements will be available for sale in the open market.

Any such issuances of additional shares of common stock may significantly dilute the equity interests of our investors and may adversely affect prevailing market prices for our common stock.

The market price of shares of Granite Ridge common stock may be volatile.

Fluctuations in the price of Granite Ridge’s securities could contribute to the loss of all or part of your investment. The trading price of Granite Ridge’s securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Price volatility may be greater if the public float and trading volume of Granite Ridge common stock is low.

Any of the factors listed below could have a material adverse effect on your investment Granite Ridge’s securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of Granite Ridge’s securities may not recover and may experience a further decline. Factors affecting the trading price of Granite Ridge’s securities may include:

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actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to Granite Ridge;

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changes in the market’s expectations about Granite Ridge’s operating results;

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success of competitors;

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lack of adjacent competitors;

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Granite Ridge’s operating results failing to meet the expectation of securities analysts or investors in a particular period;

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changes in financial estimates and recommendations by securities analysts concerning Granite Ridge or the industries in which Granite Ridge operates in general;

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operating and stock price performance of other companies that investors deem comparable to Granite Ridge;

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announcements by Granite Ridge or its competitors of significant contracts, acquisitions, joint ventures, other strategic relationships or capital commitments;

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changes in laws and regulations affecting Granite Ridge’s business;

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commencement of, or involvement in, litigation involving Granite Ridge;

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changes in Granite Ridge’s capital structure, such as future issuances of securities or the incurrence of additional debt;

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the volume of shares of Granite Ridge common stock available for public sale, including the significant percentage of shares of Granite Ridge common stock being offered for resale pursuant to this prospectus;

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any significant change in Granite Ridge’s board of directors or management;

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sales of substantial amounts of Granite Ridge common stock by our directors, executive officers or significant stockholders or the perception that such sales could occur;

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general economic and political conditions such as recessions, interest rates, fuel prices, international currency fluctuations and acts of war or terrorism; and

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changes in accounting standards, policies, guidelines, interpretations or principles.

Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general and the NYSE have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected.

In the past, following periods of market volatility, stockholders have instituted securities class action litigation. If Granite Ridge is involved in securities litigation, it could have a substantial cost and divert resources and the attention of executive management from Granite Ridge’s business regardless of the outcome of such litigation.

Granite Ridge qualifies as an “emerging growth company” within the meaning of the Securities Act and avails itself of certain exemptions from disclosure requirements available to emerging growth companies, which could make its securities less attractive to investors and may make it more difficult to compare Granite Ridge’s performance to the performance of other public companies.

Granite Ridge qualifies as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As such, Granite Ridge is eligible for and takes advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as it continues to be an emerging growth company, including, but not limited to, (i) not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, (ii) reduced disclosure obligations regarding executive compensation in Granite Ridge’s periodic reports and proxy statements and (iii) exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. As a result, Granite Ridge’s stockholders may not have access to certain information they may deem important. Granite Ridge will remain an emerging growth company until the earliest of the last day of the fiscal year (a) following September 18, 2025, (b) in which Granite Ridge has total annual gross revenue of at least $1.07 billion or (c) in which Granite Ridge is deemed to be a large accelerated filer, which means (1) the market value of its common stock that is held by non-affiliates exceeds $700 million as of the last business day of its most recently completed second fiscal quarter (2) has been subject to compliance with periodic reporting requirements for a period of at least 12 months, and (3) the date on which Granite Ridge has issued more than $1.0 billion in non-convertible debt securities during the prior three year period. We cannot predict whether investors will find Granite Ridge’s securities less attractive because it will rely on these exemptions. If some investors find Granite Ridge’s securities less attractive as a result of its reliance on these exemptions, the trading prices of Granite Ridge’s securities may be lower than they otherwise would be, there may be a less active trading market for Granite Ridge’s securities and the trading prices of Granite Ridge’s securities may be more volatile.

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standards. Granite Ridge takes advantage of the benefits of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, it, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of Granite Ridge’s financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

If the Business Combination’s benefits do not meet the expectations of financial analysts, the market price of Granite Ridge common stock may decline.

The market price of Granite Ridge common stock may decline if Granite Ridge does not achieve the perceived benefits of the Business Combination as rapidly, or to the extent anticipated by, financial analysts or the effect of the Business Combination on Granite Ridge’s financial results is not consistent with the expectations of financial analysts. Accordingly, holders of Granite Ridge common stock may experience a loss as a result of a decline in the market price of Granite Ridge common stock. In addition, a decline in the market price of Granite Ridge common stock could adversely affect Granite Ridge’s ability to issue additional securities and to obtain additional financing in the future.

Future issuances of debt securities and/or equity securities may adversely affect Granite Ridge, including the market price of Granite Ridge common stock, and may be dilutive to existing Granite Ridge stockholders.

In the future, Granite Ridge may incur debt and/or issue equity ranking senior to the Granite Ridge common stock. Those securities will generally have priority upon liquidation. Such securities also may be governed by an indenture or other instrument containing covenants restricting Granite Ridge’s operating flexibility. Additionally, any convertible or exchangeable securities that Granite Ridge issues in the future may have rights, preferences and privileges more favorable than those of the Granite Ridge common stock. Because Granite Ridge’s decision to issue debt and/or equity in the future will depend, in part, on market conditions and other factors beyond Granite Ridge’s control, it cannot predict or estimate the amount, timing, nature or success of Granite Ridge’s future capital raising efforts. As a result, future capital raising efforts may reduce the market price of Granite Ridge common stock and be dilutive to existing Granite Ridge stockholders. In addition, our ability to raise additional capital through the sale of equity or debt securities could be significantly impacted by the resale of shares of Granite Ridge common stock by Selling Securityholders pursuant to this prospectus which could result in a significant decline in the trading price of Granite Ridge common stock and potentially hinder our ability to raise capital at terms that are acceptable to us or at all.

The exercise of the Granite Ridge warrants would increase the number of shares eligible for future resale in the public market and result in dilution to holders of Granite Ridge common stock.

In addition, outstanding Granite Ridge warrants to purchase an aggregate 10,349,975 shares of Granite Ridge common stock will become exercisable in accordance with the terms of the Granite Ridge Warrant Agreement. To the extent such warrants are exercised, additional shares of Granite Ridge common stock will be issued, which will result in dilution to the holders of Granite Ridge common stock and may increase the number of shares eligible for resale in the public market. We believe the likelihood that Granite Ridge warrant holders will exercise their Granite Ridge warrants is dependent upon the trading price of Granite Ridge common stock. If the trading price for Granite Ridge common stock continues to be less than $11.50 per share, we believe holders of Granite Ridge warrants will be unlikely to exercise their warrants. To the extent warrants are exercised, sales of substantial numbers of such shares in the public market could adversely affect the market price of Granite Ridge common stock.

The Granite Ridge warrants may never be in the money, and they may expire worthless and the terms of the Granite Ridge warrants may be amended in a manner adverse to a holder if holders of at least 50% of the then outstanding public warrants approve of such amendment.

The exercise price for Granite Ridge warrants is $11.50 per share of Granite Ridge common stock. We believe the likelihood that Granite Ridge warrant holders will exercise their Granite Ridge warrants, and

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therefore the amount of cash proceeds that we would receive, is dependent upon the trading price of Granite Ridge common stock. If the trading price for Granite Ridge common stock continues to be less than $11.50 per share, we believe Granite Ridge warrant holders will be unlikely to exercise their Granite Ridge warrants. There is no guarantee that the Granite Ridge warrants will be in the money prior to their expiration, and as such, the warrants may expire worthless. Our warrants became exercisable on November 23, 2022.

The warrants were issued under the Granite Ridge Warrant Agreement (as defined herein). The Granite Ridge Warrant Agreement provides that the terms of the warrants may be amended without the consent of any holder for the purpose of (i) curing any ambiguity or to correct any defective provision or mistake, including to conform the provisions of the warrant agreement to the description of the terms of the warrants and the warrant agreement, (ii) adjusting the provisions relating to cash dividends on shares of common stock as contemplated by and in accordance with the Granite Ridge Warrant Agreement or (iii) adding or changing any provisions with respect to matters or questions arising under the Granite Ridge Warrant Agreement as the parties to the Granite Ridge Warrant Agreement may deem necessary or desirable and that the parties deem to not adversely affect the rights of the registered holders of the warrants, provided that the approval by the holders of at least 50% of the then outstanding public warrants that vote to amend the Granite Ridge Warrant Agreement, after at least 10 days’ notice that an amendment is being sought, is required to make any change that adversely affects the interests of the registered holders of public warrants. Although our ability to amend the terms of the Granite Ridge warrants with the consent of at least 50% of the then-outstanding public warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the Granite Ridge warrants, convert the Granite Ridge warrants into cash, shorten the exercise period or decrease the number of shares of Granite Ridge common stock purchasable upon exercise of a Granite Ridge warrant.

Anti-takeover provisions in the Granite Ridge organizational documents could delay or prevent a change of control.

Certain provisions of Granite Ridge’s amended and restated certificate of incorporation and Granite Ridge’s amended and restated bylaws may have an anti-takeover effect and may delay, defer or prevent a merger, acquisition, tender offer, takeover attempt or other change of control transaction that a stockholder might consider in its best interest, including those attempts that might result in a premium over the market price for the shares held by Granite Ridge’s stockholders. These provisions, among other things:

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establish a staggered board of directors divided into three classes serving staggered three-year terms, such that not all members of the Granite Ridge Board will be elected at one time;

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authorize the Granite Ridge Board to issue new series of preferred stock without stockholder approval and create, subject to applicable law, a series of preferred stock with preferential rights to dividends or our assets upon liquidation, or with superior voting rights to existing common stock;

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eliminate the ability of stockholders to call special meetings of stockholders;

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eliminate the ability of stockholders to fill vacancies on the Granite Ridge Board;

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establish advance notice requirements for nominations for election to the Granite Ridge Board or for proposing matters that can be acted upon by stockholders at annual stockholder meetings;

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permit the Granite Ridge Board to establish the number of directors;

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provide that the Granite Ridge Board is expressly authorized to make, alter or repeal the amended and restated bylaws of Granite Ridge;

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provide that stockholders can remove directors only for cause; and

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limit the jurisdictions in which certain stockholder litigation may be brought.

These anti-takeover provisions could make it more difficult for a third-party to acquire Granite Ridge, even if the third party’s offer may be considered beneficial by many of Granite Ridge’s stockholders. As a result, Granite Ridge’s stockholders may be limited in their ability to obtain a premium for their shares. These provisions could also discourage proxy contests and make it more difficult for you and other stockholders

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to elect directors of your choosing and to cause Granite Ridge to take other corporate actions you desire. Please see the section entitled “Description of Securities” for more information.

Granite Ridge’s amended and restated certificate of incorporation contains a provision renouncing its interest and expectancy in certain corporate opportunities.

Granite Ridge’s amended and restated certificate of incorporation provides that Granite Ridge, to the fullest extent provided by law, renounces any expectancy that the directors or officers of Granite Ridge will offer to Granite Ridge any corporate opportunity to which it becomes aware, except to the extent such corporate opportunity was offered to such person solely in his or her capacity as a director or officer of Granite Ridge. Officers and directors, including those nominated by the Existing GREP Members or their affiliates, may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to Grey Rock (subject to the MSA that sets forth an allocation of certain acquisition opportunities between Granite Ridge and funds associated with Grey Rock) or other businesses in which they have invested or are otherwise associated, in which case Granite Ridge may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with Granite Ridge for these opportunities, possibly causing these opportunities to not be available to Granite Ridge or causing them to be more expensive for Granite Ridge to pursue. In addition, Grey Rock and its affiliates, may dispose of properties or other assets in the future, without any obligation to offer Granite Ridge the opportunity to purchase any of those assets. As a result, Granite Ridge’s renouncing of its interest and expectancy in any business opportunity that may be from time to time presented its officers and directors, could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for Granite Ridge. We cannot assure you that any conflicts that may arise between Granite Ridge and any of such parties, on the other hand, will be resolved in Granite Ridge’s favor. As a result, competition from Grey Rock and its affiliates or businesses associated with our other officers and directors could adversely impact Granite Ridge’s results of operations.

The amended and restated certificate of incorporation of Granite Ridge designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by Granite Ridge’s stockholders, which could limit Granite Ridge’s stockholders’ ability to obtain a favorable judicial forum for disputes with Granite Ridge or its directors, officers, employees or stockholders.

The amended and restated certificate of incorporation of Granite Ridge provides that, unless Granite Ridge consents in writing to the selection of an alternative forum, that the Court of Chancery shall, to the fullest extent permitted by law, be the sole and exclusive forum for any stockholder (including a beneficial owner) to bring any derivative action on behalf of Granite Ridge, any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of Granite Ridge, any action asserting a claim against Granite Ridge, its directors, officers or employees arising pursuant to any provision of the DGCL or amended and restated certificate of incorporation of Granite Ridge or the Granite Ridge amended and restated bylaws, or any action asserting a claim against Granite Ridge, its directors, officers or employees governed by the internal affairs doctrine, in each case subject to the Court of Chancery having personal jurisdiction over any indispensable parties (or such parties consent to the personal jurisdiction of the Court of Chancery within ten days following the Court of Chancery’s determination as to such personal jurisdiction) and subject matter jurisdiction over the claim. The foregoing forum selection provision shall not apply to claims arising under the Exchange Act, the Securities Act, or any other claim for which the federal courts have exclusive jurisdiction.

In addition, the amended and restated certificate of incorporation of Granite Ridge provides that the federal district courts of the United States will be the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act; however, there is uncertainty as to whether a court would enforce such provision. Although we believe these provisions benefit Granite Ridge by providing increased consistency in the application of Delaware law for the specified types of actions and proceedings, the provisions may have the effect of discouraging lawsuits against us or our directors and officers. Alternatively, if a court were to find the choice of forum provision contained in the amended and restated certificate of incorporation of Granite Ridge to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, financial condition, and operating results. For example, under the Securities Act, state and federal courts have concurrent jurisdiction over all suits brought to enforce any duty or liability created by the Securities Act,

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and investors cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring any interest in Granite Ridge’s common stock shall be deemed to have notice of and consented to this exclusive forum provision, but will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder.

Granite Ridge is a “controlled company” under the corporate governance rules of the NYSE and, as a result, qualifies for exemptions from certain corporate governance requirements. Granite Ridge relies on certain of these exemptions, which means you will not have the same protections afforded to stockholders of companies that are subject to such requirements.

Grey Rock Energy Fund III-A, LP, Grey Rock Energy Fund III-B, LP, and Grey Rock Energy Fund III-B Holdings, LP and their affiliates (collectively, “Grey Rock Fund III”) collectively own a majority of Granite Ridge’s voting common stock. As a result, following the Business Combination, Granite Ridge is a “controlled company” within the meaning of the corporate governance standards of the rules of the NYSE. Under these rules, a listed company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements, including:

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the requirement that a majority of its board of directors consist of independent directors;

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the requirement that its director nominations be made, or recommended to the full board of directors, by its independent directors or by a nominations committee that is comprised entirely of independent directors and that it adopt a written charter or board resolution addressing the nominations process; and

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the requirement that it have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

As long as Granite Ridge remains a “controlled company,” Granite Ridge may elect to take advantage of any of these exemptions. Granite Ridge’s board of directors does not have a majority of independent directors, Granite Ridge’s compensation committee does not consist entirely of independent directors and does not have a nominating committee. Accordingly, you will not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the rules of the NYSE.

Granite Ridge could be adversely affected by changes in applicable tax laws, regulations, or administrative interpretations thereof in the United States or other jurisdictions.

Granite Ridge could also be adversely affected by changes in applicable tax laws, regulations, or administrative interpretations thereof in the United States or other jurisdictions and changes in tax law could reduce Granite Ridge’s after-tax income and adversely affect our business and financial condition. For example, the U.S. federal tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), enacted in December 2017, resulted in fundamental changes to the Code, as amended, including, among many other things, a reduction to the federal corporate income tax rate, a partial limitation on the deductibility of business interest expense, a limitation on the deductibility of certain director and officer compensation expense, limitations on net operating loss carrybacks and carryovers and changes relating to the scope and timing of U.S. taxation on earnings from international business operations. In addition, other changes could be enacted in the future to increase the corporate tax rate, limit further the deductibility of interest, or effect other changes that could have a material adverse effect on Granite Ridge’s financial condition. Such changes could also include increases in state taxes and other changes to state tax laws to replenish state and local government finances depleted by costs attributable to the COVID-19 pandemic and the reduction in tax revenues due to the accompanying economic downturn.

In addition, Granite Ridge’s effective tax rate and tax liability are based on the application of current income tax laws, regulations and treaties. These laws, regulations and treaties are complex and often open to interpretation. In the future, the tax authorities could challenge Granite Ridge’s interpretation of laws, regulations and treaties, resulting in additional tax liability or adjustment to our income tax provision that could increase Granite Ridge’s effective tax rate. Changes to tax laws may also adversely affect Granite Ridge’s ability to attract and retain key personnel.

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USE OF PROCEEDS

We are filing the registration statement of which this prospectus is a part to permit the Selling Securityholders to resell Granite Ridge common stock. We will not receive any proceeds from the sale of Granite Ridge common stock to be offered by the Selling Securityholders pursuant to this prospectus.

We would receive up to an aggregate of approximately $119.0 million from the exercise of the Granite Ridge warrants, assuming the exercise in full of all of the Granite Ridge warrants for cash. We expect to use any net proceeds from the exercise of the Granite Ridge warrants for general corporate purposes. We will have broad discretion over any use of proceeds from the exercise of the Granite Ridge warrants. There is no assurance that the holders of the Granite Ridge warrants will elect to exercise any or all of such Granite Ridge warrants. The exercise price of Granite Ridge warrants is $11.50 per warrant. We believe the likelihood that Granite Ridge warrant holders will exercise their Granite Ridge warrants, and therefore the amount of cash proceeds that we would receive, is dependent upon the trading price of Granite Ridge common stock. If the trading price for Granite Ridge common stock continues to be less than $11.50 per share, we believe holders of Granite Ridge warrants will be unlikely to exercise their Granite Ridge warrants. To the extent that the Granite Ridge warrants are exercised on a “cashless basis,” the amount of cash we would receive from the exercise of the Granite Ridge warrants will decrease.

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SECURITIES MARKET INFORMATION

Market Information

In connection with the closing of the Business Combination, Granite Ridge common stock and Granite Ridge warrants are currently listed on the New York Stock Exchange under the symbols “GRNT” and “GRNT WS,” respectively.

Each whole warrant of Granite Ridge entitles the holder to purchase one share of Granite Ridge common stock at an exercise price of $11.50 per share. The warrants became exercisable at any time commencing November 23, 2022. The warrants will expire on October 24, 2027, or five years after the consummation of the Business Combination, at 5:00 p.m., New York City time, or earlier upon redemption or liquidation.

As of January 5, 2023, there were approximately 109 holders of record of Granite Ridge common stock and 10 holders of record of Granite Ridge warrants.

Dividend Policy

Any determination to pay cash dividends will be at the discretion of the board of directors of Granite Ridge (the “Granite Ridge Board”) and will depend upon a number of factors, including Granite Ridge’s results of operations, financial condition, future prospects, contractual restrictions, restrictions imposed by applicable law and other factors the Granite Ridge Board deems relevant.

Notwithstanding the foregoing, Granite Ridge expects to pay quarterly dividends on its common stock in amounts determined from time to time by the Granite Ridge Board. The Granite Ridge Board declared an initial dividend of $0.08 per share of common stock, payable on December 15, 2022 to stockholders of record on December 1, 2022. The declaration and payment of any future dividends by Granite Ridge will be at the sole discretion of the Granite Ridge Board, which may change Granite Ridge’s dividend policy at any time. The Granite Ridge Board will take into account:

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general economic and business conditions

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the Company’s financial condition and operating results;

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the Company’s free cash flow and current and anticipated cash needs;

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the Company’s capital requirements;

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legal, tax, regulatory and contractual (including under any credit facility entered into by the Company or its subsidiaries) restrictions and implications on the payment of dividends by the Company to its stockholders or by the Company’s subsidiaries to it

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such other factors as the Granite Ridge Board may deem relevant.

Granite Ridge will not have a legal obligation to pay dividends at any rate or at all, and there is no guarantee that it will declare or pay quarterly cash dividends to its common stockholders. If Granite Ridge does not have sufficient cash at the end of each quarter, it may, but is under no obligation to, borrow funds to pay the dividends established by its dividend policy to its common stockholders.

The operating and financial restrictions and covenants in Granite Ridge’s Credit Agreement restrict, and any other future financing agreements by Granite Ridge likely will restrict its ability to pay dividends, finance future operations or capital needs, or engage, expand or pursue its business activities. Specifically, the current Granite Ridge Credit Agreement restricts its ability to make cash dividends or distributions to its shareholders (A) generally, unless the net leverage ratio does not exceed 1.50 to 1.00, availability under the credit facility is not less than 25% of the total revolving commitments, and no event of default then exists or would result from such payment; (B) generally, up to an amount not to exceed the greater of $15 million and 5% of the borrowing base then in effect, unless the net leverage ratio does not exceed 2.25 to 1.00, availability under the credit facility is not less than 10% of the total revolving commitments, utilization of the borrowing base under the credit facility is not more than 70%, and no event of default then exists or would result from such payment, and (C) up to an amount not to exceed Available Free Cash Flow (as defined in the

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Credit Agreement), unless the net leverage ratio does not exceed 2.25 to 1.00, availability under the credit facility is not less than 20% of the total revolving commitments, and no event of default then exists or would result from such payment (with all such financial metrics calculated after giving effect to such payment and any borrowing of loans in connection therewith). Granite Ridge’s ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond its control, such as a downturn in Granite Ridge’s business or the economy in general or reduced oil and natural gas prices.

Furthermore, the amount of dividends Granite Ridge would be able to pay in any quarter may be limited by the DGCL, which provides that a Delaware corporation may pay dividends only (i) out of the corporation’s surplus, which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital, or (ii) if there is no surplus, out of the corporation’s net profit for the fiscal year in which the dividend is declared, or the preceding fiscal year.

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UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

Introduction

On October 24, 2022, Executive Network Partnering Corporation, a Delaware corporation (“ENPC”), consummated its business combination by and among ENPC, Granite Ridge Resources, Inc., a Delaware corporation (“Granite Ridge”), ENPC Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), GREP Merger Sub, LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub” and, together with ENPC Merger Sub, the “Merger Subs”), and GREP Holdings, LLC, a Delaware limited liability company (“GREP”), which provides, among other things, that (i) ENPC Merger Sub merged with and into ENPC (the “ENPC Merger”), with ENPC surviving the ENPC Merger as a wholly-owned subsidiary of Granite Ridge and (ii) GREP Merger Sub merged with and into GREP (the “GREP Merger,” and together with the ENPC Merger, the “Mergers”), with GREP surviving the GREP Merger as a wholly-owned subsidiary of Granite Ridge.

The unaudited pro forma condensed combined financial statements have been prepared in accordance with Article 11 of SEC Regulation S-X as amended by the final rule, Release No. 33-10786 “Amendments to Financial Disclosures about Acquired and Disposed Business” to aid you in your analysis of the financial aspects of the Transactions (as defined below) and is for informational purposes only. The unaudited pro forma condensed combined financial statements present the pro forma effects of the following transactions, collectively referred to as the “Transactions” for purposes of this section, and other related events as described in Note 1 to the accompanying notes to the unaudited pro forma condensed combined financial statements:

•

the formation transaction of Fund III and its business combination with Fund I and Fund II (the “GREP Formation Transaction”); and

•

the business combination of Grey Rock and ENPC, referred to in this section as the “Business Combination.”

The unaudited pro forma condensed combined balance sheet as of September 30, 2022 (the “pro forma balance sheet”), and the unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2022 and the year ended December 31, 2021 (the “pro forma statement of operations,” together with the pro forma balance sheet and the corresponding notes hereto, the “pro forma financial statements”) present the pro forma financial statements of Granite Ridge after giving effect to the Transactions.

The pro forma financial statements have been developed from and should be read in conjunction with the following historical financial statements and related notes of ENPC and Grey Rock Energy Fund III, Grey Rock Energy Fund, LP and Grey Rock Energy Fund II:

•

unaudited financial statements of ENPC as of September 30, 2022 and for the nine months ended September 30, 2022 and 2021 and the related notes included elsewhere in this prospectus and the audited financial statements of ENPC as of and for the fiscal year ended December 31, 2021 and the related notes included elsewhere in this prospectus,

•

unaudited consolidated financial statements of Grey Rock Energy Fund, LP and Subsidiaries as of September 30, 2022 and for the nine months ended September 30, 2022 and 2021 and the related notes included elsewhere in this prospectus and audited consolidated financial statements of Grey Rock Energy Fund, LP and Subsidiaries as of December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019 and the related notes included elsewhere in this prospectus,

•

unaudited combined financial statements of Grey Rock Energy Fund II as of September 30, 2022 and for the nine months ended September 30, 2022 and 2021, and the related notes included elsewhere in this prospectus and audited combined financial statements of Grey Rock Energy Fund II as of and for the years ended December 31, 2021 and 2020, and the related notes included elsewhere in this prospectus, and

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•

unaudited combined financial statements of Grey Rock Energy Fund III as of September 30, 2022 and for the nine months ended September 30, 2022 and 2021, and the related notes included elsewhere in this prospectus and audited combined financial statements of Grey Rock Energy Fund III as of December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019 and the related notes included elsewhere in this prospectus.

GREP Formation Transaction

The GREP Formation Transaction is accounted for consistent with that of a common control transaction pursuant to the guidance in ASC 805-50, recognizing the assets and liabilities received in the transaction at their historical carrying amounts. Fund III has been identified as the acquirer and “predecessor” to Granite Ridge. As control of each Fund will remain with its respective general partner and there will not be a substantive economic change with respect to the Funds pre and post the GREP Formation Transaction, the transaction is accounted for consistent with that of a common control transaction and the GREP Formation Transaction combined Fund III, Fund I and Fund II at historical cost.

The pro forma balance sheet as of September 30, 2022 assumes that the GREP Formation Transaction occurred on September 30, 2022. The pro forma statement of operations for the nine months ended September 30, 2022 and the year ended December 31, 2021 gives pro forma effect to the GREP Formation Transaction as if they had occurred on January 1, 2021.

Business Combination

The Business Combination is accounted for as a reverse recapitalization, with no goodwill or other intangible assets recorded, in accordance with GAAP. Under this method of accounting, ENPC is considered the “acquired” company for financial reporting purposes. Fund III is the accounting acquirer because Grey Rock, as a group, retained a majority of the outstanding shares of Granite Ridge as of the closing of the Business Combination, and they nominated all members of the board of directors as of the closing of the Business Combination.

The pro forma balance sheet as of September 30, 2022 assumes that the Business Combination and related transactions occurred on September 30, 2022. The pro forma statement of operations for the nine months ended September 30, 2022 and the year ended December 31, 2021 give pro forma effect to the Business Combination and related transactions as if they had occurred on January 1, 2021. ENPC and Grey Rock have not had any historical relationship prior to the Business Combination. Accordingly, no pro forma adjustments were required to eliminate activities between the companies.

The pro forma financial statements are presented to reflect the Transactions and do not represent what ENPC’s financial position or results of operations would have been had the Transactions occurred on the dates noted above, nor do they project the financial position or results of operations of Granite Ridge following the Transactions. The transaction accounting adjustments are based on available information and certain assumptions that management believes are factually supportable and are expected to have a continuing impact on the results of operations with the exception of certain non-recurring charges to be incurred in connection with the Transactions, as further described below. In the opinion of management, all adjustments necessary to present fairly the pro forma financial statements have been made.

Certain non-recurring charges were incurred in connection with the GREP Formation Transaction and the Business Combination. Any such charge could affect the future results of Granite Ridge in the period in which such charges are incurred; however, these costs are not expected to be incurred in any period beyond 12 months from the effective date of the Business Combination, which closed the same day as the effective date of the transaction. Accordingly, the pro forma statement of operations for the nine months ended September 30, 2022 and for the year ended December 31, 2021 reflect the effects of these non-recurring charges.

As a result of the foregoing, the transaction accounting adjustments are preliminary and subject to change as additional information becomes available and additional analysis is performed. The transaction accounting adjustments have been made solely for the purpose of providing the pro forma financial statements presented below.

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The pro forma financial statements should be read together with the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the historical financial statements and related notes thereto of ENPC, Grey Rock Energy Fund III, Grey Rock Energy Fund, LP, and Grey Rock Energy Fund II included elsewhere in this prospectus.

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GRANITE RIDGE

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

As of September 30, 2022

				GREP Formation Transaction																Business Combination
	Historical												Transaction Accounting Adjustments				Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
(in thousands)	ENPC			Fund I			Fund II			Fund III			Transaction Accounting Adjustments				Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
Assets
Current Assets:
Cash		$	104		$	2,033		$	28,688		$	6,410		$	(21)	2a		$	37,110		$	22,368	3a,g		$	59,582
Prepaid expenses			—			—			—			—			—				—			—				—
Revenue receivable			—			1,683			18,808			54,324			—				74,815			—				74,815
Advances to operators			—			—			2,082			26,230			—				28,312			—				28,312
Other assets			—			962			2,033			4,098			—				7,093			—				7,093
Derivative assets – current portion			—			50			714			4,376			—				5,140			—				5,140
Contributions receivable			—			—			—			10			—				10			—				10
Related party receivable			—			—			205			—			—				205			—				205
Other Receivable			—			—			—			—			—				—			—				—
Total current assets			104			4,728			52,530			95,448			(21)				152,685			22,368				175,157
Property and equipment (successful efforts):
Oil and gas properties, successful efforts method			—			45,617			328,460			550,163			—				924,240			—				924,240
Accumulated depletion			—			(30,658)			(177,220)			(168,302)			—				(376,180)			—				(376,180)
Total property and equipment, net			—			14,959			151,240			381,861			—				548,060			—				548,060
Cash deposit			—			—			300			—			—				300			—				300
Derivative assets			—			—			340			812			—				1,152			—				1,152
Investments held in trust account			416,329			—			—			—			—				—			(416,329)	3a			—
Total assets		$	416,433		$	19,687		$	204,410		$	478,121		$	(21)			$	702,197		$	(393,961)			$	724,669
Liabilities, stock subject to possible redemption, partners’ capital and stockholders’ equity
Current Liabilities:
Accounts payable		$	126		$	—		$	—		$	—		$	—			$	—		$	—			$	126
Accounts payable – related party			160			—			—			—			—				—			—				160
Convertible note – related party			1,549			—			—			—			—				—			(1,549)	3b			—
Accrued expenses			8,552			652			5,091			20,595			(331)	2a			26,007			29,907	3c			64,466
Other payable			—			1			—			—			—				1			—				1
Derivative liabilities – current			—			29			558			3,941			—				4,528			—				4,528
Credit facilities – current			—			—			—			—			310	2a			310			—				310
Distributions payable			—			—			—			—			—				—			—				—
Related party payable			—			—			—			—			—				—			—				—
Franchise tax payable			68			—			—			—			—				—			—				68
Income tax payable			408			—			—			—			—				—			—				408
Total current liabilities			10,863			682			5,649			24,536			(21)				30,846			28,358				70,067
Long-term liabilities:
Asset retirement obligations			—			320			2,220			2,243			—				4,783			—				4,783
Credit facilities – noncurrent			—			—			—			—			—				—			—				—
Derivative liabilities – noncurrent			—			—			—			—			—				—			—				—
Deferred income taxes			—			—			—			—			—				—			32,617	3d			32,617
Derivative warrant liabilities			9,771			—			—			—			—				—			(143)	3e			9,628
Total liabilities			20,634			1,002			7,869			26,779			(21)				35,629			60,832				117,095

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				GREP Formation Transaction															Business Combination
	Historical												Transaction Accounting Adjustments			Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
(in thousands)	ENPC			Fund I			Fund II			Fund III			Transaction Accounting Adjustments			Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
Class A common stock subject to possible redemption			415,433			—			—			—			—			—			(415,433)	3f			—
Partners’ capital and stockholders equity																		—							—
General partner			—			161			15,817			41,614			—			57,592			(57,592)	3h			—
Limited partners			—			18,524			180,724			409,728			—			608,976			(608,976)	3h			—
Total partners’ capital			—			18,685			196,541			451,342			—			666,568			(666,568)				—
Class A common stock			0			—			—			—			—			—			(0)	3f			—
Class B common stock			0			—			—			—			—			—			(0)	3f			—
Class F common stock			0			—			—			—			—			—			(0)	3f			—
Accumulated deficit			(19,634)			—			—			—			—			—			19,634	3i			—
ParentCo Class A common stock			—			—			—			—			—			—			1,710	3f,g,h			1,710
Additional paid in capital			—			—			—			—			—			—			605,864	3b,c,d,e,f,g,h,i			605,864
Total partners’ capital, stock subject to possible redemption and stockholders’ equity			395,799			18,685			196,541			451,342			—			666,568			(454,793)				607,574
Total liabilities, stock subject to possible redemption, partners’ capital and stockholders’ equity		$	416,433		$	19,687		$	204,410		$	478,121		$	(21)		$	702,197		$	(393,961)			$	724,669

See accompanying “Notes to the Unaudited Pro Forma Condensed Combined Financial Statements”

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GRANITE RIDGE

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2022

				GREP Formation Transaction												Business Combination
	Historical												Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
(in thousands, except share and per share amounts)	ENPC			Fund I			Fund II			Fund III			Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
Revenue:
Oil, natural gas, and related product sales		$	—		$	7,806		$	110,013		$	263,263		$	381,082		$	—			$	381,082
Operating Expenses:
Lease operating expenses			—			1,216			13,662			15,840			30,718			—				30,718
Production taxes			—			512			5,171			14,628			20,311			—				20,311
Depletion and accretion expense			—			1,611			26,038			70,529			98,178			—				98,178
Impairment expense			—			—			—			—			—			—				—
General and administrative			8,720			158			2,709			4,880			7,747			(2,658)	4a,b			13,809
Gain on disposal of oil and natural gas properties			—			—			—			—			—			—				—
Administrative fee – related party			180			—			—			—			—			7,399	4b			7,579
Franchise tax expense			125			—			—			—			—			—				125
Total operating expenses			9,025			3,497			47,580			105,877			156,954			4,741				170,720
Operating Income (Loss)			(9,025)			4,309			62,433			157,386			224,128			(4,741)				210,362
Gain/(loss) on derivative contracts			—			(576)			(11,064)			(19,147)			(30,787)			—				(30,787)
Interest expense			—			(22)			(489)			(1,193)			(1,704)			—				(1,704)
Change in fair value of derivative warrant liabilities			(2,636)			—			—			—			—			39	4c			(2,597)
Income from investments held in Trust Account			2,276			—			—			—			—			(2,276)	4d			—
Income (Loss) before income taxes			(9,385)			3,711			50,880			137,046			191,637			(6,978)				175,274
Income tax expense			408			—			—			—			—			43,161	4e			43,569
Net Income (Loss)		$	(9,793)		$	3,711		$	50,880		$	137,046		$	191,637		$	(50,139)			$	131,705
Net income per share (Note 5)
Weighted average shares outstanding of Class A common stock, basic and diluted			42,014,000
Basic and diluted net income per share of Class A common stock		$	(0.23)
Weighted average shares outstanding of Class B common stock, basic and diluted			300,000
Basic and diluted net income per share of Class B common stock		$	(0.23)
Weighted average shares outstanding of Class F common stock, basic and diluted			828,000
Basic and diluted net income per share of Class F common stock		$	(0.23)
Weighted average shares outstanding of ParentCo Class A common stock																						132,923,379
Basic and diluted net income per share of ParentCo Class A common stock																					$	0.99

See accompanying “Notes to the Unaudited Pro Forma Condensed Combined Financial Statements”

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GRANITE RIDGE

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2021

				GREP Formation Transaction												Business Combination
	Historical												Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
(in thousands, except share and per share amounts)	ENPC			Fund I			Fund II			Fund III			Pro Forma Combined GREP Formation			Transaction Accounting Adjustments				Pro Forma Combined
Revenue:
Oil, natural gas, and related product sales		$	—		$	10,257		$	82,391		$	197,546		$	290,194		$	—			$	290,194
Operating Expenses:
Lease operating expenses			—			1,799			13,128			12,362			27,289			—				27,289
Production taxes			—			627			5,675			10,808			17,110			—				17,110
Depletion and accretion expense			—			3,038			31,090			60,534			94,662			—				94,662
Impairment expense			—			—			—			—			—			—				—
General and administrative			1,964			389			3,528			6,262			10,179			(3,678)	4f,g			8,465
Gain on disposal of oil and natural gas properties			—			(1,341)			(938)			—			(2,279)			—				(2,279)
Administrative fee – related party			240			—			—			—			—			10,000	4g			10,240
Franchise tax expense			159			—			—			—			—			—				159
Total operating expenses			2,363			4,512			52,483			89,966			146,961			6,322				155,646
Operating Income (Loss)			(2,363)			5,745			29,908			107,580			143,233			(6,322)				134,548
Gain/(loss) on derivative contracts			—			(1,842)			(13,232)			(17,315)			(32,389)			—				(32,389)
Interest expense			—			(138)			(848)			(1,399)			(2,385)			—				(2,385)
Change in fair value of derivative warrant liabilities			3,794			—			—			—			—			(55)	4h			3,739
Income from investments held in Trust Account			41			—			—			—			—			(41)	4i			—
Income (Loss) before income taxes			1,472			3,765			15,828			88,866			108,459			(6,418)				103,513
Income tax expense			—			—			—			—			—			25,789	4j			58,406
																		32,617	4j
Net Income (Loss)		$	1,472		$	3,765		$	15,828		$	88,866		$	108,459		$	(64,824)			$	45,107
Net income per share (Note 5)
Weighted average shares outstanding of Class A common stock, basic and diluted			42,014,000
Basic and diluted net income per share of Class A common stock		$	0.03
Weighted average shares outstanding of Class B common stock, basic and diluted			300,000
Basic and diluted net income per share of Class B common stock		$	0.03
Weighted average shares outstanding of Class F common stock, basic and diluted			828,000
Basic and diluted net income per share of Class F common stock		$	0.03
Weighted average shares outstanding of ParentCo Class A common stock																						132,923,379
Basic and diluted net loss per share of ParentCo Class A common stock																					$	0.34

See accompanying “Notes to the Unaudited Pro Forma Condensed Combined Financial Statements”

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NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Note 1 — Basis of Presentation and Description of the Transaction

The pro forma financial statements have been prepared in accordance with Article 11 of Regulation S-X as amended by the final rule, Release No. 33-10786, “Amendments to Financial Disclosures about Acquired and Disposed Businesses.” Release No. 33-10786 replaces the existing pro forma adjustment criteria which simplified requirements to depict the accounting for the transaction (“Transaction Accounting Adjustments”) and present the reasonably estimable synergies and other transaction effects that have occurred or are reasonably expected to occur (“Management Adjustments”). Only Transaction Accounting Adjustments are presented in the pro forma financial information and notes thereto. The adjustments presented in the pro forma financial statements have been identified and presented to provide relevant information necessary for an understanding of Granite Ridge upon consummation of the GREP Formation Transaction and Business Combination.

The GREP Formation Transaction is accounted for consistent with that of a common control transaction pursuant to the guidance in ASC 805-50, recognizing the assets and liabilities received in the transaction at their historical carrying amounts. Fund III is the acquirer and “predecessor” to Granite Ridge. Management determined that Fund III was the predecessor as it is the largest of the three Funds and comprised the majority of the Combined Company upon consummation of the Business Combination. For the purposes of effecting the GREP Formation Transaction, it was determined that a high degree of common ownership exists among Fund III, Fund I and Fund II and there will not be a substantive economic change with respect to the Funds, pre and post the GREP Formation Transaction. As such, the GREP Formation Transaction is accounted for consistent with that of a common control transaction and Fund III, Fund I and Fund II are combined at their historical cost.

The Business Combination is accounted for as a reverse recapitalization, with no goodwill or other intangible assets recorded, in accordance with GAAP. Under this method of accounting, ENPC is the “accounting acquiree” and GREP is the “accounting acquirer” for financial reporting purposes. Accordingly, for accounting purposes, the Business Combination is treated as the equivalent of GREP issuing shares for the net assets of ENPC, followed by a recapitalization. The net assets of ENPC are stated at historical cost. Operations prior to the Business Combination are those of GREP.

The pro forma balance sheet as of September 30, 2022 assumes that the Business Combination and related transactions occurred on September 30, 2022. The pro forma statement of operations for the nine months ended September 30, 2022 and the year ended December 31, 2021 give pro forma effect to the Business Combination and related transactions as if they had occurred on January 1, 2021, the beginning of the earliest period presented. These periods are presented on the basis that GREP is the acquirer for accounting purposes.

The unaudited pro forma adjustments reflecting the GREP Formation Transaction and the consummation of the Business Combination are based on certain currently available information and certain assumptions and methodologies that management believes are reasonable under the circumstances. The pro forma adjustments, which are described in the accompanying notes, may be revised as additional information becomes available and is evaluated. Therefore, it is likely the actual adjustments will differ from the pro forma adjustments, and it is possible that the difference may be material. Management believes that its assumptions and methodologies provide a reasonable basis for presenting all of the significant effects of the GREP Formation Transaction and the Business Combination based on information available to management at this time and the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed combined financial information.

The pro forma financial information does not give effect to any anticipated synergies, operating efficiencies, tax savings, or cost savings that may be associated with the GREP Formation Transaction or the Business Combination. The pro forma financial statements are not necessarily indicative of what the actual results of operations and financial position would have been had the GREP Formation Transaction and Business Combination taken place on the dates indicated, nor are they indicative of the future consolidated results of operations or financial position of Granite Ridge following the Business Combination.

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They should be read in conjunction with the historical financial statements and notes thereto of ENPC, Grey Rock Energy Fund, LP, Grey Rock Energy Fund II and Grey Rock Energy Fund III.

Note 2 — Preliminary Accounting of the GREP Formation Transaction

The GREP Formation Transaction closed in conjunction with the Business Combination and was valued at $1.3 billion. Grey Rock Energy Fund III is the accounting acquirer to the GREP Formation Transaction which is accounted for consistent with that of a common control transaction in accordance with ASC 805-50, recognizing the assets and liabilities received in the transaction at their historical carrying amounts.

(a)

Represents settlement of the $331 thousand of interest expense associated with the preferred limited partnership credit facility balances for Fund II and Fund III that were repaid during the nine months ended September 30, 2022 for a total decrease in cash of $21 thousand and an increase in credit facilities of $310 thousand.

Note 3 — Transaction Accounting Adjustments — Balance Sheet

The unaudited pro forma condensed combined balance sheet has been adjusted to reflect the Business Combination and has been prepared for informational purposes only.

(a)

Reflects the reclassification of cash held in ENPC’s Trust Account to cash and to reflect the cash available to consummate the Business Combination or to fund redemption of existing public shares.

(b)

Reflects the elimination of the $1,549 thousand working capital loan ENPC borrowed from the Sponsor. This loan was cancelled in conjunction with the consummation of the Business Combination.

(c)

Reflects the pro forma adjustment of $29,907 thousand for the estimated legal, accounting, printer and capital market advisory fees incurred directly related to the Business Combination.

(d)

The pro forma adjustment to deferred tax assets and liabilities were computed as if GREP became subject to corporate U.S. federal and state income taxes under Subchapter C of the U.S. Internal Revenue Code as of September 30, 2022. These balance sheet adjustments reflect future tax consequences attributable to differences between financial statement amounts and their respective tax basis utilizing an estimated blended statutory U.S. federal and state income tax rate of 23%. The adjustment amount is primarily driven by the recognition of deferred tax liabilities related to differences between the book and tax basis of oil and gas properties and related depletion and the expected realization of unrealized gain/loss on hedging activities. The change in tax status resulted in a pro forma adjustment to establish a deferred tax liability of $32,617 thousand.

(e)

Reflects the elimination of 153,500 of ENPC’s private placement warrants forfeited as part of the Business Combination.

(f)

Reflects the reclassification of ENPC’s Class A common stock subject to redemption of $415,433 thousand to 41,400,000 shares of Class A common stock and additional paid in capital, the forfeiture of ENPC’s Class B shares and the conversion of ENPC’s Class F shares in conjunction with the consummation of the Business Combination.

(g)

Reflects the redemption of 39,343,496 shares of Class A ordinary shares redeemed for $393,961 thousand allocated to ENPC common stock and additional paid in capital using a par value of $0.01 per share at a redemption price of approximately $10.00 per share in conjunction with the consummation of the Business Combination.

(h)

Reflects the exchange of the Funds’ historical Partners’ capital balances in which 130,000 thousand shares of Class A common stock are redeemed for $1,300 thousand using a par value of $0.01 per share at a redemption price of approximately $10.00 per share with the remaining Partners’ capital balances exchanged for additional paid in capital.

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(i)

Reflects the reclassification of ENPC’s historical accumulated deficit into additional paid-in capital as part of the reverse recapitalization.

Note 4 — Transaction Accounting Adjustments — Statement of Operations

The unaudited pro forma condensed combined statement of operations has been adjusted to reflect the Business Combination and has been prepared for informational purposes only. There were no adjustments to the unaudited pro forma condensed combined statement of operations related to the GREP Formation Transaction.

(a)

Reflects the pro forma adjustment to increase general and administrative expense of $1,886 thousand associated with ENPC’s future executive team and other incremental personnel expenses.

(b)

Reflects the pro forma adjustment to increase general and administrative expense of $2,855 thousand for an increase in management fees in accordance with the “Management Services Agreement” and reclassification of Fund II and Fund III’s existing management fees of $4,544 thousand to “Administrative fee-related party.”

(c)

Reflects the elimination of the gain associated with the mark-to-market of ENPC’s private placement warrants forfeited upon consummation of the Business Combination.

(d)

Reflects the elimination of “Income from investments held in Trust Account” associated with ENPC’s investment held in trust.

(e)

To record the $43,161 income tax expense impact of the unaudited pro forma adjustments at an estimated statutory rate of 23%. Fund I, Fund II and Fund III operate in multiple jurisdictions, so the statutory rate may not be reflective of the actual impact of the tax effects of the adjustments.

(f)

Reflects the pro forma adjustment to increase general and administrative expense of $2,515 thousand associated with ENPC’s future executive team and other incremental personnel expenses.

(g)

Reflects the pro forma adjustment to increase general and administrative expense of $3,807 thousand for an increase in management fees in accordance with the “Management Services Agreement” and reclassification of Fund II and Fund III’s existing management fees of $6,193 thousand to “Administrative fee-related party.”

(h)

Reflects the elimination of the gain associated with the mark-to-market of ENPC’s private placement warrants forfeited upon consummation of the Business Combination.

(i)

Reflects the elimination of “Income from investments held in Trust Account” associated with ENPC’s investment held in trust.

(j)

To record the $25,789 thousand income tax expense impact of the unaudited pro forma adjustments at an estimated statutory rate of 24%. Fund I, Fund II and Fund III operates in multiple jurisdictions, so the statutory rate may not be reflective of the actual impact of the tax effects of the adjustments. In addition, the pro forma adjustment also reflects the tax impact of $32,617 thousand to establishing the deferred tax liability of Fund I, Fund II and Fund III upon conversion to a taxable corporation.

Note 5 — Pro Forma Net Income per Share

Pro forma net income per share was calculated using the historical weighted averages shares outstanding, and the issuance of additional shares in connection with the Business Combination, assuming the shares were outstanding since January 1, 2021. As the Business Combination and the related transactions are being reflected as if they had occurred at the beginning of the earliest period presented, the calculation of weighted average shares outstanding for basic and diluted net income per share assumes that the shares issuable relating to the Business Combination and related transactions have been outstanding for the entirety of all periods presented.

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(in thousands, except share and per share information)	For the Nine Months Ended September 30, 2022			For the Year Ended December 31, 2021
Pro forma net income		$	131,705		$	45,107
Weighted average shares outstanding – basic and diluted			132,923,379			132,923,379
Net income per share – basic and diluted			0.99			0.34
Excluded securities:(1)
Public Warrants			10,350,000			10,350,000

(1)

The potentially dilutive outstanding securities were excluded from the computation of pro forma net income per share, basic and diluted, because their effect would have been anti-dilutive, issuance or vesting of such shares is contingent upon the satisfaction of certain conditions which were not satisfied by the end of the periods presented. In addition, Granite Ridge common stock of 45,000 shares issued to ENPC’s independent directors have not been reflected in the weighted average shares outstanding.

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BUSINESS OF GRANITE RIDGE

In this “Business of Granite Ridge”, unless otherwise specified or the context otherwise requires, “Grey Rock,” “we,” “us,” and “our” refer to Grey Rock Energy Fund III, our Predecessor. The following discussion of our business should be read in conjunction with the historical and unaudited pro forma condensed combined financial statements and related notes, of Fund III, Fund I, Fund II and ENPC included elsewhere in this prospectus and the accompanying financial statements and related notes included elsewhere in this prospectus.

Prior to the closing of the Business Combination, Grey Rock Energy Management, LLC (“Grey Rock”) managed three funds with similar strategies, Grey Rock Energy Fund, LP, a Delaware limited partnership (“Fund I”) formed in 2014, Grey Rock Energy Fund II, L.P., Grey Rock Energy Fund II-B, LP, and Grey Rock Energy Fund II-B Holdings, L.P., each Delaware limited partnerships (collectively, “Fund II”) formed in 2016, and Grey Rock Energy Fund III-A, LP, Grey Rock Energy Fund III-B, LP, and Grey Rock Energy Fund III-B Holdings, LP, each Delaware limited partnerships (collectively, “Fund III” and, together with Fund I and Fund II, the “Funds”) formed in 2018. The Funds held strategic investments in non-operated working interests in upstream oil and gas assets in North America. Upon the consummation of the Business Combination, the Funds and the Existing GREP Members contributed the properties of each of the Funds to GREP Holdings, LLC, a Delaware limited liability company and wholly-owned subsidiary of Granite Ridge (“GREP”). Unless the context otherwise requires, with respect to descriptions of the financials and operations of the properties owned by Granite Ridge, references to “Granite Ridge”, “Grey Rock”, the “Company”, “we”, “us”, or “our” relate to the assets contributed by GREP in the Business Combination, as owned or operated by the Funds prior to the Business Combination, and as owned or operated by Granite Ridge after the Business Combination.

Overview

Granite Ridge holds strategic investments in non-operated working interests in diversified upstream oil and gas assets in North America. As a non-operator, Granite Ridge has been able to diversify its investment exposure by participating in a large number of gross wells, as well as entering into additional project areas by partnering with numerous operating partners in core unconventional basins across the United States. Because Granite Ridge has generally been able to elect to participate on a well-by-well basis in any given well, Granite Ridge believes it has maintained increased flexibility in the timing and amount of its capital expenditures because it has not been burdened with various contractual arrangements with respect to minimum drilling obligations. Further, Granite Ridge has avoided exploratory and infrastructure costs incurred by many oil and gas producers.

•

purchasing working interests, net profits interests and options to acquire net profits interests in upstream oil and gas assets in multiple basins throughout the United States;

•

participating in the development of assets alongside operators who have significant experience in developing and producing hydrocarbons in the Company’s core asset areas;

•

generating income and capital appreciation via interests of the Company in oil and gas wells; and

•

exiting investments at the appropriate time.

Assets of Granite Ridge

Granite Ridge currently holds interests in more than 2,000 wells in core areas of the Permian, Bakken, Eagle Ford, and Haynesville plays (the “Properties”). Non-operated working interests constitute the central part of the Company’s investment strategy, but it has also made certain investments in minerals, and any other oil and gas assets that are incidental or ancillary to, preserve, protect, or enhance the Company’s assets, or are acquired as part of a package with, such non-operated working interests. Following the closing of the Business Combination, Granite Ridge operates and controls the business and affairs and assets previously controlled by the Funds.

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•

Fund I. The assets contributed by Fund I are concentrated in the Eagle Ford and Permian basins with some additional exposure to the Bakken plays. Except for the Eagle Ford, these basins are mostly oil plays driving a higher concentration of oil production. The operators of the Fund I assets are primarily basin-focused public E&P companies.

•

Fund II. The assets contributed by Fund II are concentrated in the Bakken, Haynesville, and Permian basins with some additional exposure to the Eagle Ford play. Except for the Haynesville, these basins are mostly oil plays driving a higher concentration of oil production. The operators of the Fund II assets are primarily basin-focused public E&P companies and a few large experienced private companies.

•

Fund III. The assets contributed by Fund III are concentrated in the Permian, Denver-Julesberg (“DJ”), Eagle Ford, and Bakken plays. While the vast majority of production among Fund III’s assets comes from oil, Fund III does have some exposure to dry gas in the Eagle Ford basin. The operators of Fund III’s assets include a combination of large basin-focused private companies and public E&P companies.

The following table provides a summary of certain information regarding the assets of the Company, broken down by the Fund from which they were contributed and by basin or play as of December 31, 2021, including reserves information as estimated by the Company’s third-party independent reserve engineers, Netherland, Sewell & Associates, Inc.

	As of December 31, 2021
			Productive Gas Wells				Productive Oil Wells				Average Daily Production(1) (Boe per day)		Proved Reserves (MBoe)		% Oil		% Proved Developed
	Net Acres		Gross		Net		Gross		Net		Average Daily Production(1) (Boe per day)		Proved Reserves (MBoe)		% Oil		% Proved Developed
Fund III
Eagle Ford		4,519		8		1.20		8		3.92		1,195		6,497		62%		21%
Permian		6,004		1		0.19		86		18.89		6,923		16,081		67%		41%
Bakken		1,313		—		—		103		5.17		264		954		70%		100%
DJ		1,475		68		2.11		588		14.65		1,905		3,913		34%		79%
Total		13,311		77		3.50		785		42.63		10,287		27,445		61%		43%
Fund I		��
Eagle Ford		748		62		0.90		14		3.44		132		348		83%		96%
Permian		102		—		—		25		2.28		217		147		75%		100%
Bakken		792		—		—		166		2.65		228		422		61%		92%
SCOOP		—		—		—		—		—		98		—		—		—
Total		1,642		62		0.90		205		8.37		675		917		72%		95%
Fund II
Eagle Ford		1,452		2		1.70		73		9.14		608		1,156		73%		100%
Permian		693		—		—		194		4.53		524		1,416		73%		60%
Bakken		13,046		1		0.20		717		28.63		2,462		4,200		82%		83%
Haynesville		2,298		53		9.43		—		—		1,581		8,576		—		28%
Total		17,489		56		11.33		984		42.30		5,175		15,348		35%		51%

(1)

Represents the average daily production over the full year ended December 31, 2021.

Business Strategy

Finding Optimal Risk-Reward in Direct Oil and Gas Investments

Granite Ridge’s strategy is to build a portfolio of non-operated upstream oil and gas assets across the United States that is well diversified in terms of geology, hydrocarbon mix, and operators. Granite Ridge

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focuses on participating alongside experienced operators in each basin by acquiring non-operated working interests in such basins.

Granite Ridge has acquired assets that it believes were attractively priced relative to other entry strategies.

Acquiring Assets with Development Upside at a Discount That Provide a Favorable Risk-Reward Balance

Granite Ridge seeks to acquire working interests directly and participate alongside experienced operators. Granite Ridge believes this enables it to avoid the geologic risks of exploration and the high costs of learning how to drill and complete wells in a new basin. Therefore, Granite Ridge focuses on transactions which it believes to have more development upside, rather than transactions that are mostly drilled out with limited development upside. While development-focused projects tend to be viewed as riskier, Granite Ridge believes that the returns that accrue from these transactions are higher and result in a better risk- reward balance.

Granite Ridge seeks to acquire projects at lower entry prices per acre relative to comparable operated packages by specifically targeting smaller deals and non-marketed packages.

Sourcing Deals Directly and Avoiding Competitive Auctions and Widely-Brokered Deals

Granite Ridge believes that utilizing proprietary relationships is the best ways to source deals for the Company. Granite Ridge believes deals marketed through auctions and investment banks tend to be competitive and expensive. Granite Ridge seeks to find opportunities to participate in several ways:

•

Acquiring assets directly from operators;

•

Buying interests from distressed sellers;

•

Running land programs in specific areas targeted on the basis of geology, well results and operators using a network of landmen across the country; and

•

Finding opportunistic bolt-on acquisitions and joint venture development opportunities.

Focusing on Profitable Development in De-Risked Geologies

Granite Ridge focuses its investments on proven unconventional basins. Some of the Company’s target basins include the Permian, Eagle Ford, Bakken, Haynesville, and DJ plays. Granite Ridge also considers potential transactions in other basins and monitors emerging basins that Granite Ridge believes have potential (for example, the Powder River Basin). Given that the Company’s target basins include millions of acres, Granite Ridge believes there is significant opportunity to enter the plays even though they have already experienced material amounts of drilling activity. Further, Granite Ridge seeks positions with experienced operators that have material amounts of near-term, forecastable drilling plans. The Company and the Manager discuss drilling plans with the operators of the Properties directly on a regular basis in order to plan future capital outlays for Granite Ridge accurately.

Acquiring Direct Working Interests in Properties Provides Multiple Long-Term Options

The Properties provide a number of options for Granite Ridge that the Company believes enable it to avoid uneconomic drilling activity and provide long-term upside.

(1) Project Execution / “Non-Consent”

When the Company acquires a working interest position, it has the option (but not the obligation) to participate in future drilling; in the event the Company refuses to pay for a pro-rata share of well costs, they “go non-consent.” As each well is proposed for investment by the Company, the Company and the Manager evaluate that well proposal using offsetting production data, cost information, and forward curve pricing. These variables can change well economics from the initial underwriting at the time of acquiring the asset. As opposed to investments in mineral interests where all of the costs are front-loaded, the Company typically has the ability to abandon underperforming positions. Typically, joint operating agreements (“JOAs”)

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allow a non-operator partner who goes “non-consent” in wells to back into their interest (i.e., receive their share of production) after a 200% to 500% payout on the well to the operator; the Company’s interest is not necessarily worthless in the event that Manager elects not to participate in certain wells on behalf of the Company given that future drilling locations may be available in the unit. Despite having this option, the Company’s goal is to enter areas where drilling economics will be resilient to changes in pricing and input costs in the future.

(2) Geologic Options / Out-of-the-Money Formations

Working interest owners can keep their leasehold positions for as long as wells are producing oil or gas in profitable quantities. In certain situations, leases allow operators to maintain their rights as to all geologic formations in areas of “stacked pay.” If a formation is currently uneconomic to drill, but the Company maintains the ability to drill it in the future, the Company effectively holds a call option on the breakeven price of drilling for the present value of reserves in the ground. This is particularly true in the Permian, which holds several pay zones, which are potentially economic over time at different commodity prices.

Managing Risks in the Company’s Portfolio

Granite Ridge inherently faces a number of risks in the course of executing its business, and it seeks to use a number of different techniques to mitigate key risks.

(1) Commodity Price Risk

One of the largest risks to returns in oil and gas is commodity price risk. In an effort to reduce volatility of returns, Granite Ridge uses strategic hedging on current production coupled with borrowing bases/debt facilities to moderate commodity price risk and enhance returns. Typically, the Company targets hedging 50% to 75% of producing reserves for 12 to 24 months using a combination of swaps, collars and three-way producer collars.

(2) Non-Control Risk

Because Granite Ridge purchases non-controlled assets, it faces key risks regarding drilling and field operations. The Company attempts to mitigate the uncertainty of drilling pace in a variety of ways including direct contact with operators, conducting drill pace sensitivities during underwriting, understanding lease holding requirements, and evaluating JOA terms for well proposals. The Company also uses forensic audit techniques with its operators as part of the accounting process.

(3) Environmental and Regulatory Risk

The Company teams with experienced operators, who not only have technical expertise, but also have significant amounts of time and money invested in strong health, safety, and environmental policies. Where practical and necessary, the Company hires environmental consultants to inspect properties it is purchasing.

Industry Operating Environment

The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of taxation, energy, climate change and the environment, political and social developments in the Middle East and Russia, demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.

Oil and natural gas prices have been, and Granite Ridge expects may continue to be, volatile. Lower oil and gas prices not only decrease the Company’s revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that the Properties can economically produce. Among other things, drilling operations and related activities can be significantly impacted by the accuracy of the estimation of reserves and the effect on those reserves of fluctuating market prices. If

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commodity prices decline, the cost of developing, completing, and operating a well may not decline in proportion to the prices that are received for the production, resulting in higher operating and capital costs as a percentage of revenues. While lower commodity prices may reduce the Company’s future net cash flow from operations of the assets in which it invests, Granite Ridge expects to have sufficient liquidity to continue participation in development of its oil and gas properties. In addition, Granite Ridge utilizes an active commodity hedging program that is designed to help stabilize the volatile commodity pricing environment and protect cash flows in a potential downturn.

Development

Granite Ridge primarily engages in oil and natural gas exploration and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include the Company’s acreage. In addition, Granite Ridge acquires wellbore-only working interests in wells in which it does not hold the underlying leasehold interests from third parties unable or unwilling to participate in particular well proposals. Granite Ridge typically depends on drilling partners to propose, permit, and initiate the drilling of wells. Prior to commencing drilling, Granite Ridge’s operating partners are required to provide all owners of oil, natural gas, and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. The Company assesses each participation opportunity in any given well on a case-by-case basis and expects to meet its return thresholds based upon its estimates of ultimate recoverable oil and natural gas from such well, forward curve pricing, expected oil and gas prices, expertise of the operator in such well, and completed well costs from each project, as well as other factors. Historically, Granite Ridge has participated pursuant to its working interests in a vast majority of the wells proposed to the Company. However, declines in oil prices typically reduce both the number of well proposals the Company receives and the proportion of well proposals in which the Company elects to participate. The Manager’s land and engineering team uses an extensive database to assist the Company in making these economic decisions. Given the Company’s large acreage footprint and substantial number of well participations, the Company believes it can make relatively accurate decisions regarding the economics of well participation.

Historically, Granite Ridge has not managed its commodities marketing activities internally. Instead, the Company’s operating partners generally market and sell oil and natural gas produced from wells in which the Company has an interest. The Company’s operating partners coordinate the transportation of the Company’s oil and gas production from its wells to appropriate pipelines or rail transport facilities pursuant to arrangements that they negotiate and maintain with various parties purchasing the production. Using its commodity hedging program, Granite Ridge may, from time to time, enter into financial hedging contracts to help mitigate pricing risk and volatility with respect to differentials.

Competition

Although Granite Ridge focuses on a target asset class and deal size where it believes that competition and costs are reduced as compared to the broader oil and natural gas industry, the overall industry remains intensely competitive, and the Company competes with other oil and natural gas exploration and production companies, some of which have substantially greater resources than the Company has and may be able to pay more for exploratory prospects and productive oil and natural gas properties, and competition for the Company’s target asset classes is subject to increase in the future. The Company’s larger or integrated competitors may be better able to absorb the burden of existing, as well as any changes to, federal, state, and local laws and regulations than the Company can, which would adversely affect its competitive position. The Company’s ability to acquire additional properties in the future is dependent upon its ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Marketing and Customers

The market for oil and natural gas that will be produced from the Properties depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation and storage facilities, demand for oil and natural gas, the marketing of

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competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

The Company’s oil production is expected to be sold at prices tied to the spot oil markets. The Company’s natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. Granite Ridge relies on its operating partners to market and sell its production. The Company’s operating partners include a variety of exploration and production companies, from large publicly-traded companies to small, privately-owned companies. Granite Ridge does not believe the loss of any single operator would have a material adverse effect on it as a whole.

Title to Properties

The Company’s oil and natural gas properties are subject to customary royalty and other interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes, and other burdens, including other mineral encumbrances and restrictions. At the closing of the Business Combination, Granite Ridge entered into the Credit Agreement with Texas Capital Bank, as administrative agent, and the lenders named therein, secured by a first priority mortgage and security interest in substantially all assets of Granite Ridge and its restricted subsidiaries. Granite Ridge does not believe that any of these burdens materially interfere with the use of the Properties.

Granite Ridge believes that it has satisfactory title to, or rights in, the Properties. As is customary in the oil and gas industry, due diligence investigation of title is made at the time of acquisition of any properties.

Seasonality

Winter weather events and conditions, such as ice storms, freezing conditions, droughts, floods, and tornados, and lease stipulations can limit or temporarily halt the drilling and producing activities of the Company’s operating partners and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of the Company’s operating partners and materially increase the Company’s operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt the Company’s operating partners’ operations.

Principal Agreements Affecting the Company’s Business

Granite Ridge generally does not own physical real estate but, instead, the Company’s acreage is primarily comprised of leasehold interests subject to the terms and provisions of lease agreements that provide Granite Ridge the right to participate in drilling and maintenance of wells in specific geographic areas. Lease arrangements that comprise the Company’s acreage positions are generally established using industry-standard terms that have been established and used in the oil and natural gas industry for many years. Many of the Company’s leases are or were acquired from other parties that obtained the original leasehold interest prior to the Company’s acquisition of the leasehold interest.

In general, the Company’s lease agreements stipulate three-to-five year terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the leased acreage in the applicable spacing unit is considered developed acreage and is held by production. Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. Given the current pace of drilling in the areas of the Company’s operations, Granite Ridge does not believe lease expiration issues will materially affect its acreage position.

At the closing of the Business Combination, Granite Ridge entered into the MSA with Manager, pursuant to which Manager supplies land, accounting, engineering, finance, and other back-office services to Granite Ridge in connection with continued management of the Properties contributed to Granite Ridge as part of the Business Combination. Please read the section entitled “Certain Relationships and Related Party Transactions — Management Services Agreement” for more information.

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Governmental Regulation and Environmental Matters

The Company’s operations are subject to various rules, regulations, and limitations impacting the oil and natural gas exploration and production industry as whole.

Regulation of Oil and Natural Gas Production

The Company’s oil and natural gas exploration and production business and development and operation of the Properties are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota, Montana, Louisiana, Colorado, Oklahoma, New Mexico, and Texas require permits for drilling operations, drilling bonds or other forms of financial security, and reports concerning operations, and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion, and production, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the current administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands. The effect of these regulations is to limit the amount of oil and natural gas that can be produced from the wells in which Granite Ridge participates and to limit the number of wells or the locations at which the Company’s operating partners can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties or other liabilities. The regulatory burden on the oil and natural gas industry will most likely increase the Company’s cost of doing business and may affect the Company’s profitability. Because such rules and regulations are frequently amended or reinterpreted, and typically become more stringent over time, Granite Ridge is unable to predict the future cost or impact of its and its operating partners’ compliance with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on the Company’s financial condition and profitability. Additionally, currently unforeseen environmental incidents may occur on the Properties or past non-compliance with environmental laws or regulations may be discovered, resulting in unforeseen liabilities. Additional proposals, proceedings, and regulations that affect the oil and natural gas industry are regularly considered by Congress; the courts; federal regulatory agencies such as the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency, and the Bureau of Land Management; and state legislatures and regulatory authorities. Granite Ridge cannot predict when or whether any such proposals may become effective, the substance of those regulations, or the outcome of such proceedings. Therefore, Granite Ridge is unable to predict with certainty the future compliance costs or implications of compliance on profitability.

Regulation of Transportation of Oil

Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms, and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted, and market-based rates may be permitted in certain circumstances.

Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. On January 20, 2022, the FERC established a new price index for the five-year period which commenced on July 1, 2021.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are

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equally applicable to all comparable shippers, Granite Ridge believes that the regulation of oil transportation rates will not affect operations on the Properties in any way that is of material difference from those of its competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. In Texas, when oil or gas pipelines operate at full capacity, access is generally governed by pro-rationing rules established by the Railroad Commission of Texas (“RRC”), in addition to certain pro-rationing provisions that may be set forth in the pipelines’ published tariffs. Accordingly, Granite Ridge believes that access to oil pipeline transportation services generally will be available to its operating partners to the same extent as to the Company’s similarly situated competitors.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.

Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, Granite Ridge believes that the regulation of similarly situated intrastate natural gas transportation in any states in which the Company’s operating partners operate and ship natural gas on an intrastate basis will not affect the Company’s operations in any way that is of material difference from those of the Company’s competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that is produced from wells in which Granite Ridge holds an interest, as well as the revenues it receives for sales of natural gas.

Environmental Matters

A variety of stringent federal, tribal, state, and local laws and regulations govern the environmental aspects of the oil and gas business. Any noncompliance with these laws and regulations could subject Granite Ridge or any of its properties to material administrative, civil, or criminal penalties; investigatory or remedial obligations; injunctive relief, or other liabilities. Additionally, compliance with these laws and regulations may, from time to time, result in increased costs of operations, delay in operations, or decreased production, and may affect acquisition costs.

The permits required for development and construction of and operations on the Properties may be subject to revocation, modification and renewal by issuing authorities, and such permitting could cause delays in development, construction, or operation of the Properties, thus increasing costs and potentially affecting the Company’s profitability. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of the Company’s management and Manager, the operators of the Properties are in substantial compliance with current applicable environmental laws and regulations, and Granite Ridge has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws

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and regulations or in interpretations thereof could have a significant impact on Granite Ridge or any of its properties or operating partners, as well as the oil and natural gas industry in general.

The federal Clean Air Act (“CAA”) and comparable state laws and regulations impose obligations related to the emission of air pollutants, including emissions from oil and gas sources. Under the CAA and comparable state laws, the Environmental Protection Agency (“EPA”) and state environmental regulatory agencies have developed stringent regulations governing both permitting of emissions and emissions of certain air pollutants at specified sources, including certain oil and gas sources. Both existing CAA and state regulations, and any future regulations, may require pre-approval for the construction, expansion, or modification of certain facilities that produce, or which are expected to produce, air emissions. Such regulations may also impose stringent air permit requirements, limit natural gas venting and flaring activity, and require the use of specific equipment or technologies to control emissions. Under the CAA, the EPA has enacted final regulations requiring owners and operators of certain facilities that emit greenhouse gases above certain thresholds to report those emissions. The EPA has also promulgated regulations establishing construction and operating permit requirements for greenhouse gas emissions from stationary sources that already emit conventional pollutants (i.e., sulfur dioxide, particulate matter, nitrogen dioxide, carbon monoxide, ozone, and lead) above certain thresholds. Further, the CAA requires that owners and operators of stationary sources producing, processing, and storing extremely hazardous substances have a general duty to identify hazards associated with an accidental release, design and maintain a safe facility, and minimize the consequences of any releases that occur. The CAA further requires such facilities that handle more than threshold amounts of extremely hazardous substances to develop Risk Management Plans intended to prevent and minimize impacts if releases do occur.

CAA regulations also include New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production, storage, transportation, and processing activities. These rules currently require all oil or natural gas wells that have been hydraulically fractured or refractured since November 30, 2016 to be completed using so-called “green completion” technology, which significantly reduces VOC emissions, and has the co-benefit of also limiting methane, a greenhouse gas. These regulations, referred to as NSPS Subpart OOOO and OOOOa, also apply to storage tanks and other equipment in the affected oil and natural gas industry segments, and, commencing with Subpart OOOOa, were designed to also limit methane from new and modified sources in the oil and gas sector. The EPA has since modified and rolled back various aspects of the rules, including removal of the transmission and storage sectors of the oil and gas industry from regulation and of the methane-specific standards for the production and processing segments of the industry. Subsequently, Congress partially overturned that rollback in June 2021. Most recently, on November 2, 2021, the EPA proposed to revise and add to the NSPS program rules, which, if adopted, could have a significant impact on the upstream and midstream oil and gas sectors. The proposed rules would formally reinstate methane emission limitations for new and modified facilities. The proposed rules also would regulate, for the first time under the NSPS program, existing oil and gas facilities. Specifically, EPA’s proposed new rule would require states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities.

The federal Clean Water Act (“CWA”) and comparable state laws and regulations impose strict obligations related to discharges of pollutants and dredge and fill material into regulated bodies of water, including wetlands. The discharge of pollutants into regulated waters is prohibited except in accordance with a permit issued by the EPA, the United States Army Corps of Engineers (“USACE”), or state agency or tribe with a delegated CWA permit program. For example, permitting of discharges of stormwater associated with oil and gas facility construction or operation activities may also be required. In addition, compliance with CWA requirements could limit the locations where wells, other oil and natural gas facilities, and associated access resources can be constructed.

Since the term “Waters of the United States” (“WOTUS”) was defined in a joint rulemaking by the EPA and the USACE in May 2015, the meaning of WOTUS has been heavily litigated and subject to further rulemaking. Most recently, on January 24, 2022, the U.S. Supreme Court agreed to hear a case to determine the propriety of the “significant nexus” interpretation of the rule, which could further impact the scope of the definition of WOTUS. Sackett v. Env’t Prot. Agency, No. 21-454, 142 S. Ct. 896 (2022). Oral

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arguments for Sackett were held on October 3, 2022. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations may be triggered during development and operation of the Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of the Properties.

The Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the federal CWA, imposes duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain Spill Prevention, Control, and Countermeasure (“SPCC”) Plans.

The federal Safe Drinking Water Act (“SDWA”), its implementing regulations, and delegated regulatory programs (e.g., state programs) impose requirements on drilling and operation of underground injection wells, including injection wells used for the injection disposal of oil and gas wastes, such as produced water. In addition, the EPA has asserted authority under the SDWA to regulate hydraulic fracturing that uses diesel fuel. The EPA directly administers the Underground Injection Control (“UIC”) program in some states, and in others, administration of all or portions of the program is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. In addition, because some states, including Oklahoma and Texas, have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have issued directives to operators and/or have adopted or are considering additional regulations regarding such disposal methods. Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Properties to dispose of produced water and ultimately increase the cost of operation of the Properties or delay production schedules. For example, in 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Furthermore, in response to a number of earthquakes in recent years in the Midland Basin, in September 2021 the RRC announced that it will not issue any new saltwater disposal (“SWD”) well permits in an area known as the Gardendale Seismic Response Area (“SRA”), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well. In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. And in October 2021 and January 2022, respectively, the RRC identified two additional SRAs: the Northern Culberson-Reeves SRA and the Stanton SRA. Operators in the Northern Culberson-Reeves and Stanton SRAs have implemented seismic response plans, which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff.

In addition, several cases have in recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. On January 14, 2021, the EPA issued a guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. However, on September 16, 2021, the EPA rescinded its January 14, 2021 guidance. If

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in the future CWA permitting is required for saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund, the costs of permitting and compliance for injection well operations by the companies that operate the Properties could increase.

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose strict liability, and in some cases joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who generated, transported, disposed or arranged for the transport or disposal of a hazardous substance. Such persons may be responsible for the costs of investigating releases of hazardous substances, remediating releases of hazardous substances, and compensating for damages to natural resources. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action, including the costs of certain health studies. From time to time, the EPA may designate additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or reopener of Superfund sites that previously received regulatory closure. For example, on August 26, 2022, EPA announced a proposal to designate as hazardous substances perfluorooctanoic acid (“PFOA”) and perfluorooctanesulfonic acid (“PFOS”), which have been commonly used in a variety of industrial and consumer products. While CERCLA does contain an exclusion for petroleum, the exclusion is limited and could ultimately be repealed, and oil and gas facilities often contain hazardous substances subject to regulation under CERCLA. Although the non-operating status of the Company’s interests in the Properties likely presents a lower risk that it would be held subject to CERCLA liability, should Granite Ridge or its operating partners become subject to strict liability under federal or state laws for environmental damages caused by previous owners or operators of properties Granite Ridge purchases, without regard to fault, the Company’s profitability could be negatively affected.

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Most wastes associated with the exploration, development, and production of oil or gas, including drilling fluids and produced water, are currently regulated as non-hazardous wastes pursuant to an exemption from regulation as a hazardous waste under RCRA. However, certain wastes generated at oil and gas exploration, development, production, and transmission sites are regulated as hazardous under RCRA. It is also possible that “RCRA-exempt” exploration and production wastes currently regulated as non-hazardous could be regulated as hazardous wastes in the future.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, and natural resources. These statutes include the federal Endangered Species Act, the Migratory Bird Treaty Act (“MTBA”), the Bald and Golden Eagle Protection Act, the Clean Water Act, CERCLA, analogous state laws, and each of their implementing regulations. The United States Fish and Wildlife Service (“USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances, sediments, or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.

The purpose of the Occupational Safety and Health Act (“OSHA”), comparable state statutes, and each of their implementing regulations is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), and comparable state statutes and any implementing regulations thereof may require disclosure of information about hazardous materials stored, used, or produced in operations on the Properties and that such information be provided to employees, state and local governmental authorities, and/or citizens, as applicable.

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These regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment, additional evaluation or assessment, or more stringent permitting or environmental protection measures could have a material adverse impact on the Company’s business, results of operations, and financial condition.

Scrutiny of oil and gas production activities continues in other ways. The federal government has in recent years undertaken several studies of the oil and gas industry’s potential impacts. For example, in 2016 the EPA published a final report of a four-year study focused on the possible relationship between hydraulic fracturing and drinking water. In its assessment, the EPA concluded that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. In addition, in May 2022, the U.S. Government Accountability Office (“GAO”) released a study on methane emissions from oil and gas development, which included a recommendation that the Bureau of Land Management (“BLM”) consider whether to require gas capture plans, including gas capture targets, from operators on federal lands. The results of these studies or similar governmental reviews could spur initiatives to further regulate oil and gas production activities.

Several states, including states where the Properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing. However, in May 2015, the Texas legislature enacted a bill preempting local bans on hydraulic fracturing. In December 2014, former New York Governor Andrew Cuomo banned hydraulic fracturing state-wide, and this ban was recently codified in the state’s Fiscal Year 2021 budget. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. However, in April 2019 the Colorado legislature subsequently enacted “SB 181” that gave significant local control over oil and gas well head operations. Municipalities in Colorado have enacted local rules restricting oil and gas operations based on SB 181; nevertheless, in November 2020, a Colorado district court upheld the prior Colorado Supreme Court ruling in finding that a hydraulic fracking ban in the City of Longmont was preempted by state law. Granite Ridge cannot predict whether other similar legislation in other states will ever be enacted and if so, what the provisions of such legislation would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect the Company’s operating partners and the Company’s revenue and results of operations.

The National Environmental Policy Act (“NEPA”) establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. If, for example, the Company’s third-party operating partners conduct activities on federal land, receive federal funding, or require federal permits, such activities may be covered under NEPA. Certain activities are subject to robust NEPA review which could lead to delays and increased costs that could materially adversely affect the Company’s revenues and results of operations. Other activities are covered under categorical exclusions which results in a shorter NEPA review process. In April 2022, the Biden Administration finalized a rule to undo some of the changes to NEPA enacted under the Trump Administration that were intended to streamline NEPA review (the “2020 NEPA Rule”). The April 2022 rule promulgation is considered phase one of a two-phase review of the 2020 NEPA Rule that was announced by the Biden Administration to emphasize the need to review federal actions for climate change and environmental justice impacts, among other factors. These new and (if enacted) additional anticipated changes to the NEPA review process would affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.

Climate Change

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CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on the Properties. Further, the Inflation Reduction Act (“IRA”), which passed in August 2022, includes a charge for methane emissions from specific types of facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year, and although the IRA generally provides for a conditional exemption under certain circumstances, the change applies to emissions that exceed an established emissions threshold for each type of covered facility. The charge starts at $900 per metric ton of methane in 2025 (using 2024 data), and increases to $1,500 after two years.

While Congress has from time to time considered legislation to reduce emissions of GHGs, in recent years there has not been significant activity at the federal level in the form of adopted legislation aimed at reducing GHG emissions. In the absence of comprehensive federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact Granite Ridge, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require it to incur costs to reduce emissions of GHGs associated with its operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from the Properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas or increased fuel or energy efficiency requirements, that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their greenhouse gas emissions through individually determined reduction goals every five years after 2020. While the United States under the Trump Administration withdrew from the Paris Agreement effective November 4, 2020, President Biden recommitted the United States to the Paris Agreement on January 20, 2021. Finally, it should be noted that climate changes may have significant physical effects, such as increased frequency and severity of storms, freezes, floods, drought, hurricanes and other climatic events; if any of these effects were to occur, they could have an adverse effect on the operations of the Company’s operating partners, and ultimately, the Company’s business. In addition, spurred by increasing concerns regarding climate change, the oil and gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals.

Environmental, social, and governance (“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and stockholders across the industry. While reporting on ESG metrics is currently voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place. Furthermore, in March 2022 the Securities and Exchange Commission (“SEC”) proposed rule amendments that, if adopted, would require public companies to disclose certain climate-related information in their public filings. If adopted, the new requirements would begin to phase-in starting in Fiscal Year 2023 and would begin to apply to filings made in 2024.

Company Information

Granite Ridge is a Delaware corporation, formed on May 9, 2022 to be the successor following the Business Combination. Prior to the closing of the Business Combination, Granite Ridge was a privately held company with no operations. In connection with the closing of the Business Combination, Granite Ridge common stock and Granite Ridge warrants are currently listed on the New York Stock Exchange under the symbols “GRNT” and “GRNT WS,” respectively. For more information, please see the sections

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entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Combination” and “Certain Relationships and Related Party Transactions — Business Combination Agreement.”

Granite Ridge files reports, proxy statements and other information with the SEC as required by the Exchange Act. Our SEC filings are available to the public on a website maintained by the SEC located at www.sec.gov. We also plan to make such filings available on our website at www.graniteridge.com. Through our website, we will make available, free of charge, annual, quarterly and current reports, proxy statements and other information as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. The information contained on, or that may be accessed through, our website is not part of, and is not incorporated into, this prospectus.

Human Capital Resources

As of January 9, 2023, Granite Ridge had two full time employees. Granite Ridge has entered into the MSA with Manager, pursuant to which Manager’s approximately 20 employees provide general and administrative, engineering, land, contract administration, tax, accounting, legal and compliance services to Granite Ridge.

Office Locations

The Company’s principal offices are located at 5217 McKinney Avenue, Suite 400, Dallas, TX 75205. The Company shares a portion of the Manager’s office space (which consists of approximately 11,700 square feet), pursuant to the MSA. Granite Ridge believes its office space is sufficient to meet its needs and that additional office space can be obtained if necessary.

Legal Proceedings

We are not currently a party to, nor are we aware of, any legal proceedings, investigations or claims which, in the opinion of our management, are likely to have a material adverse effect on our business, financial condition or results of operations. 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.

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PROPERTIES OF GRANITE RIDGE

Estimated Net Proved Reserves

Following the closing of the Business Combination, Granite Ridge operates and controls the business and affairs and assets previously controlled by the Funds. The tables below summarize the Company’s estimated net proved reserves at December 31, 2021, by the Fund that held such reserves as of that date, based on reports prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), the Company’s third-party independent reserve engineers for the year ending December 31, 2021. In preparing its reports, NSAI evaluated properties representing all of the Company’s proved reserves at December 31, 2021 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. The Company’s estimated net proved reserves in the table below do not include probable or possible reserves and do not in any way include or reflect the Company’s commodity derivatives.

	December 31, 2021
	Proved Reserves (MBoe)(1)		% of Total
Fund III
SEC Proved Reserves:
Developed		11,934		43%
Undeveloped		15,511		57%
Total Proved Properties		27,445		100%
Fund I
SEC Proved Reserves:
Developed		870		95%
Undeveloped		47		5%
Total Proved Properties		917		100%
Fund II
SEC Proved Reserves:
Developed		7,898		51%
Undeveloped		7,450		49%
Total Proved Properties		15,348		100%

(1)

The table above values oil and natural gas reserve quantities as of December 31, 2021 assuming constant base prices of $66.55 per barrel of oil and $3.598 per MMBtu of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, before adjustment to reflect applicable transportation and quality differentials.

Estimated net proved reserves at December 31, 2021 were 43,710 MBoe, a 51% increase from estimated net proved reserves of 28,948 MBoe at December 31, 2020. The increase was primarily due to the impact of our 2021 acquisitions. Increased development activity in 2021 led to an increase in capital spending as well as an increase in the number of undeveloped drilling locations reflected in the Company’s 2021 proved reserve estimates. As a result of the higher activity levels and our 2021 acquisitions, the number of proved undeveloped wells included in the reserves of Granite Ridge was increased from 30.83 net wells in 2020 to 35.18 net wells in 2021.

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The following table sets forth summary information by reserve category with respect to estimated proved reserves at December 31, 2021:

	SEC Pricing Proved Reserves(1)
	Reserve Volumes								PV-10(3)
Reserve Category	Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)(2)		%		Amount (In thousands)			%
Fund III
PDP Properties		5,871		28,096		10,554		38%		$	247,003		44%
PDNP Properties		944		2,614		1,380		5%			38,779		7%
PUD Properties		10,046		32,791		15,511		57%			270,100		49%
Total		16,861		63,501		27,445		100%		$	555,882		100%
Fund I
PDP Properties		599		1,319		819		89%		$	15,312		92%
PDNP Properties		31		118		51		6%			726		4%
PUD Properties		27		121		47		5%			625		4%
Total		657		1,558		917		100%		$	16,663		100%
Fund II
PDP Properties		4,182		17,615		7,118		46%		$	132,450		64%
PDNP Properties		31		4,495		780		5%			9,437		5%
PUD Properties		1,087		38,178		7,450		49%			63,798		31%
Total		5,300		60,288		15,348		100%		$	205,685		100%

(1)

The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2021 based on average prices of $66.55 per barrel of oil and $3.598 per MMbtu of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period.

(2)

Boe are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas.

(3)

Pre-tax PV10% or “PV-10,” may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure. The amounts disclosed in the table above include net abandonment costs while the reserve reports provided by Netherland, Sewell & Associates (“NSAI”) do not include costs related to abandonment. Discounted net abandonment costs for Fund III, Fund I, and Fund II were $419 thousand, $87 thousand and $602 thousand, respectively, as of December 31, 2021. See “Reconciliation of PV-10 to Standardized Measure” below.

The table above assumes prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes. The information in the table above does not give any effect to or reflect the Company’s commodity derivatives.

Reconciliation of PV-10 to Standardized Measure

PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure for proved reserves calculated using SEC pricing. PV-10 is a computation of the Standardized Measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the Standardized Measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Granite Ridge believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the

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Company’s estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to other companies. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves or for reserves calculated using prices other than SEC prices. Granite Ridge uses this measure when assessing the potential return on investment related to its oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure of discounted future net cash flows. The Company’s PV-10 measure and the Standardized Measure of discounted future net cash flows do not purport to represent the fair value of its oil and natural gas reserves.

The following table reconciles the pre-tax PV10% value of the Company’s SEC Pricing Proved Reserves by the Fund that held the reserves as of December 31, 2021 to the Standardized Measure of discounted future net cash flows.

SEC Pricing Proved Reserves
(In thousands)

Standardized Measure Reconciliation
Fund III
Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%)	$	555,882
Future Income Taxes, Discounted at 10%		(3,317)
Standardized Measure of Discounted Future Net Cash Flows	$	552,565
Fund I
Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%)	$	16,663
Future Income Taxes, Discounted at 10%		(89)
Standardized Measure of Discounted Future Net Cash Flows	$	16,574
Fund II
Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%)	$	205,685
Future Income Taxes, Discounted at 10%		(473)
Standardized Measure of Discounted Future Net Cash Flows	$	205,212

Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond Granite Ridge’s control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves. Further, the Company’s actual realized price for its oil and natural gas is not likely to average the pricing parameters used to calculate the Company’s proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from the Properties will vary from reserve estimates.

Additional discussion of the Company’s proved reserves is set forth under Note 2: “Summary of Significant Accounting Policies — Oil and Natural Gas Properties” and Note 5: “Oil and Natural Gas Properties” to the Company’s and the Funds’ annual audited financial statements included later in this prospectus.

Proved Undeveloped Reserves

At December 31, 2021, the Company had approximately 23,008 MBoe of proved undeveloped reserves as compared to 12,798 MBoe at December 31, 2020. A reconciliation of the change in proved undeveloped reserves by Fund during 2021 is as follows:

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	MBoe
Fund III(1)
Estimated Proved Undeveloped Reserves at 12/31/2020		5,290
Revisions of Previous Estimates		1,088
Extensions, Discoveries and Other Additions		3,119
Acquisition of Reserves		7,532
Divestiture of Reserves		—
Developed		(1,518)
Estimated Proved Undeveloped Reserves at 12/31/2021		15,511
Fund I(2)
Estimated Proved Undeveloped Reserves at 12/31/2020		918
Revisions of Previous Estimates		(87)
Extensions, Discoveries and Other Additions		9
Acquisition of Reserves		—
Divestiture of Reserves		(769)
Developed		(24)
Estimated Proved Undeveloped Reserves at 12/31/2021		47
Fund II(3)
Estimated Proved Undeveloped Reserves at 12/31/2020		6,590
Revisions of Previous Estimates		1,887
Extensions, Discoveries and Other Additions		631
Acquisition of Reserves		—
Divestiture of Reserves		(20)
Developed		(1,638)
Estimated Proved Undeveloped Reserves at 12/31/2021		7,450

(1)

Notable changes in proved undeveloped reserves for the year ended December 31, 2021 included the following:

•

Revisions to previous estimates. In 2021, revisions to previous estimates increased proved undeveloped reserves by 1,126 MBoe due to higher crude oil and natural gas prices. The increase was partially offset by a decrease in proved undeveloped reserves of 38 MBoe due to the removal of locations from operator drill schedules on acreage owned by Fund III. There were no adjustments attributable to well performance.

•

Extensions, discoveries and other additions. In 2021, proved undeveloped reserves increased by 1,793 MBoe as a result of new locations added to the operator drill schedules on acreage owned by Fund III, and by 1,326 MBoe as a result of additional drilling locations purchased during the year.

•

Acquisition of reserves. In 2021, acquisitions of oil and natural gas properties in the Permian, Bakken and DJ Basins increased proved undeveloped reserves by 7,532 MBoe. See Note 5: “Oil and Natural Gas Properties” to the audited combined financial statements of Grey Rock Energy Fund III included elsewhere in this prospectus.

•

Developed. In 2021, development of oil and natural gas properties resulted in the conversion of 1,518 MBoe from proved undeveloped reserves to proved developed reserves. During the year ended December 31, 2021, Fund III incurred development costs of approximately $9,472 thousand related to these locations.

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(2)

Notable changes in proved undeveloped reserves for the year ended December 31, 2021 included the following:

•

Revisions of previous estimates. In 2021, revisions to previous estimates decreased proved undeveloped reserves by 112 MBoe due to the removal of locations from operator drill schedules on acreage owned by Fund I. The decline was partially offset by an increase in proved undeveloped reserves of 25 MBoe due to higher crude oil and natural gas price adjustments. There were no adjustments attributable to well performance.

•

Extensions, discoveries and other additions. In 2021, proved undeveloped reserves increased by 9 MBoe as a result of new locations added to the operator drill schedules on acreage owned by Fund I.

•

Divestiture of reserves. In 2021, total divestitures of proved undeveloped reserves of 769 MBoe were primarily attributable to the divestiture of oil and natural gas properties in the Permian Basin. See Note 5: “Oil and Natural Gas Properties” to the audited consolidated financial statements of Grey Rock Energy Fund, LP included elsewhere in this prospectus.

•

Developed. In 2021, development of oil and natural gas properties resulted in the conversion of 24 MBoe from proved undeveloped reserves to proved developed reserves. During the year ended December 31, 2021, Fund I incurred development costs of approximately $12 thousand related to these locations.

(3)

Notable changes in proved undeveloped reserves for the year ended December 31, 2021 included the following:

•

Revisions of previous estimates. In 2021, revisions to previous estimates increased proved undeveloped reserves by 2,487 MBoe due to higher crude oil and natural gas. The increase was partially offset by a decrease in proved undeveloped reserves of 600 MBoe due to the removal of locations from operator drill schedules on acreage owned by Fund II. There were no adjustments attributable to well performance.

•

Extensions, discoveries and other additions. In 2021, proved undeveloped reserves increased by 631 MBoe as a result of new locations added to the operator drill schedules on acreage owned by Grey Rock Energy Fund II.

•

Divestiture of reserves. In 2021, total divestiture of proved undeveloped reserves of 20 MBoe were primarily attributable to the divestiture of oil and natural gas properties in the Permian Basin. See Note 5: “Oil and Natural Gas Properties” to the audited combined financial statements of Grey Rock Energy Fund II included elsewhere in this prospectus.

•

Developed. In 2021, development of oil and natural gas properties resulted in the conversion of 1,638 MBoe from proved undeveloped reserves to proved developed reserves. During the year ended December 31, 2021, Fund II incurred development costs of approximately $8,153 thousand related to these locations.

The Company’s proved undeveloped locations were increased from 30.83 net wells at December 31, 2020 to 35.18 net wells at December 31, 2021 due to 2021 acquisitions, higher commodity prices, and increased development activity. Granite Ridge expects that its proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled including the Company’s acreage. All locations comprising the Company’s remaining proved undeveloped reserves are forecasted to be drilled within five years from initially being recorded in accordance with the Company’s development plan.

At December 31, 2021, the PV-10 value of the Company’s proved undeveloped reserves amounted to 43% of the PV-10 value of its total proved reserves. There are numerous uncertainties regarding the proved and undeveloped reserves. The development of these reserves is dependent upon a number of factors which include, but are not limited to: financial targets such as drilling within cash flow or reducing debt, drilling of obligatory wells, satisfactory rates of return on proposed drilling projects, and the levels of drilling activities by operators in areas where Granite Ridge holds leasehold interests. During 2021, there was an increase in development capital spending by 37% compared to 2020. With 51% of the PV-10 value of the Company’s total proved reserves supported by producing wells, Granite Ridge believes it will have sufficient cash flows and adequate liquidity to execute its development plan.

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Independent Petroleum Engineers

Granite Ridge has engaged NSAI to independently prepare its estimated net proved reserves. NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical expert primarily responsible for preparing the estimates set forth in the NSAI 2021 Reserve Reports is Mr. Nathan Shahan. Mr. Shahan, a Licensed Professional Engineer in the State of Texas (No. 102389), has been practicing consulting petroleum engineering at NSAI since 2007 and has over 5 years of prior industry experience. He graduated from Texas A&M University in 2002 with a Bachelor of Science Degree in Petroleum Engineering and in 2007 with a Master of Engineering Degree in Petroleum Engineering. Mr. Shahan meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. He is a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.

In accordance with applicable requirements of the SEC, estimates of the Company’s net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).

The reserves set forth in the NSAI report for the Properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in the Company’s report are estimated by analogy. The estimates of the reserves, future production, and income attributable to Properties are prepared using widely industry-accepted petroleum economic software packages, as well as NSAI’s own proprietary petroleum economic software.

To estimate economically recoverable oil and natural gas reserves and related future net cash flows, Granite Ridge considers many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic productivity from a reservoir is to be determined as of the effective date of the report. With respect to the property interests Granite Ridge owns, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.

The reserve data set forth in the NSAI report represents only estimates, and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond Granite Ridge’s control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. See “Risk Factors — Granite Ridge’s

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estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of Granite Ridge’s reserves.”

Internal Controls Over Reserves Estimation Process

The Company utilizes a third-party reservoir engineering firm, NSAI, as the independent reserves evaluator for the Company’s assets. In addition, Manager employs an internal reservoir engineering department which is led by Grey Rock’s Executive Vice President (EVP) — Engineering, who is responsible for overseeing the internal preparation of Granite Ridge’s reserves pursuant to the MSA. Grey Rock’s EVP — Engineering has a degree in petroleum engineering from the University of Calgary, and has over 20 years of oil and gas experience, with more than 15 years focused on reservoir engineering.

Manager’s technical team meets with Granite Ridge’s independent third-party engineering firm to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with Manager’s prescribed internal control procedures. Manager’s internal controls over the reserves estimation process includes inter-departmental verification of input data into Manager’s reserves evaluation software such as, but not limited to the following:

•

Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in Manager’s reserves database;

•

Review of working interests and net revenue interests in Manager’s reserves database against Manager’s well ownership system;

•

Review of historical realized prices and differentials from index prices as compared to the differentials used in Manager’s reserves database;

•

Review of updated projected capital costs for upcoming projects;

•

Review of internal reserve estimates by well and by area by Manager’s reservoir engineers;

•

Discussion of material reserve variances among Manager’s reservoir engineer and Granite Ridge’s executive management; and

•

Review of a preliminary copy of the reserve report by management.

Production, Price and Production Expense History

The price that Granite Ridge receives for the oil and natural gas produced from wells in which it holds interests is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Oil supply in the United States has grown dramatically over the past few years, and the supply of oil could impact oil prices in the United States if the supply outstrips domestic demand. Historically, commodity prices have been volatile, and Granite Ridge expects that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on the Company’s financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and the Company’s ability to access capital markets.

The following table sets forth information regarding the Company’s oil and natural gas production, realized prices and production costs by the Fund that held the assets for the periods indicated. For additional information on price calculations, please see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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	Three Months Ended September 30,				Nine Months Ended September 30,				Years Ended December 31,
	2022		2021		2022		2021		2021		2020		2019
Fund III
Net Production:
Oil (MBbl)
Permian		519		445		1,531		1,340		1,763		515		243
Eagle Ford		83		51		256		196		239		36		81
Bakken		29		14		91		40		57		75		62
DJ		46		75		162		174		236		—		—
Total		677		585		2,040		1,750		2,295		626		386
Natural Gas (MMcf)
Permian		1,394		1,266		3,384		3,446		4,586		954		325
Eagle Ford		619		255		1,440		921		1,181		1,263		793
Bakken		49		60		149		165		235		289		191
DJ		494		791		1,603		2,031		2,759		—		—
Total		2,556		2,372		6,576		6,563		8,761		2,506		1,309
Total (MBoe)
Permian		752		656		2,095		1,914		2,527		673		297
Eagle Ford		186		94		496		349		436		246		213
Bakken		37		24		116		67		96		124		94
DJ		128		207		429		513		696		—		—
Total		1,103		981		3,136		2,843		3,755		1,043		604
Oil (Bbl) per day
Permian		5,769		4,945		5,671		4,963		4,829		1,410		665
Eagle Ford		923		570		948		725		656		98		222
Bakken		326		160		337		147		156		206		170
DJ		508		828		600		645		645		—		—
Total		7,526		6,503		7,556		6,480		6,286		1,714		1,057
Natural gas (Mcf) per day
Permian		15,490		14,066		12,530		12,763		12,562		2,614		890
Eagle Ford		6,872		2,831		5,334		3,410		3,237		3,460		2,173
Bakken		548		665		552		610		643		792		524
DJ		5,488		8,792		5,938		7,525		7,560		—		—
Total		28,398		26,354		24,354		24,308		24,002		6,866		3,587
Total (Boe) per day
Permian		8,352		7,289		7,759		7,090		6,923		1,845		813
Eagle Ford		2,067		1,042		1,837		1,293		1,195		674		584
Bakken		417		270		429		249		264		339		257
DJ		1,423		2,294		1,590		1,899		1,905		—		—
Total		12,259		10,895		11,615		10,531		10,287		2,858		1,654

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	Three Months Ended September 30,						Nine Months Ended September 30,						Years Ended December 31,
	2022			2021			2022			2021			2021			2020			2019
Average Sales Prices:
Oil (per Bbl)		$	90.95		$	68.99		$	96.72		$	59.85		$	63.47		$	38.14		$	53.96
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)			(7.34)			(3.97)			(7.54)			(1.48)			(4.51)			4.05			1.14
Oil Net of Settled Oil Derivatives (per Bbl)			83.61			65.02			89.18			58.37			58.96			42.19			55.10
Natural Gas (per Mcf)			11.19			6.47			10.03			5.78			5.92			1.77			1.89
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf)			(1.71)			(0.69)			(1.42)			(0.69)			(0.32)			0.12			0.34
Natural Gas Net of Settled Natural Gas Derivatives (per Mcf)			9.48			5.78			8.61			5.09			5.60			1.89			2.23
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives			81.75			56.82			83.95			50.16			52.61			27.12			38.56
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)			(8.46)			(4.04)			(7.89)			(2.50)			(3.51)			2.72			0.73
Realized Price on a Boe Basis Including Settled Commodity Derivatives			73.29			52.78			76.06			47.66			49.10			29.84			39.29
Average Costs:
Production Expenses (per Boe)		$	5.77		$	3.69		$	5.05		$	2.96		$	3.29		$	4.93		$	4.42

	Nine Months Ended September 30,				Years Ended December 31,
	2022		2021		2021		2020		2019
Fund I
Net Production:
Oil (MBbl)
Eagle Ford		22		28		37		49		78
Bakken		40		33		43		62		76
Permian		1		39		66		127		63
SCOOP		—		7		16		10		15
Total		63		107		162		248		232
Natural Gas (MMcf)
Eagle Ford		21		53		68		106		178
Bakken		147		183		240		272		206
Permian		3		68		77		217		145
SCOOP		—		53		120		51		87
Total		171		357		505		646		616

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	Nine Months Ended September 30,						Years Ended December 31,
	2022			2021			2021			2020			2019
Total (MBoe)
Eagle Ford			25			37			48			67			108
Bakken			65			63			83			107			110
Permian			2			51			79			164			87
SCOOP			—			16			36			18			29
Total			92			167			246			356			334
Oil (Bbl) per day
Eagle Ford			81			105			101			134			214
Bakken			148			121			118			170			208
Permian			5			145			182			349			173
SCOOP			—			26			43			27			40
Total			234			397			444			680			635
Natural gas (Mcf) per day
Eagle Ford			76			196			186			290			487
Bakken			544			677			657			744			564
Permian			12			254			211			596			398
SCOOP			—			196			330			139			238
Total			632			1,323			1,384			1,769			1,687
Total (Boe) per day
Eagle Ford			92			137			132			182			295
Bakken			240			234			228			294			302
Permian			7			187			217			449			239
SCOOP			—			59			98			50			80
Total			339			617			675			975			916
Average Sales Prices:
Oil (per Bbl)		$	94.80		$	64.45		$	52.89		$	36.74		$	53.74
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)			(5.81)			(11.62)			(8.44)			5.83			(0.78)
Oil Net of Settled Oil Derivatives (per Bbl)			88.99			52.83			44.45			42.57			52.96
Natural Gas (per Mcf)			10.67			3.57			3.32			1.04			1.60
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf)			(1.52)			(0.15)			(1.06)			(0.02)			0.04
Natural Gas Net of Settled Natural Gas Derivatives (per Mcf)			9.15			3.42			2.26			1.02			1.64
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives			85.25			49.08			41.63			27.52			40.19
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)			(6.84)			(7.78)			(7.73)			4.03			(0.47)
Realized Price on a Boe Basis Including Settled Commodity Derivatives			78.41			41.30			33.90			31.55			39.72
Average Costs:
Production Expenses (per Boe)		$	13.28		$	8.55		$	7.30		$	6.06		$	8.91

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	Nine Months Ended September 30,				Years Ended December 31,
	2022		2021		2021		2020
Fund II
Net Production:
Oil (MBbl)
Eagle Ford		86		110		146		173
Bakken		345		530		678		590
Permian		76		105		132		258
Haynesville		—		—		—		—
Total		507		745		956		1,021
Natural Gas (MMcf)
Eagle Ford		156		357		456		315
Bakken		540		1,018		1,323		930
Permian		182		271		356		447
Haynesville		7,836		2,784		3,460		5,450
Total		8,714		4,430		5,595		7,142
Total (MBoe)
Eagle Ford		112		169		222		226
Bakken		435		700		899		745
Permian		107		150		191		332
Haynesville		1,306		464		577		908
Total		1,960		1,483		1,889		2,211
Oil (Bbl) per day
Eagle Ford		319		407		400		475
Bakken		1,276		1,963		1,858		1,615
Permian		283		387		361		706
Haynesville		1		1		1		1
Total		1,879		2,758		2,620		2,797
Natural gas (Mcf) per day
Eagle Ford		577		1,322		1,250		863
Bakken		2,007		3,770		3,624		2,548
Permian		674		1,003		977		1,225
Haynesville		29,018		10,312		9,478		14,930
Total		32,276		16,407		15,329		19,566
Total (Boe) per day
Eagle Ford		416		627		608		619
Bakken		1,610		2,591		2,462		2,040
Permian		395		554		524		910
Haynesville		4,837		1,720		1,581		2,489
Total		7,258		5,492		5,175		6,058

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	Nine Months Ended September 30,						Years Ended December 31,
	2022			2021			2021			2020
Average Sales Prices:
Oil (per Bbl)		$	94.17		$	64.15		$	69.30		$	42.24
Effect of Gain (Loss) on Settled Oil Derivatives on Average Price (per Bbl)			(14.61)			(5.82)			(7.65)			6.07
Oil Net of Settled Oil Derivatives (per Bbl)			79.56			58.33			61.65			48.31
Natural Gas (per Mcf)			7.14			2.72			2.88			0.83
Effect of Gain (Loss) on Settled Natural Gas Derivatives on Average Price (per Mcf)			(0.83)			(0.23)			(0.50)			0.20
Natural Gas Net of Settled Natural Gas Derivatives (per Mcf)			6.31			2.49			2.38			1.03
Realized Price on a Boe Basis Excluding Settled Commodity Derivatives			56.14			40.34			43.62			22.17
Effect of Gain (Loss) on Settled Commodity Derivatives on Average Price (per Boe)			(7.47)			(3.61)			(5.37)			3.46
Realized Price on a Boe Basis Including Settled Commodity Derivatives			48.67			36.73			38.25			25.63
Average Costs:
Production Expenses (per Boe)		$	6.97		$	5.48		$	6.95		$	6.22

Drilling and Development Activity

The following table sets forth the number of gross and net productive and non-productive wells drilled in the years ended December 31, 2021, 2020 and 2019, by the Fund holding an interest in the wells as of such period. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. As a non-operator, Granite Ridge does not invest in exploratory wells, and instead invests exclusively in development wells. While there is the potential that development wells may yield dry holes, the Company currently has not encountered this. Therefore, drilling activity related to exploratory wells and dry holes was not applicable to the Funds in the years presented below.

	December 31,
	2021				2020				2019
	Gross		Net(1)		Gross		Net(1)		Gross		Net(1)
Fund III
Productive Development Wells:
Oil		44		7.75		40		6.75		54		10.04
Natural Gas		2		0.30		2		0.39		5		1.00
Fund I
Productive Development Wells:
Oil		16		0.17		9		0.62		57		0.62
Natural Gas		—		—		—		—		—		—
Fund II
Productive Development Wells:
Oil		114		3.08		84		5.40
Natural Gas		2		0.29		4		0.21

(1)

Net Well totals in 2021 and 2020 do not include an additional 20.78 and 6.20 net wells, respectively, from acquisitions which were already producing when acquired.

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The following table summarizes the Company’s cumulative gross and net productive oil and natural gas wells by geographic area and by the Fund that held an interest in such wells within the United States at each of December 31, 2021, 2020 and 2019. Wells are classified as oil or natural gas wells according to the predominant production stream. A significant majority of the Company’s wells in the Permian, Bakken, South Central Oklahoma Province (“SCOOP”) and DJ Basins are classified as oil wells, although they also produce natural gas and condensate. All of the Company’s wells in the Haynesville Basin are classified as natural gas wells. The Company’s wells within the Eagle Ford Basin are classified as either oil or natural gas wells.

	December 31,
	2021				2020				2019
	Gross		Net		Gross		Net		Gross		Net
Fund III
Permian		36		7.69		35		4.49		12		3.47
Eagle Ford		2		0.30		6		2.65		8		2.47
Bakken		8		0.06		1		—		39		5.10
DJ		—		—		—		—		—		—
Total:		46		8.05		42		7.14		59		11.04
Fund I
Eagle Ford		—		—		—		—		4		0.16
Bakken		16		0.17		1		0.01		23		0.32
Permian		—		—		8		0.61		10		0.03
SCOOP		—		—		—		—		20		0.11
Total:		16		0.17		9		0.62		57		0.62
Fund II
Bakken		83		2.53		19		1.86
Permian		15		0.04		44		0.54
Eagle Ford		16		0.51		21		3.00
Haynesville		2		0.29		4		0.21
Total:		116		3.37		88		5.61

See “Business of Granite Ridge — Overview — Assets of Granite Ridge” for the number of oil and gas wells by basin.

As of December 31, 2021, Granite Ridge had an additional 48 gross (2.55 net) wells in process, meaning wells that have been spud and are in the process of drilling, completing or waiting on completion.

Leasehold Properties

As of December 31, 2021, the Company’s principal assets included approximately 32,442 net acres located in the United States. The following table summarizes the Company’s estimated gross and net developed and undeveloped acreage by the Fund that held an interest in such acreage and geographic area at December 31, 2021.

	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Fund III
Permian		12,450		3,283		4,181		2,721		16,631		6,004
Bakken		3,947		1,313		—		—		3,947		1,313
Eagle Ford		4,444		968		14,307		3,551		18,751		4,519
DJ		14,537		1,475		—		—		14,537		1,475
Total:		35,378		7,039		18,488		6,272		53,866		13,311

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	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Fund I
Eagle Ford		4,724		748		—		—		4,724		748
Permian		831		102		—		—		831		102
Bakken		26,301		792		—		—		26,301		792
Total:		31,856		1,642		—		—		31,856		1,642
Fund II
Bakken		140,207		11,063		2,303		1,983		142,510		13,046
Permian		22,452		693		—		—		22,452		693
Haynesville		6,245		2,298		—		—		6,245		2,298
Eagle Ford		11,659		1,452		—		—		11,659		1,452
Total:		180,563		15,506		2,303		1,983		182,866		17,489

As of December 31, 2021, approximately 75% of the Company’s total acreage was developed. All of the Fund’s proved reserves are located in the United States.

Recent Acquisitions

Granite Ridge generally assesses acreage and other acquisition opportunities subject to near-term drilling activities on a lease-by-lease or well-by-well basis because Granite Ridge believes each acquisition opportunity is best assessed on that basis if development timing is sufficiently clear. Consistent with that approach, a significant portion of the Company’s acquisitions involve properties that are selected by us on a lease-by-lease or well-by-well basis for their participation in a well expected to be spud in the near future, and the subject leases or wells are then aggregated to complete one single closing with the transferor. As such, Granite Ridge generally views each acreage or well assignment from sellers as involving several separate acquisitions combined into one closing with the common transferor for convenience. However, in certain instances an acquisition may involve a larger number of leases presented by the transferors as a single package without negotiation on a lease-by-lease or well-by-well basis. In those instances, the Company, together with Manager, still reviews each lease and drilling opportunity on a lease-by-lease basis and well-by-well basis to ensure that the package as a whole meets the Company’s acquisition criteria and drilling expectations. See Note 5: “Oil and Natural Gas Properties” to the Company’s and the Funds’ financial statements regarding the Company’s recent acquisition activity.

Acreage Expirations

As a non-operator, Granite Ridge is subject to lease expirations if an operator does not commence the development of operations within the agreed terms of the Company’s leases. All of the Company’s leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms, unless Granite Ridge renews the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised. In addition, the Company’s leases typically provide that the lease does not expire at the end of the primary term if drilling operations have been commenced. While Granite Ridge generally expects to establish production from most of its acreage prior to expiration of the applicable lease terms, there can be no guarantee they can do so. The approximate expiration of the Company’s net acres which are subject to expire between 2022 and 2026 and thereafter, are set forth by the Fund that held an interest in such acreage below:

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	Acreage Subject to Expiration
Year Ended	Gross		Net
Fund III
December 31, 2022		5,084		384
December 31, 2023		—		—
December 31, 2024		4,681		2,720
December 31, 2025		—		—
December 31, 2026 and thereafter		—		—
Total		9,765		3,104
Fund I		—		—
Fund II
December 31, 2022		120		120
December 31, 2023		2,720		1,543
December 31, 2024		320		320
December 31, 2025		—		—
December 31, 2026 and thereafter		—		—
Total		3,160		1,983

Granite Ridge believes that the expired acreage was not material to its capital deployed on an aggregate basis across the Properties.

Unproved Properties

All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion.

Granite Ridge assesses all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are charged to expense.

The Company historically has acquired unproved properties by purchasing individual or small groups of leases directly from mineral owners, landmen, or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. Granite Ridge generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.

Granite Ridge believes that the majority of the Company’s unproved costs will become subject to depletion within the next five years by proving up reserves relating to the Company’s acreage through exploration and development activities, by impairing the acreage that will expire before Granite Ridge can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of the Company’s reserves.

Depletion of Oil and Natural Gas Properties

Depletion expense is driven by many factors including production levels, estimates of proved reserve quantities and future developmental costs. The following table presents depletion expenses by the Fund

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incurring such expenses during the three and nine months ended September 30, 2022 and 2021, and the years ended December 31, 2021, 2020 and 2019.

	Three Months Ended September 30,						Nine Months Ended September 30,						Years Ended December 31,
(In thousands, except per Boe data)	2022			2021			2022			2021			2021			2020			2019
Fund III
Depletion of Oil and Natural Gas Properties		$	39,775		$	15,794		$	70,389		$	45,798		$	60,477		$	22,096		$	17,092
Depletion Expense (per Boe)			36.05			16.11			22.44			16.11			16.11			21.18			28.30
Fund I
Depletion of Oil and Natural Gas Properties								$	1,576		$	2,533		$	3,049		$	9,752		$	7,278
Depletion Expense (per Boe)									17.21			15.19			12.38			27.41			21.77
Fund II
Depletion of Oil and Natural Gas Properties								$	25,795		$	24,109		$	30,687		$	47,689
Depletion Expense (per Boe)									13.16			16.26			16.25			21.57

Research and Development

Granite Ridge does not anticipate that it will perform any significant research and development under its plans of operation.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” unless otherwise specified or the context otherwise requires, “Grey Rock,” “we,” “us,” and “our” refer to Grey Rock Energy Fund III, our Predecessor, and each of Fund I and Fund II, on an individual basis unless otherwise noted and does not include the results or give pro forma effect to the transactions described in “Summary — Unaudited Pro Forma Condensed Combined Financial Information.” The following discussion and analysis should be read in conjunction with the historical and unaudited pro forma condensed combined financial statements and related notes of Fund III, Fund I, Fund II and ENPC included elsewhere in this prospectus.

Prior to the closing of the Business Combination, Grey Rock Energy Management, LLC (“Grey Rock”) managed three funds with similar strategies, Grey Rock Energy Fund, LP, a Delaware limited partnership (“Fund I”) formed in 2014, Grey Rock Energy Fund II, L.P., Grey Rock Energy Fund II-B, LP, and Grey Rock Energy Fund II-B Holdings, L.P., each Delaware limited partnerships (collectively, “Fund II”) formed in 2016, and Grey Rock Energy Fund III-A, LP, Grey Rock Energy Fund III-B, LP, and Grey Rock Energy Fund III-B Holdings, LP, each Delaware limited partnerships (collectively, “Fund III” and, together with Fund I and Fund II, the “Funds”) formed in 2018. The Funds held strategic investments in non-operated working interests in upstream oil and gas assets in North America. Upon the consummation of the Business Combination, the Funds and the Existing GREP Members contributed the properties of each of the Funds to GREP Holdings, LLC, a Delaware limited liability company and wholly-owned subsidiary of Granite Ridge (“GREP”). Unless the context otherwise requires, with respect to descriptions of the financials and operations of the properties owned by Granite Ridge, references to “Granite Ridge”, the “Company”, “we”, “us”, or “our” relate to the assets contributed by GREP in the Business Combination, as owned or operated by the Funds prior to the Business Combination, and as owned or operated by Granite Ridge after the Business Combination.

This discussion contains forward-looking statements reflecting Granite Ridge’s current expectations, estimates and assumptions concerning events and financial trends that may affect Granite Ridge’s future operating results and financial position. Actual results and the timing of events may differ materially from those contained in or implied by these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Granite Ridge does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We hold strategic investments in non-operated working interests in diversified upstream oil and 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 gas assets in North America.

Pursuant to our investment strategies, we collectively participated in 2,322 gross (124 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 we collectively participated in 2,169 gross (109 net) producing wells. As of September 30, 2022 and December 31, 2021, we leased approximately 254,215 gross (26,050 net) and 247,797 gross (24,187 net) developed acres, and 18,266 gross (7,972 net) and 20,791 gross (8,255 net) undeveloped acres, respectively, all located in the United States.

Our average daily production for the nine months ended September 30, 2022 was 19,212 Boe per day, and for the full year 2021 was 16,137 Boe per day. The increase in production is consistent with our increase in net producing wells which increased to 124 wells as of September 30, 2022, up from 109 net wells as of the end of 2021. During 2021, our wells increased from 81 net wells at the beginning of 2021 to 109 net wells

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at the end of 2021. The increase in wells was primarily driven by Fund III’s drilling success on undeveloped acreage and the acquisition of additional producing wells during the first nine months of 2022 and throughout 2021.

Unless otherwise noted, the information presented within “Management’s Discussion and Analysis of Financial Condition and Results of Operations” is applicable to the collective Funds with the exception of the “— Results of Operations” and “— Liquidity and Capital Resources” sections. Interim information related to the Results of Operations for Grey Rock Energy Fund, LP and Grey Rock Energy Fund II was derived from the unaudited condensed consolidated financial statements of Grey Rock Energy Fund, LP, and the unaudited condensed combined financial statements of Grey Rock Energy Fund II, respectively, for the nine months ended September 30, 2022 and 2021, and the related notes included elsewhere in this prospectus. Annual information related to the Results of Operations for Grey Rock Energy Fund, LP was derived from the audited consolidated financial statements of Grey Rock Energy Fund, LP as of and for the years ended December 31, 2021, 2020 and 2019, and the related notes included elsewhere in this prospectus. Annual information related to the Results of Operations of Grey Rock Energy Fund II was derived from the audited combined financial statements of Grey Rock Energy Fund II as of and for the years ended December 31, 2021 and 2020, and the related notes included elsewhere in this prospectus.

Business Combination

On May 16, 2022, the Funds and Grey Rock formed GREP, who entered into a business combination agreement (“BCA”) with Executive Network Partnering Corporation (“ENPC”), a Delaware corporation and New York Stock Exchange (“NYSE”) publicly traded special purpose acquisition company, 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. The Business Combination closed on October 24, 2022. Granite Ridge is listed on the NYSE under the ticker symbol “GRNT”.

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 to 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.

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military invasion of Ukraine by Russian troops was reported. Although the length and impact of the ongoing military conflict is highly unpredictable, the conflict in Ukraine has led and could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in credit and capital markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences as well as increase in cyberattacks and espionage. 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 agreement to remove certain Russian financial institutions from the Society for Worldwide Interbank Financial Telecommunication (“SWIFT”) payment system, expansive bans on imports and exports of products to and from Russia (including imports of Russian oil, liquefied natural gas and coal) and a ban on exportation of U.S denominated banknotes to Russia or persons located therein. 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 Granite Ridge’s business. Additional potential sanctions and penalties have also been proposed and/or threatened.

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. The situation is rapidly evolving as a result of the conflict in Ukraine, and the United States, the European Union, the United Kingdom and other countries may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect the Company’s business, financial condition, and results of operations.

Environmental, Social and Corporate Governance Initiatives

We are committed to developing strong ESG programs and continually improving our ESG performance. We view exceptional ESG performance as an opportunity to differentiate Granite Ridge 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

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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 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 natural 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.

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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 differential to the NYMEX benchmark price during the nine months ended September 30, 2022 was $(2.06) per barrel, as compared to $(3.73) per barrel in the nine months ended September 30, 2021. Our natural gas price differential during the nine months ended September 30, 2022 was $1.71 per Mcf, as compared to $1.17 per Mcf in the nine months ended September 30, 2021.

Our oil price differential to the NYMEX benchmark price during 2021 was $(3.40) per barrel, as compared to $0.82 per barrel in 2020. Our natural gas price differential during 2021 was $0.69 per Mcf, as compared to $(1.07) per Mcf in 2020. Fluctuations in our price differentials and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional storage capacity, gain/loss on derivative contracts and seasonal refinery maintenance temporarily depressing demand.

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 nine months ended September 30, 2022 and 2021.

	Nine Months Ended September 30,
	2022			2021
Average NYMEX Prices(1)
Oil (per Bbl)		$	98.24		$	64.99
Natural gas (per Mcf)			6.70			3.35

(1)

Based on average NYMEX closing prices.

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 $8.87 in the nine months ended September 30, 2022 and by $3.14 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 $87.31 compared to $58.13 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 $1.09 and $0.49 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 $7.32 compared to $4.02 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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The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2021 and 2020.

	Year Ended December 31,
	2021			2020
Average NYMEX Prices(1)
Oil (per Bbl)		$	68.00		$	39.34
Natural gas (per Mcf)			4.00			2.13

(1)

Based on average NYMEX closing prices.

The average 2021 NYMEX oil pricing was $68.00 per barrel of oil, or 73% higher than the average NYMEX price per barrel in 2020. Our settled derivatives decreased our realized oil price per barrel by $5.58 in 2021 and increased our realized oil price per barrel by $5.37 in 2020. Our average 2021 realized oil price per barrel after reflecting settled derivatives was $59.03 compared to $45.54 in 2020. The average 2021 NYMEX natural gas pricing was $4.00 per Mcf, or 87% higher than the average NYMEX price per Mcf in 2020. Our settled derivatives decreased our realized natural gas price per Mcf by $0.42 in 2021 and increased it by $0.17 in 2020. Our 2021 realized gas price per Mcf was $4.27 compared to $1.24 in 2020, which was primarily driven by higher NYMEX pricing for natural gas and gas realizations.

Results of Operations — Fund III (Predecessor)

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

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	Three months ended September 30,
	2022			2021
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.

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

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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.

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.

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.

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	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.

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.

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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)

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.

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

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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. Commodity price volatility during 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.

Year ended December 31, 2021 compared to year ended December 31, 2020

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.

	Year ended December 31,
	2021			2020
Net Sales (in thousands):
Oil sales		$	145,643		$	23,863
Natural gas and related product sales			51,903			4,427
Revenues			197,546			28,290
Average Sales Prices:
Oil (per Bbl)		$	63.47		$	38.14
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)			(4.51)			4.05
Oil net of settled oil derivatives (per Bbl)			58.96			42.19
Natural gas and related product sales (per Mcf)			5.92			1.77
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)			(0.32)			0.12
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)			5.60			1.89
Realized price on a Boe basis excluding settled commodity derivatives			52.61			27.12
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)			(3.51)			2.72
Realized price on a Boe basis including settled commodity derivatives			49.10			29.84

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	Year ended December 31,
	2021			2020
Operating Expenses (in thousands):
Lease operating expenses		$	12,362		$	5,147
Production taxes			10,808			1,815
Depletion and accretion expense			60,534			22,130
General and administrative			6,262			5,166
Total operating expenses			89,966			34,258
Costs and Expenses (per Boe):
Lease operating expenses		$	3.29		$	4.93
Production taxes			2.88			1.74
Depletion and accretion			16.12			21.21
General and administrative			1.67			4.95
Net Producing Wells at Period-End			46.13			17.31

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. In 2021, our oil and natural gas sales increased 598% from 2020, driven by an 94% increase in realized prices, excluding the effect of settled commodity derivatives, and a 260% increase in production volumes. The higher average price in 2021 as compared to 2020 was driven by higher average NYMEX oil and natural gas prices.

Realized production from oil and gas properties increases through drilling success and acquisition of additional net revenue interests. This increase in production is offset by the natural decline of the production rate of existing oil and natural gas wells. In 2021, the number of wells we participated in increased by 166% as compared to 2020. The new well additions drove the 260% increase in production in 2021 as compared to 2020.

Production for the last two years is set forth in the following table:

	Year ended December 31,
	2021		2020
Production:
Oil (MBbl)		2,295		626
Natural gas (MMcf)		8,761		2,506
Total (MBoe)(1)		3,755		1,043
Average Daily Production:
Oil (Bbl)		6,286		1,714
Natural gas (Mcf)		24,002		6,866
Total (Boe)(1)		10,287		2,858

(1)

Lease Operating Expenses

Lease operating expenses were approximately $12,362 thousand in 2021 compared to $5,147 thousand in 2020. On a per unit basis, production expenses decreased 33% from $4.93 per Boe in 2020 to $3.29 per

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Boe in 2021 due primarily to lower production volumes over which fixed costs can be spread. On an absolute dollar basis, the 140% increase in our production related expenses in 2021 compared to 2020 was primarily due to a 260% increase in production, offset by a 33% decrease in per unit costs.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $10,808 thousand in 2021 compared to $1,815 thousand in 2020. As a percentage of oil and natural gas sales, our production taxes were 5% and 6% in 2021 and 2020, respectively. The fluctuation in our average production tax rate from year to year is primarily due to changes in our oil sales as a percentage of our total oil and natural gas sales and the mix of our production volumes by basin. However, 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 $60,534 thousand in 2021 compared to $22,130 thousand in 2020. Depletion and accretion was $16.12 per Boe in 2021 compared to $21.21 per Boe in 2020. The aggregate increase in depletion and accretion expense for 2021 compared to 2020 was driven by a 260% increase in production levels and offset by a 24% decrease in the depletion and accretion rate per Boe.

General and Administrative

General and administrative expenses were approximately $6,262 thousand in 2021 compared to $5,166 thousand in 2020. The increase from 2020 to 2021 was primarily due to an increase in brokerage fees, asset software and research fees and an increase in property insurance fees as a result of increased acquisition and well development activity in 2021 relative to 2020. General and administrative expenses include management fees which were approximately $3,878 thousand in 2021 and 2020. In the investment period, management fees are calculated on committed capital. As committed capital was consistent across 2021 and 2020, management fees remained unchanged.

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 $17,315 thousand in 2021 compared to a gain of $2,928 thousand in 2020. Commodity price volatility during 2021 resulted in realized losses of $13,175 thousand compared to realized gains of $2,838 thousand in 2020. In 2021, unrealized losses were $4,140 thousand compared to unrealized gains of $90 thousand in 2020. Our average 2021 realized oil price per barrel after reflecting settled derivatives was $58.96 compared to $42.19 in 2020. Our settled derivatives decreased our realized oil price per barrel by $4.51 compared to increasing the price per barrel by $4.05 in 2020. Our realized natural gas price per Mcf was $5.60 in 2021 compared to $1.89 in 2020. Our settled derivatives decreased our realized natural gas price per Mcf by $0.32 in 2021 versus increasing the price per Mcf by $0.12 in 2020. In 2021, we ended the year with a $4,353 thousand net derivative liability compared to $213 thousand in 2020.

Interest Expense

Interest expense was approximately $1,399 thousand in 2021 compared to $428 thousand in 2020. The increase in interest expense for 2021 as compared to 2020 was primarily due to an increase in the outstanding balance on the revolving credit facility.

Year ended December 31, 2020 compared to year ended December 31, 2019

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.

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	Year ended December 31,
	2020			2019
Net Sales (in thousands):
Oil sales		$	23,863		$	20,811
Natural gas and related product sales			4,427			2,472
Revenues			28,290			23,283
Average Sales Prices:
Oil (per Bbl)		$	38.14		$	53.96
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)			4.05			1.14
Oil net of settled oil derivatives (per Bbl)			42.19			55.10
Natural gas and related product sales (per Mcf)			1.77			1.89
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)			0.12			0.34
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)			1.89			2.23
Realized price on a Boe basis excluding settled commodity derivatives			27.12			38.56
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)			2.72			0.73
Realized price on a Boe basis including settled commodity derivatives			29.84			39.29
Operating Expenses (in thousands):
Lease operating expenses		$	5,147		$	2,669
Production taxes			1,815			1,369
Depletion and accretion expense			22,130			17,100
General and administrative			5,166			4,961
Organizational expenses			—			21
Total operating expenses			34,258			26,120
Costs and Expenses (per Boe):
Lease operating expenses		$	4.93		$	4.42
Production taxes			1.74			2.27
Depletion and accretion			21.21			28.32
General and administrative			4.95			8.22
Organizational expenses			—			0.03
Net Producing Wells at Period-End			17.31			11.04

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. In 2020, our oil and natural gas sales increased 22% from 2019, driven by a 73% increase in production volumes, partially offset by a 30% decrease in realized prices, excluding the effect of settled commodity derivatives. The lower average price in 2020 as compared to 2019 was driven by lower average NYMEX oil and natural gas prices.

Realized production from oil and gas properties increases through drilling success and acquisitions of additional net revenue interests. This increase in production is offset by the natural decline of the production rate of existing oil and natural gas wells. In 2020, the number of wells we participated in increased by 57% as compared to 2019. The new well additions drove the 73% increase in production in 2020 as compared to 2019.

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Production for the last two years is set forth in the following table:

	Year ended December 31,
	2020		2019
Production:
Oil (MBbl)		626		386
Natural gas (MMcf)		2,506		1,309
Total (MBoe)(1)		1,043		604
Average Daily Production:
Oil (Bbl)		1,714		1,057
Natural gas (Mcf)		6,866		3,587
Total (Boe)(1)		2,858		1,654

(1)

Lease Operating Expenses

Lease operating expenses were approximately $5,147 thousand in 2020 compared to approximately $2,669 thousand in 2019. On a per unit basis, production expenses increased 12% from $4.42 per Boe in 2019 to $4.93 per Boe in 2020 due primarily to an increase in fixed and variable costs, partially offset by increased production volumes over which costs can be spread. On an absolute dollar basis, the 93% increase in our production related expenses in 2020 compared to 2019 was primarily due to a 73% increase in production and a 12% increase in per unit costs.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $1,815 thousand in 2020 compared to $1,369 thousand in 2019. As a percentage of oil and natural gas sales, our production taxes were 6% in 2020 and 2019, 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 $22,130 thousand in 2020 compared to $17,100 thousand in 2019. Depletion and accretion was $21.21 per Boe in 2020 compared to $28.32 per Boe in 2019. The aggregate increase in depletion and accretion expense for 2020 compared to 2019 was driven by a 73% increase in production levels and offset by a 25% decrease in the depletion and accretion rate per Boe.

General and Administrative

General and administrative expenses were approximately $5,166 thousand in 2020 compared to $4,961 thousand in 2019. The increase from 2019 to 2020 was primarily due to an increase in software, research and land services expenses related to potential asset acquisitions opportunities. General and administrative expenses include management fees which were approximately $3,878 thousand in 2020 and 2019. In the investment period, management fees are calculated on committed capital. As committed capital was consistent across 2020 and 2019, management fees remained unchanged.

Organizational Expenses

There were no organization expenses incurred in 2020. Organizational expenses were approximately $21 thousand in 2019, primarily due to the fund being in the start-up phase, following its establishment in 2018. Such expenses were no longer applicable in the subsequent periods.

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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 $2,928 thousand in 2020 compared to a gain of $137 thousand in 2019. Commodity price volatility during 2020 resulted in realized gains of $2,838 thousand compared to realized gains of $441 thousand in 2019. In 2020, unrealized gains were $90 thousand compared to unrealized losses of $303 thousand in 2019. Our average 2020 realized oil price per barrel after reflecting settled derivatives was $42.19 compared to $55.10 in 2019. Our settled derivatives increased our realized oil price per barrel by $4.05 compared to increasing the price per barrel by $1.14 in 2019. Our realized natural gas price per Mcf was $1.89 in 2020 compared to $2.23 in 2019. Our settled derivatives increased our realized natural gas price per Mcf by $0.12 in 2020 versus increasing the price per Mcf by $0.34 in 2019. In 2020, we ended the year with a $213 thousand net derivative liability compared to $303 thousand in 2019.

Interest Expense

Interest expense was approximately $428 thousand in 2020 compared to $509 thousand in 2019. The decrease in interest expense for 2020 as compared to 2019 was primarily due to a decrease in the outstanding balance on the revolving credit facility.

Liquidity and Capital Resources — Fund III (Predecessor)

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 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

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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.

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 “— Liquidity and Capital

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Resources — Fund III (Predecessor), Fund I and Fund II — Credit Agreement” for information regarding the Credit Agreement.

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 prospectus. 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 prospectus. 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 elsewhere in this prospectus. 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 our Credit Agreement.

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 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.”

Years ended December 31, 2021 and 2020 compared to years ended December 31, 2020 and 2019, respectively

Overview

Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations and credit facility borrowings. Our primary use of capital has been for the development 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 December 31, 2021, we had outstanding debt consisting of approximately $29,938 thousand of borrowings under our revolving credit facility. We had approximately $77,381 thousand in liquidity as of December 31, 2021, consisting of approximately $70,062 thousand of committed borrowing availability under the revolving credit facility and approximately $7,319 thousand of cash on hand.

With our cash on hand, cash flow from operations, and borrowing capacity under our revolving credit facility, we believe that we will have sufficient cash flow and liquidity 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.

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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 flows from operations and available borrowing capacity under our revolving credit facility. Our capital expenditures could be curtailed if our cash flows decline from expected levels.

Working Capital

At December 31, 2021, we had a working capital surplus of approximately $37,268 thousand, compared to a surplus of approximately $16,349 thousand at December 31, 2020. Current assets increased by approximately $57,418 thousand and current liabilities increased by approximately $36,499 thousand at December 31, 2021, compared to December 31, 2020. The increase in current assets in 2021 as compared to 2020 is primarily due to an increase in advances due to operators and revenue receivable. The increase in current liabilities in 2021 as compared to 2020 is primarily due to the increase of our outstanding credit facilities.

Cash Flows

Our cash flows for the years ended December 31, 2021, 2020 and 2019 are presented below:

	Year ended December 31,
(in thousands)	2021			2020			2019
Net Cash Provided by Operating Activities		$	131,715		$	14,085		$	8,670
Net Cash Used in Investing Activities			(194,014)			(80,868)			(83,707)
Net Cash Provided by Financing Activities			66,980			66,447			69,815
Net Change in Cash		$	4,681		$	(336)		$	(5,222)

Cash Flows from Operating Activities

Net cash provided by operating activities in 2021 was approximately $131,715 thousand, compared to approximately $14,085 thousand in 2020. The increase in net cash provided by operating activities results from development drilling on acquired assets in the Permian and Eagle Ford basins as well as the acquisition of producing oil and natural gas assets in the DJ basin. This development and acquisition activity contributed to a 260% increase in production period over period. Working capital changes during 2021 were impacted by an increase in revenue receivables of $23,199 thousand related to increased production in the Permian basin and increased realized oil and natural gas prices (before the effects of derivatives). Working capital changes during 2020 were impacted by an increase in revenue receivables of approximately $4,644 thousand primarily related to increased production in the Permian basin. This increased production was partially offset by a reduction of realized oil prices (before the effects of derivatives) compared to the prior period.

Net cash provided by operating activities in 2020 was approximately $14,085 thousand compared to approximately $8,670 thousand in 2019. The increase in net cash provided by operating activities results primarily from development drilling on acquired assets in the Permian basin. This development and acquisition activity contributed to a 73% increase in production year over year. The impact of increased production was partially offset by a 30% decrease in realized commodity prices (before the effects of derivatives), as commodity prices reached historic lows in 2020 due to the impacts of COVID-19. Working capital changes during 2020 were impacted by an increase in revenue receivables of approximately $4,644 thousand primarily related to increased production in the Permian basin. This increased production

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was partially offset by a reduction of realized oil prices (before the effects of derivatives) compared to the prior period. Working capital changes during 2019 were impacted by an increase in revenue receivables of approximately $4,789 thousand, which was primarily attributed to increased production in the Bakken and Eagle Ford basins as a result of acquisitions in these areas in 2019.

Cash Flows from Investing Activities

We had cash flows used in investing activities of approximately $194,014 thousand, approximately $80,868 thousand and approximately $83,707 thousand during the years ended December 31, 2021, 2020 and 2019, respectively, primarily as a result of an increase in the development and acquisition of oil and gas properties in 2021, 2020 and 2019.

Cash Flows from Financing Activities

Net cash provided by financing activities was approximately $66,980 thousand, approximately $66,447 thousand and approximately $69,815 thousand for the years ended December 31, 2021, 2020 and 2019, respectively. The cash provided by financing activities in 2021, 2020 and 2019 was primarily related to partners’ contributions and net proceeds from borrowings on our credit facilities, partially offset by repayments of borrowings.

Revolving Credit Facility

In October 2018, we entered into a revolving credit facility with an initial borrowing capacity of $0. In 2019, the borrowing base was increased to approximately $24,000 thousand with a maturity date of October 26, 2022. In 2021, the borrowing base was increased to approximately $100,000 thousand. The outstanding balance on the facility was also partially repaid throughout the year, with approximately $29,938 thousand outstanding as of December 31, 2021.

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

We have contractual commitments under our revolving credit facility which include periodic interest payments. See Note 10 to our annual combined audited financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 to our annual combined audited financial statements. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 6 to our annual combined audited financial statements. 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 2022, we are budgeting approximately $154,214 thousand in total planned capital expenditures. As of December 31, 2021, we had incurred approximately $4,612 thousand in capital expenditures that were included in accounts payable, and we estimate that we were committed to an additional approximately $43,678 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 our revolving credit facility.

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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.”

Results of Operations — Fund I

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		$	5,984		$	6,908
Natural gas and related product sales			1,822			1,274
Revenues			7,806			8,182
Average Sales Prices:
Oil (per Bbl)		$	94.80		$	64.45
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)			(5.81)			(11.62)
Oil net of settled oil derivatives (per Bbl)			88.99			52.83
Natural gas and related product sales (per Mcf)			10.67			3.57
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)			(1.52)			(0.15)
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)			9.15			3.42
Realized price on a Boe basis excluding settled commodity derivatives			85.25			49.08
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)			(6.84)			(7.78)
Realized price on a Boe basis including settled commodity derivatives			78.41			41.30
Operating Expenses (in thousands):
Lease operating expenses		$	1,216		$	1,426
Production taxes			512			506
Depletion and accretion			1,611			2,533
General and administrative			158			360
Gain on disposal of oil and natural gas properties			—			(1,011)
Total operating expenses			3,497			3,814
Costs and Expenses (per Boe):
Lease operating expenses		$	13.28		$	8.55
Production taxes			5.59			3.04
Depletion and accretion			17.59			15.19
General and administrative			1.73			2.16
Gain on disposal of oil and natural gas properties			—			(6.06)
Net Producing Wells at Period-End			10.03			9.50

Oil, Natural Gas and Related Product Sales

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5% from the nine months ended September 30, 2021, driven by a 45% decrease in production volumes, partially offset by a 74% 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.

Realized production from oil and natural gas properties increases through drilling success and 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 6% as compared to the nine months ended September 30, 2021. The increase in the number of wells we participated in partially offset the natural decline in production of existing wells.

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)		63		107
Natural gas (MMcf)		171		357
Total (MBoe)(1)		92		167
Average Daily Production:
Oil (Bbl)		234		397
Natural gas (Mcf)		632		1,323
Total (Boe)(1)		339		617

(1)

Lease Operating Expenses

Lease operating expenses were approximately $1,216 thousand for the nine months ended September 30, 2022 compared to $1,426 thousand for the nine months ended September 30, 2021. On a per unit basis, production expenses increased 55% from $8.55 per Boe for the nine months ended September 30, 2021 to $13.28 per Boe for the nine months ended September 30, 2022 due primarily to lower production volumes over which fixed costs can be spread. On an absolute dollar basis, the 15% decrease in our production expenses for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 was primarily due to a 45% decrease in production, partially offset by a 55% increase in per unit costs.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $512 thousand for the nine months ended September 30, 2022, respectively, compared to $506 thousand for the nine months ended September 30, 2021, respectively. As a percentage of oil and natural gas sales, our production taxes were 7% and 6% for the nine months ended September 30, 2022 and 2021, respectively. The fluctuation in our average production tax rate from period to period is primarily due to changes in our oil sales as a percentage of total oil and natural gas sales.

Depletion and Accretion

Depletion and accretion expense was approximately $1,611 thousand for the nine months ended September 30, 2022, respectively, compared to $2,533 thousand for the nine months ended September 30, 2021, respectively. Depletion and accretion was $17.59 per Boe for the nine months ended September 30, 2022 compared to $15.19 per Boe for the nine months ended September 30, 2021. The aggregate decrease in

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depletion and accretion expense for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 was primarily driven by a 45% decrease in production levels.

General and Administrative

General and administrative expenses were approximately $158 thousand for the nine months ended September 30, 2022, respectively, compared to $360 thousand for the nine months ended September 30, 2021, respectively. The decrease in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 was primarily due to a decrease in land services fees and fund level expenses.

Gain on Disposal of Oil and Natural Gas Properties

We did not recognize a gain on disposal of oil and natural gas properties during the nine months ended September 30, 2022. During the nine months ended September 31, 2021, we sold a portion of our Permian Basin assets, resulting in a gain on disposal of oil and natural gas properties of approximately $1,011 thousand.

Gain/(Loss) on Derivative Contracts

We recorded a loss on derivative contracts of approximately $576 thousand during the nine months ended September 30, 2022, compared to a loss of $1,832 thousand during the nine months ended September 30, 2021. Commodity price volatility during the nine months ended September 30, 2022 resulted in realized losses of $626 thousand, compared to realized losses of $1,297 thousand in the nine months ended September 30, 2021, respectively. Our average nine months ended September 30, 2022 realized oil price per barrel after reflecting settled derivatives was $88.99, compared to $52.83 in the nine months ended September 30, 2021, respectively. Our settled derivatives decreased our realized oil price per barrel by $5.81 in the nine months ended September 30, 2022, compared to $11.62, in the nine months ended September 30, 2021. Our realized natural gas price per Mcf was $9.15 in the nine months ended September 30, 2022, compared to $3.42 in the nine months ended September 30, 2021, respectively. Our settled derivatives decreased our realized natural gas price per Mcf by $1.52 in the nine months ended September 30, 2022, versus $0.15 in the nine months ended September 30, 2021. As of September 30, 2022, we ended the period with a $21 thousand net derivative asset compared to a $29 thousand net derivative liability as of December 31, 2021.

Interest Expense

Interest expense was approximately $22 thousand for the nine months ended September 30, 2022, compared to $116 thousand for the nine months ended September 30, 2021. The decrease 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 a decline in the outstanding balance on the revolving credit facility, partially offset by an increase in the weighted average interest rate.

Year ended December 31, 2021 compared to year ended December 31, 2020

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.

	Year ended December 31,
	2021			2020
Net Sales (in thousands):
Oil sales		$	8,580		$	9,120
Natural gas and related product sales			1,677			671
Revenues			10,257			9,791
Average Sales Prices:
Oil (per Bbl)		$	52.89		$	36.74
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)			(8.44)			5.83

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	Year ended December 31,
	2021			2020
Oil net of settled oil derivatives (per Bbl)			44.45			42.57
Natural gas and related product sales (per Mcf)			3.32			1.04
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)			(1.06)			(0.02)
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)			2.26			1.02
Realized price on a Boe basis excluding settled commodity derivatives			41.63			27.52
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)			(7.73)			4.03
Realized price on a Boe basis including settled commodity derivatives			33.90			31.55
Operating Expenses (in thousands):
Lease operating expenses		$	1,799		$	2,156
Production taxes			627			619
Depletion and accretion			3,038			9,837
Loss on impairment			—			5,725
General and administrative			389			1,270
Gain on disposal of oil and natural gas properties			(1,341)			(597)
Total operating expenses			4,512			19,010
Costs and Expenses (per Boe):
Lease operating expenses		$	7.30		$	6.06
Production taxes			2.54			1.74
Depletion and accretion			12.33			27.65
General and administrative			1.58			3.57
Gain on disposal of oil and natural gas properties			(5.44)			(1.68)
Net Producing Wells at Period-End			9.3			12.4

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. In 2021, our oil and natural gas sales increased 5% from 2020, driven by a 51% increase in realized prices, excluding the effect of settled commodity derivatives, and offset by a 31% decrease in production volumes. The higher average price in 2021 as compared to 2020 was driven by higher average NYMEX oil and natural gas prices.

Realized production from oil and natural gas properties increases through drilling success and acquisition of additional net revenue interests. The increase in production is offset by the natural decline of the production rate of existing oil and natural gas wells. In 2021, we made divestments in the SCOOP and Permian basins. The 31% decrease in production in 2021 as compared to 2020 was largely due in part to the sale of our SCOOP and Permian basin properties.

Production for the last two years is set forth in the following table:

	Year ended December 31,
	2021		2020
Production:
Oil (MBbl)		162		248
Natural gas (MMcf)		505		646
Total (MBoe)(1)		246		356
Average Daily Production:
Oil (Bbl)		444		680

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	Year ended December 31,
	2021		2020
Natural gas (Mcf)		1,384		1,769
Total (Boe)(1)		675		975

(1)

Lease Operating Expenses

Lease operating expenses were approximately $1,799 thousand in 2021 compared to $2,156 thousand in 2020. On a per unit basis, production expenses increased 20% from $6.06 per Boe in 2020 to $7.30 per Boe in 2021 due primarily to lower production volumes over which fixed costs can be spread. On an absolute dollar basis, the 17% decrease in our production expenses in 2021 compared to 2020 was primarily due to a 31% decrease in production, offset by a 20% increase in per unit costs.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $627 thousand in 2021 compared to $619 thousand in 2020. As a percentage of oil and natural gas sales, our production taxes were 6% in 2021 and 2020, respectively. The fluctuation in our average production tax rate from year to year is primarily due to changes in our oil sales as a percentage of total oil and natural gas sales. 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 $3,038 thousand in 2021 compared to $9,837 thousand in 2020. Depletion and accretion was $12.33 per Boe in 2021 compared to $27.65 per Boe in 2020. The decrease in depletion and accretion expense for 2021 compared to 2020 was driven by higher NYMEX prices in 2021 resulting in an increase in projected reserve volumes and value.

Loss on Impairment

We did not record any impairment of proved oil and gas properties in 2021. In 2020, as a result of low commodity prices and their effect on the proved reserve values of our properties, we recorded a loss on impairment of approximately $5,725 thousand. The impairment charge affected our reported net income in 2020 but did not reduce our cash flow.

General and Administrative

General and administrative expenses were approximately $389 thousand for 2021 compared to $1,270 thousand for 2020. The decrease in 2021 compared to 2020 was primarily due to franchise taxes and legal fees incurred in 2020 as part of an arbitration settlement that reached a final settlement in April 2020. General and administrative fees include management fees which were approximately zero in 2021 and $585 thousand in 2020. The decrease in 2021 compared to 2020 is due to Grey Rock’s agreement to suspend the management fee for Fund I. In November 2020, we extended the life of our management agreement by one year. Under the terms of the new agreement, the investment manager agreed to cease charging management fees. In October 2021, we extended the life of our management agreement by one year.

Gain on Disposal of Oil and Natural Gas Properties

We recognized a gain on disposal of oil and natural gas properties of approximately $1,341 thousand in 2021 compared to $597 thousand in 2020. The increase in 2021 compared to 2020 was driven by the sale of the majority of our Permian Basin assets, resulting in a gain of $1,165 thousand.

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Gain/(Loss) on Derivative Contracts

We recorded a loss on derivative contracts of approximately $1,842 thousand in 2021 compared to a gain of $1,714 thousand in 2020. Commodity price volatility during 2021 resulted in realized losses of $1,906 thousand compared to realized gains of $1,434 thousand in 2020. Our average 2021 realized oil price per barrel after reflecting settled derivatives was $44.45 compared to $42.57 in 2020. Our settled derivatives decreased our realized oil price per barrel by $8.44 compared to increasing the price per barrel by $5.83 in 2020. Our realized natural gas price per Mcf was $2.26 in 2021 compared to $1.02 in 2020. Our settled derivatives decreased our realized natural gas price per Mcf by $1.06 in 2021 versus $0.02 in 2020. In 2021, we ended the year with a $29 thousand net derivative liability compared to $93 thousand in 2020.

Interest Expense

Interest expense was approximately $138 thousand in 2021 compared to $245 thousand in 2020. The decrease in interest expense for 2021 as compared to 2020 was primarily due to a decline in the outstanding balance on the revolving credit facility in conjunction with a decline in the weighted average interest rate for the 2021 period versus 2020.

Year ended December 31, 2020 compared to year ended December 31, 2019

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

	Year ended December 31,
	2020			2019
Net Sales (in thousands):
Oil sales		$	9,120		$	12,455
Natural gas and related product sales			671			985
Revenues			9,791			13,440
Average Sales Prices:
Oil (per Bbl)		$	36.74		$	53.74
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)			5.83			(0.78)
Oil net of settled oil derivatives (per Bbl)			42.57			52.96
Natural gas and related product sales (per Mcf)			1.04			1.60
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)			(0.02)			0.04
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)			1.02			1.64
Realized price on a Boe basis excluding settled commodity derivatives			27.52			40.19
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)			4.03			(0.47)
Realized price on a Boe basis including settled commodity derivatives			31.55			39.72
Operating Expenses (in thousands):
Lease operating expenses		$	2,156		$	2,980
Production taxes			619			865
Depletion and accretion			9,837			7,262
Loss on impairment			5,725			—
General and administrative			1,270			1,567
Gain on disposal of oil and natural gas properties			(597)			(4,910)
Total expenses			19,010			7,764

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	Year ended December 31,
	2020			2019
Costs and Expenses (per Boe):
Lease operating expenses		$	6.06		$	8.91
Production taxes			1.74			2.59
Depletion and accretion			27.65			21.72
General and administrative			3.57			4.69
Gain on disposal of oil and natural gas properties			(1.68)			(14.68)
Net Producing Wells at Period-End			12.4			12.3

Oil, Natural Gas and Related Product Sales

In 2020, our oil and natural gas sales decreased 27% from 2019, driven by a 32% decrease in realized prices, excluding the effect of settled commodity derivatives, and offset by a 6% increase in production volumes. Investment and development of owned assets lead to a 7% increase in oil volumes and a 5% increase on gas volumes. The lower average realized price was driven by lower average NYMEX oil and natural gas prices for 2020.

Realized production from oil and gas properties increases through drilling success and acquisition of additional net revenue interests. The increase in production is offset by the natural decline of the production rate of existing oil and natural gas wells. In 2020, the number of wells we participated in increased by 1% as compared to 2019. The new well additions drove the 6% increase in production in 2020 as compared to 2019.

Our production for the last two years is set forth in the following table:

	Year ended December 31,
	2020		2019
Production:
Oil (MBbl)		248		232
Natural gas (MMcf)		646		616
Total (MBoe)(1)		356		334
Average Daily Production:
Oil (Bbl)		680		635
Natural gas (Mcf)		1,769		1,687
Total (Boe)(1)		975		916

(1)

Lease Operating Expenses

Lease operating expenses were approximately $2,156 thousand in 2020 compared to $2,980 thousand in 2019. On a per unit basis, production expenses decreased 32% from $8.91 per Boe in 2019 to $6.06 per Boe in 2020 due primarily to higher production volumes over which fixed costs can be spread. On an absolute dollar basis, the 28% decrease in our production related expenses in 2020 compared to 2019 was primarily due to a 6% increase in production and by a 32% decrease in per unit costs.

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Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were approximately $619 thousand in 2020 compared to $865 thousand in 2019. As a percentage of oil and natural gas sales, our production taxes were 6% in 2020 and 2019. The decline in realized revenues is consistent with the decline of production taxes.

Depletion and Accretion

Depletion and accretion expense was approximately $9,837 thousand in 2020 compared to $7,262 thousand in 2019. Depletion and accretion expense was $27.65 per Boe in 2020 compared to $21.72 per Boe in 2019. Natural production decline combined with lower prices in 2020 lead to a reduction of projected reserves volumes. Therefore, calculated depletion and accretion was greater in 2020 than 2019.

Loss on Impairment

In 2020, as a result of low commodity prices and their effect on the proved reserve values of our properties, we recorded a loss on impairment of approximately $5,725 thousand. The impairment charge affected our reported net income in 2020 but did not reduce our cash flow.

General and Administrative

General and administrative expenses were approximately $1,270 thousand for 2020 compared to $1,567 thousand for 2019. The decrease in 2020 compared to 2019 was primarily due to legal fees incurred in 2020 as part of an arbitration settlement that reached a final settlement in April 2020. General and administrative expense include management fees which were approximately $585 thousand in 2020 compared to $700 thousand in 2019. In November 2020, we extended the life of our management agreement by one year. Under the terms of the new agreement, the investment manager agreed to cease charging management fees as of November 2020. In October 2021, we extended the life of our management agreement by one year.

Gain on Disposal of Oil and Natural Gas Properties

We recognized a gain on disposal of oil and natural gas properties of approximately $597 thousand in 2020 compared to $4,910 thousand in 2019. The decrease in 2020 compared to 2019 was primarily due to the sale of complete unit of mineral assets in the Bakken Basin in 2019, resulting in a gain of $4,828 thousand in 2019.

Gain/(Loss) on Derivative Contracts

We recorded a gain on derivative contracts of approximately $1,714 thousand in 2020 compared to a loss of $1,371 thousand in 2019. Lower commodity prices in 2020 resulted in realized gains of $1,434 thousand compared to realized losses of $158 thousand in 2019. In 2020, unrealized gains were $280 thousand compared to an unrealized loss of $1,213 thousand in 2019.

Our average 2020 realized oil price per barrel after reflecting settled derivatives was $42.57 compared to $52.96 in 2019. Our settled derivatives increased our realized natural gas price per barrel by $5.83 compared to decreasing the realized price per barrel by $0.78 in 2019. Our realized natural gas price per Mcf was $1.02 in 2020 compared to $1.64 in 2019. Our settled derivatives decreased our realized natural gas price per Mcf by $0.02 in 2020 versus an increase of $0.04 in 2019. In 2020, we ended the year with a $93 thousand net derivative liability compared to $373 thousand in 2019.

Interest Expense

Interest expense was approximately $245 thousand in 2020 compared to $665 thousand in 2019. The decrease in interest expense for 2020 as compared to 2019 was primarily due to a decline in the outstanding balance on the revolving credit facility in conjunction with a decline in the weighted average interest rate for the 2020 period versus 2019.

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Liquidity and Capital Resources — Fund I

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, credit facility borrowings, and proceeds from the disposal of oil and natural gas properties. 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 $2,893 thousand in liquidity as of September 30, 2022, consisting of approximately $860 thousand of committed borrowing availability under the revolving credit facility and approximately $2,033 thousand of cash on hand.

Our recent capital commitments have been to fund acquisitions and 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

At September 30, 2022, we had a working capital surplus of approximately $4,046 thousand, compared to a surplus of approximately $1,276 thousand in December 31, 2021. Current assets increased by approximately $2,775 thousand and current liabilities increased by approximately $5 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 cash and revenue receivable, as well as an increase in other assets as a result of the capitalization of eligible transaction costs. The increase in current liabilities in the nine months ended September 30, 2022 as compared to December 31, 2021 is primarily due to an increase in other payable and accrued expenses during the nine months ended September 30, 2022.

Cash Flows

Our cash flows for the nine 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		$	3,977		$	4,544
Net Cash (Used in) Provided by Investing Activities			(1,584)			19,454
Net Cash Used in Financing Activities			(1,100)			(24,300)
Net Change in Cash		$	1,293		$	(302)

Cash Flows from Operating Activities

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Net cash provided by operating activities during the nine months ended September 30, 2022 was approximately $3,977 thousand, compared to approximately $4,544 thousand during the nine months ended September 30, 2021. The decrease in net cash provided by operating activities primarily relates to the divestiture of assets in the Permian basin in 2021, which contributed to the 45% decrease in production period over period, partially offset by a 74% increase in realized prices (before the effects of derivatives). Working capital changes during the nine months ended September 30, 2022 included an increase of $962 thousand in other assets as a result of the capitalization of eligible transaction costs associated with the Business Combination, compared to the nine months ended September 30, 2021, which incurred no capitalized fees. Working capital changes during the nine months ended September 30, 2022 were also impacted by an increase of approximately $484 thousand in revenue receivable related to increased realized oil and natural gas prices (before the effects of derivatives).

Cash Flows from Investing Activities

During the nine months ended September 30, 2022, we had cash flows used in investing activities of approximately $1,584 thousand, as a result of our development of oil and natural gas properties. During the nine months ended September 30, 2021, we had cash flows provided by investing activities of approximately $19,454 thousand, primarily as a result of our proceeds from the disposal of oil and natural gas properties, partially offset by the development of oil and natural gas properties.

Cash Flows from Financing Activities

Net cash used in financing activities was $1,100 thousand and approximately $24,300 thousand for the nine months ended September 30, 2022 and 2021, respectively. The cash used in financing activities for the nine months ended September 30, 2022 was primarily related to repayments on borrowings associated with our revolving credit facility. The cash used in financing activities for the nine months ended September 30, 2021 was primarily related to partners’ distributions and net repayments of borrowings.

Revolving Credit Facility

In August 2015, we entered into a revolving credit facility with an initial borrowing capacity of $10,500 thousand. As of September 30, 2022, through a series of amendments, the borrowing capacity was reduced to $860 thousand with no balance outstanding. On October 24, 2022, the revolving credit facility was terminated and Granite Ridge entered into a new revolving credit agreement. See “— Liquidity and Capital Resources — Fund III (Predecessor), Fund I and Fund II — Credit Agreement” for information regarding the Credit Agreement.

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 include periodic interest payments. See Note 9 to our interim condensed consolidated unaudited financial statements included elsewhere in this prospectus. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 to our interim condensed consolidated unaudited financial statements included elsewhere in this prospectus. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 6 to our consolidated audited financial statements included elsewhere in this prospectus. 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 not budgeting any planned capital expenditures. As of September 30, 2022, we had incurred approximately $157 thousand in capital expenditures that were included in accounts payable. We are not committed to additional capital expenditures not yet incurred. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our Credit Agreement.

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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 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.”

Years ended December 31, 2021 and 2020 compared to years ended December 31, 2020 and 2019, respectively

Overview

Our main sources of liquidity and capital resources as of the date of this report have been internally generated cash flow from operations, credit facility borrowings, and proceeds from the disposal of oil and natural gas properties. Our primary use of capital has been for the development 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 December 31, 2021, we had outstanding debt consisting of $1,100 thousand of borrowings under our revolving credit facility. We had approximately $1,340 thousand in liquidity as of December 31, 2021, consisting of $600 thousand of committed borrowing availability under the revolving credit facility and approximately $740 thousand of cash on hand.

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

Working Capital

At December 31, 2021, we had a working capital surplus of approximately $1,276 thousand, compared to a deficit of approximately $4,014 thousand at December 31, 2020. Current assets decreased by approximately $1,120 thousand and current liabilities decreased by approximately $6,410 thousand at December 31, 2021, compared to December 31, 2020. The decrease in current assets in 2021 as compared to 2020 is primarily due to a decrease in cash and advances due to operators. The decrease in current liabilities in 2021 as compared to 2020 is primarily due to the reduction of our outstanding credit facilities.

Cash Flows

Our cash flows for the years ended December 31, 2021, 2020 and 2019 are presented below:

	Year ended December 31,
(in thousands)	2021			2020			2019
Net Cash Provided by Operating Activities		$	5,473		$	8,152		$	6,426

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	Year ended December 31,
(in thousands)	2021			2020			2019
Net Cash Provided by (Used in) Investing Activities			21,280			(6,455)			8,154
Net Cash Used in Financing Activities			(27,300)			(2,500)			(13,241)
Net Change in Cash		$	(547)		$	(803)		$	1,339

Cash Flows from Operating Activities

Net cash provided by operating activities in 2021 was approximately $5,473 thousand, compared to approximately $8,152 thousand in 2020. The decrease in net cash provided by operating activities primarily relates to the divestiture of our SCOOP and Permian basin assets in 2021, which contributed to the 31% decrease in production period over period. This decrease was partially offset by a 51% increase in realized prices (before the effects of derivatives).

Net cash provided by operating activities in 2020 was approximately $8,152 thousand, compared to approximately $6,426 thousand in 2019. The increase in net cash provided by operating activities in 2020 relates to the receipt of proceeds of approximately $1,108 thousand from customary post-close adjustments related to a 2019 asset divestiture in the SCOOP basin. This amount was recorded as an other receivable as of December 31, 2019 contributing to less cash provided by operating activities in 2019. Working capital changes during 2020 also included a decrease of approximately $637 thousand in revenue receivables due primarily to lower realized oil and natural gas prices (before the effects of derivatives) and a decrease of approximately $528 thousand in accrued operating expenses primarily due to cost reductions in our Permian basin area.

Cash Flows from Investing Activities

We had cash flows provided by (used in) investing activities of approximately $21,280 thousand, approximately $(6,455) thousand and approximately $8,154 thousand during the years ended December 31, 2021, 2020 and 2019, respectively, primarily as a result of our proceeds from the disposal of oil and gas properties during 2021 and 2019 in contrast to an increase in the development of oil and gas properties in 2020.

Cash Flows from Financing Activities

Net cash used in financing activities was approximately $27,300 thousand, approximately $2,500 thousand and approximately $13,241 thousand for the years ended December 31, 2021, 2020 and 2019, respectively. The cash used in financing activities in 2021 was primarily related to partners’ distributions and repayments on borrowings. The cash used in financing activities in 2020 was primarily related to net repayments of borrowings. The cash used in financing activities in 2019 was primarily related to partners’ distributions and net repayments of borrowings.

Revolving Credit Facility

In August 2015, we entered into a revolving credit facility with an initial borrowing capacity of $10,500 thousand. In 2021, through amendments to the facility, the borrowing base was reduced to $1,700 thousand and the maturity date was extended to January 31, 2023. The outstanding balance on the facility was also partially repaid throughout the year, with $1,100 thousand outstanding as of December 31, 2021.

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

We have contractual commitments under our revolving credit facility which include periodic interest payments. See Note 10 to our annual consolidated audited financial statements. We have contractual

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commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 to our annual consolidated audited financial statements. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 6 to our annual consolidated audited financial statements. 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 2022, we are budgeting approximately $1,584 thousand in total planned capital expenditures. As of December 31, 2021, we had incurred approximately $289 thousand in capital expenditures that were included in accounts payable. We are not committed to additional capital expenditures not yet incurred. We expect to fund planned capital expenditures with cash generated from operations and, if required, borrowings under our revolving credit facility.

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 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.”

Results of Operations — Fund II

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		$	47,772		$	47,763
Natural gas and related product sales			62,241			12,059
Revenues			110,013			59,822
Average Sales Prices:
Oil (per Bbl)		$	94.17		$	64.15
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)			(14.61)			(5.82)
Oil net of settled oil derivatives (per Bbl)			79.56			58.33
Natural gas and related product sales (per Mcf)			7.14			2.72
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)			(0.83)			(0.23)
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)			6.31			2.49
Realized price on a Boe basis excluding settled commodity derivatives			56.14			40.34
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)			(7.47)			(3.61)
Realized price on a Boe basis including settled commodity derivatives			48.67			36.73

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	Nine months ended September 30,
	2022			2021
Operating Expenses (in thousands):
Lease operating expenses		$	13,662		$	8,122
Production taxes			5,171			4,505
Depletion and accretion			26,038			24,109
General and administrative			2,709			2,904
Gain on disposal of oil and natural gas properties			—			(955)
Total operating expenses			47,580			38,685
Costs and Expenses (per Boe):
Lease operating expenses		$	6.97		$	5.48
Production taxes			2.64			3.04
Depletion and accretion			13.29			16.26
General and administrative			1.38			1.96
Gain on disposal of oil and natural gas properties			—			(0.64)
Net Producing Wells at Period-End			55.48			51.41

Oil, Natural Gas and Related Product Sales

Our revenues vary from period to period 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 84% from the nine months ended September 30, 2021, driven by a 39% increase in realized prices, excluding the effect of settled commodity derivatives, and a 32% increase in production volumes, respectively. 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.

Realized production from oil and natural gas properties increases through drilling success and acquisition of additional net revenue interests. This increase in production is partially offset by the natural decline of the production rate of existing oil and natural gas wells. In the nine months ended September 30, 2022, the number of wells we participated in increased by approximately 8% as compared to the nine months ended September 30, 2021. The new well additions drove the 32% 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)		507		745
Natural gas (MMcf)		8,714		4,430
Total (MBoe)(1)		1,960		1,483
Average Daily Production:
Oil (Bbl)		1,879		2,758
Natural gas (Mcf)		32,276		16,407
Total (Boe)(1)		7,258		5,492

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Lease Operating Expenses

Lease operating expenses were approximately $13,662 thousand for the nine months ended September 30, 2022, respectively, compared to $8,122 thousand for the nine months ended September 30, 2021. On a per unit basis, production expenses increased 27% from $5.48 per Boe for the nine months ended September 30, 2021, respectively, to $6.97 per Boe for the nine months ended September 30, 2022, respectively, due to an increase in fixed and variable costs, partially offset by increased production volumes over which costs can be spread. On an absolute dollar basis, the 68% 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 32% increase in production.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $5,171 thousand for the nine months ended September 30, 2022, respectively, compared to $4,505 thousand for the nine months ended September 30, 2021, respectively. As a percentage of oil and natural gas sales, our production taxes were 5% and 8% for the nine months ended September 30, 2022 and 2021, respectively. Production taxes as a percent of total oil and natural gas sales decreased due to an increase in natural gas sales as a percentage of total oil and natural gas sales.

Depletion and Accretion

Depletion and accretion was approximately $26,038 thousand for the nine months ended September 30, 2022 compared to $24,109 thousand for the nine months ended September 30, 2021. Depletion and accretion was $13.29 per Boe for the nine months ended September 30, 2022 compared to $16.26 per Boe for the nine months ended September 30, 2021. 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 an 32% increase in production levels.

General and Administrative

General and administrative expenses were approximately $2,709 thousand for the nine months ended September 30, 2022, compared to $2,904 thousand for the nine months ended September 30, 2021. The decrease in 2022 compared to 2021 was primarily due to a decrease in land services fees and fund level expenses. General and administrative fees include management fees which were approximately $1,736 for the nine months ended September 30, 2022 and 2021. Management fees remained materially consistent period over period.

Gain on Disposal of Oil and Natural Gas Properties

We did not recognize a gain on disposal of oil and natural gas properties during the nine months ended September 30, 2022. During the nine months ended September 30, 2021, we recognized a gain on disposal of oil and natural gas properties of approximately $955 thousand. The decrease in the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 was driven by the sale of a partial unit of our Bakken Basin in the first quarter of 2021.

Gain/(Loss) on Derivative Contracts

Our average nine months ended September 30, 2022 realized oil price per barrel after reflecting settled derivatives was $79.56, compared to $58.33 in the nine months ended September 30, 2021. Our settled

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derivatives decreased our realized oil price per barrel by $14.61 in the nine months ended September 30, 2022, compared to $5.82 in the nine months ended September 30, 2021. Our realized natural gas price per Mcf was $6.31 in the nine months ended September 30, 2022, compared to $2.49 in the nine months ended September 30, 2021. Our average settled derivatives decreased our realized natural gas price per Mcf by $0.83 and $0.23 in the nine months ended September 30, 2022 and 2021, respectively. At September 30, 2022, all of our derivative contracts were recorded at their fair value, which resulted in a net asset of approximately $496 thousand and net liability of approximately $3,073 thousand as of December 31, 2021.

Interest Expense

Interest expense was approximately $489 thousand for the nine months ended September 30, 2022, respectively, compared to $611 thousand for the nine months ended September 30, 2021, respectively. The decrease in interest expense for 2022 as compared to 2021 was primarily due to a decline in the outstanding balance on the revolving credit facility, partially offset by an increase in the weighted average interest rate.

Year ended December 31, 2021 compared to year ended December 31, 2020

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.

	Year ended December 31,
	2021			2020
Net Sales (in thousands):
Oil sales		$	66,275		$	43,125
Natural gas and related product sales			16,116			5,892
Revenues			82,391			49,017
Average Sales Prices:
Oil (per Bbl)		$	69.30		$	42.24
Effect of gain (loss) on settled oil derivatives on average price (per Bbl)			(7.65)			6.07
Oil net of settled oil derivatives (per Bbl)			61.65			48.31
Natural gas and related product sales (per Mcf)			2.88			0.83
Effect of gain (loss) on settled natural gas derivatives on average price (per Mcf)			(0.50)			0.20
Natural gas and related product sales net of settled natural gas derivatives (per Mcf)			2.38			1.03
Realized price on a Boe basis excluding settled commodity derivatives			43.62			22.17
Effect of gain (loss) on settled commodity derivatives on average price (per Boe)			(5.37)			3.46
Realized price on a Boe basis including settled commodity derivatives			38.25			25.63
Operating Expenses (in thousands):
Lease operating expenses		$	13,128		$	13,760
Production taxes			5,675			3,564
Depletion and accretion			31,090			47,980
General and administrative			3,528			3,672
Gain on disposal of oil and natural gas properties			(938)			(51)
Total operating expenses			52,483			68,925
Costs and Expenses (per Boe):
Lease operating expenses		$	6.95		$	6.22
Production taxes			3.00			1.61
Depletion and accretion			16.46			21.70
General and administrative			1.87			1.66

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	Year ended December 31,
	2021		2020
Gain on disposal of oil and natural gas properties		(0.50)		(0.02)
Net Producing Wells at Period-End		53.63		52.01

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. In 2021, our oil and natural gas sales increased 68% from 2020, driven by a 97% increase in realized prices, excluding the effect of settled commodity derivatives, partially offset by a 15% decrease in production volumes. The higher average price in 2021 as compared to 2020 was driven by higher average NYMEX oil and natural gas prices.

Realized production from oil and natural gas properties increases through drilling success and acquisition of additional net revenue interests. The increase in production is offset by the natural decline of the production rate of existing oil and natural gas wells. In 2021, the number of wells we participated in increased by 3% as compared to 2020. Although there was a slight increase in net wells year-over-year, production levels declined 15% in 2021 as compared to 2020. The decline was driven by the natural decline in production from existing wells.

Production for the last two years is set forth in the following table:

	Year ended December 31,
	2021		2020
Production:
Oil (MBbl)		956		1,021
Natural gas (MMcf)		5,595		7,142
Total (MBoe)(1)		1,889		2,211
Average Daily Production:
Oil (Bbl)		2,620		2,797
Natural gas (Mcf)		15,329		19,566
Total (Boe)(1)		5,175		6,058

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Lease Operating Expenses

Lease operating expenses were approximately $13,128 thousand in 2021 compared to $13,760 thousand in 2020. On a per unit basis, production expenses increased 12% from $6.22 per Boe in 2020 to $6.95 per Boe in 2021 due primarily to lower production volumes over which fixed costs can be spread. On an absolute dollar basis, the 5% decrease in our production related expenses in 2021 compared to 2020 was primarily due to a 15% decrease in production, offset by a 12% increase in per unit costs.

Production Taxes

We pay production taxes based on realized oil and natural gas sales. Production taxes were $5,675 thousand in 2021 compared to $3,564 thousand in 2020. As a percentage of oil and natural gas sales, our production taxes were 7% in 2021 and 2020. 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 $31,090 thousand in 2021 compared to $47,980 thousand in 2020. Depletion and accretion was $16.46 per Boe in 2021 compared to $21.70 per Boe in 2020. The

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aggregate decrease in depletion and accretion expense for 2021 compared to 2020 was driven by a 24% decrease in the depletion and accretion rate per Boe and a 15% decrease in production levels.

General and Administrative

General and administrative expenses were approximately $3,528 thousand for 2021 compared to $3,672 thousand for 2020. The decrease in general and administrative expenses was primarily due to a decrease in legal fees as well as a decrease in brokerage fees which were higher in 2020 due to increased acquisition activity compared to 2021. The decrease was partially offset by an increase in franchise taxes in 2021. General and administrative expenses include management fees which were approximately $2,315 thousand in 2021 compared to approximately $2,185 thousand in 2020. Management fees after the expiration of the investment period are calculated on funded capital commitments, any fluctuations in management fees are due to an increase or decrease in invested capital measured at the beginning of each fiscal quarter.

Gain on Disposal of Oil and Natural Gas Properties

We recognized a gain on disposal of oil and natural gas properties of approximately $938 thousand in 2021 compared to $51 thousand in 2020. The increase in 2021 compared to 2020 was driven primarily by the sale of a partial unit of our Bakken Basin in 2021.

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 $13,232 thousand in 2021 compared to a gain of $8,363 thousand in 2020. Commodity price volatility during 2021 resulted in realized losses of $10,139 thousand compared to realized gains of $7,640 thousand in 2020. In 2021, unrealized losses were $3,093 thousand compared to unrealized gains of $723 thousand in 2020.

Our average 2021 realized oil price per barrel after reflecting settled derivatives was $61.65 compared to $48.31 in 2020. Our settled derivatives decreased our realized oil price per barrel by $7.65 compared to increasing the price per barrel by $6.07 in 2020. Our realized natural gas price per Mcf was $2.38 in 2021 compared to $1.03 in 2020. Our average settled derivatives decreased our realized natural gas price per Mcf by $0.50 in 2021 and increased our realized natural gas price per Mcf by $0.20 in 2020. At December 31, 2021, all of our derivative contracts were recorded at their fair value, which resulted in a net liability of approximately $3,073 thousand, as opposed to a $21 thousand net asset recorded as of December 31, 2020.

Interest Expense

Interest expense was approximately $848 thousand in 2021 compared to $1,167 thousand in 2020. The decrease in interest expense for 2021 as compared to 2020 was primarily due to a decline in the outstanding balance on the revolving credit facility in conjunction with a decline in the weighted average interest rate for the 2021 period compared to 2020.

Liquidity and Capital Resources — Fund II

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

Overview

As of September 30, 2022, we had no outstanding debt. We had approximately $68,688 thousand in liquidity as of September 30, 2022, consisting of approximately $40,000 thousand of committed borrowing availability under the revolving credit facility and approximately $28,688 thousand of cash on hand.

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Working Capital

At September 30, 2022, we had a working capital surplus of approximately $46,881 thousand, compared to a deficit of approximately $7,996 thousand at December 31, 2021. Current assets increased by approximately $34,625 thousand and current liabilities decreased by approximately $20,252 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 cash and revenue receivable, in addition to an increase in other assets as a result of the capitalization of eligible transaction costs. The decrease in current liabilities in the nine months ended September 30, 2022 as compared to December 31, 2021 is primarily due to a decrease in our outstanding credit facilities balance and the reclassification of our derivatives assets from current liabilities to current assets, partially offset by an increase in accrued expenses.

Cash Flows

Our cash flows for the nine 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		$	67,718		$	34,209
Net Cash Used in Investing Activities			(22,824)			(11,344)
Net Cash Used in Financing Activities			(20,000)			(22,084)
Net Change in Cash		$	24,894		$	781

Cash Flows from Operating Activities

Net cash provided by operating activities during the nine months ended September 30, 2022 was approximately $67,718 thousand, compared to approximately $34,209 thousand during the nine months ended September 30, 2021. The increase in net cash provided by operating activities primarily relates to higher revenues due to a 39% increase in realized prices (before the effects of derivatives) and a 32% increase in production period over period. The increase in production volumes was driven by production from natural gas wells drilled in the Haynesville area, which came online during the nine months ended September 30, 2022, and was partially offset by natural production decline from existing wells. Working capital changes during the nine months ended September 30, 2022 resulted from an increase of approximately $5,406 thousand in revenue receivables, primarily associated with our natural gas revenues due to the successful drilling and development in our Haynesville area, in addition to higher realized prices (before the effects of derivatives).

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Working capital during the nine months ended September 30, 2022 was also impacted by an increase of approximately $1,973 thousand in accrued expenses associated with operating and development expenses on our Bakken and Permian assets and an increase of approximately $1,991 in other assets as a result of the capitalization of eligible transaction costs associated with the Business Combination. Working capital changes during the nine months ended September 30, 2021 were impacted by an increase in revenue receivables of approximately $3,840 thousand due primarily to an increase in realized prices (before the effects of derivatives), as commodity prices recovered from their historic lows in 2020 as a result of COVID-19.

Cash Flows from Investing Activities

We had cash flows used in investing activities of approximately $22,824 thousand and approximately $11,344 thousand during the nine months ended September 30, 2022 and 2021, respectively, primarily due to an increase in the acquisition and development of oil and natural gas properties. Further, we recognized approximately $2,009 thousand in cash proceeds from the disposal of oil and gas properties during the nine months ended September 30, 2021 compared to $6 thousand on the disposal of oil and gas properties during the nine months ended September 30, 2022.

Cash Flows from Financing Activities

Net cash used in financing activities was $20,000 thousand and approximately $22,084 thousand for the nine months ended September 30, 2022 and 2021, respectively. Repayments on the revolving credit facility were $20,000 thousand and $4,100 thousand for the nine months ended September 30, 2022 and 2021, respectively. Additionally, the use of cash for the nine months ended September 30, 2021 was also driven by partners’ distributions, partially offset by proceeds from borrowings on the revolving credit facility.

Revolving Credit Facility

In November 2017, we entered into a revolving credit facility with an initial borrowing capacity of approximately $25,000 thousand with a maturity date of November 17, 2022. As of September 30, 2022, the borrowing base was approximately $40,000 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 “— Liquidity and Capital Resources — Fund III (Predecessor), Fund I and Fund II — Credit Agreement” for information regarding the Credit Agreement.

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 interim condensed combined unaudited financial statements included elsewhere in this prospectus. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 3 to our interim condensed combined unaudited financial statements included elsewhere in this prospectus. We have future obligations related to the abandonment of our oil and natural gas properties. See Note 6 to our annual combined audited financial statements included elsewhere in this prospectus. 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 $10,623 thousand in total planned capital expenditures. As of September 30, 2022, we had incurred approximately $1,412 thousand in capital expenditures that were included in accounts payable, and we estimate that we were committed to an additional approximately $10,623 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 our Credit Agreement.

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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 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.”

Year ended December 31, 2021 compared to year ended December 31, 2020

Overview

As of December 31, 2021, we had outstanding debt consisting of approximately $20,000 thousand of borrowings under our revolving credit facility. We had approximately $23,794 thousand in liquidity as of December 31, 2021, consisting of approximately $20,000 thousand of committed borrowing availability under the revolving credit facility and approximately $3,794 thousand of cash on hand.

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

Working Capital

At December 31, 2021, we had a working capital deficit of approximately $7,996 thousand, compared to a surplus of approximately $9,234 thousand at December 31, 2020. Current assets increased by approximately $4,908 thousand and current liabilities increased by approximately $22,138 thousand at December 31, 2021, compared to December 31, 2020. The increase in current assets in 2021 as compared to 2020 is primarily due to an increase in revenue receivable. The increase in current liabilities in 2021 as compared to 2020 is primarily due to the increase of our outstanding credit facilities.

Cash Flows

Our cash flows for the years ended December 31, 2021 and 2020 are presented below:

	Year Ended December 31,
(in thousands)	2021			2020
Net Cash Provided by Operating Activities		$	43,990		$	44,569

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	Year Ended December 31,
(in thousands)	2021			2020
Net Cash Used in Investing Activities			(13,288)			(29,420)
Net Cash Used in Financing Activities			(31,191)			(11,876)
Net Change in Cash		$	(489)		$	3,273

Cash Flows from Operating Activities

Net cash provided by operating activities in 2021 was approximately $43,990 thousand, compared to approximately $44,569 thousand in 2020. While operating revenues increased in 2021 compared to 2020 primarily due to a 97% increase in realized prices (before the effects of derivatives), changes in working capital contributed to the slight decrease in net cash provided by operating activities year over year. Working capital changes during 2021 included an increase of approximately $5,422 thousand in revenue receivables due to an increase in realized prices (before the effects of derivatives), whereas working capital changes in 2020 included a decrease of approximately $9,539 thousand in revenue receivables as a result of natural production decline and the historic low production and crude oil prices experienced in 2020 due to the effects of COVID-19.

Cash Flows from Investing Activities

We had cash flows used in investing activities of approximately $13,288 thousand and approximately $29,420 thousand during the years ended December 31, 2021 and 2020, respectively, primarily as a result of a decrease in the development of oil and gas properties in 2021 compared to 2020.

Cash Flows from Financing Activities

Net cash used in financing activities was approximately $31,191 thousand and approximately $11,876 thousand for the years ended December 31, 2021 and 2020, respectively. The cash used in financing activities in 2021 was primarily related to partners’ distributions and net repayments on borrowings. The cash used in financing activities in 2020 was primarily related to net partners’ distributions and net repayments of borrowings.

Revolving Credit Facility

In November 2017, we entered into a revolving credit facility with an initial borrowing capacity of $25,000 thousand with a maturity date of November 17, 2022. In 2021, through amendments to the facility, the borrowing base was increased to $40,000 thousand. The outstanding balance on the facility was also partially repaid throughout the year, with $20,000 thousand outstanding as of December 31, 2021.

Known Contractual and Other Obligations; Planned Capital Expenditures

Contractual and Other Obligations

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Planned Capital Expenditures

For 2022, we are budgeting approximately $21,242 thousand in total planned capital expenditures. As of December 31, 2021, we had incurred approximately $1,350 thousand in capital expenditures that were included in accounts payable, and we estimate that we were committed to an additional approximately $16,521 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 our revolving credit facility.

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 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.”

The information presented in the following sections is applicable to the collective Funds.

Liquidity and Capital Resources — Fund III (Predecessor), Fund I and Fund II

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 our Credit Agreement To the extent capital requirements exceed internal cash flow and borrowing capacity under our Credit Agreement, 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 Credit Agreement, we may issue additional debt or equity to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Our ability to raise additional capital through the sale of equity or debt securities could be significantly impacted by the resale of shares of common stock by Selling Securityholders pursuant to this prospectus. Accordingly, the shares beneficially owned by the Existing GREP Members who are Selling Securityholders hereunder represent more than 89% of the total outstanding shares of Granite Ridge common stock and all of the shares that may be offered by the Selling Securityholders collectively represent more than 96% of the total outstanding shares of Granite Ridge common stock, and these holders will have the ability to sell or distribute all of their shares pursuant to the registration statement of which this prospectus forms a part so long as it is available for use. The sale of the securities being registered in this prospectus therefore could result in a significant decline in the public trading price of Granite Ridge common stock and potentially hinder our ability to raise capital at terms that are acceptable to us or at all.

Satisfaction of Our Cash Obligations for the Next Twelve Months

With our Credit Agreement and our positive cash flows from operations, and excluding any potential cash proceeds from the exercise of Granite Ridge warrants (which we believe are unlikely to be exercised if trading prices for Granite Ridge common stock continue to be less than $11.50 per share), 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

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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. Further, our revolving credit facilities have due dates within one year of September 30, 2022. The revolving credit facilities for each of the Funds were terminated in connection with the Business Combination, and the Company entered into the Credit Agreement. See “— Credit Agreement” for information regarding the Credit Agreement.

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.

Credit Agreement

On October 24, 2022, the Funds terminated their revolving credit facilities, and the Company entered into a senior secured revolving credit agreement (the “Credit Agreement”) among the Company, as borrower, Texas Capital Bank, as administrative agent, and the lenders from time to time party thereto. The Credit Agreement has a maturity 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, each of the Company and the Required Lenders (as defined in the Credit Agreement) may request one unscheduled redetermination of the borrowing base between each scheduled redetermination. The amount of the borrowing base is determined by the lenders in their sole discretion and consistent with the oil and gas lending criteria of the lenders at the time of the relevant redetermination. The amount the Company is able to borrow under the Credit Agreement is subject to compliance with the financial covenants, satisfaction of various conditions precedent to borrowing and other provisions of the Credit Agreement.

As of the closing date of the Credit Agreement, the Company does not have any borrowings or letters of credit outstanding under the Credit Agreement, resulting in availability of approximately $150 million. The Credit Agreement is guaranteed by the restricted subsidiaries of the Company and is secured by a first priority mortgage and security interest in substantially all assets of the Company and its restricted subsidiaries.

Borrowings under the Credit Agreement may be base rate loans or SOFR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at SOFR plus an applicable margin ranging from 250 to 350 basis points, depending on the percentage of the borrowing base utilized, plus an additional 10, 15 or 20 basis point credit spread adjustment for a one, three or six month interest period, respectively. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the U.S. prime rate as published by the Wall Street Journal; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized. The Company also pays a commitment fee on unused elected commitment amounts under its facility of 50 basis points. The Company may repay any amounts borrowed under the Credit Agreement prior to the maturity date without any premium or penalty.

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The Credit Agreement also contains certain financial covenants, including the maintenance of the following financial ratios: (i) a current ratio, which is the ratio of the Company’s consolidated current assets (including unused commitments under the Credit Agreement and excluding non-cash asset retirement and derivative assets) to its consolidated current liabilities (excluding the current portion of long-term debt under the Credit Agreement and non-cash asset retirement and derivative liabilities), of not less than 1.00 to 1.00; and (ii) a leverage ratio, which is the ratio of Consolidated Total Debt to EBITDAX (each as defined in the Credit Agreement) for the prior four fiscal quarters (with EBITDAX annualized in a customary manner for the first three quarterly reporting periods), of not greater than 3.00 to 1.00.

The Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness, incur additional liens, enter into mergers and acquisitions, make or declare dividends, repurchase or redeem junior debt, make investments and loans, engage in transactions with affiliates, sell assets and enter into certain hedging transactions. In addition, the Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the administrative agent may, with the consent of majority lenders, or shall, at the direction of the majority lenders, accelerate any amounts outstanding and terminate lender commitments.

Critical Accounting Estimates

The establishment and consistent application of accounting policies is a vital component of accurately and fairly presenting our financial statements in accordance with generally accepted accounting principles in the United States (GAAP), as well as ensuring compliance with applicable laws and regulations governing financial reporting. While there are rarely alternative methods or rules from which to select in establishing accounting and financial reporting policies, proper application often involves significant judgment regarding a given set of facts and circumstances and a complex series of decisions. Further, these estimates and other factors, including those outside of management’s control could have significant adverse impact to the financial condition, results of operations and cash flows of the Fund.

Use of Estimates

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period.

Oil and Natural Gas Reserves

The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to the Fund’s properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. As of December 31, 2021, approximately 49% of our oil and 57% of our gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserve, future cash flows from our reserves, and future development of our proved undeveloped reserves.

The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Such information includes revisions of certain reserve estimates attributable to the properties included in the prior year’s estimates. These revisions

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reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in oil and natural gas prices.

External petroleum engineers independently estimated all of the proved reserve quantities included in the Fund’s financial statements, and were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests. The third- party independent reserve engineers, Netherland, Sewell & Associates, Inc., evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2021.

Oil and Natural Gas Properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. The successful efforts method inherently relies on the estimation of proved oil and natural gas reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depleted into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.

Depletion and accretion of oil and natural gas producing properties is determined using the units-of-production method. During the nine months ended September 30, 2022 and 2021, we recognized depletion and accretion expense of approximately $98,178 thousand and $72,440 thousand, respectively. During the years ended December 31, 2021 and 2020, we recognized depletion and accretion expense of approximately $94,661 thousand and approximately $79,947 thousand, respectively.

While revisions of previous reserve estimates have not historically been significant to the depletion rates, any reduction in proved reserves, could result in an acceleration of future depletion and accretion expense. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record depletion and accretion expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record depletion and accretion expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.

Impairment of Oil and Natural Gas Properties

Proved and unproved oil and natural gas properties are reviewed for impairment at least annually, or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When performing our assessment, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include:

•

Estimates of oil and natural gas reserves and expected timing of production. Our oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Reserve engineering is a subjective process, which requires assumptions associated with the underground accumulations of oil and natural gas, development costs, future commodity prices and the future regulatory and political environment. Any significant variance in these assumptions could materially affect the estimated quantity and value of the reserves, which would affect the fair value of our oil and natural gas properties. The estimates of our reserves help to inform our expectation of future oil and natural gas production, which will likely vary from actual production.

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•

Future commodity prices, which are based on publicly available forward commodity prices for a period of time and then escalated at 2.5% thereafter. A decrease in estimated future commodity prices will decrease the fair value of our oil and natural gas properties.

•

Future capital requirements, which are based on our internal forecasts and supported by the underlying cash flows generated from our oil and natural gas assets.

•

Discount rate commensurate with the risk associated with realizing projected cash flows, which is based on a variety of factors, including market and economic conditions, as well as operational and regulatory risk.

In March 2020, crude oil demand experienced significant declines due to the COVID-19 pandemic and resulting governmental led shut-downs in economic activity. During 2020, as it became apparent that the pandemic would continue with sustained significant decline in crude oil prices, we assessed our oil and natural gas properties for impairment and recorded impairment expense of approximately $5,725 thousand during the year ended December 31, 2020. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.

We did not incur any impairment expense during the nine months ended September 30, 2022 and 2021 or the years ended December 31, 2021 and 2019.

Derivative Instruments

In order to reduce uncertainty around commodity prices received for our oil and natural gas operators’ production, we enter into commodity price derivative contracts from time to time. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties’ creditworthiness.

We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and fair value is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.

Asset Retirement Obligations

We record the fair value of the liability for an ARO in the period in which it is legally or contractually incurred. Upon initial recognition of the ARO, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion over the asset’s useful life. Changes in the liability for ARO are recognized for (i) the passage of time and (ii) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted liability to its estimated settlement value.

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The estimates of our future ARO require substantial judgment. We estimate the future costs associated with our retirement obligations, the expected remaining life of the related asset and our credit-adjusted-risk-free interest rate. As revisions to these estimates occur, we may have significant changes to the related asset and its ARO.

If future abandonment cost estimates were to exceed current estimates, or if assets had shortened lives compared to current estimates, we would expect to increase the recorded liability for ARO, which would trigger recognition of additional expense and a reduction to our net income.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Notes to the Grey Rock Energy Fund III Annual Combined and the Interim Unaudited Financial Statements — Note 2. Summary of Significant Accounting Policies, Notes to the Grey Rock Energy Fund, LP and Subsidiaries Annual Consolidated and Interim Unaudited Financial Statements — Note 2. Summary of Significant Accounting Policies and Notes to the Grey Rock Energy Fund II Annual Combined and the Interim Unaudited Financial Statements — Note 2. Summary of Significant Accounting Policies.

Off-Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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 $51,038 thousand of debt outstanding, which bears interest at a floating rate. Based on the approximately $51,038 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 $510 thousand in interest expense per year. We do not currently have any

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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.

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MANAGEMENT

Directors and Executive Officers

Set forth below are the name, age and description of the business experience of our executive officers and directors.

Name	Age	Position
Luke C. Brandenberg	37	President and Chief Executive Officer
Tyler S. Farquharson	40	Chief Financial Officer
Matthew Miller	38	Director and Co-Chairman of the Board
Griffin Perry	39	Director and Co-Chairman of the Board
Amanda N. Coussens	42	Director
Thaddeus Darden	36	Director
Michele J. Everard	71	Director
Kirk Lazarine	69	Director
John McCartney	70	Director

Luke C. Brandenberg has over 15 years of experience in the energy industry. Prior to joining Granite Ridge, he served as Managing Director of Vortus Investments, a private equity firm focused on the lower/middle market upstream energy industry in North America, from April 2021 through June 2022. From 2020 to April 2021, Mr. Brandenberg partnered with Grey Rock to launch a special situations initiative and to lead the deal origination, structuring, and relationship management efforts for the new platform. From 2010 to 2020, Mr. Brandenberg served in various roles with EnCap Investments, most recently as Director — Upstream Investment Staff, where he was a key board member and the primary relationship manager on multiple portfolio companies representing a significant portion of EnCap’s equity commitments. From 2007 to 2010, Mr. Brandenberg served as an investment banking analyst in the energy group of Raymond James & Associates where he focused on public market capital raises, restructuring of oil and gas investments, and mergers and acquisitions advisory work in the upstream, midstream, and oilfield services sectors of the energy. Mr. Brandenberg has a Bachelor of Business Administration degree with honors in Business Honors and Finance from The University of Texas at Austin.

Tyler S. Farquharson has over 16 years of oil and gas finance experience. During the past five years, Mr. Farquharson was Vice President, Chief Financial Officer and Treasurer of EXCO Resources, Inc. (“EXCO”), an independent oil and natural gas company, a position he held from October 2017 to May 2022. In January 2018, EXCO filed voluntary petitions for Chapter 11 bankruptcy protection under the U.S. Bankruptcy Code. Subsequently, EXCO filed a reorganization plan in bankruptcy court in October 2018 and emerged from bankruptcy in July 2019. Mr. Farquharson began his career in August 2005 serving in various corporate finance, planning, treasury and investor relations roles at EXCO. Mr. Farquharson received a B.S. in Finance from the University of Kansas in 2005.

Matthew Miller is a Co-Founder and Managing Director at Grey Rock, and he is a member of Grey Rock’s Investment Committee and Valuation Committee. Since founding Grey Rock in 2013, Mr. Miller has focused on deal origination, valuation, due diligence, execution, project management and divestitures of the oil and gas properties managed by Grey Rock. Using his background on sophisticated valuation of major onshore acquisitions and divestitures, Mr. Miller works to ensure that the Grey Rock portfolio maximizes return for a given amount of risk. Mr. Miller and his team have originated, diligenced, and closed over $250 million in assets in the Midland, Delaware, Eagle Ford, Bakken, and Haynesville plays. From 2008 to 2013, Mr. Miller served as a Vice President at Bluescape Resources, a company focused on finding distressed upstream U.S. oil and gas investment opportunities. Prior to Bluescape Resources, Mr. Miller worked at McKinsey & Co. from 2006 to 2008 where his clients included several multi-billion dollar private equity firms. Mr. Miller holds a BS in Commerce from the University of Virginia, and he is a CFA charterholder. Granite Ridge believes Mr. Miller is qualified to serve on the Granite Ridge Board because of his extensive experience in the energy sector, his business acumen, and his leadership skills.

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Griffin Perry is a Co-Founder and Managing Director at Grey Rock, and he is a member of Grey Rock’s Investment Committee. Since founding Grey Rock in 2013, Mr. Perry has focused on controls, investor relations, risk management, and day-to-day operations of Grey Rock. Further, Mr. Perry assists in origination and portfolio management of Grey Rock’s assets. From 2012 to 2013, Mr. Perry was the President of Caddis Energy, an oil and gas investment company that partnered with industry leaders to raise capital and develop a pipeline of business focusing on both operated and non-operated oil and gas properties. From 2007 to 2012, Mr. Perry worked as a financial advisor with UBS and Deutsche Bank. During his tenure in these positions, Mr. Perry worked to grow assets under management from $300 million to $500 million. He is also a member of the Cotton Bowl Board. Mr. Perry holds a BA in economics and history from Vanderbilt University. Granite Ridge believes Mr. Perry is qualified to serve on the Granite Ridge Board because of extensive experience in the energy sector, his business acumen, and his leadership skills.

Amanda N. Coussens is the Chief Financial Officer and Chief Commercial Officer for P10, Inc. (NYSE: PX), a publicly traded asset manager, with over $20 billion in assets under management where she has served since January 2021 and taken P10, Inc. both through an initial public offering and a subsequent debt refinance. Prior to P10, Inc., from 2017 through 2020, Ms. Coussens served as Chief Financial Officer and Chief Compliance Officer of PetroCap, LLC (“PetroCap”), an upstream energy private equity fund, where she oversaw finance both for PetroCap and portfolio companies of PetroCap. Prior to PetroCap, from 2015 through 2017, Ms. Coussens served as a consulting Chief Financial Officer with Aduro Advisors where she worked for several start-up venture and private equity funds in the upstream energy sector. Prior to Aduro Advisors, from 2014 through 2016, Ms. Coussens served as Chief Financial Officer for White Deer Energy, a private equity firm targeting investments in oil and gas exploration and production, oilfield service and equipment manufacturing, and the midstream sector of the energy industry. Prior to White Deer Energy, from 2013 through 2014, Ms. Coussens served as Director of Financial Services for Timmon Advisors, LLC, an asset management firm, and from 2010 through 2013, Ms. Coussens served as Director of SEC and Financial Reporting for Edelman Financial Group (formerly Sanders Morris Harris) (NASDAQ: EF), a publicly traded asset management firm with over $20 billion of assets under management, overseeing aspects of SEC reporting and acquisition integration. Ms. Coussens began her career as an audit and tax associate for Null-Lairson, P.C. from 2002 to 2004, an audit manager for Grant Thornton from 2004 to 2008, and a controller for Tudor, Pickering, Holt and Co. and TPH Partners from 2008 to 2010. Ms. Coussens is a Certified Public Accountant and holds a B.A. in Accounting from the University of Houston, where she graduated with honors. Granite Ridge believes Ms. Coussens is qualified to serve on the Granite Ridge Board because of her extensive experience in the energy industry in finance, accounting, and operational roles, including her prior expertise as the CFO of a publicly traded company and experience with oil and gas private equity firms.

Thaddeus Darden is a Partner at Grey Rock, and he is a member of Grey Rock’s Valuation Committee. Joining Grey Rock in 2014, Mr. Darden manages financial modeling and assists in deal diligence, portfolio valuation, and business development. His focus is to accurately forecast and understand the financial performance and sensitivities of portfolios of oil and gas properties managed by Grey Rock. From 2010 to 2014, Mr. Darden worked at Bain & Company primarily in the oil and gas practice. During Mr. Darden’s tenure at Bain, he provided deal diligences, built growth strategies, and streamlined operations for numerous upstream and midstream oil and gas companies. Mr. Darden holds a BS in Systems Engineering from the University of Virginia where he was a Jefferson Scholar. Granite Ridge believes Mr. Darden is qualified to serve on the Granite Ridge Board because of his extensive experience in the energy sector and his business acumen.

Michele J. Everard was employed in the University of Michigan’s Investment Office for over thirty-eight years, most recently as Managing Director, until her retirement in December of 2019. Ms. Everard was responsible for investment strategy, recommendation of new investment opportunities and monitoring of the University Endowment’s Real Estate and Natural Resources portfolios. She was a member of the University’s Investment Committee and participated in the management of all of the University’s investment programs, including the Endowment Fund which ranks in the top ten among institutions of higher education. Ms. Everard has a Bachelor of Business Administration in finance from Eastern Michigan University and is a CFA charterholder. Granite Ridge believes Ms. Everard is qualified to serve on the Granite Ridge Board because of her depth of knowledge as the director of real asset investments for the University of Michigan.

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Kirk Lazarine is a Co-Founder and Managing Director at Grey Rock, and he is a member of Grey Rock’s Investment Committee. Since founding Grey Rock in 2013, Mr. Lazarine has focused on business development, deal origination, due diligence, land agreements, portfolio management and divestitures of oil and gas properties managed by Grey Rock. Using networks built over a 30+ year career in oil and gas, Mr. Lazarine provides a unique source of deal flow, contacts, and experience. Mr. Lazarine has participated in transactions totaling over $1 billion of assets across the U.S., including several hundred wells and 700,000 acres. From 2004 to 2013, Mr. Lazarine served as CEO of KOR Resources, where he led the acquisition of a significant lease position in the Eagle Ford oil window with Matt Miller. Prior to KOR, Mr. Lazarine served at Chevron for 23 years including as a manager for Chevron’s unconventional gas team. Mr. Lazarine has negotiated several hundred agreements, including purchase and sale agreements, leases, JOAs, farm-ins, JVs, and EDAs. Mr. Lazarine holds a BBA from Southwest Texas State University and a BS in Petroleum Land Management from the University of Houston, and is a member of the AAPL and WHAPL. Granite Ridge believes Mr. Lazarine is qualified to serve on the Granite Ridge Board because of extensive experience in the energy sector, his business acumen, and his leadership skills.

John McCartney joined the executive management team of US Robotics in March 1984 as Vice President and Chief Financial Officer. At US Robotics, he served in various executive capacities, including as Executive Vice President, International, until serving as President and Chief Operating Officer from January 1996 until its merger with 3Com Corporation in June 1997. Since 2010 Mr. McCartney has served as Chairman of the Board of Huron Consulting Group (NASDAQ: HURN), where he has been a director since 2004. From June 1997 to March 1998, Mr. McCartney held the position of President of 3Com Corporation’s Client Access Unit. Mr. McCartney has served on the board of Datatec Limited, a publicly traded networking technology and services company since 2007, where he currently is a member of its nominations committee. Mr. McCartney also serves as a director of EQT, Corp. (NYSE: EQT), a publicly traded natural gas exploration and production company and as a member of its public policy and corporate responsibility, and corporate governance committees. During the past several years, Mr. McCartney previously served on the boards of Transco, Inc. a Chicago-based company that provides solutions to customers in the electric utility industry, Westcon Group, Inc., a specialty distributor of networking and communications equipment, Rice Energy Inc., a formerly publicly traded independent natural gas and oil company acquired by EQT in 2017, and Covance Inc., a formerly publicly traded drug development services company acquired by Laboratory Corporation of America Holdings (NYSE: LH) in 2015. Mr. McCartney received a B.A. in Philosophy from Davidson College and an M.B.A. from The Wharton School of the University of Pennsylvania. Granite Ridge believes Mr. McCartney is qualified to serve on the Granite Ridge Board because of his deep public company, governance and accounting experience, having served as chairman and vice chairman of the boards of numerous public and private companies, including another energy company.

Family Relationships

There are no family relationships between any of our executive officers and directors.

Board Composition

Granite Ridge’s amended and restated certificate of incorporation and Granite Ridge’s amended and restated bylaws provide for a classified board of directors consisting of three classes of directors, each serving staggered three-year terms (other than the initial Class I directors and Class II directors), as follows:

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Our Class I directors are Kirk Lazarine, Thaddeus Darden and Michele J. Everard, and their initial term will expire at our 2023 annual meeting of stockholders.

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Our Class II directors are Matthew Miller and John McCartney, and their terms will expire at our 2024 annual meeting of stockholders.

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Our Class III directors are Griffin Perry and Amanda N. Coussens, and their terms will expire at our 2025 annual meeting of stockholders.

Upon expiration of the term of a class of directors, directors for that class will be elected for three-year terms at the annual meeting of stockholders in the year in which that term expires. Each director’s term continues until the election and qualification of his or her successor or his or her earlier death, resignation

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or removal. Any increase or decrease in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of an equal number of directors.

Independence of Directors

The NYSE listing standards generally define an “independent director” as a person that, in the opinion of the issuer’s board of directors, has no material relationship with the listed company (either directly or as a partner, stockholder or officer of an organization that has a relationship with the company).

As of the Closing Date, the Existing GREP Members collectively own a majority of Granite Ridge’s voting common stock. As a result, under the NYSE’s current listing standards, Granite Ridge qualifies for, and expects to avail itself of, the controlled company exemptions under the corporate governance rules of the NYSE. As a controlled company, Granite Ridge is not be required to have a majority of “independent directors” on its board of directors, as defined under the rules of the NYSE, or a compensation committee and a nominating and governance committee composed entirely of “independent directors.” Notwithstanding the exemption, The Granite Ridge Board has determined that Amanda Coussens, Michele Everard, and John McCartney are independent directors of Granite Ridge, as defined under the NYSE rules and that Granite Ridge shall have a compensation committee.

Board Leadership Structure and Role in Risk Oversight

The individuals selected to be on the Granite Ridge Board recognize that the leadership structure and combination or separation of the Chief Executive Officer and Chairman (or co-Chairmen, as applicable) roles is driven by the needs of Granite Ridge at any point in time. As a result, the Granite Ridge Board does not have a fixed policy regarding the separation of the offices of Chief Executive Officer and Chairman (or co-Chairmen, as applicable) and instead the Granite Ridge Board will maintain the flexibility to select the Chairman (or co-Chairmen, as applicable) and its leadership structure, from time to time, based on the criteria that it deems in the best interests of Granite Ridge and its stockholders. Currently, the roles of Chief Executive Officer and Chairman (or co-Chairmen, as applicable) are separate. The individuals selected to be on the Granite Ridge Board believe that, at this time, having a separate Chief Executive Officer and Chairman is the appropriate leadership structure for Granite Ridge.

The Granite Ridge Board oversees the risk management activities designed and implemented by its management and by the Manager through the MSA. The Granite Ridge Board does not have a standing risk management committee, but rather anticipates executing its oversight responsibility both directly and through its standing committees. The Granite Ridge Board also will consider specific risk topics, including risks associated with Granite Ridge’s strategic initiatives, business plans and capital structure. Granite Ridge’s management, directly and through Granite Ridge’s MSA with the Manager, is primarily responsible for managing the risks associated with operation and business of the company and provide appropriate updates to the Granite Ridge Board and the Audit Committee. The Granite Ridge Board delegates to the Audit Committee oversight of its risk management process, and Granite Ridge’s other board committees also consider risks as they perform their respective committee responsibilities. All board committees report to the Granite Ridge Board as appropriate, including, but not limited to, when a matter rises to the level of a material or enterprise risk.

Committees of the Granite Ridge Board

The standing committees of the Granite Ridge Board consist of an Audit Committee, a Compensation Committee, an Environmental, Sustainability and Governance Committee (“ESG Committee”) and a Conflicts Committee. Each committee reports to the Granite Ridge Board as they deem appropriate and as the Granite Ridge Board may request. The duties and responsibilities of these committees are set forth below.

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Audit Committee

The primary purposes of Granite Ridge’s Audit Committee are to assist the Granite Ridge Board’s oversight of:

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the accounting and financial reporting processes of Granite Ridge and audits of Granite Ridge’s financial statements;

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the integrity of Granite Ridge’s financial statements and Granite Ridge’s compliance with legal and regulatory requirements;

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the qualifications, independence, and performance of any independent registered public accounting firm engaged for the purpose of preparing or issuing an audit report or performing other audit, review, or attest services for Granite Ridge;

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reviewing, with Granite Ridge’s independent registered public accounting firm, the scope and results of their audit;

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overseeing the financial reporting process and discussing with management and Granite Ridge’s independent registered public accounting firm the quarterly and annual financial statements that Granite Ridge files with the SEC

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the design and implementation of Granite Ridge’s internal audit function; and

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the preparation of an annual Audit Committee report and the publishing of the report in Granite Ridge’s proxy statement for its annual meeting of stockholders, in accordance with applicable rules and regulations.

Granite Ridge’s Audit Committee consists of Amanda Coussens, Michele Everard, and John McCartney with Ms. Coussens serving as chair. Rule 10A-3 of the Exchange Act and the NYSE rules require that Granite Ridge’s Audit Committee be composed entirely of independent directors. The Granite Ridge Board has affirmatively determined that each of Amanda Coussens, Michele Everard, and John McCartney meet the definition of “independent director” for purposes of serving on the Audit Committee under Rule 10A-3 of the Exchange Act and the NYSE rules.

Each member of Granite Ridge’s Audit Committee also meets the financial literacy requirements of NYSE listing standards. In addition, the Granite Ridge Board has determined that Ms. Coussens qualifies as an “audit committee financial expert,” as such term is defined in Item 407(d)(5) of Regulation S-K. The Granite Ridge Board has adopted a written charter for the Audit Committee, which is available on Granite Ridge’s website at www.graniteridge.com. The information on our website is deemed not to be incorporated in this prospectus or to be part of this prospectus.

Compensation Committee

The primary purposes of Granite Ridge’s Compensation Committee are to:

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oversee Granite Ridge’s overall compensation philosophy that applies to all Granite Ridge employees;

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review, evaluate, and approve the agreements, plans, policies, and programs of Granite Ridge to compensate Granite Ridge’s executive officers and directors and, in certain instances, which may compensate individuals providing services to Granite Ridge pursuant to the MSA; and

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discharge the Granite Ridge Board’s responsibilities relating to compensation of Granite Ridge’s executive officers and directors.

Granite Ridge’s Compensation Committee is composed of Thaddeus Darden, Matthew Miller and John McCartney, with Mr. Darden serving as chair. The Granite Ridge Board has adopted a written charter for the Compensation Committee, which is available on Granite Ridge’s website at www.graniteridge.com. The information on our website is deemed not to be incorporated in this prospectus or to be part of this prospectus.

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ESG Committee

The ESG Committee’s responsibilities include, among other things:

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the oversight and monitoring of Granite Ridge’s environmental, sustainability and governance initiatives;

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reviewing and recommending to the Granite Ridge Board any changes to its corporate governance principles;

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assisting the Granite Ridge Board by identifying individuals qualified to become members of the Granite Ridge Board, and recommending director nominees to the Granite Ridge Board;

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advising the Granite Ridge Board about the appropriate composition of the Granite Ridge Board and its committees;

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leading the Granite Ridge Board in the annual performance evaluation of the Granite Ridge Board and its committees and of management;

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directing all matters relating to the succession of the Granite Ridge’s management; and

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any amendments to the charter of the ESG Committee.

Granite Ridge’s ESG Committee is composed of Amanda Coussens, Thaddeus Darden, and Griffin Perry, with Mr. Perry serving as chair. The Granite Ridge Board has adopted a written charter for the ESG Committee, which is available on Granite Ridge’s website at www.graniteridge.com. The information on our website is deemed not to be incorporated in this prospectus or to be part of this prospectus.

Conflicts Committee

The Conflicts Committee’s responsibilities include, among other things, reviewing and approving:

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new material arrangements and transactions between Granite Ridge and Grey Rock or its affiliates;

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amendments to, waivers of, or resolution of material disputes related to agreements between Grey Rock and its affiliates on the one hand and Granite Ridge and its affiliates on another, including any material amendment, waiver, or disputes relating to the MSA;

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related person transactions pursuant to Granite Ridge’s related party transactions policy; and

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any amendment to the charter of the Conflicts Committee.

Granite Ridge’s Conflicts Committee is composed of Amanda Coussens, Michele Everard, and John McCartney, with Ms. Everard serving as chair. The Conflicts Committee is composed entirely of independent directors who the Granite Ridge Board has determined meet the independence requirements of the NYSE. The Granite Ridge Board has adopted a written charter for the Conflicts Committee, which is available on Granite Ridge’s website at www.graniteridge.com. The information on our website is deemed not to be incorporated in this prospectus or to be part of this prospectus.

Code of Business Conduct and Ethics and Corporate Governance Guidelines

Granite Ridge has adopted a written code of business conduct and ethics that applies to its directors, officers, employees and individuals providing services to Granite Ridge pursuant to the MSA, in accordance with applicable federal securities laws, a copy of which is available on Granite Ridge’s website at www.graniteridge.com. Granite Ridge intends to disclose on its website any future amendments of the code of ethics or waivers that exempt any principal executive officer, principal financial officer, principal accounting officer or controller, persons performing similar functions or Granite Ridge’s directors from provisions in the code of business conduct and ethics. Additionally, Granite Ridge has adopted corporate governance guidelines, a copy of which is available on Granite Ridge’s corporate website, that address items such as the qualifications and responsibilities of its directors and director candidates and corporate governance policies and standards. The information on our website is deemed not to be incorporated in this prospectus or to be part of this prospectus.

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Compensation Committee Interlocks and Insider Participation

None of our officers currently serves, and in the past year has not served, (i) as a member of the compensation committee or the board of directors of another entity, one of whose officers served on our compensation committee, or (ii) as a member of the compensation committee of another entity, one of whose officers served on our board of directors.

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EXECUTIVE COMPENSATION

Effective July 1, 2022, Luke Brandenberg, the Company’s Chief Executive Officer and President, and Tyler Farquharson, the Company’s Chief Financial Officer, became employees of the Manager on an interim basis pending the closing of the Business Combination. Each of Mr. Brandenberg and Mr. Farquharson received an annual base salary of $250,000, prorated for the period of employment, and the opportunity to participate in the Manager’s standard health and dental benefit plans through the closing. Effective as of the closing of the Business Combination, Messrs. Brandenberg and Farquharson entered into employment agreements with the Company, described under “— Employment, Severance and Change of Control Agreements.”

After the completion of the Business Combination, no directors or members of ENPC’s management team remained with Granite Ridge and its consolidated subsidiaries after giving effect to the Business Combination (the “Combined Company”) or are paid consulting or management fees from the Combined Company. Additionally, no executive officer or director of ENPC received cash compensation for services rendered to ENPC prior to the Business Combination. Any compensation be paid to our executive officers will be determined, or recommended to the Granite Ridge Board for determination, by its Compensation Committee. Pursuant to the MSA, persons employed by the Manager will provide services to Granite Ridge. See the section entitled “Certain Relationships and Related Party Transactions — Management Services Agreement” for a description of the MSA. None of the persons employed by the Funds, GREP or the Manager as of December 31, 2022 are executive officers of Granite Ridge.

Effective as of the Business Combination, our named executive officers are:

Name			Principal Position
Luke C. Brandenberg			President and Chief Executive Officer
Tyler S. Farquharson			Chief Financial Officer

Elements of Compensation

The principal elements of compensation for the named executive officers will be base salaries, annual cash bonuses, and health, welfare and certain additional benefits.

Base Salary. Base salaries are generally set at levels commensurate with the named executive officer’s position and responsibilities, with any adjustments deemed necessary to attract and retain individuals with superior talent appropriate relative to their expertise and experience.

Annual Cash Bonuses. Annual cash incentive awards are expected to be used to motivate and reward our executives. Annual cash incentive awards will be determined on a discretionary basis and are generally based on individual and Company performance.

Employee Benefits. The named executive officers participate in all medical, dental, hospitalization, accidental death and dismemberment, disability, travel and life insurance plans, and all other plans as are offered by Granite Ridge to its executive personnel, including savings, pension, profit-sharing and deferred compensation plans.

Equity Incentive Awards. Named executive officers will participate in the Granite Ridge 2022 Omnibus Incentive Plan (the “Incentive Plan”), with awards to be determined in the Board’s discretion.

Employment, Severance and Change in Control Arrangements

Employment Agreements

On the Closing Date, Granite Ridge entered into an employment agreements with each of Messrs. Luke C. Brandenberg and Tyler S. Farquharson, pursuant to which Mr. Brandenberg will serve as the Company’s President and Chief Executive Officer and Mr. Farquharson will serve as the Company’s Chief Financial Officer, each for a three-year term, following which the agreements will be automatically extended for additional one-year terms, unless either of Granite Ridge on the one hand, or Mr. Brandenberg or Mr. Farquharson on the other hand, give at least 90 days’ prior notice of non-extension.

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Under the terms of the employment agreement, Mr. Brandenberg is entitled to the following:

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An annual base salary of $400,000, subject to increase (but not decrease) as determined by the Board;

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A target bonus equal to 50% of the executive’s current base salary, based on satisfaction of performance criteria to be established by the Board;

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An annual long term-incentive award pursuant to the Incentive Plan and applicable award agreement, and the terms and conditions thereof, determined by the Board, in its discretion;

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An expense reimbursement for all reasonable business and travel expenses paid or incurred by the executive while performing his duties, responsibilities, and authorities under the agreement and promoting the Company’s business and activities during the executive’s term; and

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Participation in all medical, dental, hospitalization, accidental death and dismemberment, disability, travel and life insurance plans, and all other plans as are offered by Granite Ridge to its executive personnel, including savings, pension, profit-sharing and deferred compensation plans, subject to the general eligibility and participation provisions set forth in such plan.

Under the terms of the employment agreement, Mr. Farquharson is entitled to the following:

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An annual base salary of $385,000, subject to increase (but not decrease) as determined by the Board;

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A target bonus equal to 30% of the executive’s current base salary, based on satisfaction of performance criteria to be established by the Board;

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An annual long term-incentive award pursuant to the Incentive Plan and applicable award agreement, and the terms and conditions thereof, determined by the Board, in its discretion;

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Both executives’ employment will terminate upon the earliest to occur of: (i) the executive’s death; (ii) a termination by Granite Ridge by reason of the executive’s disability; (iii) a termination by Granite Ridge with or without cause; or (iv) a termination by executive with or without good reason. Each of Mr. Brandenberg and Mr. Farquharson’s employment agreements provide for certain payments and benefits upon termination of their employment. The material terms of these arrangements are described below:

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Termination for cause or without good reason. In connection with a termination of employment by Granite Ridge for cause or by the executive without good reason, the executive will be entitled to payment of all accrued and unpaid base salary through the termination date, all approved but unreimbursed documented business expenses and other amounts payable under the agreement incurred through the termination date and payment and/or provision of all vested benefits to which the executive may be entitled through the termination date with respect to applicable benefit or incentive compensation plans, policies or programs.

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Termination in connection with death or disability. In addition to the payments described above, in connection with any termination by Granite Ridge in connection with the executive’s death or disability, the executive will be entitled to the executive’s pro rata target bonus.

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Termination without cause or for good reason. In addition to the payments described above in connection with termination for cause or without good reason, in connection with any termination by Granite Ridge without cause or by executive for good reason, the executive with also be entitled to payment of the following in a lump sum within 60 days following the termination date: (i) severance amount equal to two (2) times the sum of (a) the executive’s annual base salary as in effect for the fiscal

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year preceding the termination date and (b) the executive’s target bonus for the fiscal year preceding the period in which termination occurs, and (ii) during the 18-month period following the termination date, eligibility to elect for continued coverage for himself and his eligible dependents under the Company’s group health insurance plan.

In addition, if either of the executives’ employment is terminated by the Granite Ridge without cause or by the executive for good reason during the six-month period immediately following a change in control, then in lieu of the severance amount described above, the executive will be entitled to payment of the following in (i) within 60 days following the termination date: (i) a payment equal to three (3) times the sum of (a) the executive’s annual base salary as in effect for the fiscal year preceding the termination date and (b) the executive’s target bonus for the fiscal year preceding the period in which the termination date occurs, less applicable withholdings and deductions, and (ii) vesting, at the time of such termination, in any time-based long-term awards that previously were granted to the executive but which had not yet vested.

The payments described above are subject to the executive’s delivery to Granite Ridge of an executed release of claims. Upon termination of the executive’s employment, the executive will continue to be subject to the non-competition and non-solicitation covenants for 12 months, as well as their non-disparagement covenants.

If any of the payments or benefits received or to be received by the executive constitute “parachute payments” within the meaning of Section 280G of the Code and would be subject to excise tax, then such payments will be reduced in a manner determined by Granite Ridge (by the minimum amounts possible) that is consistent with Section 409A until no amount payable by the executive will be subject to excise tax.

For purposes of the employment agreement:

“Cause” means any act or omission of the executive that constitutes any: (i) material breach of the agreement, (ii) the executive’s failure or refusal to perform the executive’s duties, responsibilities, and authorities under the agreement, including, but not limited to, the failure or refusal to follow any lawful directive of the Board or the CEO and President, as applicable, (iii) material violation of any written employment policy or rule of the Company or its related entities, which results, or is likely to result in, any material reputational, financial, or other harm to the Company or its related entities, (iv) misappropriation of any funds, property, or business opportunity of the Company or its related entities, (v) illegal use or distribution of drugs or any abuse of alcohol in any manner that adversely affects the executive’s performance, (vi) fraud upon the Company or its related entities, or bad faith, dishonest, or disloyal acts or omissions toward the Company or its related entities, (vii) commission, indictment, or conviction of any felony or any misdemeanor involving moral turpitude, or (viii) other acts or omissions contrary to the best interests of the Company or its related entities which has caused, or is likely to cause, material harm to them. If the Board or Company, as applicable, determines in its sole discretion that a cure is possible and appropriate, the Company shall give such executive written notice of the acts or omissions constituting Cause and no termination of the agreement shall be for Cause unless and until such executive fails to cure such acts or omissions within 30 days following receipt of such written notice.

“Good Reason” shall exist in the event any of the following actions are taken without the executive’s consent: (i) a material diminution the executive’s annual base salary, duties, responsibilities, or authorities; (ii) a requirement that the executive report to an officer or employee other than the Board or the CEO and President, as applicable; (iii) a material relocation of the executive’s primary work location more than 50 miles away from the Company’s corporate headquarters; or (iv) any other action or inaction by the Company that constitutes a material breach of its obligations under the agreement. However, “Good Reason” will only exist if the executive gives Granite Ridge notice within 90 days after the first occurrence of any of the foregoing events, Granite Ridge fails to correct the matter within 30 days following receipt of such notice.

The foregoing description of Mr. Brandenberg and Mr. Farquharson’s employment agreements does not purport to be complete and is qualified in its entirety by the full text of the Executive Employment Agreements, which are attached to this registration statement of which this prospectus forms a part.

Except as described above, we have not entered into any employment, severance, change in control or similar agreements with any of our NEOs, nor are we otherwise currently responsible for any payment upon

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the termination of any of our NEOs. We do provide for accelerated vesting of option awards upon our change in control, which is described in more detail below under “— Granite Ridge 2022 Omnibus Incentive Plan.”

Granite Ridge 2022 Omnibus Incentive Plan

At the special meeting of ENPC stockholders held in connection with the Business Combination, ENPC stockholders approved the Granite Ridge 2022 Omnibus Incentive Plan (the “Incentive Plan”), which applies to Granite Ridge following the closing of the Business Combination. In connection with the closing, the Granite Ridge Board adopted the Incentive Plan, which became effective immediately. The purpose of the Incentive Plan is to promote and closely align the interests of Granite Ridge’s employees, officers, directors, consultants or advisors and the Company’s stockholders by providing stock-based compensation and other performance-based compensation. The objectives of the Incentive Plan are to attract and retain individuals of exceptional skill upon whom, in large measure, Granite Ridge’s sustained progress, growth and profitability depend and to provide an increased incentive for these individuals to contribute to the future success and prosperity of Granite Ridge, thus enhancing the value of the Company’s common stock for the benefit of its stockholders. The Incentive Plan allows for the grant of stock options, both incentive stock options and “non-qualified” stock options; stock appreciation rights (SARs), alone or in conjunction with other awards; restricted stock and restricted stock units (RSUs); and other stock-based awards. We refer to these collectively herein as Awards.

The following description of the Incentive Plan is not intended to be complete and is qualified in its entirety by the complete text of the Incentive Plan, a copy of which is attached hereto as an exhibit to the registration statement of which this prospectus forms a part. Stockholders are urged to read the Incentive Plan in its entirety. Any capitalized terms which are used in this summary description but not defined here or elsewhere in this prospectus have the meanings assigned to them in the Incentive Plan.

Administration

The Incentive Plan will be administered by the Compensation Committee, or such other person or persons designated by the Compensation Committee to administer the plan, which we refer to herein as the “Plan Administrator”. The Granite Ridge Board may also grant awards and administer the Incentive Plan with respect to such awards. The Plan Administrator will have broad authority, subject to the provisions of the Incentive Plan, to administer and interpret the Incentive Plan and Awards granted thereunder. All decisions and actions of the Plan Administrator will be final. To the extent required to comply with the provisions of Rule 16b-3 promulgated under the Exchange Act, any Award granted to any participant who, at the time of the Award, is the owner, directly or indirectly, of stock possessing more than ten percent (10%) of the total combined voting power of all classes of stock of the Company or any Subsidiary will be determined by the Granite Ridge Board.

Eligibility; Interests of Directors or Officers

The Company’s directors may grant Awards under the Incentive Plan to themselves as well as to officers and other employees of the Company and its subsidiaries, as well as to other service providers, including employees of the Manager.

Stock Subject to the Incentive Plan

The maximum number of shares of common stock that may be issued under the Incentive Plan will not exceed 6,500,000 shares, subject to certain adjustments in the event of a change in the Company’s capitalization. Shares of common stock issued under the Incentive Plan may be either authorized and unissued shares or previously issued shares acquired by us. On termination or expiration of an Award under the Incentive Plan, in whole or in part, the number of shares of common stock subject to such Award but not issued thereunder or that are otherwise forfeited back to the Company will again become available for grant under the Incentive Plan. Shares of common stock (i) accepted by the Company in payment of the exercise price of an option, (ii) withheld from a participant or delivered to the Company in satisfaction of required withholding taxes and (iii) representing the difference between the total number of shares with

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respect to which a SAR is awarded and the number of shares actually delivered upon exercise of such SAR, in each case, shall not be available for reissuance under the Plan.

Limits on Non-Employee Director Compensation

Under the Incentive Plan, the aggregate dollar value of all cash fees and Awards to the Company’s non-employee directors for services in such capacity shall not exceed $750,000 during any fiscal year.

Types of Awards

Stock Options. All stock options granted under the Incentive Plan will be evidenced by a written agreement with the participant, which provides, among other things, whether the option is intended to be an incentive stock option (meaning they are intended to satisfy the requirements of Code section 422 for incentive stock options) or a non-qualified stock option (meaning they are not intended to satisfy the requirements of section 422 of the Code), the number of shares subject to the option, the exercise price, exercisability (or vesting), the term of the option, which may not generally exceed ten years, and other terms and conditions. Subject to the express provisions of the Incentive Plan, options generally may be exercised over such period, in installments or otherwise, as the Plan Administrator may determine. The exercise price for any stock option granted may not generally be less than the fair market value of the common stock subject to that option on the grant date. The exercise price may be paid in cash, the delivery of previously owned shares, any cashless exercise mechanism or any combination of the foregoing methods. Other than in connection with a change in the Company’s capitalization, we will not, without stockholder approval, reduce the exercise price of a previously awarded option, and at any time when the exercise price of a previously awarded option is above the fair market value of a share of common stock, we will not, without stockholder approval, cancel and re-grant or exchange such option for cash or a new Award with a lower (or no) exercise price.

Stock Appreciation Rights or SARs. SARs may be granted alone or in conjunction with all or part of a stock option. SARs will be subject to terms and conditions established by the Plan Administrator and consistent with the Incentive Plan. Upon exercising a SAR, the participant is entitled to receive the amount by which the fair market value of the common stock at the time of exercise exceeds the exercise price of the SAR. This amount is payable in fully vested shares of common stock or cash.

Restricted Stock and RSUs. Awards of restricted stock consist of shares of stock that are transferred to the participant subject to restrictions that may result in forfeiture if specified conditions are not satisfied. RSUs result in the transfer of shares of common stock or cash or other consideration to the participant only after specified conditions are satisfied. The Plan Administrator will determine the restrictions and conditions applicable to each Award of restricted stock or RSUs, which may include performance vesting conditions. The Plan Administrator may specify certain performance criteria which must be satisfied before an Award of restricted stock or RSUs will vest. The performance goals may vary from participant to participant, group to group, and period to period.

Dividend Equivalents. Awards may be granted that provide a right to the participant to receive the equivalent value of dividends paid on shares of Granite Ridge common stock, as determined by the Plan Administrator and consistent with the Incentive Plan. Dividend equivalents may be paid or credited to an account for the participant, settled in cash or shares of Granite Ridge common stock and subject to the same restrictions on transferability and forfeitability as the RSUs with respect to which the dividend equivalents are granted and subject to other terms and conditions as set forth in the award agreement.

Other Stock or Stock-Based Awards. Other stock or stock-based awards are Awards of common stock, including fully-vested common stock, and other Awards that are valued in whole or in part by reference to the fair market value of the Granite Ridge common stock.

Transferability

Awards generally may not be sold, transferred for value, pledged, assigned or otherwise alienated or hypothecated by a participant other than by will or the laws of descent and distribution, and each Award

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may be exercisable only by the participant during his or her lifetime or, if permissible under applicable law, by the participant’s legal guardian or representative.

Amendment and Termination

The Granite Ridge Board has the right to amend, revise, discontinue or terminate the Incentive Plan at any time, provided certain enumerated material amendments may not be made without stockholder approval. No amendment or alteration to the Incentive Plan or an Award or Award agreement will be made that would adversely affect the rights of the participant under any Award, without such participant’s consent. The Incentive Plan will automatically terminate as to the grant of future Awards ten years after such adoption by the Granite Ridge Board, unless earlier terminated by the Granite Ridge Board.

Change of Control

Upon a Change of Control where the Company is not the surviving corporation (or survives only as a subsidiary of another corporation), unless the Plan Administrator determines otherwise, all outstanding Awards shall be assumed by, or replaced with comparable Awards by, the surviving corporation (or a the Company or subsidiary of the surviving corporation). In the event the outstanding Awards are not assumed or replaced as provided in the preceding sentence, any outstanding Awards issued under the Incentive Plan (other than restricted stock and RSUs that are subject to achievement of performance-based goals) will become fully vested. Restricted stock and RSUs that are subject to performance-based goals will vest, as determined by the Plan Administrator, based on the level of attainment of the specified performance goals, unless otherwise provided in the applicable Award Agreement. Notwithstanding the foregoing, in the event of a Change in Control the Plan Administrator may, in its discretion, cancel outstanding Awards and pay to participants the cash value of such Awards based upon the highest price per share of common stock received or to be received by other stockholders of the Company in connection with the Change of Control.

Clawback

All awards granted under the Incentive Plan will be subject to reduction, cancelation, forfeiture, or recoupment to the extent necessary to comply with (a) any clawback, forfeiture or other similar policy that the Company’s board of directors or the Plan Administrator may adopt from time to time and (b) to the extent necessary to comply with applicable law.

New Plan Benefits

Future grants under the Incentive Plan will be made at the discretion of the Plan Administrator or the Company board of directors and, accordingly, are not yet determinable. In addition, the value of the Awards granted under the Incentive Plan will depend on a number of factors, including the fair market value of the Company common stock on future dates, the exercise decisions made by the participants and/or the extent to which any applicable performance goals necessary for vesting or payment are achieved. Consequently, it is not possible to determine the benefits that might be received by participants receiving discretionary grants under the Incentive Plan.

Summary Compensation Table

The table below presents information regarding the compensation earned or received by the named executive officers during the year ended December 31, 2022 (the only year for which any named executive officers earned or received compensation from the Company):

Name and Principal Position	Year		Salary ($)		Stock Awards ($)		All other compensation ($)		Total ($)
Luke C. Brandenberg, President and Chief Executive Officer		2022		71,371(1)		—		—		71,371
Tyler S. Farquharson, Chief Financial Officer		2022		68,871(2)		—		—		68,871

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(1)

Mr. Brandenberg also earned $78,629 in salary from the Manager from July 1, 2022 through the closing of the Business Combination.

(2)

Mr. Farquharson also earned $78,629 in salary from the Manager from July 1, 2022 through the date of the Business Combination.

No named executive officer received equity based compensation during the year ended December 31, 2022. In January 2023, Mr. Brandenberg was awarded a stock award under the Incentive Plan in the amount of $200,000 and Mr. Farquharson was awarded a stock award under the Incentive Plan in the amount of $150,000.

Director Compensation

The table below presents information regarding the compensation earned or received by our directors during the year ended December 31, 2022:

Name	Fees Earned or Paid in Cash(1)			Stock Awards		Total
Amanda N. Coussens(2)		$	16,386		—		$	16,386
Thaddeus Darden		$	13,654		—		$	13,654
Michele J. Everard		$	13,654		—		$	13,654
Kirk Lazarine		$	13,654		—		$	13,654
John McCartney		$	13,654		—		$	13,654
Matthew Miller		$	13,654		—		$	13,654
Griffin Perry		$	13,654		—		$	13,654

(1)

Represents cash retainer for the fourth quarter of 2022, paid in arrears, and prorated from the date of the closing of the Business Combination through December 31, 2022.

(2)

Includes cash retainer for service as the Audit Committee Chair for the fourth quarter of 2022, paid in arrears and prorated from the date of the closing of the Business Combination through December 31, 2022.

In January 2023, the Compensation Committee recommended and the Board approved the following compensation for the Board: an annual Board retainer of $75,000 per director, payable quarterly in arrears in cash (or at the election of the director, in stock); an annual equity grant of $75,000 per director; an additional annual retainer for the Audit Committee Chair of $15,000, payable quarterly in arrears in cash (or at the election of the Audit Committee Chair, in stock); and for each of the independent directors, a one-time initial equity grant of $100,000.

Each director will be reimbursed for travel and miscellaneous expenses to attend meetings and activities of the Granite Ridge Board or its committees. Each director will also be fully indemnified by us for actions associated with serving as a director to the fullest extent permitted under Delaware law.

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DESCRIPTION OF SECURITIES

The following summary of the material terms of Granite Ridge’s securities is not intended to be a complete summary of the rights and preferences of such securities. Granite Ridge’s securities are governed by Granite Ridge’s amended and restated certificate of incorporation, Granite Ridge’s amended and restated bylaws and the DGCL. We urge you to read (1) the Granite Ridge’s amended and restated certificate of incorporation in its entirety for a complete description of the rights and preferences of Granite Ridge’s securities and (2) Granite Ridge’s amended and restated bylaws.

Authorized and Outstanding Capital Stock

The amended and restated certificate of incorporation of Granite Ridge authorizes the issuance of 431,000,000 shares of Granite Ridge common stock and 1,000,000 shares of preferred stock, par value $0.0001 per share. The outstanding shares of Granite Ridge common stock are duly authorized, validly issued, fully paid and non-assessable. Common stockholders of record are entitled to one vote for each share held on all matters to be voted on by stockholders. As of January 5, 2023, there were 133,270,477 shares of Granite Ridge common stock and no shares of preferred stock issued and outstanding.

Common Stock

Voting Power

Unless otherwise required by law or as otherwise provided in any certificate of designation for any series of preferred stock, common stockholders of record are entitled to one vote for each share held on all matters to be voted on by stockholders. Granite Ridge’s board of directors is divided into three classes, each of which is generally served for a term of three years with only one class of directors being elected in each year and with directors only permitted to be removed for cause. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors up for election at such time.

Dividends

Holders of Granite Ridge common stock will be entitled to receive such dividends and other distributions, if any, as may be declared from time to time by Granite Ridge’s board of directors in its discretion out of funds legally available therefor and shall share equally on a per share basis in such dividends and distributions. The payment of cash dividends in the future will be dependent upon Granite Ridge’s revenues and earnings, if any, capital requirements and general financial condition subsequent to completion of the Business Combination. The payment of any cash dividends subsequent to the Business Combination will be within the discretion of Granite Ridge’s board of directors at such time. If Granite Ridge incurs any indebtedness, Granite Ridge’s ability to declare dividends may be limited by restrictive covenants Granite Ridge may agree to in connection therewith.

Liquidation, Dissolution and Winding Up

In the event of the voluntary or involuntary liquidation, dissolution, distribution of assets or winding-up of Granite Ridge, the holders of Granite Ridge common stock will be entitled to receive an equal amount per share of all of Granite Ridge’s assets of whatever kind available for distribution to stockholders, after the rights of the holders of Granite Ridge’s creditors and holders of preferred stock, if any, have been satisfied.

Preferred Stock

The amended and restated certificate of incorporation of Granite Ridge provides that shares of preferred stock may be issued from time to time in one or more series. Granite Ridge’s board of directors is authorized to fix the voting rights, if any, designations, powers, preferences, the relative, participating, optional or other special rights and any qualifications, limitations and restrictions thereof, applicable to such additional shares of each series. Granite Ridge’s board of directors may, without stockholder approval, issue preferred stock with voting and other rights that could adversely affect the voting power and other rights of the holders of the common stock and could have anti-takeover effects. The ability of Granite Ridge’s

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board of directors to issue preferred stock without stockholder approval could have the effect of delaying, deferring or preventing a change of control of Granite Ridge or the removal of existing management. Granite Ridge currently has no preferred stock outstanding as of the date of this prospectus. Although Granite Ridge does not currently intend to issue any shares of preferred stock, it cannot assure you that it will not do so in the future.

Warrants

As of November 10, 2022, Granite Ridge has outstanding 10,349,975 warrants to purchase Granite Ridge common stock. The warrants were issued at the closing of the Business Combination to the holders of ENPC’s then outstanding warrants.

In connection with the Business Combination, ENPC assigned all its rights, title and interest in the Existing Warrant Agreement to Granite Ridge, and the shares for which ENPC warrants were exercisable automatically converted to shares of Granite Ridge common stock (the ENPC Warrant Agreement as assigned to Granite Ridge following the Business Combination is referred to herein as the “Granite Ridge Warrant Agreement”). Pursuant to the Granite Ridge Warrant Agreement, each whole warrant entitles the registered holder to purchase one share of Granite Ridge common stock at a price of $11.50 per share, subject to adjustment as discussed below, at any time commencing November 23, 2022. Pursuant to the Granite Ridge Warrant Agreement, a warrant holder may exercise its warrants only for a whole number of shares of Granite Ridge common stock. The warrants will expire five years after the consummation of the Business Combination, at 5:00 p.m., New York City time, or earlier upon redemption or liquidation.

Granite Ridge will have no obligation to settle such warrant exercise unless a registration statement under the Securities Act with respect to the shares of Granite Ridge common stock underlying the warrants is then effective and a prospectus relating thereto is current, subject to Granite Ridge satisfying its obligations described below with respect to registration. No warrant will be exercisable and Granite Ridge will not be obligated to issue a share of Granite Ridge common stock upon exercise of a warrant unless the share of Granite Ridge common stock issuable upon such warrant exercise has been registered, qualified, or deemed to be exempt under the securities laws of the state of residence of the registered holder of the warrants. In the event that the conditions in the two immediately preceding sentences are not satisfied with respect to a warrant, the holder of such warrant will not be entitled to exercise such warrant and such warrant may have no value and expire worthless. In no event will Granite Ridge be required to net cash settle any warrant.

We have filed with the SEC a registration statement for the registration, under the Securities Act, of the Granite Ridge warrants and the Granite Ridge common stock issuable upon exercise of the Granite Ridge warrants, and we will use our commercially reasonable efforts to maintain the effectiveness of such registration statements and a current prospectus relating to those Granite Ridge common stock until the warrants expire or are redeemed, as specified in the Granite Ridge Warrant Agreement.

From and after the sixty-first (61st) business day after the consummation of the Business Combination, warrant holders may, during any period when we will have failed to maintain an effective registration statement and until a registration statement has been declared effective by the SEC, exercise warrants on a “cashless basis” in accordance with Section 3(a)(9) of the Securities Act or another exemption. Notwithstanding the above, if shares of Granite Ridge common stock are at the time of any exercise of a warrant not listed on a national securities exchange such that they satisfy the definition of a “covered security” under Section 18(b)(1) of the Securities Act, Granite Ridge may, at its option, require holders of public warrants who exercise their warrants to do so on a “cashless basis” in accordance with Section 3(a)(9) of the Securities Act and, in the event Granite Ridge so elects, Granite Ridge will not be required to file or

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maintain in effect a registration statement, and in the event Granite Ridge does not so elect, Granite Ridge will use its best efforts to register or qualify the shares under applicable blue sky laws to the extent an exemption is not available.

Redemption of Warrants for Cash

Once the warrants become exercisable, Granite Ridge may call the warrants for redemption for cash:

•

in whole and not in part;

•

at a price of $0.01 per warrant;

•

upon not less than 30 days’ prior written notice of redemption (the “30-day redemption period”) to each warrant holder; and

•

if, and only if, the closing price of Granite Ridge common stock equals or exceeds $18.00 per share (as adjusted for stock splits, stock capitalizations, reorganizations, recapitalizations and the like) for any 20 trading days within a 30-trading day period ending three business days before Granite Ridge sends the notice of redemption to the warrant holders.

Granite Ridge has established the last of the redemption criterion discussed above to prevent a redemption call unless there is at the time of the call a significant premium to the warrant exercise price. If the foregoing conditions are satisfied and Granite Ridge issues a notice of redemption of the warrants, each warrant holder will be entitled to exercise his, her or its warrant prior to the scheduled redemption date. However, the price of the shares of Granite Ridge common stock may fall below the $18.00 redemption trigger price (as adjusted for stock splits, stock capitalizations, reorganizations, recapitalizations and the like) as well as the $11.50 warrant exercise price after the redemption notice is issued.

Redemption Procedures and Cashless Exercise

If Granite Ridge calls the warrants for redemption as described above, management will have the option to require any holder that wishes to exercise his, her or its warrant to do so on a “cashless basis.” In determining whether to require all holders to exercise their warrants on a “cashless basis,” management will consider, among other factors, Granite Ridge’s cash position, the number of warrants that are outstanding, and the dilutive effect on Granite Ridge’s stockholders of issuing the maximum number of shares of Granite Ridge common stock issuable upon the exercise of Granite Ridge’s warrants. If management takes advantage of this option, all holders of warrants would pay the exercise price by surrendering their warrants for that number of shares of Granite Ridge common stock equal to the quotient obtained by dividing (x) the product of the number of shares of Granite Ridge common stock underlying the warrants, multiplied by the excess of the “fair market value” of shares of Granite Ridge common stock (defined below) over the exercise price of the warrants by (y) the fair market value. The “fair market value” will mean the average closing price of the shares of Granite Ridge common stock for the 10 trading days ending on the third trading day prior to the date on which the notice of redemption is sent to the holders of warrants. If management takes advantage of this option, the notice of redemption will contain the information necessary to calculate the number of shares of Granite Ridge common stock to be received upon exercise of the warrants, including the “fair market value” in such case. Requiring a cashless exercise in this manner will reduce the number of shares to be issued and thereby lessen the dilutive effect of a warrant redemption. This feature is an attractive option to Granite Ridge if Granite Ridge does not need the cash from the exercise of the warrants after the Business Combination.

A holder of a warrant may notify Granite Ridge in writing in the event it elects to be subject to a requirement that such holder will not have the right to exercise such warrant, to the extent that after giving effect to such exercise, such person (together with such person’s affiliates), to the warrant agent’s actual knowledge, would beneficially own in excess of 4.9% or 9.8% (as specified by the holder) of the shares of Granite Ridge common stock outstanding immediately after giving effect to such exercise.

Adjustment to Exercise Price

If the number of outstanding shares of Granite Ridge common stock is increased by a share capitalization payable in shares of Granite Ridge common stock, or by a split-up of common stock or other

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similar event, then, on the effective date of such share capitalization, split-up or similar event, the number of shares of Granite Ridge common stock issuable on exercise of each warrant will be increased in proportion to such increase in the outstanding shares of common stock. A rights offering to all or substantially all holders of Granite Ridge common stock entitling holders to purchase shares of Granite Ridge common stock at a price less than the fair market value will be deemed a share capitalization of a number of shares of Granite Ridge common stock equal to the product of (i) the number of shares of Granite Ridge common stock actually sold in such rights offering (or issuable under any other equity securities sold in such rights offering that are convertible into or exercisable for shares of Granite Ridge common stock) and (ii) the quotient of (x) the price per share of Granite Ridge common stock paid in such rights offering and (y) the fair market value. For these purposes (i) if the rights offering is for securities convertible into or exercisable for shares of Granite Ridge common stock, in determining the price payable for shares of Granite Ridge common stock, there will be taken into account any consideration received for such rights, as well as any additional amount payable upon exercise or conversion and (ii) fair market value means the volume weighted average price of shares of Granite Ridge common stock as reported during the ten (10) trading day period ending on the trading day prior to the first date on which the shares of Granite Ridge common stock trades on the applicable exchange or in the applicable market, regular way, without the right to receive such rights.

If the number of outstanding shares of Granite Ridge common stock is decreased by a consolidation, combination, reverse share split or reclassification of shares of Granite Ridge common stock or other similar event, then, on the effective date of such consolidation, combination, reverse share split, reclassification or similar event, the number of shares of Granite Ridge common stock issuable on exercise of each warrant will be decreased in proportion to such decrease in outstanding share of Granite Ridge common stock.

Whenever the number of shares of Granite Ridge common stock purchasable upon the exercise of the warrants is adjusted, as described above, the warrant exercise price will be adjusted by multiplying the warrant exercise price immediately prior to such adjustment by a fraction (x) the numerator of which will be the number of shares of Granite Ridge common stock purchasable upon the exercise of the warrants immediately prior to such adjustment, and (y) the denominator of which will be the number of shares of Granite Ridge common stock so purchasable immediately thereafter.

In case of any reclassification or reorganization of the outstanding shares of Granite Ridge common stock (other than those described above or that solely affects the par value of such shares of Granite Ridge common stock), or in the case of any merger or consolidation of Granite Ridge with or into another corporation (other than a consolidation or merger in which Granite Ridge is the continuing corporation and that does not result in any reclassification or reorganization of outstanding shares of Granite Ridge common stock), or in the case of any sale or conveyance to another corporation or entity of the assets or other property of us as an entirety or substantially as an entirety in connection with which we are dissolved, the holders of the warrants will thereafter have the right to purchase and receive, upon the basis and upon the terms and conditions specified in the warrants and in lieu of the shares of Granite Ridge common stock immediately theretofore purchasable and receivable upon the exercise of the rights represented thereby, the kind and amount of shares of Granite Ridge common stock or other securities or property (including cash) receivable upon such reclassification, reorganization, merger or consolidation, or upon a dissolution following any such sale or transfer, that the holder of the warrants would have received if such holder had exercised their warrants immediately prior to such event. If less than 70% of the consideration receivable by the holders of shares of Granite Ridge common stock in such a transaction is payable in the form of shares of Granite Ridge common stock in the successor entity that is listed for trading on a national securities exchange or is quoted in an established over-the-counter market, or is to be so listed for trading or quoted immediately following such event, and if the registered holder of the warrant properly exercises the warrant within thirty days following public disclosure of such transaction, the warrant exercise price will be reduced as specified in the warrant agreement based on the Black-Scholes Warrant Value (as defined in the warrant agreement) of the warrant. The purpose of such exercise price reduction is to provide additional value to holders of the warrants when an extraordinary transaction occurs during the exercise period of the warrants pursuant to which the holders of the warrants otherwise do not receive the full potential value of the warrants.

The foregoing description of potential adjustments is not complete. For a full description of any potential adjustments to the Granite Ridge warrants, warrantholders should refer to the Granite Ridge Warrant Agreement.

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Other provisions

The warrants were issued in registered form under the Granite Ridge Warrant Agreement. The Granite Ridge Warrant Agreement provides that the terms of the warrants may be amended without the consent of any holder for the purpose of (i) curing any ambiguity or to correct any defective provision or mistake, including to conform the provisions of the warrant agreement to the description of the terms of the warrants and the warrant agreement, (ii) adjusting the provisions relating to cash dividends on shares of common stock as contemplated by and in accordance with the Granite Ridge Warrant Agreement or (iii) adding or changing any provisions with respect to matters or questions arising under the Granite Ridge Warrant Agreement as the parties to the Granite Ridge Warrant Agreement may deem necessary or desirable and that the parties deem to not adversely affect the rights of the registered holders of the warrants, provided that the approval by the holders of at least 50% of the then outstanding public warrants that vote to amend the Granite Ridge Warrant Agreement, after at least 10 days’ notice that an amendment is being sought, is required to make any change that adversely affects the interests of the registered holders of public warrants.

The warrants may be exercised upon surrender of the warrant certificate on or prior to the expiration date at the offices of the warrant agent, with the exercise form on the reverse side of the warrant certificate completed and executed as indicated, accompanied by full payment of the exercise price (or on a cashless basis, if applicable), by certified or official bank check payable to Granite Ridge, for the number of warrants being exercised. The warrant holders do not have the rights or privileges of holders of Granite Ridge common stock and any voting rights until they exercise their warrants and receive shares of Granite Ridge common stock. After the issuance of shares of Granite Ridge common stock upon exercise of the warrants, each holder will be entitled to one vote for each share held of record on all matters to be voted on by stockholders.

No fractional shares will be issued upon exercise of the warrants. If, upon exercise of the warrants, a holder would be entitled to receive a fractional interest in a share, Granite Ridge will, upon exercise, round down to the nearest whole number the number of shares of Granite Ridge common stock to be issued to the warrant holder.

Voting limitation

The Granite Ridge Warrant Agreement provides that no holder may vote more than 15% of the outstanding public warrants (measured on a beneficial basis and including such holder’s affiliates) unless consented to by Granite Ridge in writing to the warrant agent. In order to vote a public warrant, the beneficial owner thereof must identify itself and must represent that it together with its affiliates is not voting (on a beneficial basis) more than 15% of the outstanding public warrants based on the most recent disclosure by Granite Ridge in a filing with the SEC of the outstanding amounts of public warrants unless Granite Ridge allows a holder to vote greater than 15%.

Certain Anti-Takeover Provisions of Delaware Law and the Amended and Restated Certificate of Incorporation of the Granite Ridge

The amended and restated certificate of incorporation of Granite Ridge provides that Granite Ridge is not subject to Section 203 of the DGCL. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a three-year period following the time that such stockholder becomes an interested stockholder, unless the business combination is approved in a prescribed manner. A “business combination” includes, among other things, a merger or consolidation, asset or stock sale, or other transaction resulting in a financial benefit to the interested stockholder. Subject to certain exceptions, an “interested stockholder” is a person who, together with affiliates and associates, owns, or did own within three years prior to the determination of interested stockholder status, 15% or more of the corporation’s outstanding voting stock.

Under Section 203, a business combination between a corporation and an interested stockholder is prohibited unless it satisfies one of the following conditions:

•

the transaction is approved by the board of directors before the date the interested stockholder attained that status;

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•

upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the voting stock outstanding, shares owned by persons who are directors and also officers, and employee stock plans, in some instances; and

•

on or after such time, the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Classified Board

Written Consent by Stockholders

The amended and restated certificate of incorporation of Granite Ridge provides that for so long as the Grey Rock Entities (as defined in the amended and restated certificate of incorporation of Granite Ridge) collectively hold at least a majority of the voting power of all then outstanding shares of capital stock of Granite Ridge, any action required or permitted to be taken at any annual or special meeting of the stockholders may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, is signed by the holders of such outstanding shares of capital stock of Granite Ridge having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted.

Advance Notice Requirements for Stockholder Proposals and Director Nominations

Granite Ridge’s amended and restated bylaws provide that stockholders seeking to bring business before Granite Ridge’s annual meeting of stockholders, or to nominate candidates for election as directors at Granite Ridge’s annual meeting of stockholders, must provide timely notice of their intent in writing. To be timely, a stockholder’s notice will need to be received by the company secretary at Granite Ridge’s principal executive offices not earlier than the opening of business on the 120th day before the meeting and not later than the later of (x) the close of business on the 90th day before the meeting or (y) the close of business on the 10th day following the day on which public announcement of the date of the annual meeting is first made by Granite Ridge. Pursuant to Rule 14a-8 of the Exchange Act, proposals seeking inclusion in Granite Ridge’s annual proxy statement must comply with the notice periods contained therein. Granite Ridge’s amended and restated bylaws also specify certain requirements as to the form and content of a stockholders’ meeting. These provisions may preclude Granite Ridge’s stockholders from bringing matters before Granite Ridge’s annual meeting of stockholders or from making nominations for directors at Granite Ridge’s annual meeting of stockholders.

Exclusive Forum

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jurisdiction) and subject matter jurisdiction over the claim. The foregoing forum selection provision shall not apply to claims arising under the Exchange Act, the Securities Act, or any other claim for which the federal courts have exclusive jurisdiction. Further, unless Granite Ridge consents in writing to the selection of an alternative forum, the federal district courts shall be the exclusive forum for any complaint arising under the Securities Act; however, there is uncertainty as to whether a court would enforce such provision. Any person or entity purchasing or otherwise acquiring an interest in Granite Ridge common stock will be deemed to have received notice of and consented to the foregoing forum selection provisions, which could limit Granite Ridge stockholders’ ability to choose the judicial forum for disputes with Granite Ridge.

Transfer Agent and Warrant Agent

The transfer agent for the Granite Ridge common stock and warrant agent for the Granite Ridge warrants is Continental Stock Transfer & Trust Company. Granite Ridge has agreed to indemnify Continental Stock Transfer & Trust Company in its roles as transfer agent and warrant agent, its agents and each of its stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in those capacities, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Exchange Listing

Granite Ridge common stock and Granite Ridge warrants are listed on the NYSE under the symbols “GRNT” and “GRNT WS,” respectively.

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SECURITIES ACT RESTRICTIONS ON RESALE OF COMMON STOCK

Rule 144

Pursuant to Rule 144, a person who has beneficially owned restricted shares of Granite Ridge’s voting common stock or warrants for at least six (6) months would be entitled to sell their securities provided that (i) such person is not deemed to have been one of Granite Ridge’s affiliates at the time of, or at any time during the three (3) months preceding, a sale and (ii) Granite Ridge is subject to the Exchange Act periodic reporting requirements for at least three (3) months before the sale and have filed all required reports under Section 13 or 15(d) of the Exchange Act during the twelve (12) months (or such shorter period as Granite Ridge were required to file reports) preceding the sale.

Persons who have beneficially owned restricted shares of Granite Ridge’s voting common stock or warrants for at least six (6) months but who are Granite Ridge’s affiliates at the time of, or at any time during the three (3) months preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three-month period only a number of securities that does not exceed the greater of:

•

1% of the total number of shares of such securities then-outstanding; or

•

the average weekly reported trading volume of such securities during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

Sales by Granite Ridge’s affiliates under Rule 144 are also limited by manner of sale provisions and notice requirements and to the availability of current public information about us.

Restrictions on the Use of Rule 144 by Shell Companies or Former Shell Companies

Rule 144 is not available for the resale of securities initially issued by shell companies (other than business combination related shell companies) or issuers that have been at any time previously a shell company. However, Rule 144 also includes an important exception to this prohibition if the following conditions are met:

•

the issuer of the securities that was formerly a shell company has ceased to be a shell company;

•

the issuer of the securities is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act;

•

the issuer of the securities has filed all Exchange Act reports and materials required to be filed, as applicable, during the preceding twelve (12) months (or such shorter period that the issuer was required to file such reports and materials), other than Current Reports on Form 8-K; and

•

at least one (1) year has elapsed from the time that the issuer filed current Form 10 type information with the SEC reflecting its status as an entity that is not a shell company.

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SELLING SECURITYHOLDERS

This prospectus relates to the resale by the Selling Securityholders from time to time of up to 128,233,953 shares of Granite Ridge common stock. The shares of Granite Ridge common stock being offered by the Selling Securityholders are those previously issued to the Selling Securityholders in connection with the Business Combination. We are registering the shares of Granite Ridge common stock in order to permit the Selling Securityholders to offer the shares for resale from time to time. Except for their ownership of the shares of Granite Ridge common stock and participation in the Business Combination as described herein, the Selling Securityholders have not had any material relationship with us within the past three years.

When we refer to the “Selling Securityholders” in this prospectus, we mean the persons listed in the table below, and the pledgees, donees, transferees, assignees, successors, designees and others who later come to hold any of the Selling Securityholders’ interest in the Granite Ridge common stock other than through a public sale.

The table below lists the Selling Securityholders and other information regarding the beneficial ownership of the shares of Granite Ridge common stock by each of the Selling Securityholders. The second column lists the number of shares of Granite Ridge common stock beneficially owned by each selling securityholder, based on its ownership of the shares of Granite Ridge common stock, as of November 10, 2022.

The third column lists the shares of Granite Ridge common stock being offered by this prospectus by the Selling Securityholders.

The fourth column assumes the sale of all of the shares offered by the Selling Securityholders pursuant to this prospectus but no other shares owned by the Selling Securityholders prior to this offering.

The Selling Securityholders may sell all, some or none of their shares in this offering. See “Plan of Distribution.”

Unless otherwise indicated, the address of each selling securityholder named in the table below is 5217 McKinney Avenue, Suite 400, Dallas, TX 75205.

Name of selling securityholder	Number of shares of Common Stock Owned Prior to Offering		Maximum Number of shares of Common Stock to be Sold Pursuant to this Prospectus		Number of shares of Common Stock Owned After Offering
ENPC Holdings II, LLC(1)		1,174,106(2)		1,174,106		0
GREP Holdco II LLC(3)(4)		9,507,742		9,507,742		0
GREP Holdco II-B Holdings LLC(3)(4)		14,050,471		14,050,471		0
GREP Holdco III-A LLC(4)(5)		28,847,450		28,847,450		0
GREP Holdco III-B Holdings LLC(4)(5)		66,233,134		66,233,134		0
Griffin Perry		5,725		5,725		0
Matthew Miller		17,175		17,175		0
Thaddeus and Lee Ellen Darden(6)		29,884		29,884		0
Kirk Lazarine		5,725		5,725		0
Richard Boyce		21,429		21,429		0
Michael M. Calbert		21,429		21,429		0
Gisel Ruiz		21,429		21,429		0
Boylston Real Assets Fund, LP		257,616		257,616		0
Bryan Harlan		26,770		14,312		12,458
Charles G. King, Jr.		3,586		1,717		1,869

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Name of selling securityholder	Number of shares of Common Stock Owned Prior to Offering		Maximum Number of shares of Common Stock to be Sold Pursuant to this Prospectus		Number of shares of Common Stock Owned After Offering
Christopher Carter and Julia Dawn Cheek		1,717		1,717		0
Corinne A. Hutchinson		11,954		5,725		6,229
Covert Family Limited Partnership		207,927		114,496		93,431
Flying W5 LP		47,310		28,624		18,686
Gore Creek Private Fund S2B LLC		572,480		572,480		0
Grey Rock Energy Partners GP II-A, L.P.		19,434		19,434		0
Gringotts 5404 LLC		57,248		57,248		0
Hunstable 2015 Family Trust		28,624		28,624		0
Jacob Novak		410,815		286,240		124,575
James McMahan		14,312		14,312		0
Joe C. Thompson, Jr. “F” Trust		176,784		114,496		62,288
John W. Bender		14,816		8,587		6,229
Mary T. Wolf “F” Trust		90,912		28,624		62,288
Michael Randolph		9,091		2,862		6,229
Missouri Department of Transportation		572,480		572,480		0
Reaser Family Acquisition Trust Two		143,120		143,120		0
Robert G. Baty, Jr.		1,456		1,145		311
Stewart Hunter		56,150		34,349		21,801
The Hayden Company		57,248		57,248		0
The Williamsburg Corporation		57,248		57,248		0
Thomas Houston Duncan		2,862		2,862		0
Three Angel Investments LLC		57,248		57,248		0
University of Richmond		858,721		858,721		0
Carnegie Corporation of New York		858,721		858,721		0
Georgetown University		686,977		686,977		0
Gore Creek Private Fund S1B (TE) LLC		57,248		57,248		0
Grey Rock Energy Partners GP II-B, L.P.		23,502		23,502		0
Regents of the University of Michigan		1,717,445		1,717,445		0
The Metropolitan Museum of Art		1,431,201		1,431,201		0
Adam Griffin		1,431		1,431		0
David Eric Holley		1,431		1,431		0
Kent A. Bowker Geological Consulting LLC		2,862		2,862		0
Northwestern University		20,541		14,312		6,229
Privateer LTCG, LP		338,723		77,285		261,438
Ryan Riggelson		572		572		0
Vanderhider Family Partnership LTD		57,248		57,248		0
William Scott Eads		572		572		0
Grey Rock Energy Partners GP, L.P.		25,912		25,912		0

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(1)

ENPC Holdings II, LLC is the record holder of the shares reported herein. Taggart M. Romney, Eric F. Scheuermann, and Spencer J. Zwick are the three managers of ENPC Holdings II, LLC’s board of managers. Any action by ENPC Holdings II, LLC with respect to the Company or the Granite Ridge common stock, including voting and dispositive decisions, requires at least a majority vote of the managers of the board of managers. Under the so-called “rule of three,” because voting and dispositive decisions are made by a majority of the managers, none of the managers is deemed to be a beneficial owner of securities held by ENPC Holdings II, LLC, even those in which such manager holds a pecuniary interest. Accordingly, none of the managers on ENPC Holdings II, LLC’s board of managers is deemed to have or share beneficial ownership of the shares held by ENPC Holdings II, LLC. The address of ENPC Holdings II, LLC is 137 Newbury Street, 7th Floor Boston, MA 02116.

(2)

Includes 371,518 shares that are subject to vesting and forfeiture provisions set forth in the Sponsor Agreement dated as of May 16, 2022, by and among ENPC Holdings, LLC, ENPC Holdings II, LLC, certain other stockholders named therein, Executive Network Partnering Corporation, Granite Ridge Resources, Inc., and GREP Holdings, LLC.

(3)

The number of shares beneficially owned gives effect to direction given by GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC to issue (i) 21,322 shares and 31,509 shares, respectively, to GREP Holdco I LLC that would otherwise have been delivered to GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC at the Closing, pursuant to that certain letter agreement dated as of the Closing Date by and among GREP Holdco II LLC, GREP Holdco II-B Holdings, LLC and GREP Holdco I LLC and (ii) 3,336,485 shares and 4,935,858 shares, respectively, pro rata to the limited partners of GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC that would otherwise have been delivered to GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC at the Closing. Each of GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC is indirectly controlled by GREP GP II, LLC (“Fund II GP”). Fund II GP is the sole general partner of Grey Rock Energy Partners GP II, L.P. (“GREP GP II”), which is the sole member of GREP GP II Holdings, LLC (“GREP GP II Holdings”), which is the sole general partner of each of Grey Rock Energy Partners GP II-A, L.P. (“GP II-A”) and Grey Rock Energy Partners GP II-B, L.P. (“GP II-B”). GP II-A is the sole general partner of Grey Rock Energy Fund II, LP (“Fund II-A”), which is the sole member of GREP Holdco II LLC. GP II-B is the sole general partner of each of Grey Rock Energy Fund II-B, LP (“Fund II-B”) and Grey Rock Energy Fund II-B Holdings, L.P. (“Fund II-B Holdings”). Fund II-B and Fund II-B Holdings are the sole members of GREP Holdco II-B Holdings, LLC. As a result, (i) Fund II GP, GREP GP II, GREP GP II Holdings, GP II-A, and Fund II-A may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco II LLC, and (ii) Fund II GP, GREP GP II, GREP GP II Holdings, GP II-B, Fund II-B and Fund II-B Holdings may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco II-B Holdings, LLC. Fund II GP, GREP GP II, GREP GP II Holdings, GP II-A and Fund II-A disclaim beneficial ownership of the Granite Ridge common stock held by GREP Holdco II LLC in excess of such entity’s pecuniary interest therein. Fund II GP, GREP GP II, GREP GP II Holdings, GP II-B, Fund II-B and Fund II-B Holdings disclaim beneficial ownership of the Granite Ridge common stock held by GREP Holdco II-B Holdings, LLC in excess of such entity’s pecuniary interest therein.

(4)

Investment discretion with respect to each of Fund I GP, Fund II GP and Fund III GP and their respective indirect subsidiaries, which hold the Granite Ridge common stock referred to in notes 3-5 above, is maintained by a separate investment committee constituted at each of Fund I GP, Fund II GP and Fund III GP (each, a “Grey Rock Investment Committee”). The members of each Grey Rock Investment Committee are Matthew Miller, Griffin Perry and Kirk Lazarine. Approval of a majority of the members of each of the respective Grey Rock Investment Committees is required to approve any investment decision for each of Fund I GP, Fund II GP and Fund III GP. Under the so-called “rule of three,” if voting and dispositive decisions regarding an entity’s securities are made by three or more individuals, and a voting or dispositive decision requires the approval of at least a majority of those individuals, then none of the individuals is deemed a beneficial owner of the entity’s securities. Based upon the foregoing analysis, no member of any Grey Rock Investment Committee exercises voting or dispositive control over any of the securities held directly or indirectly by any of Fund I GP, Fund II GP

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or Fund III GP, even those in which he directly holds a pecuniary interest. Accordingly, none of them will be deemed to have or share beneficial ownership of such shares.

(5)

Each of GREP Holdco III-A, LLC and Holdco III-B Holdings, LLC is indirectly controlled by GREP GP III, LLC (“Fund III GP”). Fund III GP is the sole general partner of Grey Rock Energy Partners GP III, L.P. (“GREP GP III”), which is the sole member of GREP GP III Holdings, LLC (“GREP GP III Holdings”), which is the sole general partner of each of Grey Rock Energy Partners GP III-A, L.P. (“GP III-A”) and Grey Rock Energy Partners GP III-B, L.P. (“GP III-B”). GP III-A is the sole general partner of Grey Rock Energy Fund III-A, LP (“Fund III-A”), which is the sole member of GREP Holdco III-A, LLC. GP III-B is the sole general partner of Grey Rock Energy Fund III-B, LP (“Fund III-B”) and Grey Rock Energy Fund III-B Holdings, LP (“Fund III-B Holdings”). Fund III-B and Fund III-B Holdings are the sole members of GREP Holdco III-B Holdings, LLC. As a result, (i) Fund III GP, GREP GP III, GREP GP III Holdings, GP III-A, and Fund III-A may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco III-A, LLC and (ii) Fund III GP, GREP GP III, GREP GP III Holdings, GP III-B, Fund III-B and Fund III-B Holdings may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco III-B Holdings, LLC. Fund III GP, GREP GP III, GREP GP III Holdings, GP III-A and Fund III-A disclaim beneficial ownership of the Granite Ridge common stock held by GREP Holdco III-A, LLC in excess of such entity’s pecuniary interest therein. Fund III GP, GREP GP III, GREP GP III Holdings, GP III-B, Fund III-B and Fund III-B Holdings disclaim beneficial ownership of the Granite Ridge common stock held by GREP Holdco III-B Holdings, LLC in excess of such entity’s pecuniary interest therein.

(6)

Includes 5,725 shares owned directly by Mr. Darden and 24,159 shares owned by Monticello Avenue LLC, over which Mr. and Mrs. Darden has voting and investment power. Mr. Darden disclaims beneficial ownership of shares held by Monticello Avenue LLC, except to the extent of his pecuniary interest.

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BENEFICIAL OWNERSHIP OF SECURITIES

The following table sets forth information known to Granite Ridge regarding the beneficial ownership of Granite Ridge common stock as of November 10, 2022, by:

•

each person or “group” (as such term is used in Section 13(d)(3) of the Exchange Act) known to Granite Ridge who is a beneficial owner of more than 5% of outstanding shares of Granite Ridge common stock;

•

each of Granite Ridge’s executive officers and directors; and

•

all executive officers and directors of Granite Ridge as a group.

Beneficial ownership is determined according to the rules of the SEC, which generally provide that a person has beneficial ownership of a security if he, she or it possesses sole or shared voting or investment power over that security, including options and warrants that are currently exercisable or exercisable within 60 days. Shares of common stock issuable pursuant to options or warrants are deemed to be outstanding for purposes of computing the beneficial ownership percentage of the person or group holding such options or warrants but are not deemed to be outstanding for purposes of computing the beneficial ownership percentage of any other person.

The beneficial ownership of Granite Ridge common stock is based on 133,270,477 shares of Granite Ridge common stock outstanding as of January 5, 2023. The beneficial ownership percentages set forth in the table below with respect to Granite Ridge common stock do not take into account (i) the issuance of any shares (or options to acquire shares) under the Incentive Plan and (ii) the issuance of any shares upon the exercise of warrants to purchase up to a total of 10,349,975 shares of Granite Ridge common stock outstanding (other than any warrants held by each such person named below).

Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to all shares of Granite Ridge common stock beneficially owned by them.

	Granite Ridge Common Stock
Name of Beneficial Owners	Number of Shares		Percent
Fund II(1)(3)(4)		23,601,149		17.7%
Fund III(2)(3)(4)		95,080,584		71.3%
Luke C. Brandenberg(4)		—		—
Tyler S. Farquharson(4)		—		—
Matthew Miller(3)(4)		17,175		*
Griffin Perry(3)(4)		5,725		*
Amanda N. Coussens(4)		—		—
Thaddeus Darden(4)(5)		29,884		*
Michele Everard(4)		—		—
Kirk Lazarine(4)		5,725		*
John McCartney(4)		—		—
All officers, directors and director nominees of Granite Ridge as a group (nine individuals)		58,509		*

less than 1%.

(1)

Represents (i) 9,507,742 shares of Granite Ridge common stock held by GREP Holdco II LLC and (ii) 14,050,471 shares of Granite Ridge common stock held by GREP Holdco II-B Holdings, LLC, 19,434 shares of Granite Ridge common stock held by Grey Rock Energy Partners GP II-A, L.P., and 23,502 shares of Granite Ridge common stock held by Grey Rock Energy Partners GP II-B, L.P. as of November 10, 2022. The number of shares beneficially owned gives effect to direction given by GREP

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Holdco II LLC and GREP Holdco II-B Holdings, LLC to issue (i) 21,322 shares and 31,509 shares, respectively, to GREP Holdco I LLC that would otherwise have been delivered to GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC at the closing of the Business Combination, pursuant to that certain letter agreement dated as of the Closing Date by and among GREP Holdco II LLC, GREP Holdco II-B Holdings, LLC and GREP Holdco I LLC and (ii) 3,336,485 shares and 4,935,858 shares, respectively, pro rata to the limited partners of GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC that would otherwise have been delivered to GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC at the closing. Each of GREP Holdco II LLC and GREP Holdco II-B Holdings, LLC is indirectly controlled by GREP GP II, LLC (“Fund II GP”). Fund II GP is the sole general partner of Grey Rock Energy Partners GP II, L.P. (“GREP GP II”), which is the sole member of GREP GP II Holdings, LLC (“GREP GP II Holdings”), which is the sole general partner of each of Grey Rock Energy Partners GP II-A, L.P. (“GP II-A”) and Grey Rock Energy Partners GP II-B, L.P. (“GP II-B”). GP II-A is the sole general partner of Grey Rock Energy Fund II, LP (“Fund II-A”), which is the sole member of GREP Holdco II LLC. GP II-B is the sole general partner of each of Grey Rock Energy Fund II-B, LP (“Fund II-B”) and Grey Rock Energy Fund II-B Holdings, L.P. (“Fund II-B Holdings”). Fund II-B and Fund II-B Holdings are the sole members of GREP Holdco II-B Holdings, LLC. As a result, (i) Fund II GP, GREP GP II, GREP GP II Holdings, GP II-A, and Fund II-A may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco II LLC, and (ii) Fund II GP, GREP GP II, GREP GP II Holdings, GP II-B, Fund II-B and Fund II-B Holdings may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco II-B Holdings, LLC. Fund II GP, GREP GP II, GREP GP II Holdings, GP II-A and Fund II-A disclaim beneficial ownership of the Granite Ridge common stock held by GREP Holdco II LLC in excess of such entity’s pecuniary interest therein. Fund II GP, GREP GP II, GREP GP II Holdings, GP II-B, Fund II-B and Fund II-B Holdings disclaim beneficial ownership of the Granite Ridge common stock held by GREP Holdco II-B Holdings, LLC in excess of such entity’s pecuniary interest therein.

(2)

Represents (i) 28,847,450 shares of Granite Ridge common stock held by GREP Holdco III-A, LLC and (i) 66,233,134 shares of Granite Ridge common stock held by GREP Holdco III-B Holdings, LLC as of November 10, 2022. Each of GREP Hold III-A, LLC and Holdco III-B Holdings, LLC is indirectly controlled by GREP GP III, LLC (“Fund III GP”). Fund III GP is the sole general partner of Grey Rock Energy Partners GP III, L.P. (“GREP GP III”), which is the sole member of GREP GP III Holdings, LLC (“GREP GP III Holdings”), which is the sole general partner of each of Grey Rock Energy Partners GP III-A, L.P. (“GP III-A”) and Grey Rock Energy Partners GP III-B, L.P. (“GP III-B”). GP III-A is the sole general partner of Grey Rock Energy Fund III-A, LP (“Fund III-A”), which is the sole member of GREP Holdco III-A, LLC. GP III-B is the sole general partner of Grey Rock Energy Fund III-B, LP (“Fund III-B”) and Grey Rock Energy Fund III-B Holdings, LP (“Fund III-B Holdings”). Fund III-B and Fund III-B Holdings are the sole members of GREP Holdco III-B Holdings, LLC. As a result, (i) Fund III GP, GREP GP III, GREP GP III Holdings, GP III-A, and Fund III-A may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco III-A, LLC and (ii) Fund III GP, GREP GP III, GREP GP III Holdings, GP III-B, Fund III-B and Fund III-B Holdings may be deemed to share the power to vote or direct the vote or to dispose or direct the disposition of the Granite Ridge common stock owned by GREP Holdco III-B Holdings, LLC. Fund III GP, GREP GP III, GREP GP III Holdings, GP III-A and Fund III-A disclaim beneficial ownership of the Granite Ridge common stock to by GREP Holdco III-A, LLC in excess of such entity’s pecuniary interest therein. Fund III GP, GREP GP III, GREP GP III Holdings, GP III-B, Fund III-B and Fund III-B Holdings disclaim beneficial ownership of the Granite Ridge common stock held by GREP Holdco III-B Holdings, LLC in excess of such entity’s pecuniary interest therein.

(3)

Investment discretion with respect to each of Fund II GP and Fund III GP and their respective indirect subsidiaries, which hold the Granite Ridge common stock referred to in notes 1-2 above, is maintained by a separate investment committee constituted at each of Fund II GP and Fund III GP (each, a “Grey Rock Investment Committee”). The members of each Grey Rock Investment Committee are Matthew Miller, Griffin Perry and Kirk Lazarine. Approval of a majority of the members of each of the respective Grey Rock Investment Committees is required to approve any investment decision for

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each of Fund II GP and Fund III GP. Under the so-called “rule of three,” if voting and dispositive decisions regarding an entity’s securities are made by three or more individuals, and a voting or dispositive decision requires the approval of at least a majority of those individuals, then none of the individuals is deemed a beneficial owner of the entity’s securities. Based upon the foregoing analysis, no member of any Grey Rock Investment Committee exercises voting or dispositive control over any of the securities held directly or indirectly by any of Fund II GP or Fund III GP, even those in which he directly holds a pecuniary interest. Accordingly, none of them are deemed to have or share beneficial ownership of such shares.

(4)

The business address of each of the persons and entities indicated is 5217 McKinney Avenue, Suite 400, Dallas, Texas 75205.

(5)

Includes 5,725 shares owned directly by Mr. Darden and 24,159 shares owned by Monticello Avenue LLC, over which Mr. Darden has voting and investment power. Mr. Darden disclaims beneficial ownership of shares held by Monticello Avenue LLC, except to the extent of his pecuniary interest.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Business Combination Agreement

On the Closing Date, ENPC and Granite Ridge, consummated the Business Combination pursuant to the terms of the Business Combination Agreement, dated as of May 16, 2022 (the “Business Combination Agreement”), by and among ENPC, Granite Ridge, ENPC Merger Sub, Inc., a Delaware corporation and a wholly-owned subsidiary of Granite Ridge (“ENPC Merger Sub”), GREP Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Granite Ridge (“GREP Merger Sub”), and GREP Holdings, LLC, a Delaware limited liability company (“GREP”). Pursuant to the Business Combination Agreement, on the Closing Date, (i) ENPC Merger Sub merged with and into ENPC (the “ENPC Merger”), with ENPC surviving the ENPC Merger as a wholly-owned subsidiary of Granite Ridge and (ii) GREP Merger Sub merged with and into GREP (the “GREP Merger,” and together with the ENPC Merger, the “Mergers”), with GREP surviving the GREP Merger as a wholly-owned subsidiary of Granite Ridge (the transactions contemplated by the foregoing clauses (i) and (ii) the “Business Combination,” and together with the other transactions contemplated by the Business Combination Agreement, the “Transactions”).

In connection with the Business Combination, public stockholders of 39,343,496 shares of ENPC Class A common stock exercised their rights to have those shares redeemed for cash at a redemption price of approximately $10.07 per share, or an aggregate of approximately $396.1 million. The Existing GREP Members and their direct and indirect members were issued 130.0 million shares of Granite Ridge common stock at the closing of the Business Combination. Upon consummation of the Business Combination, each public stockholder’s ENPC common stock and ENPC warrants were automatically converted into an equivalent number of shares of Granite Ridge common stock and Granite Ridge warrants as a result of the Business Combination. At the effective time of the Mergers, (i) 495,357 shares of ENPC Class F common stock were converted to 1,238,393 shares of ENPC Class A common stock (of which 371,518 of those shares are, upon conversion to Granite Ridge common stock, subject to certain vesting and forfeiture provisions set forth in that certain Sponsor Agreement, dated May 16, 2022, by and among ENPC Holdings, LLC, ENPC Holdings II, LLC, ENPC, Granite Ridge, GREP and certain other parties named therein (the “Sponsor Agreement”)) and the remaining shares of ENPC Class F common stock outstanding were automatically cancelled for no consideration (the “ENPC Class F Conversion”) (ii) all other remaining shares of ENPC Class A common stock held by Holdco and the independent directors of ENPC were automatically cancelled without any conversion, payment or distribution (the “Sponsor Share Cancellation”) and (iii) all shares of ENPC Class B common stock outstanding were deemed transferred to ENPC and surrendered and forfeited for no consideration (the “ENPC Class B Contribution”). Following the ENPC Class F Conversion, the Sponsor Share Cancellation, the ENPC Class B Contribution and the CAPSTM Separation, each share of ENPC Class A common stock outstanding was automatically converted into one share of Granite Ridge common stock. The aggregate consideration paid in the Business Combination to the Existing GREP Members and their direct and indirect members consisted of 130.0 million shares of Granite Ridge common stock.

Warrant Agreement Assignment, Assumption and Amendment

On the Closing Date, the Company entered into the Assignment, Assumption and Amendment Agreement (the “Warrant Agreement Amendment and Assignment”), by and among the Company, ENPC and Continental Stock Transfer & Trust Company (“Continental”). The Warrant Agreement Amendment and Assignment assigned the existing Warrant Agreement, dated September 15, 2020, as amended on March 24, 2021 (“Amendment No. 1”), by and between ENPC and Continental (as amended, the “Existing Warrant Agreement”) to the Company, and the Company agreed to perform all applicable obligations under such agreement.

Pursuant to the Warrant Agreement Amendment and Assignment, ENPC assigned all its rights, title and interest in the Existing Warrant Agreement to the Company and all warrants of ENPC to purchase shares of ENPC Class A common stock, par value $0.0001 per share (“ENPC Class A common stock”), as contemplated under the Existing Warrant Agreement, will no longer be exercisable for shares of ENPC Class A common stock, but instead will be Granite Ridge warrants exercisable for shares of common stock,

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par value $0.0001 per share, of Granite Ridge (“Granite Ridge common stock”), on the same terms that were in effect prior to the Closing under the terms of the Existing Warrant Agreement, except as described in the Warrant Agreement Amendment and Assignment.

Registration Rights and Lock-Up Agreement

On the Closing Date of the Business Combination, the Company entered into the Registration Rights and Lock-Up Agreement (the “RRA and Lock-Up Agreement”) with Granite Ridge, ENPC Holdings II, LLC, a Delaware limited liability company (“Holdco”), Richard Boyce, Michael M. Calbert, Gisel Ruiz and the Existing GREP Members, with respect to the shares of Granite Ridge common stock issued as consideration under the Business Combination Agreement. The RRA and Lock-Up Agreement includes, among other things, the following provisions:

Management Services Agreement

On the Closing Date of the Business Combination, in connection with the consummation thereof, Grey Rock Administration, LLC, a Delaware limited liability company (“Manager”) indirectly owned by four of the Company’s directors, Matthew Miller, Griffin Perry, Thaddeus Darden and Kirk Lazarine, entered into a Management Services Agreement with Granite Ridge (the “MSA”). Under the MSA, Manager will provide general management, administrative and operating services covering the oil and gas assets and other properties of Granite Ridge (the “Assets”) and the day-to-day business and affairs of Granite Ridge relating to the Assets. Granite Ridge shall pay Manager an annual services fee of $10 million and shall reimburse Manager for certain Granite Ridge group costs related to the operation of the Assets (including for third

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party costs allocated or attributable to the Assets). The initial term of the MSA expires on April 30, 2028; however, the MSA will automatically renew for additional consecutive one-year renewal terms until terminated in accordance with its terms. Upon any termination of the MSA, Manager shall provide transition services for a period of up to 90 days.

If Granite Ridge terminates the MSA for convenience prior to the end of the initial term or any renewal term if less than 90 days’ notice is given by Granite Ridge, or upon a change of control of Granite Ridge (or a sale of all or substantially all the Assets of Granite Ridge), or if Manager terminates the MSA due to Granite Ridge’s uncured material breach of the MSA, then Granite Ridge will be required to pay a termination fee to Manager equal to the lesser of $10 million or 50% of the remaining unpaid annual service fee applicable to the remainder of the initial term or to any renewal term, as applicable. Granite Ridge will not be required to pay a termination fee if the MSA is terminated by notice (a) by Granite Ridge with at least 90 days’ notice prior to expiration of the initial term or any renewal term, or (b) terminated by notice by Granite Ridge (i) upon a change of control or bankruptcy of Manager, (ii) upon the occurrence of certain key person events, (iii) upon the occurrence of uncured circumstances of malfeasance by Manager or certain of its employees or (iv) upon Manager’s uncured material breach of the MSA.

Manager is obligated to provide the services in good faith, in a workmanlike, reasonable and prudent manner, with at least the same degree of care, judgment and skill as historically provided by Manager with respect to the Assets prior to the Business Combination, in accordance with customary oil and gas industry practices and standards and in material compliance with contractual requirements affecting the Assets and all applicable laws. Manager will also indemnify Granite Ridge for (i) Manager’s own gross negligence, willful misconduct and actual fraud and (ii) any claims by Manager’s (and its affiliates’) employees or consultants relating to the terms and conditions of their employment or arrangement with Manager or such affiliate, except and excluding claims under agreements with Granite Ridge or its subsidiaries.

During the term of the MSA, each of Manager and Granite Ridge will be required to present to the other all opportunities sourced by it to acquire or invest in upstream oil, gas or other hydrocarbon assets located in North America. During the Term (as defined therein), each such opportunity will be offered 75% to Granite Ridge and 25% to Grey Rock Energy Fund IV-A, LP, Grey Rock Energy Fund IV-B, LP, and Grey Rock Energy Fund IV-B Holdings, LP, each Delaware limited partnerships (collectively, “Fund IV”) (or any additional oil and gas-focused funds or investment vehicles formed by affiliates of Manager admitted as a party to the MSA in accordance with its terms) with associated costs to be allocated in accordance with the ownership percentage in any assets acquired.

Indemnity Agreements

On the Closing Date of the Business Combination, the Company entered into indemnity agreements (the “Indemnity Agreements”) with each of Matthew Miller, Griffin Perry, Thaddeus Darden, Kirk Lazarine, John McCartney, Amanda N. Coussens and Michele J. Everard, each of whom is a director of the Company, and Luke C. Brandenberg, Tyler S. Farquharson, and Emily Fuquay, each of whom is an officer of the Company. Each Indemnity Agreement provides that, subject to limited exceptions, the Company will indemnify the director or executive officer to the fullest extent permitted by law for claims arising in his or her capacity as our director or officer.

Policies and Procedures for Related Person Transactions

Policy for Approval of Related Party Transactions

The Granite Ridge Board has adopted a Related Party Transactions Policy. The purpose of the policy is to describe the procedures used to identify, review, approve and disclose, if necessary, any transaction or series of transactions in which: (i) the amount involved will or may be expected to exceed $120,000 in any calendar year, (ii) Granite Ridge was, is or will be a participant (even if not necessarily a party); and (iii) a Related Party has or will have a direct or indirect interest (with such transactions being “Interested Transactions”).

The Conflicts Committee reviews the material facts relating to all Interested Transactions and either approves or disapproves of the Company’s entry into the Interested Transaction, subject to certain exceptions.

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If advance Conflicts Committee approval of an Interested Transaction is not feasible, then at the Conflicts Committee’s next meeting, the Interested Transaction will be considered and, if the Conflicts Committee determines it to be appropriate, ratified (or if not ratified, the Conflicts Committee will determine if the transaction should be terminated). In determining whether to approve or ratify an Interested Transaction, the Conflicts Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable to the Company than terms generally available from an unaffiliated third-party under the same or similar circumstances, whether the Interested Transaction is material to the Company and the extent of the Related Party’s interest in the Interested Transaction.

A “Related Party” under this policy will include: (i) the Company’s directors, nominees for director or executive officers; (ii) any record or beneficial owner of more than 5% of any class of the Company’s voting securities; (iii) any immediate family member of any of the foregoing if the foregoing person is a natural person; (iv) a senior officer of the Manager providing services to the Company pursuant to the MSA; and (v) any other person who maybe a “related person” pursuant to Item 404 of Regulation S-K under the Exchange Act.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a discussion of certain material U.S. federal income tax consequences of the acquisition, ownership and disposition of shares of Granite Ridge common stock and Granite Ridge warrants (collectively, “Granite Ridge Securities”). This discussion is limited to certain U.S. federal income tax considerations to beneficial owners of Granite Ridge Securities who are initial purchasers of such Granite Ridge Securities pursuant to this offering and hold the Granite Ridge Securities as a capital asset within the meaning of Section 1221 of the Code. This discussion assumes that any distributions made by us on Granite Ridge Securities and any consideration received by a holder in consideration for the sale or other disposition of Granite Ridge Securities will be in U.S. dollars.

This summary is based upon U.S. federal income tax laws as of the date of this prospectus, which is subject to change or differing interpretations, possibly with retroactive effect. This discussion is a summary only and does not describe all of the tax consequences that may be relevant to you in light of your particular circumstances, including but not limited to the alternative minimum tax, the Medicare tax on certain investment income and the different consequences that may apply if you are subject to special rules that apply to certain types of investors, including but not limited to:

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financial institutions or financial services entities;

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broker-dealers;

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governments or agencies or instrumentalities thereof;

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regulated investment companies;

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real estate investment trusts;

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expatriates or former long-term residents of the United States;

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persons that actually or constructively own five percent or more (by vote or value) of Granite Ridge common stock;

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persons that acquired Granite Ridge common stock pursuant to an exercise of employee share options, in connection with employee share incentive plans or otherwise as compensation;

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insurance companies;

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dealers or traders subject to a mark-to-market method of accounting with respect to Granite Ridge Securities;

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persons holding Granite Ridge Securities as part of a “straddle,” constructive sale, hedge, conversion or other integrated or similar transaction;

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U.S. holders (as defined below) whose functional currency is not the U.S. dollar;

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partnerships (or entities or arrangements classified as partnerships or other pass-through entities for U.S. federal income tax purposes) and any beneficial owners of such partnerships;

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tax-exempt entities;

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controlled foreign corporations; and

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passive foreign investment companies.

If a partnership (including an entity or arrangement treated as a partnership or other pass-thru entity for U.S. federal income tax purposes) holds Granite Ridge Securities, the tax treatment of a partner, member or other beneficial owner in such partnership will generally depend upon the status of the partner, member or other beneficial owner, the activities of the partnership and certain determinations made at the partner, member or other beneficial owner level. If you are a partner, member or other beneficial owner of a partnership holding Granite Ridge Securities, you are urged to consult your tax advisor regarding the tax consequences of the acquisition, ownership and disposition of Granite Ridge Securities.

This discussion is based on the Code, and administrative pronouncements, judicial decisions and final, temporary and proposed Treasury regulations as of the date hereof, which are subject to change, possibly

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on a retroactive basis, and changes to any of which subsequent to the date of this prospectus may affect the tax consequences described herein. This discussion does not address any aspect of state, local or non-U.S. taxation, or any U.S. federal taxes other than income taxes (such as gift and estate taxes).

We have not sought, and do not expect to seek, a ruling from the U.S. Internal Revenue Service (the “IRS”) as to any U.S. federal income tax consequence described herein. The IRS may disagree with the discussion herein, and its determination may be upheld by a court. Moreover, there can be no assurance that future legislation, regulations, administrative rulings or court decisions will not adversely affect the accuracy of the statements in this discussion. You are urged to consult your tax advisor with respect to the application of U.S. federal tax laws to your particular situation, as well as any tax consequences arising under the laws of any state, local or foreign jurisdiction.

THIS DISCUSSION IS ONLY A SUMMARY OF CERTAIN MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS ASSOCIATED WITH THE ACQUISITION, OWNERSHIP AND DISPOSITION OF GRANITE RIDGE SECURITIES. EACH PROSPECTIVE INVESTOR IN GRANITE RIDGE SECURITIES IS URGED TO CONSULT ITS OWN TAX ADVISOR WITH RESPECT TO THE PARTICULAR TAX CONSEQUENCES TO SUCH INVESTOR OF THE ACQUISITION, OWNERSHIP AND DISPOSITION OF GRANITE RIDGE SECURITIES, INCLUDING THE APPLICABILITY AND EFFECT OF ANY U.S. FEDERAL NON-INCOME, STATE, LOCAL, AND NON-U.S. TAX LAWS.

U.S. Holders

This section applies to you if you are a “U.S. holder.” A U.S. holder is a beneficial owner Granite Ridge Securities who or that is, for U.S. federal income tax purposes:

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an individual who is a citizen or resident of the United States;

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a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) organized in or under the laws of the United States, any state thereof or the District of Columbia;

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an estate the income of which is includible in gross income for U.S. federal income tax purposes regardless of its source; or

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a trust, if (i) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons (as defined in the Code) have authority to control all substantial decisions of the trust or (ii) it has a valid election in effect under Treasury Regulations to be treated as a United States person.

Taxation of Distributions.

If we pay distributions in cash or other property (other than certain distributions of our stock or rights to acquire our stock) to U.S. holders of shares of Granite Ridge common stock, such distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of current and accumulated earnings and profits will constitute a return of capital that will be applied against and reduce (but not below zero) the U.S. holder’s adjusted tax basis in Granite Ridge common stock. Any remaining excess will be treated as gain realized on the sale or other disposition of the Granite Ridge common stock and will be treated as described under “U.S. Holders — Gain or Loss on Sale, Taxable Exchange or Other Taxable Disposition of Granite Ridge Securities” below.

Dividends we pay to a U.S. holder that is a taxable corporation generally will qualify for the dividends received deduction if the requisite holding period is satisfied. With certain exceptions (including, but not limited to, dividends treated as investment income for purposes of investment interest deduction limitations), and provided certain holding period requirements are met, dividends we pay to a non-corporate U.S. holder may constitute “qualified dividend income” that will be subject to tax at preferential long-term capital gains rates. If the holding period requirements are not satisfied, then a corporation may not be able to qualify for the dividends received deduction and would have taxable income equal to the entire dividend amount, and non-corporate U.S. holders may be subject to tax on such dividend at regular ordinary income tax rates instead of the preferential rate that applies to qualified dividend income.

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Gain or Loss on Sale, Taxable Exchange or Other Taxable Disposition of Granite Ridge Securities.

Upon a sale or other taxable disposition of Granite Ridge Securities, a U.S. holder generally will recognize capital gain or loss in an amount equal to the difference between the amount realized and the U.S. holder’s adjusted tax basis in the Granite Ridge Securities. Any such capital gain or loss generally will be long-term capital gain or loss if the U.S. holder’s holding period for the Granite Ridge Securities so disposed of exceeds one year. Long-term capital gains recognized by non-corporate U.S. holders may be eligible to be taxed at reduced rates. The deductibility of capital losses is subject to limitations.

Generally, the amount of gain or loss recognized by a U.S. holder is an amount equal to the difference between (i) the sum of the amount of cash and the fair market value of any property received in such disposition and (ii) the U.S. holder’s adjusted tax basis in its Granite Ridge Securities so disposed of. A U.S. holder’s adjusted tax basis in its Granite Ridge Securities generally will equal the U.S. holder’s acquisition cost less any prior distributions treated as a return of capital.

Exercise or Lapse of Granite Ridge Warrant

A U.S. holder generally will not recognize gain or loss upon the acquisition of a share Granite Ridge common stock on the exercise of a Granite Ridge warrant for cash. A U.S. holder’s initial tax basis in a share of Granite Ridge common stock received upon exercise of the Granite Ridge warrant generally will be an amount equal to the sum of the U.S. holder’s initial investment in the Granite Ridge warrant and the exercise price of such warrant. It is unclear whether a U.S. holder’s holding period for the share of Granite Ridge common stock received upon exercise of the Granite Ridge warrant will commence on the date of exercise of the Granite Ridge warrant or the day following the date of exercise of the Granite Ridge warrant; in either case, the holding period will not include the period during which the U.S. holder held the Granite Ridge warrant. If a warrant is allowed to lapse unexercised, a U.S. holder generally will recognize a capital loss equal to such holder’s tax basis in the warrant.

The tax consequences of a cashless exercise of a warrant are not clear under current tax law. A cashless exercise may not be taxable, either because the exercise is not a realization event or because the exercise is treated as a “recapitalization” for U.S. federal income tax purposes. In either situation, a U.S. holder’s tax basis in the shares of Granite Ridge common stock received generally would equal the U.S. holder’s tax basis in the Granite Ridge warrants exercised therefor. If the cashless exercise were treated as not being a realization event, it is unclear whether a U.S. holder’s holding period in the shares of Granite Ridge common stock will commence on the date of exercise of the Granite Ridge warrant or the day following the date of exercise of the warrant; in either case, the holding period would not include the period during which the U.S. holder held the warrants. If the cashless exercise were treated as a recapitalization, the holding period of the shares of Granite Ridge common stock would include the holding period of the Granite Ridge warrants exercised therefor.

It is also possible that a cashless exercise could be treated in whole or in part as a taxable exchange in which gain or loss would be recognized. In such event, a U.S. holder could be deemed to have surrendered a number of warrants with a fair market value equal to the exercise price for the number of warrants deemed exercised. For this purpose, the number of warrants deemed exercised would be equal to the amount needed to receive on exercise the number of Granite Ridge common stock issued pursuant to the cashless exercise. In this situation, the U.S. holder would recognize capital gain or loss in an amount equal to the difference between the fair market value of the warrants deemed surrendered to pay the exercise price and the U.S. holder’s tax basis in the warrants deemed surrendered. Such gain or loss would be long-term or short-term, depending on the U.S. holder’s holding period in the warrants deemed surrendered. In this case, a U.S. holder’s tax basis in the Granite Ridge common stock received would equal the sum of the U.S. holder’s tax basis in the Granite Ridge warrants deemed exercised and the exercise price of such warrants. It is unclear whether a U.S. holder’s holding period for the Granite Ridge common stock would commence on the date following the date of exercise or on the date of exercise of the Granite Ridge warrant; in either case, the holding period would not include the period during which the U.S. holder held the warrant.

Information Reporting and Backup Withholding.

In general, information reporting requirements may apply to dividends paid to a U.S. holder and to the proceeds of the sale or other disposition of Granite Ridge Securities, unless the U.S. holder is an exempt

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recipient. Backup withholding may apply to such payments if the U.S. holder fails to provide a taxpayer identification number, a certification of exempt status or has been notified by the IRS that it is subject to backup withholding (and such notification has not been withdrawn).

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be allowed as a credit against a U.S. holder’s U.S. federal income tax liability and may entitle such holder to a refund, provided the required information is timely furnished to the IRS.

Non-U.S. Holders

This section applies to you if you are a “Non-U.S. holder.” As used herein, the term “Non-U.S. holder” means a beneficial owner of Granite Ridge Securities who or that is for U.S. federal income tax purposes:

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a non-resident alien individual (other than certain former citizens and residents of the United States subject to U.S. tax as expatriates);

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a foreign corporation; or

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an estate or trust that is not a U.S. holder;

but generally does not include an individual who is present in the United States for 183 days or more in the taxable year of the disposition of Granite Ridge Securities. If you are such an individual, you should consult your tax advisor regarding the U.S. federal income tax consequences of the acquisition, ownership or sale or other disposition of Granite Ridge Securities.

Taxation of Distributions.

In general, any distributions we make to a Non-U.S. holder of shares of Granite Ridge Securities, to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles), will constitute dividends for U.S. federal income tax purposes and, provided such dividends are not effectively connected with the Non-U.S. holder’s conduct of a trade or business within the United States, we will be required to withhold tax from the gross amount of the dividend at a rate of 30%, unless such Non-U.S. holder is eligible for a reduced rate of withholding tax under an applicable income tax treaty and provides proper certification of its eligibility for such reduced rate (usually on an IRS Form W-8BEN or W-8BEN-E). Any distribution not constituting a dividend will be treated first as reducing (but not below zero) the Non-U.S. holder’s adjusted tax basis in its shares of Granite Ridge common stock and, to the extent such distribution exceeds the Non-U.S. holder’s adjusted tax basis, as gain realized from the sale or other disposition of the Granite Ridge common stock, which will be treated as described under “Non-U.S. Holders — Gain on Sale, Taxable Exchange or Other Taxable Disposition of Granite Ridge Securities” below. In addition, if we determine that we are likely to be classified as a “United States real property holding corporation” (see “Non-U.S. Holders — Gain on Sale, Taxable Exchange or Other Taxable Disposition of Granite Ridge Securities” below), we generally will withhold 15% of any distribution that exceeds our current and accumulated earnings and profits.

The withholding tax generally does not apply to dividends paid to a Non-U.S. holder who provides a Form W-8ECI, certifying that the dividends are effectively connected with the Non-U.S. holder’s conduct of a trade or business within the United States. Instead, the effectively connected dividends will be subject to regular U.S. federal income tax as if the Non-U.S. holder were a U.S. resident, subject to an applicable income tax treaty providing otherwise. A corporate Non-U.S. holder receiving effectively connected dividends may also be subject to an additional “branch profits tax” imposed at a rate of 30% (or a lower applicable treaty rate).

Gain on Sale, Taxable Exchange or Other Taxable Disposition of Granite Ridge Securities.

A Non-U.S. holder generally will not be subject to U.S. federal income or withholding tax in respect of gain realized on a sale, taxable exchange or other taxable disposition of Granite Ridge Securities unless:

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the gain is effectively connected with the conduct by the Non-U.S. holder of a trade or business within the United States (and, under certain income tax treaties, is attributable to a United States permanent establishment or fixed base maintained by the Non-U.S. holder); or

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•

we are or have been a “United States real property holding corporation” for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the Non-U.S. holder held Granite Ridge common stock, and, in the case where shares of Granite Ridge common stock are regularly traded on an established securities market, the Non-U.S. holder has owned, directly or constructively, more than 5% of Granite Ridge Securities at any time within the shorter of the five-year period preceding the disposition or such Non-U.S. holder’s holding period for the shares of Granite Ridge common stock. There can be no assurance that Granite Ridge common stock will be treated as regularly traded on an established securities market for this purpose. These rules may be modified for Non-U.S. holders of Granite Ridge warrants. If we are or have been a “United States real property holding corporation” and you own warrants, you are urged to consult your own tax advisor regarding the application of these rules.

Unless an applicable treaty provides otherwise, gain described in the first bullet point above will be subject to tax at generally applicable U.S. federal income tax rates as if the Non-U.S. holder were a U.S. resident. Any gains described in the first bullet point above of a Non-U.S. holder that is a foreign corporation may also be subject to an additional “branch profits tax” imposed at a 30% rate (or lower treaty rate).

If the second bullet point above applies to a Non-U.S. holder, gain recognized by such holder on the sale, exchange or other disposition of Granite Ridge Securities will be subject to tax at generally applicable U.S. federal income tax rates. In addition, a buyer of Granite Ridge Securities from such holder may be required to withhold U.S. federal income tax at a rate of 15% of the amount realized upon such disposition. We will be classified as a United States real property holding corporation if the fair market value of our “United States real property interests” equals or exceeds 50% of the sum of the fair market value of our worldwide real property interests plus our other assets used or held for use in a trade or business, as determined for U.S. federal income tax purposes.

Exercise, Lapse or Redemption of Granite Ridge Warrant

The U.S. federal income tax treatment of a Non-U.S. holder’s exercise of a warrant, or the lapse of a warrant held by a Non-U.S. Holder, generally will correspond to the U.S. federal income tax treatment of the exercise or lapse of a Granite Ridge warrant by a U.S. Holder, as described under “U.S. Holders — Exercise or Lapse of Granite Ridge Warrant” above, although to the extent a cashless exercise results in a taxable exchange, the consequences would be similar to those described above under “Non-U.S. Holders — Gain on Sale, Taxable Exchange or Other Taxable Disposition of Granite Ridge Securities.”

Information Reporting and Backup Withholding.

Information returns will be filed with the IRS in connection with payments of dividends and the proceeds from a sale or other disposition of shares of Granite Ridge Securities. A Non-U.S. holder may have to comply with certification procedures to establish that it is not a United States person in order to avoid information reporting and backup withholding requirements. The certification procedures required to claim a reduced rate of withholding under a treaty generally will satisfy the certification requirements necessary to avoid the backup withholding as well.

Backup withholding is not an additional tax. The amount of any backup withholding from a payment to a Non-U.S. holder will be allowed as a credit against such holder’s U.S. federal income tax liability and may entitle such holder to a refund, provided that the required information is timely furnished to the IRS.

FATCA Withholding Taxes

Sections 1471 through 1474 of the Code and the Treasury Regulations and administrative guidance promulgated thereunder (commonly referred as the “Foreign Account Tax Compliance Act” or “FATCA”) generally impose withholding at a rate of 30% in certain circumstances on dividends in respect of Granite Ridge Securities which are held by or through certain foreign financial institutions (including investment funds), unless any such institution (1) enters into, and complies with, an agreement with the IRS to report, on an annual basis, information with respect to interests in, and accounts maintained by, the institution that are owned by certain U.S. persons and by certain non-U.S. entities that are wholly or partially owned by U.S. persons and to withhold on certain payments, or (2) if required under an intergovernmental agreement

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between the United States and an applicable foreign country, reports such information to its local tax authority, which will exchange such information with the U.S. authorities. An intergovernmental agreement between the United States and an applicable foreign country may modify these requirements. Accordingly, the entity through which Granite Ridge Securities are held will affect the determination of whether such withholding is required. Similarly, dividends in respect of Granite Ridge Securities held by an investor that is a non-financial non-U.S. entity that does not qualify under certain exceptions will generally be subject to withholding at a rate of 30%, unless such entity either (1) certifies to us or the applicable withholding agent that such entity does not have any “substantial United States owners” or (2) provides certain information regarding the entity’s “substantial United States owners,” which will in turn be provided to the U.S. Department of Treasury. Under certain circumstances, a Non-U.S. holder might be eligible for refunds or credits of such withholding taxes, and a Non-U.S. holder might be required to file a U.S. federal income tax return to claim such refunds or credits.

Thirty percent withholding under FATCA was scheduled to apply to payments of gross proceeds from the sale or other disposition of property that produces U.S.-source interest or dividends beginning on January 1, 2019, but on December 13, 2018, the IRS released proposed regulations that, if finalized in their proposed form, would eliminate the obligation to withhold on gross proceeds. Such proposed regulations also delayed withholding on certain other payments received from other foreign financial institutions that are allocable, as provided for under final Treasury Regulations, to payments of U.S.-source dividends, and other fixed or determinable annual or periodic income. Although these proposed Treasury Regulations are not final, taxpayers generally may rely on them until final Treasury Regulations are issued. All prospective investors should consult their tax advisors regarding the possible implications of FATCA on their investment in our securities.

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PLAN OF DISTRIBUTION

Selling Securityholders

This prospectus includes the registration of the issuance by the Company of up to 10,349,975 shares of Granite Ridge common stock issuable upon exercise of the Granite Ridge warrants.

This prospectus also includes the registration for possible resale of 128,233,953 shares of Granite Ridge common stock issued as merger consideration in connection with the Business Combination. As of the date of this prospectus, the Selling Securityholders have advised us that they do not currently have any plan of distribution. Unless the context otherwise requires, as used in this prospectus, “Selling Securityholders” includes the Selling Securityholders named in the table included in the section above entitled “Selling Securityholders” and donees, transferees, assignees, successors, designees and others who later come to hold any of the Selling Securityholders’ interest in the Granite Ridge common stock other than through a public sale.

We will not receive any of the proceeds from the sale of the securities by the Selling Stockholders. We will receive proceeds from Granite Ridge warrants exercised in the event that such Granite Ridge warrants are exercised for cash.

The Selling Securityholders may offer and sell all or a portion of the securities covered by this prospectus from time to time, in one or more or any combination of the following transactions:

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on the New York Stock Exchange, in the over-the-counter market or on any other national securities exchange on which our securities are listed or traded;

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directly to purchasers, including through a specific bidding, auction or other process or in privately negotiated transactions;

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in one or more underwritten transactions;

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in a block trade in which a broker-dealer will attempt to sell the offered securities as agent but may purchase and resell a portion of the block as principal to facilitate the transaction;

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through purchases by a broker-dealer as principal and resale by the broker-dealer for its account pursuant to this prospectus;

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in ordinary brokerage transactions and transactions in which the broker solicits purchasers;

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through the writing or settlement of options (including put or call options), or other hedging transactions, whether through an options exchange or otherwise;

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through the distribution of the securities by any selling securityholder to its partners, members or stockholders;

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agreements with broker dealers to sell a specified number of the securities at a stipulated price per share;

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in short sales entered into after the effective date of the registration statement of which this prospectus is a part;

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“at the market” or through market makers or into an existing market for the securities;

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through a combination of any of the above methods of sale; or

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any other method permitted pursuant to applicable law.

In addition, a selling securityholder that is an entity may elect to make a pro rata in-kind distribution of securities to its members, partners or stockholders pursuant to the registration statement of which this prospectus is a part by delivering a prospectus with a plan of distribution. Such members, partners or stockholders would thereby receive freely tradeable securities pursuant to the distribution through a registration statement. To the extent a distributee is an affiliate of ours (or to the extent otherwise required by law), we may file a prospectus supplement in order to permit the distributees to use the prospectus to resell the securities acquired in the distribution.

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The Selling Securityholders may sell the securities at prices then prevailing, related to the then prevailing market price or at negotiated prices. The offering price of the securities from time to time will be determined by us and by the Selling Securityholders and, at the time of the determination, may be higher or lower than the market price of our securities on the New York Stock Exchange or any other exchange or market.

The Selling Securityholders may also sell our securities short and deliver these securities to close out their short positions, or loan or pledge the securities to broker-dealers that in turn may sell these securities. The shares may be sold directly or through broker-dealers acting as principal or agent, or pursuant to a distribution by one or more underwriters on a firm commitment or best-efforts basis. The Selling Securityholders may also enter into hedging transactions with broker-dealers. In connection with such transactions, broker-dealers of other financial institutions may engage in short sales of our securities in the course of hedging the positions they assume with us and with the Selling Securityholders. The Selling Securityholders may also enter into options or other transactions with broker-dealers or other financial institutions which require the delivery to such broker-dealer or other financial institution of securities offered by this prospectus, which securities such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction). The Selling Securityholders also may resell all or a portion of the securities in open market transactions in reliance upon Rule 144 under the Securities Act, provided that they meet the criteria and conform to the requirements of that rule. In connection with an underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the Selling Securityholders or from purchasers of the offered securities for whom they may act as agents. In addition, underwriters may sell the securities to or through dealers, and those dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The Selling Securityholders and any underwriters, dealers or agents participating in a distribution of the securities may be deemed to be “underwriters” within the meaning of the Securities Act, and any profit on the sale of the securities by the Selling Securityholders and any commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.

The Selling Securityholders may agree to indemnify an underwriter, broker-dealer or agent against certain liabilities related to the sale of the securities, including liabilities under the Securities Act. The Selling Securityholders have advised us that they have not entered into any agreements, understandings or arrangements with any underwriters or broker-dealers regarding the sale of their securities. Upon our notification by a selling securityholder that any material arrangement has been entered into with an underwriter or broker-dealer for the sale of securities through a block trade, special offering, exchange distribution, secondary distribution or a purchase by an underwriter or broker-dealer, we will file a supplement to this prospectus, if required, pursuant to Rule 424(b) under the Securities Act, disclosing certain material information, including:

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the name of the selling securityholder;

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the number of securities being offered;

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the terms of the offering;

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the names of the participating underwriters, broker-dealers or agents;

•

any discounts, commissions or other compensation paid to underwriters or broker-dealers and any discounts, commissions or concessions allowed or reallowed or paid by any underwriters to dealers;

•

the public offering price; and

•

other material terms of the offering.

In addition, upon being notified by a selling securityholder that a donee, pledgee, transferee or other successor-in-interest intends to sell securities, we will, to the extent required, promptly file a supplement to this prospectus to name specifically such person as a selling securityholder.

The Selling Securityholders are subject to the applicable provisions of the Exchange Act and the rules and regulations under the Exchange Act, including Regulation M. This regulation may limit the timing of purchases and sales of any of the securities offered in this prospectus by the Selling Securityholders. The anti-manipulation rules under the Exchange Act may apply to sales of securities in the market and to the

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activities of the Selling Securityholders and their affiliates. Furthermore, Regulation M may restrict the ability of any person engaged in the distribution of the securities to engage in market-making activities for the particular securities being distributed for a period of up to five business days before the distribution. The restrictions may affect the marketability of the securities and the ability of any person or entity to engage in market-making activities for the securities.

In compliance with guidelines of the Financial Industry Regulatory Authority (“FINRA”), the maximum compensation or discount to be received by any FINRA member or independent broker or dealer may not exceed 8% of the aggregate amount of securities offered pursuant to this prospectus.

To the extent required, this prospectus may be amended and/or supplemented from time to time to describe a specific plan of distribution. Instead of selling the securities under this prospectus, the Selling Securityholders may sell the securities in compliance with the provisions of Rule 144 under the Securities Act, if available, or pursuant to other available exemptions from the registration requirements of the Securities Act.

A holder of Granite Ridge warrants may exercise its Granite Ridge warrants in accordance with the Granite Ridge Warrant Agreement on or before the expiration date set forth therein by surrendering, at the office of the warrant agent, Continental Stock Transfer & Trust Company, the certificate evidencing such Granite Ridge warrants, with the form of election to purchase set forth thereon, properly completed and duly executed, accompanied by full payment of the exercise price and any and all applicable taxes due in connection with the exercise of the Granite Ridge warrants, subject to any applicable provisions relating to cashless exercises in accordance with the Granite Ridge Warrant Agreement.

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TRANSFER AGENT AND REGISTRAR

The Transfer Agent for our securities is Continental Stock Transfer & Trust Company.

LEGAL MATTERS

Certain legal matters relating to the validity of Granite Ridge’s securities covered by this registration statement will be passed upon for Granite Ridge by Holland & Knight LLP, Dallas, Texas.

EXPERTS

The audited financial statements of ENPC as of December 31, 2021 and 2020, and for the year ended December 31, 2021 and for the period from June 22, 2020 (inception) through December 31, 2020, and the related notes thereto included in this prospectus have been audited by WithumSmith+Brown, PC, an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere in this prospectus, and are included in reliance on such report given on the authority of such firm as an expert in accounting and auditing.

The audited consolidated financial statements of Grey Rock Energy Fund, L.P. and its subsidiaries (“Fund I”) as of December 31, 2021 and 2020, and for each of the years in the three year period ended December 31, 2021 and the related notes thereto included in this prospectus have been audited by BKD, LLP, an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere in this prospectus, and are included in reliance on such report given on the authority of such firm as an expert in accounting and auditing.

The audited combined financial statements of Grey Rock Energy Fund II, L.P. and its subsidiaries, Grey Rock Energy Fund II-B, L.P., Grey Rock Energy Fund II-B Holdings and its subsidiaries, and Grey Rock Preferred Limited Partner II, L.P. (collectively, “Fund II”) as of December 31, 2021 and 2020, and for the years then ended, and the related notes thereto included in this prospectus have been audited by BKD, LLP, an independent auditor, as set forth in their report thereon appearing elsewhere in this prospectus, and are included in reliance on such report given on the authority of such firm as an expert in accounting and auditing.

The audited combined financial statements of Grey Rock Energy Fund III-A, L.P. and its subsidiaries, Grey Rock Energy Fund III-B, L.P., Grey Rock Energy Fund III-B Holdings, L.P. and its subsidiaries, and Grey Rock Preferred Limited Partner III, L.P. (collectively, “Fund III”) as of December 31, 2021 and 2020, and for each of the years in the three year period ended December 31, 2021, and the related notes thereto included in this prospectus have been audited by FORVIS, LLP (formerly BKD, LLP), an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere in this prospectus, and are included in reliance on such report given on the authority of such firm as an expert in accounting and auditing.

The information included herein regarding estimated quantities of proved reserves of Fund I, Fund II and Fund III, the future net revenues from those reserves and their present value as of December 31, 2021, are based on the proved reserves report prepared by Netherland, Sewell & Associates, Inc. These estimates are included herein in reliance upon the authority of such firm as an expert in these matters.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

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INDEX TO FINANCIAL STATEMENTS

	Page
Condensed Financial Statements (Unaudited) of Executive Network Partnering Corporation
Unaudited Condensed Balance Sheets as of September 30, 2022 (Unaudited) and December 31, 2021		F-3
Unaudited Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2022 and 2021		F-4
Unaudited Condensed Statements of Changes in Stockholders’ Deficit for the Three and Nine Months Ended September 30, 2022 and 2021		F-5
Unaudited Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2022 and 2021		F-6
Notes to Unaudited Condensed Financial Statements		F-7
Audited Financial Statements of Executive Network Partnering Corporation
Report of Independent Registered Public Accounting Firm		F-24
Balance Sheets as of December 31, 2021 and 2020		F-25
Statement of Operations for the Year Ended December 31, 2021 and for the Period from June 22, 2020 (inception) through December 31, 2020		F-26
Statement of Changes in Stockholders’ Deficit for the Year Ended December 31, 2021 and for the Period from June 22, 2020 (inception) through December 31, 2020.		F-27
Statement of Cash Flows for the Year Ended December 31, 2021 and for the Period from June 22, 2020 (inception) through December 31, 2020		F-28
Notes to Financial Statements		F-29
Condensed Combined Financial Statements (Unaudited) of Grey Rock Energy Fund III-A, LP (Predecessor)
Condensed Combined Balance Sheets (Unaudited) as of December 31, 2021 and September 30, 2022		F-45
Condensed Combined Statements of Income (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-46
Condensed Combined Statements of Changes in Partners’ Capital (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-47
Condensed Combined Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-48
Notes to Condensed Combined Financial Statements		F-49
Audited Financial Statements of Grey Rock Energy Fund III-A, LP (Predecessor)
Report of Independent Registered Public Accounting Firm		F-62
Combined Balance Sheets as of December 31, 2021 and 2020		F-63
Combined Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019		F-64
Combined Statements of Changes in Partners’ Capital for the Years Ended December 31, 2021, 2020 and 2019		F-65
Combined Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019		F-66
Notes to Combined Financial Statements		F-67

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	Page
Condensed Consolidated Financial Statements (Unaudited) of Grey Rock Energy Fund, LP
Condensed Consolidated Balance Sheets (Unaudited) as of December 31, 2021 and September 30, 2022		F-85
Condensed Consolidated Statements of Income (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-86
Condensed Consolidated Statements of Changes in Partners’ Capital (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-87
Condensed Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-88
Notes to Condensed Consolidated Financial Statements		F-89
Audited Financial Statements of Grey Rock Energy Fund, LP
Report of Independent Registered Public Accounting Firm		F-100
Consolidated Balance Sheets as of December 31, 2021 and 2020		F-101
Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019		F-102
Consolidated Statements of Changes in Partners’ Capital for the Years Ended December 31, 2021, 2020 and 2019		F-103
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019		F-104
Notes to Consolidated Financial Statements		F-105
Condensed Combined Financial Statements (Unaudited) of Grey Rock Energy Fund II, LP
Condensed Combined Balance Sheets (Unaudited) as of December 31, 2021 and September 30, 2022		F-122
Condensed Combined Statements of Operations (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-123
Condensed Combined Statements of Changes in Partners’ Capital (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-124
Condensed Combined Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2021 and 2022		F-125
Notes to Condensed Combined Financial Statements		F-126
Audited Financial Statements of Grey Rock Energy Fund II, LP
Independent Auditor’s Report		F-138
Combined Balance Sheets as of December 31, 2021 and 2020		F-140
Combined Statements of Operations for the Years Ended December 31, 2021 and 2020		F-141
Combined Statements of Changes in Partners’ Capital for the Years Ended December 31, 2021 and 2020		F-142
Combined Statements of Cash Flows for the Years Ended December 31, 2021 and 2020		F-143
Notes to Combined Financial Statements		F-144

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EXECUTIVE NETWORK PARTNERING CORPORATION

CONDENSED BALANCE SHEETS

	September 30, 2022			December 31, 2021
	(Unaudited)
Assets:
Current assets:
Cash		$	103,949		$	93,862
Prepaid expenses			—			206,980
Total current assets			103,949			300,842
Investments held in Trust Account			416,329,383			414,052,978
Total Assets		$	416,433,332		$	414,353,820
Liabilities, Class A Common Stock Subject to Possible Redemption and Stockholders’ Deficit:
Current liabilities:
Accounts payable		$	126,086		$	68,735
Accounts payable – related party			160,000			—
Accrued expenses			8,551,883			953,135
Franchise tax payable			68,389			174,603
Income tax payable			407,567			—
Convertible note – related party			1,548,481			—
Total current liabilities			10,862,406			1,196,473
Convertible note – related party, long term			—			430,000
Derivative warrant liabilities			9,771,325			7,135,560
Total Liabilities			20,633,731			8,762,033
Commitments and Contingencies
Class A common stock subject to possible redemption; $0.0001 par value; 41,400,000 shares issued and outstanding at $10.03 and $10.00 per share redemption value as of September 30, 2022 and December 31, 2021, respectively			415,433,227			414,000,000
Stockholders’ Deficit:
Preferred stock, $0.0001 par value; 1,000,000 shares authorized; none issued or outstanding as of September 30, 2022 and December 31, 2021			—			—
Class A common stock, $0.0001 par value; 380,000,000 shares authorized; 614,000 shares issued and outstanding as of September 30, 2022 and December 31, 2021, net of shares subject to possible redemption			61			61
Class B common stock, $0.0001 par value; 1,000,000 shares authorized; 300,000 shares issued and outstanding as of September 30, 2022 and December 31, 2021			30			30
Class F common stock, $0.0001 par value; 50,000,000 shares authorized; 828,000 shares issued and outstanding as of September 30, 2022 and December 31, 2021			83			83
Accumulated deficit			(19,633,800)			(8,408,387)
Total stockholders’ deficit			(19,633,626)			(8,408,213)
Total Liabilities, Class A Common Stock Subject to Possible Redemption and Stockholders’ Deficit		$	416,433,332		$	414,353,820

The accompanying notes are an integral part of these unaudited condensed financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

UNAUDITED CONDENSED STATEMENTS OF OPERATIONS

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2022			2021			2022			2021
Operating expenses
General and administrative expenses		$	204,115		$	308,210		$	8,719,899		$	849,209
Administrative fee – related party			60,000			60,000			180,000			180,000
Franchise tax expense			50,411			50,411			125,360			149,589
Loss from operations			(314,526)			(418,621)			(9,025,259)			(1,178,798)
Change in fair value of derivative warrant liabilities			(211,605)			1,482,770			(2,635,765)			2,421,945
Income from investments held in Trust Account			1,775,512			1,134			2,276,405			30,970
Income (loss) before income tax expense			1,249,381			1,065,283			(9,384,619)			1,274,117
Income tax expense			362,272			—			407,567			—
Net income (loss)		$	887,109		$	1,065,283		$	(9,792,186)		$	1,274,117
Weighted average shares outstanding of Class A common stock, basic and diluted			42,014,000			42,014,000			42,014,000			42,014,000
Basic and diluted net income (loss) per share of Class A common stock		$	0.02		$	0.02		$	(0.23)		$	0.03
Weighted average shares outstanding of Class B common stock, basic and diluted			300,000			300,000			300,000			300,000
Basic and diluted net income (loss) per share of Class B common stock		$	0.02		$	0.02		$	(0.23)		$	0.03
Weighted average shares outstanding of Class F common stock, basic and diluted			828,000			828,000			828,000			828,000
Basic and diluted net income (loss) per share of Class F common stock		$	0.02		$	0.02		$	(0.23)		$	0.03

The accompanying notes are an integral part of these unaudited condensed financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

UNAUDITED CONDENSED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT
For the Three and Nine Months Ended September 30, 2022

	Common Stock															Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Deficit
	Class A					Class B					Class F
	Shares		Amount			Shares		Amount			Shares		Amount
Balance – December 31, 2021		614,000		$	61		300,000		$	30		828,000		$	83		$	—		$	(8,408,387)		$	(8,408,213)
Net income		—			—		—			—		—			—			—			3,322,933			3,322,933
Balance – March 31, 2022 (unaudited)		614,000			61		300,000			30		828,000			83			—			(5,085,454)			(5,085,280)
Increase in redemption value of Class A common stock subject to possible redemption		—			—		—			—		—			—			—			(70,397)			(70,397)
Net loss		—			—		—			—		—			—			—			(14,002,228)			(14,002,228)
Balance – June 30, 2022 (unaudited)		614,000			61		300,000			30		828,000			83			—			(19,158,079)			(19,157,905)
Increase in redemption value of Class A common stock subject to possible redemption		—			—		—			—		—			—			—			(1,362,830)			(1,362,830)
Net income		—			—		—			—		—			—			—			887,109			887,109
Balance – September 30, 2022 (unaudited)		614,000		$	61		300,000		$	30		828,000		$	83		$	—		$	(19,633,800)		$	(19,633,626)

For the Three and Nine Months Ended September 30, 2021

	Common Stock															Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Deficit
	Class A					Class B					Class F
	Shares		Amount			Shares		Amount			Shares		Amount
Balance – December 31, 2020		614,000		$	61		300,000		$	30		828,000		$	83		$	—		$	(9,880,718)		$	(9,880,544)
Net income		—			—		—			—		—			—			—			1,621,543			1,621,543
Balance – March 31, 2021 (unaudited)		614,000			61		300,000			30		828,000			83			—			(8,259,175)			(8,259,001)
Net loss		—			—		—			—		—			—			—			(1,422,012)			(1,422,012)
Balance – June 30, 2021 (unaudited)		614,000			61		300,000			30		828,000			83			—			(9,681,187)			(9,681,013)
Net income		—			—		—			—		—			—			—			1,074,586			1,074,586
Balance – September 30, 2021 (unaudited)		614,000		$	61		300,000		$	30		828,000		$	83		$	—		$	(8,606,601)		$	(8,606,427)

The accompanying notes are an integral part of these unaudited condensed financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS

	For the Nine Months Ended September 30,
	2022			2021
Cash Flows from Operating Activities:
Net income (loss)		$	(9,792,186)		$	1,274,117
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Change in fair value of derivative warrant liabilities			2,635,765			(2,421,945)
Interest income from investments held in Trust Account			(2,276,405)			(30,970)
Changes in assets and liabilities:
Prepaid expenses			206,980			150,417
Accounts payable			57,351			157,199
Accounts payable – related party			160,000			—
Accrued expenses			7,598,748			(94,681)
Franchise tax payable			(106,214)			86,359
Income tax payable			407,567			—
Net cash used in operating activities			(1,108,394)			(879,504)
Cash Flows from Financing Activities:
Proceeds from convertible note – related party			1,118,481			180,000
Net cash provided by financing activities			1,118,481			180,000
Net change in cash			10,087			(699,504)
Cash – beginning of the period			93,862			888,097
Cash – end of the period		$	103,949		$	188,593

The accompanying notes are an integral part of these unaudited condensed financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
SEPTEMBER 30, 2022

Note 1 — Description of Organization, Business Operations and Going Concern

Organization and General

Executive Network Partnering Corporation (the “Company”) is a blank check company incorporated in Delaware on June 22, 2020. The Company was formed for the purpose of identifying a company to partner with, in order to effectuate a merger, share exchange, asset acquisition, share purchase, reorganization or similar partnering transaction with one or more businesses (“Partnering Transaction”). The Company may pursue a Partnering Transaction in any business or industry but expect to focus on a business where the Company believes its strong network, operational background, and aligned economic structure will provide the Company with a competitive advantage. The Company is an emerging growth company and, as such, the Company is subject to all of the risks associated with emerging growth companies. The Company’s sponsor is ENPC Holdings, LLC, a Delaware limited liability company (the “Sponsor”).

As of September 30, 2022, the Company had not commenced any operations. All activity for the period from June 22, 2020 (inception) through September 30, 2022 relates to the Company’s formation and the initial public offering (“Initial Public Offering”) and since the closing of the Initial Public Offering, the search for a prospective initial Partnering Transaction. The Company will not generate any operating revenues until after the completion of its initial Partnering Transaction, at the earliest. The Company generates non-operating income in the form of interest income on investments held in trust account from the proceeds derived from the Initial Public Offering.

Financing

The registration statement for the Company’s Initial Public Offering was declared effective on September 15, 2020. On September 18, 2020, the Company consummated its Initial Public Offering of 41,400,000 of its securities called CAPS™ (“CAPS™”) (with respect to the Class A common stock included in the CAPS™ being offered, the “Public Shares”), which included 5,400,000 CAPS™ issued as a result of the underwriters’ exercise in full of their over-allotment option, at $10.00 per CAPS™, generating gross proceeds of $414.0 million, and incurring offering costs of approximately $4.8 million.

Concurrently with the closing of the Initial Public Offering, the Company completed the private sale of 614,000 private placement CAPS™ (“Private Placement CAPS™”), at a price of $10.00 per Private Placement CAPS™ to the Sponsor, generating gross proceeds to the Company of approximately $6.1 million (Note 4). The CAPS™ have been retroactively restated to reflect the March 24, 2021, 2.5:1 forward stock split for each share of Class A common stock and warrant.

Trust Account

Upon the closing of the Initial Public Offering and the sale of Private Placement CAPS™, $414.0 million ($10.00 per CAPS™) of the net proceeds of the sale of the CAPS™ in the Initial Public Offering and the Private Placement were placed in a trust account (“Trust Account”) located in the United States with Continental Stock Transfer & Trust Company acting as trustee, and held as cash or invested only in U.S. “government securities,” within the meaning set forth in Section 2(a)(16) of the Investment Company Act of 1940 (the “Investment Company Act”), with a maturity of 185 days or less, or in money market funds meeting the conditions of paragraphs (d)(2), (d)(3) and (d)(4) of Rule 2a-7 under the Investment Company Act, which invest only in direct U.S. government treasury obligations, as determined by the Company, until the earlier of: (i) the completion of a Partnering Transaction and (ii) the distribution of the Trust Account as described below.

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initial Partnering Transaction. However, the Company will only complete a Partnering Transaction if the post- transaction company owns or acquires 50% or more of the voting securities of the partner candidate or otherwise acquires a controlling interest in the partner candidate sufficient for it not to be required to register as an investment company under the Investment Company Act. The Company’s certificate of incorporation provides that, other than the withdrawal of interest earned on the funds that may be released to the Company to pay taxes, none of the funds held in Trust Account will be released until the earlier of: (i) the completion of the Partnering Transaction; (ii) the redemption of any of the common stock included in the CAPS™ being sold in the Initial Public Offering to its holders (the “Public Stockholders”) properly tendered in connection with a stockholder vote to amend certain provisions of the Company’s certificate of incorporation prior to a Partnering Transaction or (iii) the redemption of 100% of the Public Shares if the Company does not complete a Partnering Transaction within the Partnering Period (defined below).

The Company, after signing a definitive agreement for a Partnering Transaction, will either (i) seek stockholder approval of the Partnering Transaction at a meeting called for such purpose in connection with which Public Stockholders may seek to redeem their Public shares, regardless of whether they vote for or against the Partnering Transaction or do not vote at all, for cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account calculated as of two business days prior to the consummation of the initial Partnering Transaction, including interest earned on the funds held in the Trust Account and not previously released to the Company to pay its taxes, or (ii) provide the Public Stockholders with the opportunity to sell their shares to the Company by means of a tender offer (and thereby avoid the need for a stockholder vote) for an amount in cash equal to their pro rata share of the aggregate amount then on deposit in the Trust Account calculated as of two business days prior to commencement of the tender offer, including interest earned on the funds held in the Trust Account and not previously released to the Company to pay its taxes. As a result, such common stock will be recorded at redemption amount and classified as temporary equity upon the completion of the Initial Public Offering, in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 480, “Distinguishing Liabilities from Equity.” The amount in the Trust Account is initially anticipated to be $10.00 per Public Share. The decision as to whether the Company will seek stockholder approval of the Partnering Transaction or will allow stockholders to sell their shares in a tender offer will be made by the Company, solely in its discretion, and will be based on a variety of factors such as the timing of the transaction and whether the terms of the transaction would otherwise require the Company to seek stockholder approval. If the Company seeks stockholder approval, it will complete its Partnering Transaction only if a majority of the voting power of the outstanding shares of common stock voted are voted in favor of the Partnering Transaction. However, in no event will the Company redeem its Public Shares in an amount that would cause its net tangible assets to be less than $5,000,001 immediately prior to or upon consummation of the Company’s initial Partnering Transaction. In such case, the Company would not proceed with the redemption of its Public Shares and the related Partnering Transaction, and instead may search for an alternate Partnering Transaction.

The Company will only have 24 months from the closing of the Initial Public Offering, or September 18, 2022 (or 27 months, or December 18, 2022, if the Company has executed a letter of intent, agreement in principle or definitive agreement for the Partnering Transaction within 24 months) to complete its initial Partnering Transaction (the “Partnering Period”). If the Company does not complete a Partnering Transaction within this period of time (and stockholders do not approve an amendment to the certificate of incorporation to extend this date), it will (i) cease all operations except for the purpose of winding up, (ii) as promptly as reasonably possible but not more than ten business days thereafter, redeem the Public Shares, at a per-share price, payable in cash, equal to their pro rata share of the aggregate amount then on deposit in the Trust Account including interest earned on the funds held in the Trust Account and not previously released to the Company to pay its taxes (less up to $100,000 of such net interest to pay dissolution expenses), and (iii) as promptly as reasonably possible following such redemption, subject to the approval of the remaining stockholders and the board of directors, liquidate and dissolve, subject in the case of clauses (ii) and (iii), to the Company’s obligations under Delaware law to provide for claims of creditors and in all cases subject to the other requirements of applicable law.

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Shares they hold in connection with the completion of the Partnering Transaction, (ii) waive their redemption rights with respect to any Founder Shares and Public Shares they hold in connection with a stockholder vote to approve an amendment to the Company’s amended and restated certificate of incorporation to modify the substance or timing of the Company’s obligation to redeem 100% of its Public Shares if the Company has not consummated a Partnering Transaction within the Partnering Period or with respect to any other material provisions relating to stockholders’ rights or pre-Partnering Transaction activity and (iii) waive their rights to liquidating distributions from the Trust Account with respect to any Founder Shares they hold if the Company fails to complete the Partnering Transaction within 24 the Partnering Period (although they will be entitled to liquidating distributions from the Trust Account with respect to any Public Shares they hold if the Company fails to complete the Partnering Transaction within the Partnering Period).

Pursuant to the letter agreement, the Sponsor has agreed that it will be liable to the Company if and to the extent any claims by a third party for services rendered or products sold to the Company, or a prospective target business with which the Company has entered into a written letter of intent, confidentiality or other similar agreement or Partnering Transaction agreement, reduce the amount of funds in the Trust Account to below the lesser of $10.00 per Public Share and (ii) the actual amount per Public Share held in the Trust Account as of the date of the liquidation of the Trust Account, if less than $10.00 per public share due to reductions in the value of the Trust assets, less taxes payable, provided that such liability will not apply to any claims by a third party or prospective target business who executed a waiver of any and all rights to the monies held in the Trust Account (whether or not such waiver is enforceable) nor will it apply to any claims under the Company’s indemnity of the underwriter of the initial public offering against certain liabilities, including liabilities under the Securities Act of 1933, as amended (the “Securities Act”).

Proposed Partnering Transaction

On May 16, 2022, the Company, Granite Ridge Resources, Inc., a Delaware corporation, ENPC Merger Sub, Inc., a Delaware corporation, GREP Merger Sub, LLC, a Delaware limited liability company, and GREP Holdings, LLC, a Delaware limited liability company (“GREP”), entered into a business combination agreement (as it may be amended, supplemented or otherwise modified from time to time, the “Business Combination Agreement”) pursuant to which the Company and GREP shall enter into a business combination. For additional information regarding the Business Combination Agreement, see the Company’s Current Report on Form 8-K filed with the SEC on May 17, 2022.

Going Concern Considerations

As of September 30, 2022, the Company had approximately $104,000 in its operating bank account, working capital deficit of approximately $10.7 million. Interest income on the balance in the Trust Account may be used to pay the Company’s franchise and income tax obligations. Management intends to use substantially all of the funds held in the Trust Account to complete the initial Partnering Transaction and to pay the Company’s expenses relating thereto. To the extent that the Company’s capital stock or debt is used, in whole or in part, as consideration to complete the initial Partnering Transaction, the remaining proceeds held in the Trust Account will be used as working capital to finance the operations of the target business or businesses, make other acquisitions and pursue growth strategies.

The Company’s liquidity needs up to the closing of the Initial Public Offering and the sale of Private Placement CAPS™had been satisfied through a capital contribution of $25,000 from the Sponsor to purchase Class F and Class B common stock, the loan under the Note (as defined in Note 4) of approximately $171,000 to the Company to cover for offering costs in connection with the Initial Public Offering, and the net proceeds from the consummation of the Private Placement not held in the Trust Account. The Company fully repaid the Note on September 22, 2020. In addition, in order to finance transaction costs in connection with a Partnering Transaction, the Company’s officers, directors and initial stockholders may, but are not obligated to, provide the Company Working Capital Loans (see Note 4). As of September 30, 2022 and December 31, 2021, there were approximately $1.5 million and $430,000 outstanding under the Working Capital Loans, respectively.

In connection with the Company’s assessment of going concern considerations in accordance with FASB Accounting Standards Update (“ASU”) 2014-15, “Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” the Company has until September 18, 2022 (or 27 months, or

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December 18, 2022, if the Company has executed a letter of intent, agreement in principle or definitive agreement for the Partnering Transaction within 24 months) to consummate a Partnering Transaction. It is uncertain that the Company will be able to consummate a Partnering Transaction by this time. If a Partnering Transaction is not consummated by this date, there will be a mandatory liquidation and subsequent dissolution of the Company. Management has determined that the liquidity condition and mandatory liquidation, should a Partnering Transaction not occur, and potential subsequent dissolution raises substantial doubt about the Company’s ability to continue as a going concern. Management intends to complete the Partnering Transaction prior to the liquidation date. No adjustments have been made to the carrying amounts of assets or liabilities should the Company be required to liquidate after September 18, 2022 (or 27 months, or December 18, 2022, if the Company has executed a letter of intent, agreement in principle or definitive agreement for the Partnering Transaction within 24 months).

Note 2 — Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 8 of Regulation S-X and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”). Accordingly, certain disclosures included in the annual financial statements have been condensed or omitted from these financial statements as they are not required for interim financial statements under U.S. GAAP and the rules of the SEC. In the opinion of management, all adjustments (consisting of normal accruals) considered for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2022 are not necessarily indicative of the results that may be expected for the period ending December 31, 2022, or for any future interim periods.

The accompanying unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Annual Report on Form 10-K filed by the Company with the SEC on March 30, 2022.

Emerging Growth Company

The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the independent registered public accounting firm attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in its periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.

Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that an emerging growth company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such an election to opt out is irrevocable. The Company has elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, the Company, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of the Company’s unaudited condensed financial statements with another public company that is neither an emerging growth company nor an emerging growth company that has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

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Use of Estimates

The preparation of unaudited condensed financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the unaudited condensed financial statements and the reported amounts of expenses during the reporting periods. Making estimates requires management to exercise significant judgment. It is at least reasonably possible that the estimate of the effect of a condition, situation or set of circumstances that existed at the date of the unaudited condensed financial statements, which management considered in formulating its estimate, could change in the near term due to one or more future confirming events. One of the more significant accounting estimates included in these financial statements is the determination of the fair value of the warrant liability. Accordingly, the actual results could differ significantly from those estimates.

Cash and Cash Equivalents

The Company considers all short-term investments with an original maturity of three months or less when purchased to be cash equivalents. The Company had no cash equivalents as of September 30, 2022 and December 31, 2021.

Investments Held in Trust Account

The Company’s portfolio of investments held in the Trust Account is comprised of U.S. government securities, within the meaning set forth in Section 2(a)(16) of the Investment Company Act, with a maturity of 185 days or less, or investments in money market funds that invest in U.S. government securities and generally have a readily determinable fair value, or a combination thereof. When the Company’s investments held in the Trust Account are comprised of U.S. government securities, the investments are classified as trading securities. When the Company’s investments held in the Trust Account are comprised of money market funds, the investments are recognized at fair value. Trading securities and investments in money market funds are presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in net gain from investments held in Trust Account in the accompanying unaudited condensed statements of operations. The estimated fair values of investments held in the Trust Account are determined using available market information.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash accounts in a financial institution, which, at times, may exceed the Federal Deposit Insurance Corporation coverage of $250,000, and cash equivalents held in Trust Account. As of September 30, 2022 and December 31, 2021, the Company has not experienced losses on these accounts and management believes the Company is not exposed to significant risks on such accounts.

Fair Value of Financial Instruments

The fair value of the Company’s assets and liabilities which qualify as financial instruments under the FASB ASC Topic 820, “Fair Value Measurements,” approximates the carrying amounts represented in the condensed balance sheets, except for the derivative assets and liabilities.

Fair Value Measurement

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). These tiers consist of:

•

Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets;

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•

Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable such as quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active; and

•

Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions, such as valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.

In some circumstances, the inputs used to measure fair value might be categorized within different levels of the fair value hierarchy. In those instances, the fair value measurement is categorized in its entirety in the fair value hierarchy based on the lowest level input that is significant to the fair value measurement.

Offering Costs Associated with the Initial Public Offering

Offering costs consisted of legal, accounting, underwriting fees and other costs incurred through the Initial Public Offering that were directly related to the Initial Public Offering. Offering costs were allocated to the separable financial instruments issued in the Initial Public Offering based on a relative fair value basis, compared to total proceeds received. Offering costs associated with derivative warrant liabilities were expensed as incurred and presented as non-operating expenses in the statements of operations. Offering costs associated with the Class A common stock issued were charged against the carrying value of Class A common stock subject to possible redemption upon the completion of the Initial Public Offering.

Class A Common Stock Subject to Possible Redemption

The Company accounts for its Class A common stock subject to possible redemption in accordance with the guidance in ASC Topic 480, “Distinguishing Liabilities from Equity.” Class A common stock subject to mandatory redemption (if any) is classified as a liability instrument and measured at fair value. Conditionally redeemable Class A common stock (including Class A common stock that features redemption rights that are either within the control of the holder or subject to redemption upon the occurrence of uncertain events not solely within the Company’s control) is classified as temporary equity. At all other times, Class A common stock is classified as stockholders’ equity. As part of the Private Placement CAPS™, the Company issued 614,000 shares of Class A common stock to the Sponsor (“Private Placement Shares”). These Private Placement Shares will not be transferable, assignable or salable until 30 days after the completion of the initial Partnering Transaction, as such are considered non-redeemable and presented as permanent equity in the Company’s condensed balance sheets. The Company’s Class A common stock features certain redemption rights that are considered to be outside of the Company’s control and subject to the occurrence of uncertain future events. Accordingly, as of September 30, 2022 and December 31, 2021, 41,400,000 shares of Class A common stock subject to possible redemption is presented as temporary equity, outside of the stockholders’ deficit section of the Company’s condensed balance sheets.

Under ASC 480, the Company has elected to recognize changes in the redemption value immediately as they occur and adjust the carrying value of the security to equal the redemption value at the end of each reporting period. This method would view the end of the reporting period as if it were also the redemption date for the security. Immediately upon the closing of the Initial Public Offering, the Company recognized the accretion from initial book value to redemption amount value. The change in the carrying value of the redeemable Class A common stock resulted in charges against additional paid-in capital (to the extent available) and accumulated deficit.

Derivative Warrant Liabilities

The Company does not use derivative instruments to hedge its exposures to cash flow, market or foreign currency risks. The Company evaluates all of the Company’s financial instruments, including issued warrants to purchase its Class A common stock, to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to ASC 480 and ASC 815-15. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period.

The Company issued 10,350,000 warrants to purchase Class A common stock to investors in the Company’s Initial Public Offering, including the over-allotment, and simultaneously issued 153,500 Private

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Placement Warrants. All of the Company’s outstanding warrants are recognized as derivative liabilities in accordance with ASC 815-40. Accordingly, the Company recognizes the warrant instruments as liabilities at fair value and adjusts the instruments to fair value at the end of each reporting period. The liabilities are subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in the condensed statements of operations. The fair value of the warrants issued in connection with the Initial Public Offering was initially measured using a Monte-Carlo simulation model and subsequently been measured based on the listed market price of such warrants at each measurement date when separately listed and traded. The fair value of the warrants issued in connection with the Private Placement have been estimated using a Black-Scholes Option Pricing model at each measurement date. The determination of the fair value of the warrant liability may be subject to change as more current information becomes available and, accordingly, the actual results could differ significantly. Derivative warrant liabilities are classified as non-current liabilities, as their liquidation is not reasonably expected to require the use of current assets or require the creation of current liabilities.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized. The effective tax rate was 28.11% and 0.00% for the three months ended September 30, 2022 and 2021, and (4.22)% and 0.00% for the nine months ended September 30, 2022 and 2021, respectively. The effective tax rate differs from the statutory tax rate of 21% for the three and nine months ended September 30, 2022 and 2021, due to changes in fair value in warrant liabilities and the valuation allowance on the deferred tax assets. There were no unrecognized tax positions and no amounts accrued for interest and penalties as of September 30, 2022 and December 31, 2021.

ASC Topic 740, “Income Taxes” prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than- not to be sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense. The Company is currently note aware of any issues under review that could result in significant payments, accruals or material deviation from its position.

Net Income (Loss) per Share of Common Stock

The Company complies with accounting and disclosure requirements of FASB ASC Topic 260, “Earnings Per Share.” The Company has three classes of shares, which are referred to as Class A common stock, Class B common stock and Class F common stock. Income and losses are shared pro rata between the three classes of shares. This presentation assumes a business combination as the most likely outcome. Net income (loss) per share of common stock is calculated by dividing the net income (loss) by the weighted average number of common stock outstanding for the respective period.

The calculation of diluted net (loss) income per share of common stock does not consider the effect of the warrants underlying the Units sold in the Initial Public Offering and the Private Placement Warrants to purchase 10,503,500 shares of Class A common stock in the calculation of diluted income (loss) per share, because their inclusion would be anti-dilutive under the treasury stock method. As a result, diluted net (loss) income per share of common stock is the same as basic net income (loss) per share of common stock for the three and nine months ended September 30, 2022 and 2021. Accretion associated with the redeemable Class A common stock is excluded from earnings per share as the redemption value approximates fair value.

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The tables below present a reconciliation of the numerator and denominator used to compute basic and diluted net income (loss) per share of common stock for each class of common stock:

	For the Three Months Ended September 30, 2022									For the Three Months Ended September 30, 2021
	Class A			Class B			Class F			Class A			Class B			Class F
Basic net income per common stock:
Numerator:
Allocation of net income		$	874,750		$	6,246		$	17,239		$	1,037,430		$	7,408		$	20,445
Denominator:
Weighted average common stock outstanding, basic and diluted			42,014,000			300,000			828,000			42,014,000			300,000			828,000
Basic and diluted net income per share of common stock		$	0.02		$	0.02		$	0.02		$	0.02		$	0.02		$	0.02

	For the Nine Months Ended September 30, 2022									For the Nine Months Ended September 30, 2021
	Class A			Class B			Class F			Class A			Class B			Class F
Basic net (loss) income per common stock:
Numerator:
Allocation of net (loss) income		$	(9,525,322)		$	(68,016)		$	(187,722)		$	1,240,804		$	8,860		$	24,453
Denominator:
Weighted average common stock outstanding, basic and diluted			42,014,000			300,000			828,000			42,014,000			300,000			828,000
Basic and diluted net (loss) income per share of common stock		$	(0.23)		$	(0.23)		$	(0.23)		$	0.03		$	0.03		$	0.03

Recent Accounting Pronouncements

In June 2022, the FASB issued ASU 2022-03, ASC Subtopic 820, “Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions”. The ASU amends ASC 820 to clarify that a contractual sales restriction is not considered in measuring an equity security at fair value and to introduce new disclosure requirements for equity securities subject to contractual sale restrictions that are measured at fair value. The ASU applies to both holders and issuers of equity and equity-linked securities measured at fair value. The amendments in this ASU are effective for the Company in fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. Early adoption is permitted for both interim and annual financial statements that have not yet been issued or made available for issuance. The Company is still evaluating the impact of this pronouncement on the condensed financial statements.

The Company’s management does not believe that any other recently issued, but not yet effective, accounting standards updates, if currently adopted, would have a material effect on the accompanying unaudited condensed financial statements.

Note 3 — Initial Public Offering

Public CAPS™

On September 18, 2020, the Company consummated its Initial Public Offering of 41,400,000 CAPS™, which included 5,400,000 CAPS™ issued as a result of the underwriters’ exercise in full of their over-allotment option, at $10.00 per CAPS™, generating gross proceeds of $414.0 million, and incurring offering costs of approximately $4.8 million.

Each CAPS™ consists of one share of Class A common stock and one-quarter of one redeemable warrant (each, a “Public Warrant”). Each whole Public Warrant may be exercised to purchase one share of Class A common stock for $11.50 per share, subject to adjustment (see Note 8).

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Underwriting Agreement

The Company granted the underwriters a 45-day option to purchase up to 5,400,000 additional CAPS™ to cover any over-allotment, at the Initial Public Offering price less the underwriting discounts and commissions. The underwriters exercised the over-allotment option in full on September 18, 2020.

The underwriters were entitled to an underwriting discount of $0.01 per CAPS™, or approximately $4.1 million in the aggregate, paid upon the closing of the Initial Public Offering.

Note 4 — Related Party Transactions

Founder Shares and Performance Shares

On June 22, 2020, the Sponsor paid for certain offering costs on behalf of the Company in exchange for (i) 737,789 Class F common stock (the “Founder Shares”) in exchange for a capital contribution of $6,250, or approximately $0.008 per share and (ii) 1,200 shares of Class B common stock (the “Performance Shares”) for a capital contribution of $18,750, or $15.625 per share. On July 17, 2020 and March 24, 2021, the Company effected a 100:1 and a 2.5:1 forward stock split for each share of Class B common stock, respectively, resulting in an aggregate of 300,000 Performance Shares outstanding. On July 29, 2020, the Company effected a reverse stock split for Class F common stock, resulting in an aggregate of 690,000 shares of Class F common stock outstanding. On September 17, 2020, the Company effected a 1 for 1.2 forward stock split that increased the outstanding Class F common stock from 690,000 shares to 828,000 shares. All shares and associated amounts have been retroactively restated to reflect the stock splits. Of the 828,000 Founder Shares outstanding, up to 108,000 of the Founder Shares would be forfeited depending on the extent to which the underwriter’s over-allotment is exercised, so that such Founder Shares would represent 5% of the outstanding shares issued in the Initial Public Offering. The underwriters fully exercised their over-allotment option on September 18, 2020; thus, these 108,000 Founder Shares were no longer subject to forfeiture. The Founder Shares are entitled to (together with the Performance Shares) a number of votes representing 20% of the Company’s outstanding common stock (not including the private placement shares) prior to the completion of the Partnering Transaction.

The Initial Stockholders agreed not to transfer, assign or sell any of their Founder Shares until the earlier to occur of (i) 180 days after the completion of the Partnering Transaction and (ii) the date on which the Company completes a liquidation, merger, capital stock exchange or other similar transaction after the Partnering Transaction that results in all of the stockholders having the right to exchange their Class A common stock for cash, securities or other property; except to certain permitted transferees.

Private Placement CAPS™

Substantially concurrently with the closing of the Initial Public Offering, the Company completed the private sale of 614,000 Private Placement CAPS™, at a price of $10.00 per Private Placement CAPS™ to the Sponsor, generating gross proceeds to the Company of approximately $6.1 million.

Each Private Placement CAPS™ consists of one share of Class A common stock and one-quarter of one redeemable warrant (each, a “Private Placement Warrant”). Each Private Placement Warrant entitles the holder to purchase one share of Class A common stock at $11.50 per share. A portion of the proceeds from the sale of the Private Placement CAPS™ was added to the proceeds from the Initial Public Offering held in the Trust Account. If the Company does not complete a Partnering Transaction, then the proceeds will be part of the liquidating distribution to the Public Stockholders and the warrants will expire worthless.

Related Party Loans

On June 22, 2020, the Sponsor agreed to loan the Company up to an aggregate of $300,000 pursuant to an unsecured promissory note (the “Note”) to cover expenses related to this Initial Public Offering. This loan was payable without interest upon the completion of the Initial Public Offering. The Company borrowed approximately $171,000 under the Note. The Company fully repaid the Note on September 22, 2020. Subsequent to the repayment, the facility was no longer available to the Company.

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In order to finance transaction costs in connection with a Partnering Transaction, the Sponsor or an affiliate of the Sponsor or certain of the Company’s officers and directors may, but are not obligated to, loan the Company funds as may be required (each a “Working Capital Loan”). Up to $1.5 million of such Working Capital Loans may be convertible into Private Placement CAPS™ (“Working Capital CAPS™”) at a price of $10.00 per Working Capital CAPS™ at the option of the lender. The Working Capital CAPS™ would be identical to the Private Placement CAPS™ issued to the Sponsor.

The Company has elected the fair value option to account for its Working Capital Loan. As a result of applying the fair value option, the Company records each draw at fair value with a gain or loss recognized at issuance, and subsequent changes in fair value are recorded as change in the fair value of Working Capital Loan on the condensed statements of operations. On September 23, 2021, the Company issued a Working Capital Loan to ENPC Holdings, LLC (“Sponsor”), pursuant to which the Company borrowed $180,000 for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. On October 27, 2021, the Company issued a Working Capital Loan to the Sponsor, pursuant to which the Company borrowed $180,000 for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. On February 18, 2022, the Company issued a Working Capital Loan to the Sponsor, pursuant to which the Company borrowed $340,000 for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. On May 17, 2022, the Company issued a Working Capital Loan to the Sponsor, pursuant to which the Company borrowed approximately $158,000 for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. On May 27, 2022, the Company issued a Working Capital Loan to the Sponsor, pursuant to which the Company borrowed $620,000 for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. The Working Capital Loan does not bear any interest. All unpaid principal under the Working Capital Loan will be due and payable in full on the earlier of (i) January 11, 2023 and (ii) the effective date of the Partnering Transaction (such earlier date, the “Maturity Date”). The Sponsor will have the option, at the time of consummation of a Partnering Transaction, to convert any amounts outstanding under the Working Capital Loan into Working Capital CAPS™.

During the three and nine months ended September 30, 2022, the Company borrowed approximately $0 and $1.1 million, respectively, pursuant to the Working Capital Loans for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. As of September 30, 2022 and December 31, 2021, the Company had approximately $1.5 million and $430,000 outstanding under the Working Capital Loan, respectively.

Administrative Services Agreement

Commencing on the date that the Company’s securities are first listed on the New York Stock Exchange through the earlier of consummation of the Partnering Transaction and the Company’s liquidation, the Company will pay an affiliate of the Sponsor for office space, secretarial and administrative services provided to members of the Company’s management team $20,000 per month. The Company incurred $60,000 in expenses in connection with such services during the three months ended September 30, 2022 and 2021, and $180,000 in expenses during the nine months ended September 30, 2022 and 2021, as reflected in the accompanying unaudited condensed statements of operations. As of September 30, 2022 and December 31, 2021, there were $160,000 and $0 outstanding in accounts payable-related party, respectively.

In addition, the Sponsor, executive officers and directors, or any of their respective affiliates will be reimbursed for any out-of-pocket expenses incurred in connection with activities on the Company’s behalf such as identifying potential target businesses and performing due diligence on suitable Partnering Transactions. The Company’s audit committee will review on a quarterly basis all payments that were made to the Sponsor, executive officers or directors, or their affiliates.

Note 5 — Commitments and Contingencies

Registration Rights

The holders of the Founder Shares, Performance Shares, private placement warrants and private placement shares underlying the Private Placement CAPS™ and the Private Placement CAPS™ that may

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be issued upon conversion of Working Capital Loans (and any shares of Class A common stock into which such securities may convert and that may be issued upon exercise of private placement warrants) are entitled to registration rights pursuant to a registration rights agreement, requiring the Company to register such securities for resale. The holders of these securities are entitled to make up to three demands, excluding short form demands, that the Company registers such securities. In addition, the holders have certain “piggy-back” registration rights with respect to registration statements filed subsequent to the completion of the Partnering Transaction. The Company will bear the expenses incurred in connection with the filing of any such registration statements.

Partnering Transaction Advisory Engagement Letter

In September 2020, the Company engaged Evercore Group L.L.C. as a capital markets advisor in connection with the Partnering Transaction to assist the Company with the potential Partnering Transaction. The Company agreed to pay Evercore Group L.L.C. for such services upon the consummation of the Partnering Transaction a cash fee in an amount equal to 2.25% of the gross proceeds of the Initial Public Offering (exclusive of any applicable finders’ fees which might become payable), which equates to approximately $9.3 million. Pursuant to the terms of the capital markets advisory agreement, no fee will be due if the Company does not complete a Partnering Transaction. On May 15, 2022, Evercore Group L.L.C agreed to waive their right to such fee and such agreement was terminated.

Risks and Uncertainties

Management continues to evaluate the impact of the COVID-19 pandemic on the industry and has concluded that while it is reasonably possible that the pandemic could have a negative effect on the Company’s financial position, and the results of its operations and/or search for a target company, the specific impact is not readily determinable as of the date of the unaudited condensed financial statements. The unaudited condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty.

In February 2022, the Russian Federation and Belarus commenced a military action with the country of Ukraine. As a result of this action, various nations, including the United States, have instituted economic sanctions against the Russian Federation and Belarus. Further, the impact of this action and related sanctions on the world economy is not determinable as of the date of these unaudited condensed financial statements, and the specific impact on the Company’s financial condition, results of operations, and cash flows is also not determinable as of the date of these unaudited condensed financial statements.

On August 16, 2022, the Inflation Reduction Act of 2022 (the “IR Act”) was signed into federal law. The IR Act provides for, among other things, a new U.S. federal 1% excise tax on certain repurchases of stock by publicly traded U.S. domestic corporations and certain U.S. domestic subsidiaries of publicly traded foreign corporations occurring on or after January 1, 2023. The excise tax is imposed on the repurchasing corporation itself, not its shareholders from which shares are repurchased. The amount of the excise tax is generally 1% of the fair market value of the shares repurchased at the time of the repurchase. However, for purposes of calculating the excise tax, repurchasing corporations are permitted to net the fair market value of certain new stock issuances against the fair market value of stock repurchases during the same taxable year. In addition, certain exceptions apply to the excise tax. The U.S. Department of the Treasury (the “Treasury”) has been given authority to provide regulations and other guidance to carry out and prevent the abuse or avoidance of the excise tax. Any share redemption or other share repurchase that occurs after December 31, 2022, in connection with a Partnering Transaction, extension vote or otherwise, may be subject to the excise tax. Whether and to what extent the Company would be subject to the excise tax in connection with a Partnering Transaction, extension vote or otherwise will depend on a number of factors, including (i) the fair market value of the redemptions and repurchases in connection with the Partnering Transaction, extension or otherwise, (ii) the structure of a Partnering Transaction, (iii) the nature and amount of any “PIPE” (Private Investment in Public Entity) or other equity issuances in connection with a Partnering Transaction (or otherwise issued not in connection with a Partnering Transaction but issued within the same taxable year of a Partnering Transaction) and (iv) the content of regulations and other guidance from the Treasury. In addition, because the excise tax would be payable by the Company and not by the redeeming

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holder, the mechanics of any required payment of the excise tax have not been determined. The foregoing could cause a reduction in the cash available on hand to complete a Partnering Transaction and in the Company’s ability to complete a Partnering Transaction.

Note 6 — Warrants

No fractional warrants will be issued upon separation of the CAPS™ and only whole warrants will trade. Each whole warrant entitles the registered holder to purchase one share of Class A common stock at a price of $11.50 per share, subject to adjustment as discussed below, at any time commencing on the later of 12 months from the closing of the Initial Public Offering and 30 days after the completion of a Partnering Transaction, provided in each case that the Company has an effective registration statement under the Securities Act covering the shares of Class A common stock issuable upon exercise of the warrants and a current prospectus relating to them is available (or the Company permits holders to exercise their warrants on a cashless basis under the circumstances specified in the warrant agreement) and such shares are registered, qualified or exempt from registration under the securities, or blue sky, laws of the state of residence of the holder. The Company has agreed that as soon as practicable, but in no event later than fifteen (15) business days after the closing of the Partnering Transaction, the Company will use its commercially reasonable efforts to file with the SEC a registration statement for the registration, under the Securities Act, of the shares of Class A common stock issuable upon exercise of the warrants. The Company will use its best efforts to cause the same to become effective and to maintain the effectiveness of such registration statement, and a current prospectus relating thereto, until the expiration of the warrants in accordance with the provisions of the warrant agreement. If a registration statement covering the shares of Class A common stock issuable upon exercise of the warrants is not effective by the sixtieth (60th) business day after the closing of the Partnering Transaction, warrant holders may, until such time as there is an effective registration statement and during any period when the Company will have failed to maintain an effective registration statement, exercise warrants on a “cashless basis” in accordance with Section 3(a)(9) of the Securities Act or another exemption. Notwithstanding the above, if the shares of Class A common stock are at the time of any exercise of a warrant not listed on a national securities exchange such that they satisfy the definition of a “covered security” under Section 18(b)(1) of the Securities Act, the Company may, at its option, require holders of Public Warrants who exercise their warrants to do so on a “cashless basis” in accordance with Section 3 (a)(9) of the Securities Act and, in the event the Company so elect, it will not be required to file or maintain in effect a registration statement, and in the event the Company does not so elect, it will use its best efforts to register or qualify the shares under applicable blue sky laws to the extent an exemption is not available.

The warrants will expire five years after the completion of the Partnering Transaction, or earlier upon redemption or liquidation. In addition, if (x) the Company issues additional Class A common stock or equity-linked securities for capital raising purposes in connection with the Partnering Transaction at an issue price or effective issue price of less than $9.20 per share of Class A common stock (with such issue price or effective issue price to be determined in good faith by the board of directors and, in the case of any such issuance to the Initial Stockholders or its affiliates, without taking into account any shares held by the Initial Stockholders or such affiliates, as applicable, prior to such issuance) (the “Newly Issued Price”), (y) the aggregate gross proceeds from such issuances represent more than 60% of the total equity proceeds, and interest thereon, available for the funding of the Partnering Transaction on the date of the consummation of the Partnering Transaction (net of redemptions), and (z) the volume weighted average trading price of the shares of Class A common stock during the 20 trading day period starting on the trading day after the day on which the Company consummates its Partnering Transaction (such price, the “Market Value”) is below $9.20 per share, the exercise price of the warrants will be adjusted (to the nearest cent) to be equal to 110% of the Newly Issued Price, and the $18.00 per share redemption trigger price described below will be adjusted (to the nearest cent) to be equal to 180% of the higher of the Market Value and the Newly Issued Price.

The Private Placement Warrants are identical to the Public Warrants, except that the Private Placement Warrants and the shares of Class A common stock issuable upon exercise of the Private Placement Warrants will not be transferable, assignable or salable until 30 days after the completion of a Partnering Transaction, subject to certain limited exceptions. Additionally, the Private Placement Warrants will be non-redeemable so long as they are held by the Sponsor or its permitted transferees. If the Private Placement

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Warrants are held by someone other than the Sponsor or its permitted transferees, the Private Placement Warrants will be redeemable by the Company and exercisable by such holders on the same basis as the Public Warrants.

The Company may also redeem the Public Warrants, in whole and not in part, at a price of $0.01 per warrant:

•

at any time while the warrants are exercisable,

•

upon a minimum of 30 days’ prior written notice of redemption,

•

if, and only if, the last sales price of shares of the Class A common stock equals or exceeds $18.00 per share for any 20 trading days within a 30 trading day period (the “30-day trading period”) ending three business days before the Company sends the notice of redemption, and

•

If the Company calls the Public Warrants for redemption, management will have the option to require all holders that wish to exercise the Public Warrants to do so on a “cashless basis,” as described in the warrant agreement.

In no event will the Company be required to net cash settle any warrant. If the Company is unable to complete a Partnering Transaction within the Partnering Period and the Company liquidates the funds held in the Trust Account, holders of warrants will not receive any of such funds with respect to their warrants, nor will they receive any distribution from the Company’s assets held outside of the Trust Account with the respect to such warrants. Accordingly, the warrants may expire worthless.

As of September 30, 2022 and December 31, 2021, the Company had 10,350,000 Public Warrants and 153,500 Private Placement Warrants outstanding.

Note 7 — Class A Common Stock Subject to Possible Redemption

The Company’s Class A common stock feature certain redemption rights that are considered to be outside of the Company’s control and subject to the occurrence of future events. The Company is authorized to issue 380,000,000 Class A common stock with a par value of $0.0001 per share. Holders of the Company’s Class A common stock are entitled to one vote for each share. As of September 30, 2022 and December 31, 2021, there were 42,014,000 Class A common stock outstanding, which 41,400,000 were subject to possible redemption and are classified outside of permanent equity in the condensed balance sheets.

The Class A common stock subject to possible redemption reflected on the condensed balance sheets is reconciled on the following table:

Gross proceeds from Initial Public Offering	$	414,000,000
Less:
Fair value of Public Warrants at issuance		(13,558,500)
Offering costs allocated to Class A common stock subject to possible redemption		(4,588,064)
Plus:
Accretion on Class A common stock subject to possible redemption value		18,146,564
Class A common stock subject to possible redemption as of December 31, 2021 and March 31, 2022		414,000,000
Increase in redemption value of Class A common stock subject to redemption		70,397
Class A common stock subject to possible redemption as of June 30, 2022		414,070,397
Increase in redemption value of Class A common stock subject to redemption		1,373,955
Class A common stock subject to possible redemption as of September 30, 2022	$	415,444,352

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Note 8 — Stockholders’ Deficit

Preferred stock — The Company is authorized to issue 1,000,000 shares of preferred stock with a par value of $0.0001 per share. As of September 30, 2022 and December 31, 2021, there were no shares of preferred stock issued or outstanding.

Class A Common Stock — The Company is authorized to issue 380,000,000 shares of Class A common stock with a par value of $0.0001 per share. As of September 30, 2022 and December 31, 2021, there were 42,014,000 shares of Class A common stock issued and outstanding, 41,400,000 shares of which were subject to possible redemption and are classified as temporary equity in the accompanying unaudited condensed balance sheets.

Class B Common Stock — The Company is authorized to issue 1,000,000 shares of Class B common stock with a par value of $0.0001 per share. On July 17, 2020, the Company effected a 100:1 stock split for each share of Class B common stock, resulting in an aggregate of 120,000 shares of Class B common stock outstanding. On March 24, 2021, the Company effected a 2.5:1 forward stock split for each share of Class B common stock, resulting in an aggregate of 300,000 shares of Class B common stock outstanding. All shares and associated amounts have been retroactively restated to reflect the stock split. As of September 30, 2022 and December 31, 2021, there were 300,000 shares of Class B common stock issued and outstanding.

Each year following the completion of a Partnering Transaction, 10,000 shares of the Company’s Class B shares will convert into 1,000 shares of Class A common stock. However, if the price of a share of the Company’s Class A common stock exceeds $11.00 for 20 out of any 30 trading days following the completion of the Partnering Transaction, then the number of shares of Class A common stock deliverable (“conversion shares”) will be calculated as the greater of: (1) (a) 20% of the increase in the price of one Class A, year-over-year (but only after the price exceeds the “price threshold” being initially $10.00 and adjusted at the beginning of each year to be equal to the greater of: (i) the price of the Class A common stock for the previous year; and (ii) the price threshold at the end of the previous year) multiplied by (b) the number of shares of Class A common stock outstanding at the close of the Partnering Transaction, excluding those shares of Class A common stock received by the Sponsor through the Class F common stock; and (2) 2,500 shares of Class A common stock. This calculation shall be based on the Company’s fiscal year which may change as a result of the Partnering Transaction. The increase in the price of the Class A common stock, shall be based on the Company’s annual volume weighted average price (“VWAP”) for the Company’s fiscal year provided that with respect to the 12th fiscal year end following the Partnering Transaction the conversion calculation for the remaining 10,000 shares of Class B shares, the calculation shall be the greater of (i) such annual VWAP and (ii) the VWAP of the last 20 trading days of such fiscal year.

The conversion shares will be calculated not only on the increase of the price of one share of Class A common stock but also on any dividends paid on one share of Class A common stock in such year. The price threshold for a particular year will be reduced by the dividends per shares of Class A common stock paid in such year. Upon a change of control, holders of the Class B shares shall receive the greater of: (a) the value of 6,000,000 shares of Class A common stock at the time of the announcement of the change of control or $60,000,000. Such calculation shall decrease by 1/12 each year.

For so long as any shares of Class B common stock remain outstanding, the Company may not, without the prior vote or written consent of the holders of a majority of the shares of Class B common stock then outstanding, voting separately as a single class, amend, alter or repeal any provision the Company’s amended and restated certificate of incorporation, whether by merger, consolidation or otherwise, if such amendment, alteration or repeal would alter or change the powers, preferences or relative, participating, optional or other or special rights of the Class B common stock.

Class F Common Stock — The Company is authorized to issue 50,000,000 shares of Class F common stock with a par value of $0.0001 per share. On July 29, 2020, the Company effected a reverse stock split for Class F common stock, resulting in an aggregate of 690,000 shares of Class F common stock outstanding. On September 17, 2020, the Company effected a 1 for 1.2 forward stock split that increased the outstanding Class F common stock from 690,000 to 828,000 shares. All shares and associated amounts have been retroactively restated to reflect the reverse stock split on July 29, 2020 and the 1 for 1.2 forward stock split

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on September 17, 2020. As of September 30, 2022 and December 31, 2021, there were 828,000 shares of Class F common stock issued and outstanding.

The Founder Shares will automatically convert into shares of Class A common stock concurrently with or immediately following the consummation of a Partnering Transaction on a one-for-one basis, subject to adjustment for stock splits, stock dividends, reorganizations, recapitalizations and the like. In the case that additional shares of Class A common stock or equity-linked securities are issued or deemed issued in connection with a Partnering Transaction, the number of shares of Class A common stock issuable upon conversion of all Founder Shares will equal, in the aggregate, on an as converted basis, 5% of the total number of shares of Class A common stock outstanding after such conversion (including the private placement shares) including the total number of shares of Class A common stock issued, or deemed issued or issuable upon conversion or exercise of any equity-linked securities or rights issued or deemed issued, by the Company in connection with or in relation to the consummation of the Partnering Transaction, provided that such conversion of Founder Shares will never occur on a less than one-for-one basis.

For so long as any shares of Class F common stock remain outstanding, the Company may not, without the prior vote or written consent of the holders of a majority of the shares of Class F common stock then outstanding, voting separately as a single class, amend, alter or repeal any provision of the Company’s certificate of incorporation, whether by merger, consolidation or otherwise, if such amendment, alteration or repeal would alter or change the powers, preferences or relative, participating, optional or other or special rights of the shares of Class F common stock. Any action required or permitted to be taken at any meeting of the holders of shares of Class F common stock may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, shall be signed by the holders of the outstanding shares of Class F common stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares of Class F common stock were present and voted.

Note 9 — Fair Value Measurements

The following tables present information about the Company’s financial assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2022 and December 31, 2021 by level within the fair value hierarchy:

	Fair Value Measured as of September 30, 2022
	Level 1			Level 2			Level 3			Total
Assets:
Investments held in Trust Account – U.S. Treasury Securities		$	416,329,383		$	—		$	—		$	416,329,383
Liabilities:
Warrant liabilities – Public Warrants		$	9,625,500		$	—		$	—		$	9,625,500
Warrant liabilities – Private Placement Warrants		$	—		$	—		$	145,825		$	145,825

	Fair Value Measured as of December 31, 2021												��
	Level 1			Level 2			Level 3			Total
Assets:
Investments held in Trust Account – U.S. Treasury Securities		$	414,052,978		$	—		$	—		$	414,052,978
Liabilities:
Warrant liabilities – Public Warrants		$	7,027,650		$	—		$	—		$	7,027,650
Warrant liabilities – Private Placement Warrants		$	—		$	—		$	107,910		$	107,910

Transfers to/from Levels 1, 2, and 3 are recognized at the beginning of the reporting period. There were no transfers between levels for the three and nine months ended September 30, 2022 and 2021.

The fair value of the warrants issued in connection with the Initial Public Offering was initially measured using a Monte-Carlo simulation model and subsequently been measured based on the listed market price of

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such warrants at each measurement date when separately listed and traded in November 2020. The fair value of the warrants issued in connection with the Private Placement has been estimated using a Black-Scholes Option Pricing model at each measurement date.

The estimated fair value of the Private Placement Warrants has been determined using Level 3 inputs. Inherent in a Black-Scholes Option Pricing model are assumptions related to expected stock-price volatility, expected life, risk-free interest rate and dividend yield. The Company estimates the implied volatility based on the trading price of the public warrants as of the valuation date. The risk-free interest rate is based on the U.S. Treasury zero-coupon yield curve on the grant date for a maturity similar to the expected remaining life of the warrants. The expected life of the warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which the Company anticipates remaining at zero.

The following table provides quantitative information regarding Level 3 fair value measurements inputs at their measurement:

	September 30, 2022			December 31, 2021
Exercise price		$	11.50		$	11.50
Stock Price		$	9.98		$	9.81
Term (in years)			5.00			5.00
Volatility			8.50%			14.20%
Risk-free interest rate			4.06%			1.34%
Dividend yield			0.00%			0.00%
Probability of success			90.00%			80.00%

The change in the fair value of the derivative warrant liabilities measured with Level 3 inputs for the three and nine months ended September 30, 2022 and 2021 is summarized as follows:

Level 3 warrant liabilities as of December 31, 2021	$	107,910
Change in fair value of warrant liabilities		(60,325)
Level 3 warrant liabilities as of March 31, 2022		47,585
Change in fair value of warrant liabilities		93,635
Level 3 warrant liabilities as of June 30, 2022		141,220
Change in fair value of warrant liabilities		4,605
Level 3 warrant liabilities as of September 30, 2022	$	145,825

Level 3 warrant liabilities as of December 31, 2020	$	165,780
Change in fair value of warrant liabilities		(30,700)
Level 3 warrant liabilities as of March 31, 2021		135,080
Change in fair value of warrant liabilities		23,025
Level 3 warrant liabilities as of June 30, 2021		158,105
Change in fair value of warrant liabilities		(33,770)
Level 3 warrant liabilities as of September 30, 2021	$	124,335

Note 10 — Subsequent Events

Management has evaluated subsequent events to determine if events or transactions occurring through the date of the unaudited condensed financial statements were issued. Based upon this review, the Company did not identify any subsequent event that would have required adjustment or disclosure in the unaudited condensed financial statements, except for the below.

On October 18, 2022, in connection with the Partnering Transaction, holders of 39,343,496 shares of Class A Common Stock exercised their right to redeem their shares for cash at a redemption price of approximately $10.07 per share, for an aggregate redemption amount of approximately $396.1 million.

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On October 20, 2022, the Company held a special meeting of its stockholders (the “Special Meeting”), at which holders of 30,908,389 shares of ENPC’s Class A common stock (“Class A Common Stock”), par value $0.0001 per share, 300,000 shares of ENPC’s Class B common stock (“Class B Common Stock”), par value $0.0001 per share, and 828,000 shares of ENPC’s Class F common stock (“Class F Common Stock”), par value $0.0001 per share, were present in person or by proxy, collectively representing 78.9% of the voting power of ENPC’s outstanding voting capital stock as of the date of the Special Meeting, and constituting a quorum for the transaction of business at the Special Meeting. The proposals listed below are described in more detail in the definitive proxy statement of ENPC which was filed with the Securities and Exchange Commission (the “SEC”) on September 29, 2022 (the “Proxy Statement”). The stockholders approved the Business Combination Proposal, each of the Charter Proposals and the Incentive Plan Proposal (each as defined in the Proxy Statement). As set forth in the Proxy Statement, the Adjournment Proposal (as defined in the Proxy Statement) would only be presented to stockholders, if necessary, to permit further solicitation and vote of proxies in the event that there are insufficient votes for the approval of one or more proposals at the Special Meeting. As each of the other Proxy Statement proposals passed, there was no need to present the Adjournment Proposal to the stockholders.

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of
Executive Network Partnering Corporation

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Executive Network Partnering Corporation (the “Company”) as of December 31, 2021 and 2020, the related statements of operations, changes in stockholders’ deficit and cash flows for the year ended December 31, 2021 and for the period from June 22, 2020 (inception) through December 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the year ended December 31, 2021 and for the period from June 22, 2020 (inception) through December 2020, in conformity with accounting principles generally accepted in the United States of America.

Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, if the Company is unable to raise additional funds to alleviate liquidity needs and complete a partnering transaction by December 18, 2022 then the Company will cease all operations except for the purpose of liquidating. The liquidity condition and date for mandatory liquidation and subsequent dissolution raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ WithumSmith+Brown, PC

We have served as the Company’s auditor since 2020.

New York, New York
March 30, 2022
PCAOB ID Number 100

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EXECUTIVE NETWORK PARTNERING CORPORATION

BALANCE SHEETS

	December 31,
	2021			2020
Assets:
Current assets:
Cash		$	93,862		$	888,097
Prepaid expenses			206,980			440,771
Total current assets			300,842			1,328,868
Investments held in Trust Account			414,052,978			414,011,571
Total Assets		$	414,353,820		$	415,340,439
Liabilities, Class A Common Stock Subject to Possible Redemption and Stockholders’ Deficit:
Current liabilities:
Accounts payable		$	68,735		$	80,044
Accrued expenses			953,135			107,000
Franchise tax payable			174,603			104,159
Total current liabilities			1,196,473			291,203
Convertible note – related party			430,000			—
Derivative warrant liabilities			7,135,560			10,929,780
Total Liabilities			8,762,033			11,220,983
Commitments and Contingencies
Class A common stock subject to possible redemption; $0.0001 par value; 41,400,000 shares issued and outstanding at $10.00 per share redemption value as of December 31, 2021 and 2020(1)			414,000,000			414,000,000
Stockholders’ Deficit:
Preferred stock, $0.0001 par value; 1,000,000 shares authorized; none issued or outstanding as of December 31, 2021 and 2020			—			—
Class A common stock, $0.0001 par value; 380,000,000 shares authorized; 614,000 shares issued and outstanding as of December 31, 2021 and 2020(1)			61			61
Class B common stock, $0.0001 par value; 1,000,000 shares authorized; 300,000 shares issued and outstanding as of December 31, 2021 and 2020(1)			30			30
Class F common stock, $0.0001 par value; 50,000,000 shares authorized; 828,000 shares issued and outstanding as of December 31, 2021 and 2020			83			83
Additional paid-in capital			—			—
Accumulated deficit			(8,408,387)			(9,880,718)
Total stockholders’ deficit			(8,408,213)			(9,880,544)
Total Liabilities, Class A Common Stock Subject to Possible Redemption and Stockholders’ Deficit		$	414,353,820		$	415,340,439

(1)

On March 24, 2021, the Company effected a 2.5:1 forward stock split for each share of Class A common stock and Class B common stock issued and outstanding. All shares and associated amounts have been retroactively restated to reflect the stock split.

The accompanying notes are an integral part of these financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

STATEMENTS OF OPERATIONS

Operating expenses	For the Year Ended December 31, 2021			For the Period from June 22, 2020 (Inception) through December 31, 2020
General and administrative expenses		$	1,964,225		$	172,982
Administrative fee – related party			240,000			80,000
Franchise tax expense			159,071			104,159
Loss from operations			(2,363,296)			(357,141)
Change in fair value of derivative warrant liabilities			3,794,220			2,835,950
Offering costs associated with derivative warrant liabilities			—			(182,130)
Income from investments held in Trust Account			41,407			11,571
Net income		$	1,472,331		$	2,308,250
Weighted average shares outstanding of Class A common stock, basic and diluted(1)			42,014,000			22,857,358
Basic and diluted net income per share of Class A common stock		$	0.03		$	0.10
Weighted average shares outstanding of Class B common stock, basic and diluted(2)			300,000			300,000
Basic and diluted net income per share of Class B common stock		$	0.03		$	0.10
Weighted average shares outstanding of Class F common stock, basic and diluted(3)			828,000			778,756
Basic and diluted net income per share of Class F common stock		$	0.03		$	0.10

(1)

On March 24, 2021, the Company effected a 2.5:1 forward stock split for each share of Class A common stock issued and outstanding. All shares and associated amounts have been retroactively restated to reflect the stock split.

(2)

On July 17, 2020, the Company effected a 100:1 stock split for each share of Class B common stock issued and outstanding. On March 24, 2021, the Company effected a 2.5:1 forward stock split for each share of Class B common stock issued and outstanding. All shares and associated amounts have been retroactively restated to reflect the stock splits.

(3)

On July 29, 2020, the Company effected a reverse stock split for all Class F common stock issued and outstanding. On September 17, 2020, the Company effected a 1 for 1.2 forward stock split for all Class F common stock issued and outstanding. All shares and associated amounts have been retroactively restated to reflect the stock splits.

The accompanying notes are an integral part of these financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

	FOR THE YEAR ENDED DECEMBER 31, 2021
	Common Stock															Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Deficit
	Class A(1)					Class B(2)					Class F(3)
	Shares		Amount			Shares		Amount			Shares		Amount
Balance – December 31, 2020		614,000		$	61		300,000		$	30		828,000		$	83		$	—		$	(9,880,718)		$	(9,880,544)
Net income		—			—		—			—		—			—			—			1,472,331			1,472,331
Balance – December 31, 2021		614,000		$	61		300,000		$	30		828,000		$	83		$	—		$	(8,408,387)		$	(8,408,213)

	FOR THE PERIOD FROM JUNE 22, 2020 (INCEPTION) THROUGH DECEMBER 31, 2020
	Common Stock															Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Deficit
	Class A(1)					Class B(2)					Class F(3)
	Shares		Amount			Shares		Amount			Shares		Amount
Balance – June 22, 2020 (inception)		—		$	—		—		$	—		—		$	—		$	—		$	—		$	—
Issuance of Class B common stock to Sponsor		—			—		300,000			30		—			—			18,720			—			18,750
Issuance of Class F common stock to Sponsor		—			—		—			—		828,000			83			6,167			—			6,250
Sale of 614,000 Private Placement CAPSTM, net of fair value of Private Placement Warrants		614,000			61		—			—		—			—			5,932,709			—			5,932,770
Accretion on Class A common stock subject to possible redemption amount		—			—		—			—		—			—			(5,957,596)			(12,188,968)			(18,146,564)
Net income		—			—		—			—		—			—			—			2,308,250			2,308,250
Balance – December 31, 2020		614,000		$	61		300,000		$	30		828,000		$	83		$	—		$	(9,880,718)		$	(9,880,544)

(1)

On March 24, 2021, the Company effected a 2.5:1 forward stock split for each share of Class A common stock, issued and outstanding. All shares and associated amounts have been retroactively restated to reflect the stock split.

(2)

(3)

The accompanying notes are an integral part of these financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

STATEMENTS OF CASH FLOWS

	For the Year Ended December 31, 2021			For the Period from June 22, 2020 (Inception) through December 31, 2020
Cash Flows from Operating Activities:
Net income		$	1,472,331		$	2,308,250
Adjustments to reconcile net income to net cash used in operating activities:
Change in fair value of derivative warrant liabilities			(3,794,220)			(2,835,950)
General and administrative expenses paid by related party under note payable			—			29,287
Offering costs associated with derivative warrant liabilities			—			182,130
Interest income from investments held in Trust Account			(41,407)			(11,571)
Changes in assets and liabilities:
Prepaid expenses			233,791			(440,771)
Accounts payable			(11,309)			80,044
Accrued expenses			846,135			22,000
Franchise tax payable			70,444			104,159
Net cash used in operating activities			(1,224,235)			(562,422)
Cash Flows from Investing Activities
Cash deposited in Trust Account			—			(414,000,000)
Net cash used in investing activities			—			(414,000,000)
Cash Flows from Financing Activities:
Proceeds received from initial public offering, gross			—			414,000,000
Proceeds received from private placement			—			6,140,000
Proceeds from Convertible note – related party			430,000			—
Repayment of note payable to related party			—			(171,450)
Offering costs paid			—			(4,518,031)
Net cash provided by financing activities			430,000			415,450,519
Net change in cash			(794,235)			888,097
Cash – beginning of the period			888,097			—
Cash – end of the period		$	93,862		$	888,097
Supplemental disclosure of noncash activities:
Offering costs paid in exchange for issuance of Class B common stock to Sponsor		$	—		$	18,750
Offering costs paid in exchange for issuance of Class F common stock to Sponsor		$	—		$	6,250
Offering costs included in accrued expenses		$	—		$	85,000
Offering costs paid through note payable		$	—		$	142,163

The accompanying notes are an integral part of these financial statements.

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EXECUTIVE NETWORK PARTNERING CORPORATION

NOTES TO FINANCIAL STATEMENTS

NOTE 1 — Description of Organization, Business Operations and Going Concern

Organization and General

As of December 31, 2021, the Company had not commenced any operations. All activity for the period from June 22, 2020 (inception) through December 31, 2021 relates to the Company’s formation and the initial public offering (“Initial Public Offering”) and since the closing of the Initial Public Offering, the search for a prospective initial Partnering Transaction. The Company will not generate any operating revenues until after the completion of its initial Partnering Transaction, at the earliest. The Company will generate non-operating income in the form of interest income on investments held in Trust Account from the proceeds derived from the Initial Public Offering.

Financing

The registration statement for the Company’s Initial Public Offering was declared effective on September 15, 2020. On September 18, 2020, the Company consummated its Initial Public Offering of 41,400,000 of its securities called CAPSTM (“CAPSTM”) (with respect to the Class A common stock included in the CAPSTM being offered, the “Public Shares”), which included 5,400,000 CAPSTM issued as a result of the underwriters’ exercise in full of their over-allotment option, at $10.00 per CAPSTM, generating gross proceeds of $414.0 million, and incurring offering costs of approximately $4.8 million.

Concurrently with the closing of the Initial Public Offering, the Company completed the private sale of 614,000 private placement CAPSTM (“Private Placement CAPSTM”), at a price of $10.00 per Private Placement CAPSTM to the Sponsor (the “Private Placement”), generating gross proceeds to the Company of approximately $6.1 million (Note 4). The CAPSTM have been retroactively restated to reflect the March 24, 2021, 2.5:1 forward stock split for each share of Class A common stock and warrant.

Trust Account

Upon the closing of the Initial Public Offering and the sale of Private Placement CAPSTM, $414.0 million ($10.00 per CAPSTM) of the net proceeds of the sale of the CAPSTM in the Initial Public Offering and the Private Placement were placed in a trust account (“Trust Account”) located in the United States with Continental Stock Transfer & Trust Company acting as trustee, and held as cash or invested only in U.S. “government securities,” within the meaning set forth in Section 2(a)(16) of the Investment Company Act, with a maturity of 185 days or less, or in money market funds meeting the conditions of paragraphs (d)(2), (d)(3) and (d)(4) of Rule 2a-7 under the Investment Company Act, which invest only in direct U.S. government treasury obligations, as determined by the Company, until the earlier of: (i) the completion of a Partnering Transaction and (ii) the distribution of the Trust Account as described below.

The Company must complete a Partnering Transaction with one or more partner candidate businesses having an aggregate fair market value of at least 80% of the net assets held in the Trust Account (excluding the taxes payable on the income earned on the Trust Account) at the time of the agreement to enter into the initial Partnering Transaction. However, the Company will only complete a Partnering Transaction if the post- transaction company owns or acquires 50% or more of the voting securities of the partner candidate

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or otherwise acquires a controlling interest in the partner candidate sufficient for it not to be required to register as an investment company under the Investment Company Act of 1940, as amended (the “Investment Company Act”). The Company’s certificate of incorporation provides that, other than the withdrawal of interest earned on the funds that may be released to the Company to pay taxes, none of the funds held in Trust Account will be released until the earlier of: (i) the completion of the Partnering Transaction; (ii) the redemption of any of the common stock included in the CAPSTM being sold in the Initial Public Offering (the “Public Shares”) to its holders (the “Public Stockholders”) properly tendered in connection with a stockholder vote to amend certain provisions of the Company’s certificate of incorporation prior to a Partnering Transaction or (iii) the redemption of 100% of the Public Shares if the Company does not complete a Partnering Transaction within the Partnering Period (defined below).

The Company will only have 27 months from the closing of the Initial Public Offering, or December 18, 2022, to complete its initial Partnering Transaction (the “Partnering Period”). If the Company does not complete a Partnering Transaction within this period of time (and stockholders do not approve an amendment to the certificate of incorporation to extend this date), it will (i) cease all operations except for the purpose of winding up, (ii) as promptly as reasonably possible but not more than ten business days thereafter, redeem the Public Shares, at a per-share price, payable in cash, equal to their pro rata share of the aggregate amount then on deposit in the Trust Account including interest earned on the funds held in the Trust Account and not previously released to the Company to pay its taxes (less up to $100,000 of such net interest to pay dissolution expenses), and (iii) as promptly as reasonably possible following such redemption, subject to the approval of the remaining stockholders and the board of directors, liquidate and dissolve, subject in the case of clauses (ii) and (iii), to the Company’s obligations under Delaware law to provide for claims of creditors and in all cases subject to the other requirements of applicable law.

The holders of the Founder Shares immediately prior to the Initial Public Offering (the “Initial Stockholders”) have entered into a letter agreement with the Company, pursuant to which they have agreed to (i) waive their redemption rights with respect to any Founder Shares (as defined in Note 4) and Public Shares they hold in connection with the completion of the Partnering Transaction, (ii) waive their redemption rights with respect to any Founder Shares and Public Shares they hold in connection with a stockholder vote to approve an amendment to the Company’s amended and restated certificate of incorporation to modify

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the substance or timing of the Company’s obligation to redeem 100% of its Public Shares if the Company has not consummated a Partnering Transaction within the Partnering Period or with respect to any other material provisions relating to stockholders’ rights or pre-Partnering Transaction activity and (iii) waive their rights to liquidating distributions from the Trust Account with respect to any founder shares they hold if the Company fails to complete the Partnering Transaction within the Partnering Period (although they will be entitled to liquidating distributions from the Trust Account with respect to any Public Shares they hold if the Company fails to complete the Partnering Transaction within the Partnering Period).

Pursuant to the letter agreement, the Sponsor has agreed that it will be liable to the Company if and to the extent any claims by a third party for services rendered or products sold to the Company, or a prospective target business with which the Company has entered into a written letter of intent, confidentiality or other similar agreement or Partnering Transaction agreement, reduce the amount of funds in the Trust Account to below the lesser of (i) $10.00 per Public Share and (ii) the actual amount per Public Share held in the Trust Account as of the date of the liquidation of the Trust Account, if less than $10.00 per public share due to reductions in the value of the Trust assets, less taxes payable, provided that such liability will not apply to any claims by a third party or prospective target business who executed a waiver of any and all rights to the monies held in the Trust Account (whether or not such waiver is enforceable) nor will it apply to any claims under the Company’s indemnity of the underwriter of our initial public offering against certain liabilities, including liabilities under the Securities Act.

Going Concern

As of December 31, 2021, the Company had approximately $94,000 in its operating bank account and a working capital deficit of approximately $896,000. Interest income on the balance in the Trust Account may be used to pay the Company’s franchise and income tax obligations. Management intends to use substantially all of the funds held in the Trust Account to complete the initial Partnering Transaction and to pay the Company’s expenses relating thereto. To the extent that the Company’s capital stock or debt is used, in whole or in part, as consideration to complete the initial Partnering Transaction, the remaining proceeds held in the Trust Account will be used as working capital to finance the operations of the target business or businesses, make other acquisitions and pursue our growth strategies.

The Company’s liquidity needs up to the closing of the Initial Public Offering and the sale of Private Placement CAPSTM had been satisfied through a capital contribution of $25,000 from the Sponsor to purchase Class F and Class B common stock, the loan under a note agreement with the Sponsor of approximately $171,000 (the “Note”) to cover for offering costs in connection with the Initial Public Offering, the Company fully repaid the Note on September 22, 2020, and certain portion of the net proceeds from the consummation of the Private Placement not held in the Trust Account. In addition, in order to finance transaction costs in connection with a Partnering Transaction, the Company’s officers, directors and initial stockholders may, but are not obligated to, provide the Company working capital loans (the “Working Capital Loans”). As of December 31, 2021 and 2020, the Company had $430,000 and $0 note outstanding under the Working Capital Loans.

In connection with the Company’s assessment of going concern considerations in accordance with Financial Accounting Standard Board’s Accounting Standards Update (“ASU”) 2014-15, “Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” the Company has until December 18, 2022 to consummate a Partnering Transaction. It is uncertain that the Company will be able to consummate a Partnering Transaction by this time. If a Partnering Transaction is not consummated by this date, there will be a mandatory liquidation and subsequent dissolution of the Company. Management has determined that the liquidity condition and mandatory liquidation, should a Partnering Transaction not occur, and potential subsequent dissolution raises substantial doubt about the Company’s ability to continue as a going concern. Management intends to complete the Business Combination prior to the liquidation date. No adjustments have been made to the carrying amounts of assets or liabilities should the Company be required to liquidate after December 18, 2022.

NOTE 2 — Summary of Significant Accounting Policies

Basis of presentation

The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) for financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).

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Emerging Growth Company

The Company is an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in its periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.

This may make comparison of the Company’s financial statements with another public company that is neither an emerging growth company nor an emerging growth company that has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of expenses during the reporting period. Making estimates requires management to exercise significant judgment. It is at least reasonably possible that the estimate of the effect of a condition, situation or set of circumstances that existed at the date of the financial statements, which management considered in formulating its estimate, could change in the near term due to one or more future confirming events. One of the more significant accounting estimates included in these financial statements is the determination of the fair value of the warrant liability. Such estimates may be subject to change as more current information becomes available and the actual results could differ significantly from those estimates.

Cash and Cash Equivalents

Investments Held in the Trust Account

The Company’s portfolio of investments held in the Trust Account is comprised of U.S. government securities, within the meaning set forth in Section 2(a)(16) of the Investment Company Act, with a maturity of 185 days or less, or investments in money market funds that invest in U.S. government securities and generally have a readily determinable fair value, or a combination thereof. To the extent that the Company’s investments held in the Trust Account are comprised of U.S. government securities, the investments are classified as trading securities and are recognized at fair market value. To the extent that the Company’s investments held in the Trust Account are comprised of money market funds, the investments are recognized at fair value. Trading securities and investments in money market funds are presented on the balance sheets at fair value at the end of each reporting period. Gains and losses resulting from the change in fair value of these securities are included in net gain from investments held in Trust Account in the accompanying

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statements of operations. The estimated fair values of investments held in the Trust Account are determined using available market information.

Concentrations of Credit Risk

Financial instruments that potentially subject the Company to concentration of credit risk consist of a cash account in a financial institution which, at times, may exceed the Federal Depository Insurance Corporation coverage limits of $250,000, and investments held in Trust Account. As of December 31, 2021 and 2020, the Company has not experienced losses on these accounts and management believes the Company is not exposed to significant risks on such accounts.

Financial Instruments

The fair value of the Company’s assets and liabilities, which qualify as financial instruments under FASB ASC Topic 820, “Fair Value Measurements” equal or approximate the carrying amounts represented in the balance sheets.

Fair Value Measurement

Fair value is defined as the price that would be received for sale of an asset or paid for transfer of a liability, in an orderly transaction between market participants at the measurement date. U.S. GAAP establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). These tiers consist of:

•

Level 1, defined as observable inputs such as quoted prices (unadjusted) for identical instruments in active markets;

•

Offering Costs Associated with the Initial Public Offering

Offering costs consist legal, accounting, underwriting fees and other costs incurred in connection with the formation and preparation for the Initial Public Offering. Offering costs are allocated to the separable financial instruments issued in the Initial Public Offering based on a relative fair value basis, compared to total proceeds received. Offering costs associated with warrant liabilities are expensed as incurred, presented as non-operating expenses in the statements of operations. Offering costs associated with the Public Shares were charged to the initial carrying value of the temporary equity upon the completion of the Initial Public Offering.

Class A Common Stock Subject to Possible Redemption

The Company accounts for its Class A common stock subject to possible redemption in accordance with the guidance in ASC Topic 480 “Distinguishing Liabilities from Equity.” Class A common stock subject to mandatory redemption (if any) is classified as a liability instrument and measured at fair value. Conditionally redeemable Class A common stock (including Class A common stock that features redemption rights that are either within the control of the holder or subject to redemption upon the occurrence of uncertain events not solely within the Company’s control) is classified as temporary equity. At all other times,

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Class A common stock is classified as stockholders’ equity. The Company’s Class A common stock features certain redemption rights that are considered to be outside of the Company’s control and subject to the occurrence of uncertain future events. Accordingly, as of December 31, 2021 and 2020, 41,400,000 shares of Class A common stock subject to possible redemption is presented as temporary equity, outside of the stockholders’ deficit section of the Company’s balance sheets.

Derivative Warrant Liabilities

The Company does not use derivative instruments to hedge its exposures to cash flow, market or foreign currency risks. Management evaluates all of the Company’s financial instruments, including issued warrants to purchase its Class A common stock, to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to ASC 480 and ASC 815-15. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period.

The Company issued 10,350,000 warrants to purchase Class A common stock to investors in its Initial Public Offering, including the over-allotment, and simultaneously issued 153,500 Private Placement Warrants. All of the Company’s outstanding warrants are recognized as derivative liabilities in accordance with ASC 815-40. Accordingly, the Company recognizes the warrant instruments as liabilities at fair value and adjust the instruments to fair value at each reporting period. The liabilities are subject to re-measurement at each balance sheet date until exercised, and any change in fair value is recognized in the Company’s statements of operations. The fair value of the warrants issued in connection with the Initial Public Offering was initially measured using a Monte-Carlo simulation model and subsequently been measured based on the listed market price of such warrants at each measurement date when separately listed and traded. The fair value of the warrants issued in connection with the Private Placement have been estimated using a Black-Scholes Option Pricing model at each measurement date. The determination of the fair value of the warrant liability may be subject to change as more current information becomes available and, accordingly, the actual results could differ significantly. Derivative warrant liabilities and convertible note are classified as non-current liabilities, as their liquidation is not reasonably expected to require the use of current assets or require the creation of current liabilities.

Income Taxes

ASC Topic 740, “Income Taxes” prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense.

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Net Income per Share of Common Stock

The Company complies with accounting and disclosure requirements of FASB ASC Topic 260, “Earnings Per Share.” The Company has three classes of shares, which are referred to as Class A common stock, Class B common stock and Class F common stock. Income and losses are shared pro rata among the three classes of shares. Net income (loss) per share of common stock is calculated by dividing the net income (loss) by the weighted average number of common stock outstanding for the respective period.

The calculation of diluted net income (loss) per share of common stock does not consider the effect of the warrants underlying the CAPSTM sold in the Initial Public Offering (including exercise of the over-allotment option) and the Private Placement to purchase 10,503,500 shares of Class A common stock in the calculation of diluted income (loss) per share, because their exercise is contingent upon future events and their inclusion would be anti-dilutive under the treasury stock method. As a result, diluted net income per share of common stock is the same as basic net income per share of common stock for the year ended December 31, 2021 and for the period from June 22, 2020 (inception) through December 31, 2020. Accretion associated with the redeemable Class A common stock is excluded from earnings per share as the redemption value approximates fair value.

The table below presents a reconciliation of the numerator and denominator used to compute basic and diluted net income per share of common stock for each class of common stock:

	For the Year Ended December 31, 2021									For the Period from June 22, 2020 (Inception) through December 31, 2020
	Class A			Class B			Class F			Class A			Class B			Class F
Basic net income per common stock:
Numerator:
Allocation of net income		$	1,433,835		$	10,238		$	28,258		$	2,204,221		$	28,931		$	75,098
Denominator:
Weighted average common stock outstanding, basic and diluted			42,014,000			300,000			828,000			22,857,358			300,000			778,756
Basic and diluted net income per share of common stock		$	0.03		$	0.03		$	0.03		$	0.10		$	0.10		$	0.10

Recent Accounting Pronouncements

In August 2020, the FASB issued Accounting Standards Update (“ASU”) No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (“ASU 2020-06”), which simplifies accounting for convertible instruments by removing major separation models required under current U.S. GAAP. The ASU also removes certain settlement conditions that are required for equity-linked contracts to qualify for the derivative scope exception, and it simplifies the diluted earnings per share calculation in certain areas. The Company adopted ASU 2020-06 on January 1, 2021 using the modified retrospective method for transition. Adoption of the ASU did not impact the Company’s financial position, results of operations or cash flows.

NOTE 3 — Initial Public Offering

Public CAPSTM

On September 18, 2020, the Company consummated its Initial Public Offering of 41,400,000 CAPSTM, which included 5,400,000 CAPSTM issued as a result of the underwriters’ exercise in full of their over-allotment option, at $10.00 per CAPSTM, generating gross proceeds of $414.0 million, and incurring offering costs of approximately $4.8 million.

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Each CAPSTM consists of one share of Class A common stock and one-quarter of one redeemable warrant (each, a “Public Warrant”). Each whole Public Warrant may be exercised to purchase one share of Class A common stock for $11.50 per share, subject to adjustment (see Note 8).

Underwriting Agreement

The Company granted the underwriters a 45-day option to purchase up to 5,400,000 additional CAPSTM to cover any over-allotment, at the Initial Public Offering price less the underwriting discounts and commissions. The underwriters exercised the over-allotment option in full on September 18, 2020.

The underwriters were entitled to an underwriting discount of $0.01 per CAPSTM, or approximately $4.1 million in the aggregate, paid upon the closing of the Initial Public Offering.

NOTE 4 — Related Party Transactions

Founder Shares and Performance Shares

On June 22, 2020, the Sponsor paid for certain offering costs on behalf of the Company in exchange for (i) 737,789 Class F common stock (the “Founder Shares”) in exchange for a capital contribution of $ 6,250, or approximately $0.008 per share and (ii) 1,200 shares of Class B common stock (the “Performance Shares”) for a capital contribution of $18,750, or $15.625 per share. On July 17, 2020 and March 24, 2021, the Company effected a 100:1 and a 2.5:1 forward stock split for each share of Class B common stock, respectively, resulting in an aggregate of 300,000 Performance Shares outstanding. On July 29, 2020, the Company effected a reverse stock split for Class F common stock, resulting in an aggregate of 690,000 shares of Class F common stock. On September 17, 2020, the Company effected a 1 for 1.2 forward stock split that increased the outstanding Class F common stock from 690,000 shares to 828,000 shares. All shares and associated amounts have been retroactively restated to reflect the stock splits. Of the 828,000 Founder Shares outstanding, up to 108,000 of the Founder Shares would be forfeited depending on the extent to which the underwriter’s over- allotment is exercised, so that such Founder Shares would represent 5% of the outstanding shares issued in the Initial Public Offering. The underwriters fully exercised their over-allotment option on September 18, 2020; thus, these 108,000 Founder Shares were no longer subject to forfeiture. The Founder Shares are entitled to (together with the Performance Shares) a number of votes representing 20% of the Company’s outstanding common stock (not including the private placement shares) prior to the completion of the Partnering Transaction. As of December 31, 2021 and 2020, after giving effect to the 2.5:1 forward stock split for each share of Class B common stock, which was effective on March 24, 2021, the Company had an aggregate of 828,000 Founders Shares and 300,000 Performance Shares, issued and outstanding.

The Initial Stockholders agreed not to transfer, assign or sell any of their Founder Shares until the earlier to occur of: (i) 180 days after the completion of the Partnering Transaction and (ii) the date on which the Company completes a liquidation, merger, capital stock exchange or other similar transaction after the Partnering Transaction that results in all of the stockholders having the right to exchange their Class A common stock for cash, securities or other property; except to certain permitted transferees. Such obligation by the Initial Stockholders will be terminated at closing.

Private Placement CAPSTM

Substantially concurrently with the closing of the Initial Public Offering, the Company completed the private sale of 245,600 Private Placement CAPSTM (614,000 Private Placement CAPSTM after giving effect to the Forward Split), at a price of $25.00 per Private Placement CAPSTM ($10.00 per Private Placement CAPSTM after giving effect to the Forward Split) to the Sponsor, generating gross proceeds to us of approximately $6.1 million.

Each Private Placement CAPSTM consists of one share of Class A common stock and one-quarter of one redeemable warrant (each, a “Private Placement Warrant”). Each Private Placement Warrant entitles the holder to purchase one share of Class A common stock at $11.50 per share. A portion of the proceeds from the sale of the Private Placement CAPSTM was added to the proceeds from the Initial Public Offering

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held in the Trust Account. If the Company does not complete a Partnering Transaction, then the proceeds will be part of the liquidating distribution to the Public Stockholders and the warrants will expire worthless.

Related Party Loans

On June 22, 2020, the Sponsor agreed to loan the Company up to an aggregate of $300,000 pursuant to an unsecured promissory note to cover expenses related to the Initial Public Offering. This loan was payable without interest upon the completion of the Initial Public Offering. The Company borrowed $171,000 under the Note and fully repaid the Note on September 22, 2020. Subsequent to the repayment, the facility was no longer available to the Company.

In order to finance transaction costs in connection with an intended initial Partnering Transaction, the Sponsor or an affiliate of the Sponsor or certain of the Company’s officers and directors may, but are not obligated to, loan the Company funds as may be required. Up to $1.5 million of the Working Capital Loans may be convertible into CAPSTM at a price of $25.00 per CAPSTM ($10.00 per CAPSTM after giving effect to the Forward Split) at the option of the lender. The CAPSTM would be identical to the Private Placement CAPSTM issued to the Sponsor. Except as described below, the terms of such loans, if any, have not been determined and no written agreements exist with respect to such loans.

On September 23, 2021, the Company issued a Working Capital Loan to the Sponsor, pursuant to which the Company borrowed $180,000 for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. On October 27, 2021, the Company issued a Working Capital Loan to the Sponsor, pursuant to which the Company borrowed $180,000 for ongoing expenses reasonably related to the business of the Company and the consummation of the Partnering Transaction. The Working Capital Loans do not bear any interest. All unpaid principal under the Working Capital Loans will be due and payable in full on the earlier of (i) January 11, 2023 and (ii) the effective date of the Partnering Transaction (such earlier date, the “Maturity Date”). The Sponsor will have the option, at the time of consummation of a Partnering Transaction, to convert any amounts outstanding under the Working Capital Loans into CAPSTM.

During the year ended December 31, 2021, the Company borrowed from Sponsor total of $430,000 pursuant to the Working Capital Loans for ongoing expenses reasonably related to the business of us and the consummation of the Partnering Transaction. As of December 31, 2021 and 2020, $430,000 and $0 were outstanding under the Working Capital Loans.

Administrative Services Agreement

Commencing on the date that the Company’s securities were first listed on the New York Stock Exchange through the earlier of consummation of the Partnering Transaction and the Company’s liquidation, the Company will pay an affiliate of the Sponsor for office space, secretarial and administrative services provided to members of the Company’s management team $20,000 per month. The Company incurred $240,000 and $80,000 in expenses in connection with such services during year ended December 31, 2021 and for the period from June 22, 2020 (inception) through December 31, 2020, as reflected in related party general and administrative expenses in the accompanying statements of operations. As of December 31, 2021 and 2020, the Company had approximately $0 and $80,000 in accounts payable in connection with such services as reflected in the accompanying balance sheets.

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NOTE 5 — Commitments and Contingencies

Registration Rights

The holders of the Founder Shares, Performance Shares, Private Placement Warrants and private placement shares underlying Private Placement CAPSTM and Private Placement CAPSTM that may be issued upon conversion of Working Capital Loans (and any shares of Class A common stock into which such securities may convert and that may be issued upon exercise of Private Placement Warrants) are entitled to registration rights pursuant to a registration rights agreement, requiring the Company to register such securities for resale. The holders of these securities are entitled to make up to three demands, excluding short form demands, that the Company registers such securities. In addition, the holders have certain “piggy-back” registration rights with respect to registration statements filed subsequent to the completion of the Partnering Transaction. The Company will bear the expenses incurred in connection with the filing of any such registration statements.

Partnering Transaction Advisory Engagement Letter

In September 2020, the Company engaged Evercore as a capital markets advisor in connection with the Partnering Transaction, to assist the Company with the potential Partnering Transaction. The Company agreed to pay Evercore for such services upon the consummation of the Partnering Transaction a cash fee in an amount equal to 2.25% of the gross proceeds of the Initial Public Offering (exclusive of any applicable finders’ fees which might become payable), which equates to approximately $9.3 million. Pursuant to the terms of the capital markets advisory agreement, no fee will be due if the Company does not complete a Partnering Transaction.

NOTE 6 — Warrants

No fractional warrants will be issued upon separation of the CAPSTM and only whole warrants will trade. Each whole warrant entitles the registered holder to purchase one share of Class A common stock at a price of $11.50 per share, subject to adjustment as discussed below, at any time commencing on the later of 12 months from the closing of the Initial Public Offering and 30 days after the completion of a Partnering Transaction, provided in each case that the Company has an effective registration statement under the Securities Act covering the shares of Class A common stock issuable upon exercise of the warrants and a current prospectus relating to them is available (or the Company permits holders to exercise their warrants on a cashless basis under the circumstances specified in the warrant agreement) and such shares are registered, qualified or exempt from registration under the securities, or blue sky, laws of the state of residence of the holder. The Company has agreed that as soon as practicable, but in no event later than fifteen (15) business days after the closing of the Partnering Transaction, the Company will use its commercially reasonable efforts to file with the SEC a registration statement for the registration, under the Securities Act, of the shares of Class A common stock issuable upon exercise of the warrants. The Company will use its best efforts to cause the same to become effective and to maintain the effectiveness of such registration statement, and a current prospectus relating thereto, until the expiration of the warrants in accordance with the provisions of the warrant agreement. If a registration statement covering the shares of Class A common stock issuable upon exercise of the warrants is not effective by the sixtieth (60th) business day after the closing of the Partnering Transaction, warrant holders may, until such time as there is an effective registration statement and during any period when the Company will have failed to maintain an effective registration statement, exercise warrants on a “cashless basis” in accordance with Section 3(a)(9) of the Securities Act or another exemption. Notwithstanding the above, if the shares of Class A common stock are at the time of any exercise of a warrant not listed on a national securities exchange such that they satisfy the definition of a “covered security” under Section 18(b)(1) of the Securities Act, the Company may, at its option, require holders of Public Warrants who exercise their warrants to do so on a “cashless basis” in accordance with Section 3 (a)(9) of the Securities Act and, in the event the Company so elect, it will not be required to file or maintain in effect a registration statement, and in the event the Company does not so elect, it will use its best efforts to register or qualify the shares under applicable blue sky laws to the extent an exemption is not available.

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equity-linked securities for capital raising purposes in connection with the Partnering Transaction at an issue price or effective issue price of less than $9.20 per share of Class A common stock (with such issue price or effective issue price to be determined in good faith by the board of directors and, in the case of any such issuance to the Initial Stockholders or its affiliates, without taking into account any shares held by the Initial Stockholders or such affiliates, as applicable, prior to such issuance) (the “Newly Issued Price”), (y) the aggregate gross proceeds from such issuances represent more than 60% of the total equity proceeds, and interest thereon, available for the funding of the Partnering Transaction on the date of the consummation of the Partnering Transaction (net of redemptions), and (z) the volume weighted average trading price of the shares of Class A common stock during the 20 trading day period starting on the trading day after the day on which the Company consummates its Partnering Transaction (such price, the “Market Value”) is below $9.20 per share, the exercise price of the warrants will be adjusted (to the nearest cent) to be equal to 110% of the Newly Issued Price, and the $18.00 per share redemption trigger price described below will be adjusted (to the nearest cent) to be equal to 180% of the higher of the Market Value and the Newly Issued Price.

The Company may also redeem the Public Warrants, in whole and not in part, at a price of $0.01 per warrant:

•

at any time while the warrants are exercisable,

•

upon a minimum of 30 days’ prior written notice of redemption,

•

if, and only if, there is a current registration statement in effect with respect to the shares of Class A common stock underlying such warrants commencing five business days prior to the 30-day trading period and continuing each day thereafter until the date of redemption. If the Company calls the Public Warrants for redemption, management will have the option to require all holders that wish to exercise the Public Warrants to do so on a “cashless basis,” as described in the warrant agreement.

As of December 31, 2021 and 2020, the Company had 10,350,000 Public Warrants and 153,500 Private Placement Warrants outstanding.

NOTE 7 — Class A Common Stock Subject to Possible Redemption

The Company’s Class A common stock feature certain redemption rights that are considered to be outside of the Company’s control and subject to the occurrence of future events. The Company is authorized to issue 380,000,000 Class A common stock with a par value of $0.0001 per share. Holders of the Company’s Class A common stock are entitled to one vote for each share. As of December 31, 2021 and 2020, there were 42,014,000 shares of Class A common stock issued and outstanding, of which 41,400,000 shares of Class A common stock subject to possible redemption and are classified outside of permanent equity in the balance sheets.

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The Class A common stock subject to possible redemption reflected on the balance sheets is reconciled on the following table:

Gross proceeds from Initial Public Offering	$	414,000,000
Less:
Fair value of Public Warrants at issuance		(13,558,500)
Offering costs allocated to Class A common stock subject to possible redemption		(4,588,064)
Plus:
Accretion on Class A common stock subject to possible redemption value		18,146,564
Class A common stock subject to possible redemption	$	414,000,000

NOTE 8 — Stockholders’ Deficit

Preferred stock — The Company is authorized to issue 1,000,000 shares of preferred stock with a par value of $0.0001 per share. As of December 31, 2021 and 2020, there are no shares of preferred stock issued or outstanding.

Class A Common Stock — The Company is authorized to issue 380,000,000 shares of Class A common stock with a par value of $0.0001 per share. On March 24, 2021, the Company effected a 2.5:1 forward stock split for each share of Class A Common Stock. As of December 31, 2021 and 2020, there were 614,000 shares of Class A common stock outstanding. Conditionally redeemable Class A common stock (including Class A common stock that features redemption rights that are either within the control of the holder or subject to redemption upon the occurrence of uncertain events not solely within our control) is classified as temporary equity. At all other times, Class A common stock is classified as stockholders’ equity. The Company’s Class A common stock features certain redemption rights that are considered to be outside of the Company’s control and subject to the occurrence of uncertain future events. Accordingly, as of December 31, 2021 and 2020, 41,400,000 shares of Class A common stock subject to possible redemption are presented as temporary equity, outside of the stockholders’ equity section of our balance sheets.

Class B Common Stock — The Company is authorized to issue 1,000,000 shares of Class B common stock with a par value of $0.0001 per share. On July 17, 2020, the Company effected a 100:1 stock split for each share of Class B common stock, resulting in an aggregate of 120,000 shares of Class B common stock outstanding. On March 24, 2021, the Company effected a 2.5:1 forward stock split for each share of Class B common stock, resulting in an aggregate of 300,000 shares of Class B common stock outstanding. All shares and associated amounts have been retroactively restated to reflect the stock split. As of December 31, 2021 and 2020, there were 300,000 shares of Class B common stock issued and outstanding.

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price threshold for a particular year will be reduced by the dividends per shares of Class A common stock paid in such year. Upon a change of control, holders of the Class B shares shall receive the greater of: (a) the value of 6,000,000 shares of Class A common stock at the time of the announcement of the change of control or $60,000,000. Such calculation shall decrease by 1/12 each year.

Class F Common Stock — The Company is authorized to issue 50,000,000 shares of Class F common stock with a par value of $0.0001 per share. On July 29, 2020, the Company effected a reverse stock split for Class F common stock, resulting in an aggregate of 690,000 shares of Class F common stock. On September 17, 2020, the Company effected a 1 for 1.2 forward stock split that increased the outstanding Class F common stock from 690,000 shares to 828,000 shares. All shares and associated amounts have been retroactively restated to reflect the reverse stock split on July 29, 2020 and the 1 for 1.2 forward stock split on September 17, 2020. As of December 31, 2021 and 2020, there were 828,000 shares of Class F common stock issued and outstanding.

The Founder Shares will automatically convert into shares of Class A common stock concurrently with or immediately following the consummation of a Partnering Transaction on a 1 for 2.5 basis, subject to adjustment for stock splits, stock dividends, reorganizations, recapitalizations and the like. In the case that additional shares of Class A common stock or equity-linked securities are issued or deemed issued in connection with a Partnering Transaction, the number of shares of Class A common stock issuable upon conversion of all founder shares will equal, in the aggregate, on an as converted basis, 5% of the total number of shares of Class A common stock outstanding after such conversion (including the private placement shares) including the total number of shares of Class A common stock issued, or deemed issued or issuable upon conversion or exercise of any equity- linked securities or rights issued or deemed issued, by the Company in connection with or in relation to the consummation of the Partnering Transaction, provided that such conversion of Founder Shares will never occur on a less than 1 for 2.5 basis.

NOTE 9 — Fair Value Measurements

The following table presents information about the Company’s financial assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2021 and 2020 by level within the fair value hierarchy:

	Fair Value Measured as of December 31, 2021
	Level 1			Level 2			Level 3			Total
Assets:
Investments held in Trust Account – U.S. Treasury Securities		$	414,052,978		$	—		$	—		$	414,052,978
Liabilities:
Warrant liabilities – Public Warrants		$	7,027,650		$	—		$	—		$	7,027,650
Warrant liabilities – Private Placement Warrants		$	—		$	—		$	107,910		$	107,910

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	Fair Value Measured as of December 31, 2020
	Level 1			Level 2			Level 3			Total
Assets:
Investments held in Trust Account – U.S. Treasury Securities		$	414,011,571		$	—		$	—		$	414,011,571
Liabilities:
Warrant liabilities – Public Warrants		$	10,764,000		$	—		$	—		$	10,764,000
Warrant liabilities – Private Placement Warrants		$	—		$	—		$	165,780		$	165,780

Transfers to/from Levels 1, 2, and 3 are recognized at the beginning of the reporting period. The estimated fair value of the Public Warrants transferred from a Level 3 measurement to a Level 1 fair value measurement in December 2020, upon trading of the Public Warrants in an active market. There were no transfers between levels for the year ended December 31, 2021.

The fair value of the Public Warrants issued in connection with the Initial Public Offering was initially measured using a Monte Carlo simulation model and subsequently been measured based on the listed market price of such warrants. The fair value of the warrants issued in connection with the Private Placement have been estimated using a Black-Scholes Option Pricing model at each measurement date.

The estimated fair value of the Private Placement Warrants, and the Public Warrants prior to being separately listed and traded, is determined using Level 3 inputs. Inherent in a Black-Scholes Option Pricing model are assumptions related to expected stock-price volatility, expected life, risk-free interest rate and dividend yield. The Company estimates the volatility of its Class A common stock warrants based on implied volatility from the Company’s traded warrants. The risk-free interest rate is based on the U.S. Treasury zero-coupon yield curve on the grant date for a maturity similar to the expected remaining life of the warrants. The expected life of the warrants is assumed to be equivalent to their remaining contractual term. The dividend rate is based on the historical rate, which the Company anticipates remaining at zero. Significant increases (decreases) in the expected volatility in isolation would result in a significantly higher (lower) fair value measurement.

The following table provides quantitative information regarding Level 3 fair value measurements inputs at their measurement:

	December 31, 2021			December 31, 2020
Exercise price		$	11.50		$	11.50
Stock Price		$	9.81		$	10.01
Term (in years)			5.00			5.00
Volatility			14.20%			17.00%
Risk-free interest rate			1.34%			0.56%
Dividend yield			0.00%			0.00%
Probability of success			80.00%			100.00%

The change in the fair value of the derivative warrant liabilities measured with Level 3 inputs for the year ended December 31, 2021 and for the period from June 22, 2020 (inception) through December 31, 2020 is summarized as follows:

Level 3 warrant liabilities as of June 22, 2020 (inception)	$	—
Issuance of Public and Private Placement Warrants		13,765,730
Transfer of Public Warrants to Level 1		(12,109,500)
Change in fair value of derivative warrant liabilities		(1,490,450)
Level 3 warrant liabilities as of December 31, 2020		165,780
Change in fair value of derivative warrant liabilities		(57,870)
Level 3 warrant liabilities as of December 31, 2021	$	107,910

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NOTE 10 — Income Taxes

The Company does not currently have taxable income but will generate taxable income in the future primarily consisting of interest income earned on the Trust Account. The Company’s general and administrative costs are generally considered start-up costs and are not currently deductible.

The income tax provision (benefit) consists of the following for year ended December 31, 2021 and for the period from June 22, 2020 (inception) through December 31, 2020:

	For the Year Ended December 31, 2021			For the Period from June 22, 2020 (Inception) through December 31, 2020
Current
Federal		$	(24,709)		$	(19,444)
State			—			—
Deferred
Federal			(462,887)			(53,126)
State			—			—
Valuation allowance			487,596			72,570
Income tax provision		$	—		$	—

The Company’s net deferred tax assets are as follows as of December 31, 2021 and 2020:

	As of December 31,
	2021			2020
Deferred tax assets:
Start-up/Organization costs		$	516,013		$	53,126
Net operating loss carryforwards			44,153			19,444
Total deferred tax assets			560,166			72,570
Valuation allowance			(560,166)			(72,570)
Deferred tax asset, net of allowance		$	—		$	—

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible. Management considers the scheduled reversal of deferred tax assets, projected future taxable income and tax planning strategies in making this assessment. After consideration of all of the information available, management believes that significant uncertainty exists with respect to future realization of the deferred tax assets and has therefore established a full valuation allowance.

There were no unrecognized tax benefits as of December 31, 2021 and 2020. No amounts were accrued for the payment of interest and penalties as of December 31, 2021 and 2020. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company is subject to income tax examinations by major taxing authorities since inception.

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A reconciliation of the statutory federal income tax rate (benefit) to the Company’s effective tax rate (benefit) is as follows:

	For the Year Ended December 31, 2021		For the Period from June 22, 2020 (Inception) through December 31, 2020
Statutory federal income tax rate		21.0%		21.0%
Change in fair value of derivative warrant liabilities		(54.1)%		(25.8)%
Offering costs associated with derivative warrant liabilities		0.0%		1.7%
Change in valuation allowance		33.1%		3.1%
Income tax expenses (benefit)		0.0%		0.0%

NOTE 11 — Subsequent Events

The Company evaluated subsequent events and transactions that occurred after the balance sheet date up to the date that the financial statements were issued. Based upon this review, other than as noted below, the Company did not identify any subsequent events that have occurred that would require adjustments to the disclosures in the financial statements.

In February 2022, the Russian Federation and Belarus commenced a military action with the country of Ukraine. As a result of this action, various nations, including the United States, have instituted economic sanctions against the Russian Federation and Belarus. Further, the impact of this action and related sanctions on the world economy are not determinable as of the date of these financial statements and the specific impact on the Company’s financial condition, results of operations, and cash flows is also not determinable as of the date of these financial statements.

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GREY ROCK ENERGY FUND III
(PREDECESSOR TO GRANITE RIDGE RESOURCES, INC.)

CONDENSED COMBINED BALANCE SHEETS

	As of September 30, 2022			As of December 31, 2021
(in thousands)	(Unaudited)
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

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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		$	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

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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

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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

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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”.

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.

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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 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.

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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

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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

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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.

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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.

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.

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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

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

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

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

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

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

4. Fair value measurements

Fair Values — Recurring

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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:

(in thousands)	Level 1			Level 2			Level 3			September 30, 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:

(in thousands)	Level 1			Level 2			Level 3			December 31, 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.

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.

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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.

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.

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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

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

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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.

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.

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

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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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Report of Independent Registered Public Accounting Firm

To the Partners
Grey Rock Energy Fund III-A, LP
Grey Rock Energy Fund III-B, LP
Grey Rock Energy Fund III-B Holdings, LP
Grey Rock Preferred Limited Partner III, L.P.
Dallas, Texas

Opinion on the Combined Financial Statements

We have audited the accompanying combined balance sheets of Grey Rock Energy Fund III-A, LP and its subsidiaries, Grey Rock Energy Fund III-B, LP, Grey Rock Energy Fund III-B Holdings, LP and its subsidiaries and Grey Rock Preferred Limited Partner III, L.P. (collectively, the Partnership) as of December 31, 2021 and 2020, the related combined statements of operations, changes in partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively referred to as the “combined financial statements”).

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These combined financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s combined financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the combined financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the combined financial statements.

Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the combined financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ FORVIS, LLP

We have served as the Partnership’s auditor since 2018.

Dallas, Texas
September 9, 2022

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GREY ROCK ENERGY FUND III

Combined Balance Sheets

	December 31,
	2021			2020
ASSETS
Current assets:
Cash		$	7,319,365		$	2,637,558
Revenue receivable			32,697,273			9,499,185
Advances to operators			37,149,729			8,170,656
Other assets			69,436			—
Other Receivable			468,596			—
Contributions receivable			93,687			73,541
Total current assets			77,798,086			20,380,940
Property and equipment:
Oil and natural gas properties, successful efforts method			376,657,406			211,705,035
Accumulated depletion			(98,265,958)			(39,223,565)
Total property and equipment, net			278,391,448			172,481,470
TOTAL ASSETS		$	356,189,534		$	192,862,410
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued expenses		$	6,639,039		$	3,819,158
Derivative liabilities – current portion			3,952,787			213,093
Credit facilities – current portion			29,938,307			—
Total current liabilities			40,530,133			4,032,251
Long-term liabilities:
Credit facilities			—			9,897,179
Derivative liabilities			400,285			—
Asset retirement obligations			963,428			503,543
Total long-term liabilities			1,363,713			10,400,722
Commitments and contingencies (Note 9)
Partners’ capital:
General partner			15,462,283			657,346
Limited partners			298,833,405			177,772,091
Total partners’ capital			314,295,688			178,429,437
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$	356,189,534		$	192,862,410

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

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GREY ROCK ENERGY FUND III

Combined Statements of Operations

	Year ended December 31,
	2021			2020			2019
REVENUES
Oil, natural gas, and related product sales		$	197,545,818		$	28,290,460		$	23,282,767
EXPENSES
Lease operating expenses			12,361,625			5,146,922			2,668,218
Production taxes			10,807,624			1,815,408			1,368,712
Depletion and accretion expense			60,533,801			22,130,049			17,100,435
Professional fees			1,552,702			790,010			939,246
Management fees			3,877,500			3,877,500			3,877,500
General and administrative			832,573			498,209			143,939
Organizational expenses			—			—			21,496
Total expenses			89,965,825			34,258,098			26,119,546
Net operating income/(loss)			107,579,993			(5,967,638)			(2,836,779)
OTHER EXPENSE
Gain/(loss) on derivative contracts			(17,314,944)			2,928,004			137,440
Interest expense			(1,398,798)			(428,187)			(509,242)
Total other income/(expense)			(18,713,742)			2,499,817			(371,802)
NET INCOME/(LOSS)		$	88,866,251		$	(3,467,821)		$	(3,208,581)

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

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GREY ROCK ENERGY FUND III

Combined Statements of Changes in Partners’ Capital

	General Partner			Limited Partner			Total
Balance at December 31, 2018		$	176,012		$	58,429,824		$	58,605,836
Net income/(loss)			34,607			(3,243,188)			(3,208,581)
Partners’ contributions			157,164			53,342,839			53,500,003
Balance at December 31, 2019		$	367,783		$	108,529,475		$	108,897,258
Net income/(loss)			62,790			(3,530,611)			(3,467,821)
Partners’ contributions			226,773			72,773,227			73,000,000
Balance at December 31, 2020		$	657,346		$	177,772,091		$	178,429,437
Net income			288,107			88,578,144			88,866,251
Partners’ contributions			146,004			46,853,996			47,000,000
Carried interest reallocation			14,370,826			(14,370,826)			—
Balance at December 31, 2021		$	15,462,283		$	298,833,405		$	314,295,688

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

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GREY ROCK ENERGY FUND III

Combined Statements of Cash Flows

	Year Ended December,
	2021			2020			2019
Operating activities:
Net income/(loss)		$	88,866,251		$	(3,467,821)		$	(3,208,581)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Depletion and accretion expense			60,533,801			22,130,049			17,100,434
Unrealized (gain)/loss on derivative contracts			4,139,979			(90,190)			303,283
Amortization of loan origination costs			41,128			41,127			20,564
Increase/(decrease) in cash attributable to changes in operating assets and liabilities:
Revenue receivable			(23,198,088)			(4,644,088)			(4,789,329)
Other assets			(69,436)			—			—
Accrued expenses			1,402,522			116,027			(756,545)
Net cash provided by operating activities			131,716,157			14,085,104			8,669,826
Investing activities:
Acquisition of proved oil and gas properties			(83,181,294)			(13,263,947)			(34,868,314)
Proceeds from the disposal of oil and gas properties			3,027,165			—			—
Refund of advances to operators			3,248,808			—			—
Development of oil and gas properties			(117,108,883)			(67,603,965)			(48,838,994)
Net cash used in investing activities			(194,014,204)			(80,867,912)			(83,707,308)
Financing activities:
Proceeds from borrowing			52,000,000			26,000,000			21,335,488
Repayments of borrowing			(32,000,000)			(32,500,000)			(5,000,000)
Partners’ contributions, net of change in contributions receivable			46,979,854			72,946,652			53,479,810
Net cash provided by financing activities			66,979,854			66,446,652			69,815,298
Net increase/(decrease) in cash			4,681,807			(336,156)			(5,222,184)
Cash at beginning of year			2,637,558			2,973,714			8,195,898
Cash at end of year		$	7,319,365		$	2,637,558		$	2,973,714
Supplemental disclosure of cash flow information
Cash paid during the year for interest		$	740,331		$	482,903		$	482,903
Supplemental disclosure of non cash investing activities
Acquired and assumed asset retirement obligations		$	36,893		$	138,150		$	209,622
Revision of asset retirement obligations		$	439,763		$	63,160		$	2,905
Oil and natural gas property development costs in accrued expenses		$	4,612,322		$	3,194,963		$	679,009

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

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GREY ROCK ENERGY FUND III

Notes to the Combined Financial Statements

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 (“Commencement of Operations”). 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 (“Commencement of Operations”). 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, and realizing profits through participation in oil and natural gas wells.

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 (“Commencement of Operations”). Grey Rock III-B was created for the purpose of acquiring net profits interests (“NPI”) in oil and natural gas assets from Grey Rock III-B Holdings, a related party, in multiple basins in North America, in accordance with the 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 (“Commencement of Operations”). 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” or “Grey Rock Energy Fund III”.

Grey Rock Energy Partners GP III-A, LP, a Delaware limited partnership (the “General Partner”), acts as general partner of Grey Rock III-A. Grey Rock Energy Partners GP III-B, LP, a Delaware limited partnership (the “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 8 years. The investment term is 3 years and may be extended by the General Partner, in its sole discretion, for one year. The harvest period is 3 years and may be extended by the General Partner, in its sole discretion, for one year. 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.

On May 16, 2022, the Partnership and certain funds affiliated with Grey Rock (collectively, “GREP”) signed a business combination agreement (“BCA”) with Executive Network Partnering Corporation (“ENPC”), a New York Stock Exchange (“NYSE”) publicly traded special purpose acquisition company, valued at approximately $1.3 billion. The business combination is expected to close upon ENPC stockholder approval and satisfaction of other customary closing conditions. GREP is expected to be listed on the NYSE under the ticker symbol “GRNT”.

Summary of significant accounting policies

Principles of Combination

The accompanying 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 are commonly owned and controlled. All inter-entity balances and transactions have been eliminated in combination.

Basis of Presentation

The combined financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Comprehensive income/(loss) for the

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Partnership is the same as net income/(loss) for all years presented. 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 of Financial Instruments

The Partnership has adopted and follows Accounting Standard Codification (“ASC”) 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in 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.

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, and accounts payable and accrued expenses, approximate their fair values because of the short maturity of these instruments.

Cash

Cash represents liquid cash and investments with an original maturity of 90 days or less. The Partnership places its cash with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Partnership has not incurred any losses related to amounts in excess of FDIC limits. As of December 31, 2021 and 2020, the Partnership did not have any restrictions over its cash.

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 years ended December 31, 2021, 2020 and 2019, the Partnership had no bad debt expense, and did not record an allowance for doubtful accounts.

Advance to operators

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may request advance payments from working interest partners for their share of the costs. The Partnership expects such advances to be applied by these operators against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to operators are presented as an investing outflow within capital expenditures for oil and natural gas properties on the statements of cash flows.

Other assets

Other assets is comprised of payments made in advance for services deemed to have future value to the Partnership. At December 31, 2021 prepaid expenses equaled approximately $70,000, respectively. As of December 31, 2020 the Partnership had no prepaid expenses.

Oil and Natural Gas Properties

The Partnership uses the successful efforts method of accounting for oil and natural gas producing activities, as further defined under ASC 932, Extractive Activities — Oil and Gas. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory leases that find proved reserves, and to drill and equip development leases and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determinations of whether the wells have proved reserves. If the Partnership determines that the wells do not have proved reserves, the costs are charged to expense.

There were no exploratory wells capitalized pending determinations of whether the wells have proved reserves at December 31, 2021 and 2020. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. The Partnership capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the years ended December 31, 2021, 2020 and 2019, no interest costs were capitalized because exploration and development projects lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves. Depletion expense for oil and natural gas producing property and related equipment was approximately $60,477,000, $22,096,000 and $17,092,000 for the years ended December 31, 2021, 2020 and 2019, respectively.

Effective January 1, 2019, the Partnership adopted ASU 2017-1, Business Combinations: Clarifying the Definition of Business, which provides a methodology to determine when a set of assets is not a business. The methodology requires that when substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. As a result, the Partnership has determined that no acquisitions of oil and natural gas properties during the year ended December 31, 2021 qualified as the purchase of a business. The Partnership has determined that acquisitions of oil and natural gas properties totaling approximately $1,764,000 during the year ended December 31, 2020 qualified as the purchase of a business. The Partnership has determined that all other acquisitions of oil and natural gas properties qualified as a concentrated group of similar identifiable assets. The Partnership has determined that no acquisitions of oil and natural gas properties during the year ended December 31, 2019 qualified as the purchase of a business. See discussions of the Partnership’s oil and natural gas asset acquisitions in Note 5, Oil and natural gas properties.

Upon the sale or retirement of a complete unit of proved property, the costs and related accumulated depletion are eliminated from the property accounts, and the resulting gain or loss is recognized. Upon the retirement or sale of a partial unit of proved property, the cost is charged to the property accounts without a resulting gain or loss recognized in income. The Partnership sold a partial unit of proved oil and natural gas properties during the year ended December 31, 2021, removing accumulated depletion of approximately $1,434,000. The Partnership did not sell any units of provided oil and natural gas properties during the years ended December 31, 2020 and 2019, respectively.

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accordance with ASC 360, Property, Plant, and Equipment. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Partnership recognizes an impairment charge in operating income equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. The Partnership did not recognize an impairment of proved properties for the years ended December 31, 2021, 2020 and 2019.

Upon the sale or retirement of a complete unit of proved property, the costs and related accumulated impairment are removed from the property accounts, and the resulting gain or loss is recognized. Upon the retirement or sale of a partial unit of proved property, the cost is charged to the property accounts without a resulting gain or loss recognized in income. As a result of the sale of a partial unit of oil and natural gas properties during the year ended December 31, 2021, there was no impact to accumulated impairment. The Partnership did not sell any units of provided oil and natural gas properties during the years ended December 31, 2020 and 2019, respectively.

Asset Retirement Obligation

The Partnership follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which they are incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Partnership’s asset retirement obligation relates to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.

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

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 the 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 gas, less revenue deductions such as gathering, transportation and compression costs. Management has determined that the variable revenue constraint is overcome at the date control passes to the customer since the variable consideration to be received can be reasonably estimated based on daily market prices and historical transportation charges. Revenue is presented net of these costs within the combined statements of income. At the end of each month, amounts due from customers are accrued in revenue receivable in the combined 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.

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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 years ended December 31, 2021, 2020 and 2019, the Partnership’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in 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 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 two 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 years ended December 31, 2021, 2020 and 2019 were approximately $145,643,000, $23,863,000 and $20,811,000, respectively. Natural gas and NGL sales for the years ended December 31, 2021, 2020 and 2019 were approximately $51,903,000, $4,427,000 and $2,472,000, respectively.

The Partnership’s disaggregated revenue has two primary sources: oil sales and natural gas sales. Substantially all of the Partnership’s oil and natural gas sales come from four geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Denver-Julesburg “DJ” (Colorado) and the Bakken Basin (Montana/North Dakota). The following tables present the disaggregation of the Partnership’s oil revenues and natural gas revenues by basin for the years ended December 31, 2021, 2020 and 2019.

	Year Ended December 31, 2021
	Eagle Ford			Permian			Denver-Julesburg			Bakken
Revenues		$	26,091,370		$	137,802,417		$	29,190,615		$	4,461,416

	Year Ended December 31, 2020
	Eagle Ford			Permian			Denver-Julesburg			Bakken
Revenues		$	3,607,702		$	21,906,740		$	—		$	2,776,018

	Year Ended December 31, 2019
	Eagle Ford			Permian			Denver-Julesburg			Bakken
Revenues		$	6,038,886		$	13,899,122		$	—		$	3,344,759

Lease Operating Expenses

Lease operating expenses represent severance and production taxes, field employees’ salaries, salt water disposal, ad valorem taxes, repairs and maintenance, expensed work overs and other operating expenses. Lease operating expenses are expensed as incurred.

Production Taxes

The Partnership incurs severance tax on the sale of its production which is generated in Texas, Colorado and North Dakota. These taxes are reported on a gross basis and are included in production taxes within the accompanying combined statements of operations. Sales-based taxes for the years ended December 31, 2021, 2020 and 2019 were approximately $10,808,000, $1,815,000 and $1,369,000, respectively.

Ad Valorem Taxes

The Partnership incurs ad valorem tax on the value of its properties in Texas. These taxes are included in lease operating expenses within the accompanying combined statements of operations. Ad valorem taxes for the years ended December 31, 2021, 2020 and 2019 were approximately $488,000, $71,000 and $43,000, respectively.

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Income Taxes

Because the Partnership is a limited partnership interest, 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 agreements, 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 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 December 31, 2021 and 2020. 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.

Use of Estimates

The preparation of 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 combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

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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 becomes effective for us beginning January 1, 2022 and the Partnership expects to adopt using a modified retrospective approach with certain available practical expedients. Oil and gas leases are excluded from the guidance. We do not expect this ASU to materially affect the combined financial statements, cash flows and related note disclosures.

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

Derivative instruments

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 swap contracts and collar options. 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 combined statements of operations. There were no derivative assets as of December 31, 2021 or 2020. Derivative liabilities are included within current and noncurrent liabilities in the combined balance sheets as of December 31, 2021. All derivative liabilities were classified as current as of December 31, 2020.

Swap, Collar, and Producer 3-way Option Contracts

Generally, a swap contract is an agreement that obligates two parties to exchange a series of cash flows at specified intervals based upon or calculated by reference to changes in specified prices or rates for a specified notional amount of the underlying assets. The payment flows are usually netted against each other, with the difference being paid by one party to the other.

The fair value of open swaps, collar options, and producer 3-way contracts reported in the 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 swap or option contract to comply with the terms of the swap or option contract. The loss incurred by the failure of counterparties is generally limited to the aggregate fair value of swap or option contracts in an unrealized gain position as well as any collateral posted with the counterparty. The loss incurred by the failure of counterparties is generally limited to the aggregate fair value of swap or option contracts in an unrealized gain position as well as any collateral posted with the counterparty.

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

Volume of Derivative Activities

At December 31, 2021, 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:

Year

Type of Contract

(Volume/Month)

Contract Prices

Range

Weighted
Average

Jan 2022 – Jun 2023

Producer 3-way (crude oil)

58,165 – 2,340

$87.50 – $40.00

61.31

Feb 2022 – Mar 2023

Producer 3-way (natural gas)

195,124 – 26,519

$7.85 – $1.90

3.66

Feb 2022 – Dec 2022

Collar (natural gas)

141,473 – 37,042

$4.33 – $2.80

3.45

At December 31, 2020, 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:

Year

Contract Prices

Type of Contract

(Volume/Month)

Range

Weighted
Average

Jan 2021 – Dec 2021

Collar (crude oil)

4,257 – 1,779

$46.65 – $32.50

39.58

Jan 2021 – Dec 2021

Producer 3-way (crude oil)

35,290 – 9,215

$58.25 – $34.06

44.71

Feb 2021 – Jun 2021

Collar (natural gas)

66,182 – 38,186

$3.48 – $2.15

2.75

Jul 2021 – Dec 2021

Short swap (natural gas)

36,354 – 30,699

$2.81

2.81

Feb 2021 – Apr 2022

Producer 3-way (natural gas)

39,885 – 10,579

$3.63 – $2.00

2.79

Impact of Derivatives on the Combined Balance Sheets and Combined Statements of Operations

The following table identifies the fair value amounts of derivative instruments included in the accompanying combined balance sheets as derivative liabilities categorized by primary underlying risk, at December 31, 2021. The following table also identifies the net loss amounts included in the accompanying combined statements of operations as gain/(loss) on derivative contracts for the year ended December 31, 2021.

	Derivative assets			Derivative liabilities			Total loss from derivative instruments
Primary underlying risk Commodity price
Crude oil		$	—		$	(3,876,240)		$	(13,937,479)
Natural gas			—			(476,832)			(3,377,465)
Total		$	—		$	(4,353,072)		$	(17,314,944)

	Realized loss			Unrealized loss			Total
Primary underlying risk Commodity price
Crude oil		$	(10,350,846)		$	(3,586,633)		$	(13,937,479)
Natural gas			(2,824,119)			(553,346)			(3,377,465)
Total		$	(13,174,965)		$	(4,139,979)		$	(17,314,944)

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The following table identifies the fair value amounts of derivative instruments included in the accompanying combined balance sheets as derivative liabilities categorized by primary underlying risk, at December 31, 2020. The following table also identifies the net gain amounts included in the accompanying combined statements of operations as gain/(loss) on derivative contracts for the year ended December 31, 2020.

	Derivative assets			Derivative liabilities			Total gain from derivative instruments
Primary underlying risk Commodity price
Crude oil		$	—		$	(289,606)		$	2,621,558
Natural gas			76,513			—			306,446
Total		$	76,513		$	(289,606)		$	2,928,004

	Realized gain			Unrealized gain			Total
Primary underlying risk Commodity price
Crude oil		$	2,535,138		$	86,420		$	2,621,558
Natural gas			302,676			3,770			306,446
Total		$	2,837,814		$	90,190		$	2,928,004

The following table identifies the net gain amounts included in the accompanying combined statements of operations as gain/(loss) on derivative contracts for the year ended December 31, 2019.

	Realized gain			Unrealized (loss)/gain			Total
Primary underlying risk Commodity price
Crude oil		$	423,033		$	(376,027)		$	47,006
Natural gas			17,690			72,744			90,434
Total		$	440,723		$	(303,283)		$	137,440

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 liabilities measured at fair value as of December 31, 2021:

	Level 1			Level 2			Level 3			December 31, 2021
Liabilities (at fair value):
Derivative		$	—		$	(4,353,072)		$	—		$	(4,353,072)

The following table presents information about the Partnership’s recurring liabilities measured at fair value as of December 31, 2020:

	Level 1			Level 2			Level 3			December 31, 2020
Liabilities (at fair value):
Derivative		$	—		$	(213,093)		$	—		$	(213,093)

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

	December 31, 2021						December 31, 2020
	Carrying Value			Fair Value			Carrying Value			Fair Value
Liabilities (not at fair value):
Revolving credit facility		$	29,938,307		$	29,938,307		$	9,897,179		$	9,897,179

Fair Values — Non Recurring

Oil and natural gas properties

Oil and natural gas properties consisted of only proved properties as of December 31, 2021 and 2020. The book value of the Partnership’s oil and natural gas properties consists of all acquisition costs, drilling costs and other associated capitalized costs.

In certain acquisitions, the oil and natural gas properties have ongoing development, and as the non-operator, the Partnership is committed to fund future costs associated with the assumed authorization for expenditures (AFE). The consideration exchanged for the assets acquired and liabilities assumed was derived using the asset approach to calculate the fair-value shortly before the acquisition dates and was completed to provide a return to the investors of the Partnership. The consideration exchanged for the assets acquired and liabilities assumed was derived using ASU 2017-1 to calculate the fair-value shortly before the acquisition dates. Certain acquisitions of oil and natural gas properties meet the definition of a business combination under the ASC 805, Business Combinations, and have been accounted for using the acquisition method of accounting. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values.

2021 Acquisitions

Bakken Basin — The Partnership acquired proved undeveloped oil and natural gas properties in the Bakken Basin of approximately $188,000 in February. Customary post close adjustments were made during the year end December 31, 2021 which resulted in cash outflow of approximately $3,000.

Permian Basin — The Partnership acquired proved undeveloped oil and natural gas properties in the Permian Basin of approximately $1,480,000 in January, $508,000 in February, $619,000 in March, $3,293,000 in April, $12,000 in June, $3,785,000 in July, $13,608,000 in September, $4,554,000 in October, $8,527,000 in November, and $4,225,000 in December. The Partnership acquired proved oil and natural gas properties in the Permian Basin of approximately $100,000 in January. The Partnership paid customary opportunity fees during the year end December 31, 2021 which resulted in cash outflow of approximately $3,065,000.

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DJ Basin — The Partnership acquired proved developed nonproducing oil and natural gas properties, and proved oil and natural gas properties of approximately $3,669,000 and $36,697,000 in April. Customary post close adjustments were made during the year end December 31, 2021 which resulted in cash inflow of approximately $1,149,000.

2021 Divestitures

Eagle Ford Basin — For the year ended December 31, 2021, the Partnership sold a partial unit of oil and natural gas properties in the Eagle Ford Basin for approximately $3,027,000, eliminating equivalent amounts from the property accounts.

2020 Acquisitions

Bakken Basin — The Partnership acquired proved undeveloped oil and natural gas properties in the Bakken Basin of approximately $89,000 in April. Customary post close adjustments were made during the year end December 31, 2020 which resulted in cash inflow of approximately $52,000.

Permian Basin — The Partnership acquired proved undeveloped oil and natural gas properties in the Permian Basin of approximately $5,440,000 in February, $88,000 in April, $3,136,000 in May, $496,000 in June, $1,835,000 in September, and $255,000 in November. The Partnership acquired proved developed nonproducing oil and natural gas properties of approximately $57,000 in April and $249,000 in August. The Partnership acquired proved oil and natural gas properties in the Permian Basin of approximately $1,800,000 in February and made customary post close adjustments that resulted in cash inflows of approximately $36,000 in August that included proved developed producing properties. This acquisition met the definition of a business combination. The fair value of assets acquired and liabilities assumed is outlined in the paragraph below. Unrelated customary post close adjustments were made during the year end December 31, 2020 which resulted in cash inflow of approximately $93,000.

The following table presents a summary of the fair value of the assets acquired and the liabilities assumed in the Permian Basin acquisition that met the definition of a business combination:

	December 31, 2020
Fair value of proved assets acquired and liabilities assumed
Proved oil and gas properties(1)		$	1,766,581
Less: Asset retirement obligations			(3,031)
Net assets acquired			1,763,550
Cash consideration transferred (including liabilities assumed)		$	1,763,550

(1)

Amount includes asset retirement costs of $3,031 for 2020

2020 Divestitures

For the year ended December 31, 2020 the Partnership did not divest of any oil and natural gas properties.

2019 Acquisitions

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December 31, 2019, the Partnership acquired various proved oil and natural gas properties, which included working interests ranging from 0.43%-43.86%, net revenue interests ranging from 0.33% – 36.92%, in Texas and North Dakota.

Bakken Basin — The Partnership acquired oil and natural gas properties in the Bakken Basin of approximately $24,707,000 in June. Customary post close adjustments were made during the year end December 31, 2019 which resulted in cash inflow of approximately $805,000.

Eagle Ford Basin — The Partnership acquired oil and natural gas properties in the Eagle Ford Basin of approximately $1,179,000 in September, $2,285,000 in October, and $527,000 in December. The Partnership acquired various proved undeveloped properties in the Eagle Ford Basin of approximately $597,000 in June, $125,000 in July, $321,000 in September and $5,932,000 in October.

2019 Divestitures

For the year ended December 31, 2019 the Partnership did not divest of any oil and natural gas properties.

Asset retirement obligations

The Partnership has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations have been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of December 31, 2021 and 2020. In 2021 the estimated liability was revised downward due to price increases which extended the useful life of the assets. In 2020, declining prices lead to a decrease in the useful life of the assets resulting in an increase to the estimate. The Partnership evaluated 843 and 122, respectively, wells and has estimated a range of abandonment dates between the years 2023 and 2058.

The following table presents the changes in the asset retirement obligations during the years ended December 31, 2021, 2020 and 2019:

	2021			2020			2019
Asset retirement obligations, beginning of year		$	503,543		$	267,791		$	46,835
Additions to capitalized asset retirement obligations			439,762			138,151			209,622
Revisions to asset retirement costs			(36,893)			63,160			2,905
Accretion of discount			57,016			34,441			8,429
Asset retirement obligations, end of year		$	963,428		$	503,543		$	267,791

Partners’ capital

Commitments and contributions

Funded and unfunded capital commitments as of December 31, 2021 are as follows:

	General Partner			Limited Partner			Total
Committed capital		$	750,000		$	240,680,450		$	241,430,450
Less: Unfunded committed capital			120,867			5,289,019			5,409,886
Funded Capital Contributions		$	629,133		$	235,391,431		$	236,020,564

Funded and unfunded capital commitments as of December 31, 2020 are as follows:

	General Partner			Limited Partner			Total
Committed capital		$	750,000		$	240,680,450		$	241,430,450
Less: Unfunded committed capital			245,127			52,144,613			52,389,740
Funded Capital Contributions		$	504,873		$	188,535,837		$	189,040,710

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The balance of the Partnership’s unfunded commitments is due upon one or more capital calls by the General Partner, as needed by the Partnership for property acquisitions or operations by the Partnership. As of December 31, 2021 and 2020, contributions receivable was approximately $84,000 and $63,000, respectively, from the General Partner and approximately $10,000 and $11,000, respectively, from Limited Partners.

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

Allocation of Net Profits and Losses

(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)

(d)

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

In accordance with the Limited Partnership Agreement, the reallocation from the general partner to the limited partners was approximately $14,371,000 for the year ended December 31, 2021. There was no reallocation between partners during the years ended December 31, 2020 and December 31, 2019. The allocation of carried interest will remain provisional until the final liquidation of the Partnership.

Distributions

Related party transactions

The Partnership pays an annual management fee to the Management Company as compensation for providing managerial services to the Partnership. The management fee will accrue beginning on the initial closing date 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 years ended December 31, 2021, 2020 and 2019, annual management fees were approximately $3,878,000.

As of December 31, 2021 and 2020, the Partnership had a related party payable with the Management Company for organizational expenses incurred on behalf of the Partnership of approximately $8,000 and $7,000 respectively, that was included in accrued expenses on the accompanying combined balance sheets. During the years ended December 31, 2021, 2020 and 2019, the organizational expenses incurred on behalf of the Partnership were approximately $223,000, $180,000 and $342,000, respectively.

Commitments and contingencies

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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. As of December 31, 2021 there were no significant outstanding commitments.

10.

Credit facility

Since 2018, the Partnership has maintained a revolving credit facility (the “Facility”) which had an initial borrowing capacity of $24,000,000. As of December 31, 2021 and 2020, the borrowing capacity was $100,000,000 and $19,000,000, respectively, of which approximately $30,000,000 and $10,000,000, respectively was outstanding. The Facility has a maturity date of October 26, 2022.

The Facility is collateralized by all of the oil and natural gas properties of the Partnership and requires compliance with certain financial covenants. As of December 31, 2021 and 2020, the Partnership, was in compliance with all covenants required by the Facility. Further, the Partnership had unamortized loan origination costs of $62,000 and $103,000 as of December 31, 2021 and 2020, respectively.

Additionally, the Facility bears interest at an annual base rate of the Prime Rate minus an acceptable margin of 0.50%. As of December 31, 2021 and 2020, the weighted average interest rate on borrowed amounts was approximately 3.35% and 3.37%, respectively.

While the Facility has a due date within one year of the issuance of these combined financial statements, the Partnership utilizes the financing for long-term operating purposes and does not have liquid funds available to repay the balance as of December 31, 2021. Management intends to renew the Facility on comparable terms at or near the maturity date and believes it is probable such renewal will be successful.

11.

Risk concentrations

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 continues to significantly impact the worldwide economy and specific economic sectors. As a result, commodity prices declined precipitously, which may impact the Partnership’s performance and may lead to future losses.

12.

Subsequent events

In connection with preparing the combined financial statements for the year ended December 31, 2021, management has evaluated subsequent events for potential recognition and disclosure through the date September 9, 2022, which is the date the combined financial statements were available to be issued.

Through September 9, 2022, the Partnership repaid approximately $35,000,000, and borrowed approximately $16,000,000 from the revolving credit facility.

Through September 9, 2022, the Partnership acquired oil and natural gas properties totaling approximately $35,734,000. Customary post close adjustments on prior period acquisitions resulted in approximately $755,000 being eliminated from the property accounts.

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13.

Supplemental Oil and Gas Information (unaudited)

Oil and Natural Gas Exploration and Production Activities

Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profit interests and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, material, supplies, and fuel consumed. Production taxes include production and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts.

Oil and Natural Gas Reserves and Related Financial Data

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

Oil and Natural Gas Reserve Data

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

	Natural Gas (MMcf)		Oil (MBbl)		MBoe
Proved Developed and Undeveloped Reserves at December 31, 2018		13,148		4,722		6,914
Revisions of Previous Estimates		(7,494)		(1,681)		(2,930)
Extensions, Discoveries and Other Additions		1,704		917		1,201
Acquisition of Reserves		19,686		1,788		5,069
Production		(1,309)		(386)		(604)
Proved Developed and Undeveloped Reserves at December 31, 2019		25,735		5,360		9,650
Revisions of Previous Estimates		(10,129)		(101)		(1,790)
Extensions, Discoveries and Other Additions		950		798		956
Acquisition of Reserves		8,615		3,918		5,353
Production		(2,506)		(626)		(1,043)
Proved Developed and Undeveloped Reserves at December 31, 2020		22,665		9,349		13,126
Revisions of Previous Estimates		1,838		186		493
Extensions, Discoveries and Other Additions		8,505		1,948		3,365
Acquisition of Reserves		39,254		7,673		14,216
Production		(8,761)		(2,295)		(3,755)
Proved Developed and Undeveloped Reserves at December 31, 2021		63,501		16,861		27,445

Notable changes in proved reserves for the year ended December 31, 2021 included the following:

•

Extensions and discoveries. In 2021, total extensions and discoveries of 3,365 MBoe were primarily attributable to successful drilling in the Eagle Ford and Permian Basins as well as the addition of

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proved undeveloped locations. Included in these extensions and discoveries were 233 MBoe as a result of successful drilling in the Eagle Ford and Permian Basins and 3,120 MBoe as a result of additional proved undeveloped locations. Extensions from current production were 12 MBoe from the Eagle Ford and Permian Basins.

•

Revisions to previous estimates. In 2021, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 493 MBoe. The upward revision in reserves was due to higher crude oil prices, increasing reserves by 1,550 MBoe, offset by unfavorable adjustments attributable to well performance of 1,057 MBoe.

•

Acquisition of reserves. In 2021, total acquisition of reserves of 14,216 MBoe were primarily attributable to acquisitions of oil and natural gas properties in the Permian, Bakken and DJ Basins (see Note 5).

Notable changes in proved reserves for the year ended December 31, 2020 included the following:

•

Extensions and discoveries. In 2020, total extensions and discoveries of 956 MBoe were primarily attributable to successful drilling in the Permian Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 418 MBoe as a result of successful drilling in the Permian Basin and 494 MBoe as a result of additional proved undeveloped locations. Extensions from current production were 44 MBoe from the Permian Basin.

•

Revisions to previous estimates. In 2020, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 1,790 MBoe. The downward revision in reserves was due to a combination of unfavorable adjustments attributable to well performance and lower crude oil prices, reducing reserves by 1,497 MBoe and 293 MBoe, respectively.

•

Acquisition of reserves. In 2020, acquisition of reserves of 5,353 MBoe were primarily attributable to acquisitions of oil and natural gas properties in the Permian and Bakken Basins (see Note 5).

Notable changes in proved reserves for the year ended December 31, 2019 included the following:

•

Extensions and discoveries. In 2019, total extensions and discoveries of 1,201 MBoe were primarily attributable to successful drilling in the Permian Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 396 MBoe as a result of successful drilling in the Permian Basin and 805 MBoe as a result of additional proved undeveloped locations.

•

Revisions to previous estimates. In 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,930 MBoe. The downward revision in reserves was due to a combination of unfavorable adjustments attributable to the removal of proven undeveloped locations and lower crude oil prices, reducing reserves by 2,105 MBoe and 825 MBoe, respectively.

•

Acquisition of reserves. In 2019, acquisition of reserves of 5,069 MBoe were primarily attributable to acquisitions of oil and natural gas properties in the Bakken and Eagle Ford Basins (see Note 5).

	Natural Gas (MMcf)		Oil (MBbl)		MBoe
Proved Developed Reserves:
December 31, 2018		442		530		604
December 31, 2019		8,381		2,177		3,574
December 31, 2020		15,479		5,256		7,836
December 31, 2021		30,710		6,815		11,934
Proved Undeveloped Reserves:
December 31, 2018		12,706		4,192		6,310
December 31, 2019		17,354		3,183		6,076
December 31, 2020		7,186		4,093		5,290
December 31, 2021		32,791		10,046		15,511

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

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

Future oil and natural gas sales, production and development costs have been estimated using prices and costs in effect at the end of the years included, as required by ASC 932, Extractive Activities — Oil and Gas (“ASC 932”). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our oil and natural gas reserves and for asset retirement obligations, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Partnership’s proved oil and natural gas reserves. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Partnership. Material revisions to estimates of proved reserves may occur in the future; development and production of reserves may not occur in the period assumed; actual prices realized are expected to vary significantly from those used and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2021, 2020 and 2019:

	December 31,
	2021			2020			2019
	(In thousands)
Future cash inflows		$	1,428,934		$	391,069		$	345,651
Future production costs			(381,379)			(145,370)			(92,391)
Future development costs			(175,771)			(66,800)			(89,055)
Future income tax expense			(5,272)			(1,893)			(1,592)
Future net cash flows			866,512			177,006			162,613
10% discount for estimated timing of cash flows			(313,947)			(71,106)			(78,244)
Standardized measure of discounted future net cash flows		$	552,565		$	105,900		$	84,369

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

	December 31,
	2021			2020			2019
	(In thousands)
Balance, beginning of year		$	105,900		$	84,369		$	80,986
Sales of oil and natural gas produced, net of production costs			(174,377)			(21,328)			(19,246)
Extensions and discoveries			43,615			7,579			14,068
Previously estimated development cost incurred during the period			12,545			21,346			18,317
Net change of prices and production costs			185,875			(42,576)			(20,175)
Change in future development costs			(2,877)			4,157			(1,745)
Revisions of quantity and timing estimates			15,854			(10,497)			(27,921)
Accretion of discount			10,702			8,516			8,190
Change in income taxes			(2,194)			(332)			125
Acquisition of Reserves			332,947			60,676			33,708
Other			24,575			(6,010)			(1,938)
Balance, end of period		$	552,565		$	105,900		$	84,369

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

	(Unaudited)
(in thousands)	As of September 30, 2022			As of December 31, 2021
ASSETS
Current assets:
Cash		$	2,033		$	740
Revenue receivable			1,683			1,199
Prepaid expenses			—			14
Derivative assets			50			—
Other assets			962			—
Total current assets			4,728			1,953
Property and equipment:
Oil and gas properties, successful efforts method			45,617			44,128
Accumulated depletion			(30,658)			(29,082)
Total property and equipment, net			14,959			15,046
TOTAL ASSETS		$	19,687		$	16,999
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued expenses		$	652		$	636
Other payable			1			12
Derivative liabilities			29			29
Total current liabilities			682			677
Long-term liabilities:
Credit facilities			—			1,100
Asset retirement obligations			320			248
Total long-term liabilities			320			1,348
TOTAL LIABILITIES			1,002			2,025
Commitments and contingencies (Note 8)
Partners’ capital:
General partner			161			129
Limited partners			18,524			14,845
Total partners’ capital			18,685			14,974
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$	19,687		$	16,999

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

Condensed Consolidated Statements of Income (Unaudited)

	Nine months ended September 30,
(in thousands)	2022			2021
REVENUES
Oil, natural gas, and related product sales		$	7,806		$	8,182
EXPENSES
Lease operating expenses			1,216			1,426
Production taxes			512			506
Depletion and accretion expense			1,611			2,533
General and administrative			158			360
Gain on disposal of oil and natural gas properties			—			(1,011)
Total expenses			3,497			3,814
Net operating income			4,309			4,368
OTHER EXPENSE
Loss on derivative contracts			(576)			(1,832)
Interest expense			(22)			(116)
Total other expense			(598)			(1,948)
NET INCOME		$	3,711		$	2,420

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

Condensed Consolidated Statements of Changes in Partners’ Capital (Unaudited)

(in thousands)	General Partner			Limited Partners			Total
Balance at December 31, 2021		$	129		$	14,845		$	14,974
Net income			32			3,679			3,711
Balance at September 30, 2022		$	161		$	18,524		$	18,685

(in thousands)	General Partner			Limited Partners			Total
Balance at December 31, 2020		$	307		$	32,902		$	33,209
Net income			21			2,399			2,420
Partners’ distributions			(210)			(21,790)			(22,000)
Balance at September 30, 2021		$	118		$	13,511		$	13,629

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Nine months ended September 30,
(in thousands)	2022			2021
Operating activities:
Net income		$	3,711		$	2,420
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and accretion expense			1,611			2,533
Change in unrealized (gain) loss on derivative contracts			(50)			535
Gain on disposal of oil and gas properties			—			(1,011)
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Revenue receivable			(484)			120
Prepaid expenses			14			—
Other assets			(962)			—
Other receivable			—			(27)
Accrued expenses			148			(26)
Other payable			(11)			—
Net cash provided by operating activities			3,977			4,544
Investing activities:
Refund of advances to operators			—			237
Proceeds from disposal of oil and natural gas properties			—			22,224
Development of oil and natural gas properties			(1,584)			(3,007)
Net cash (used in)/provided by investing activities			(1,584)			19,454
Financing activities:
Partners’ distributions			—			(22,000)
Repayments of borrowings on credit facilities			(1,100)			(2,300)
Net cash (used in)/provided by financing activities			(1,100)			(24,300)
Net increase/(decrease) in cash			1,293			(302)
Cash at beginning of period			740			1,287
Cash at end of period		$	2,033		$	985
Supplemental disclosure of cash flow information:
Cash paid during the year for interest		$	14		$	107
Supplemental disclosure of non cash investing activities:
Change in oil and natural gas property development costs in accrued expenses		$	157		$	320
Acquired and assumed asset retirement obligations		$	5		$	—
Revision of asset retirement costs		$	32		$	—
Advances to operators applied to development of oil and natural gas properties		$	—		$	332

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements (Unaudited)

Nature of operations

Grey Rock Energy Fund, LP (“Grey Rock”) was formed on June 18, 2013 as a Delaware limited partnership and commenced operations on January 3, 2014. Grey Rock was created for the purpose of purchasing non-operated oil and natural gas assets in multiple basins throughout the United States, and realizing profits through participation in oil and natural gas wells.

Grey Rock Aggie, LLC (“Aggie”), was formed on March 27, 2014 as a Delaware limited liability company. Grey Rock Bobcat, LLC (“Bobcat”) was formed on December 12, 2013 as a Delaware limited liability company. Grey Rock Cavalier, LLC (“Cavalier”) was formed on August 7, 2014 as a Delaware limited liability company. Grey Rock Commodore, LLC (“Commodore”) was formed on June 16, 2014. Aggie, Bobcat, Cavalier, and Commodore (collectively the “Underlying Entities”), were formed for the purpose of holding non-operated oil and gas assets purchased by Grey Rock. GREP Holdco I LLC (“Holdco”) was formed on July 21, 2015 for the purpose of acquiring a line of credit collateralized by the oil and gas assets owned by Grey Rock. Upon formation of Holdco, Grey Rock transferred 100% membership interest in the Underlying Entities to Holdco, and assumed 100% membership interest in Holdco.

Collectively, Grey Rock, Holdco, and the Underlying Entities are known as the “Partnership”.

Grey Rock Energy Partners GP, LP, a Delaware limited partnership (the “General Partner”), acts as general partner of the Partnership. 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 six years. The term 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.

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 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.

Summary of significant accounting policies

Principles of Consolidation

The accompanying interim condensed consolidated financial statements include the accounts of Grey Rock, Holdco, Aggie, Bobcat, Cavalier, and Commodore, all of which share common ownership and management. All inter-company balances and transactions have been eliminated in consolidation.

Basis of Presentation

The condensed consolidated balance sheet as of December 31, 2021 was derived from the audited consolidated financial statements, and the unaudited interim condensed consolidated financial statements

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as of September 30, 2022 and for the nine month periods ended September 30, 2022 and 2021, provided herein have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to rules and regulations of the Securities and Exchange Commission (“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 consolidated financial statements include all normal recurring adjustments necessary to fairly present the results of the interim periods. The condensed consolidated statements of income for the nine months ended September 30, 2022 and the results of cash flows for the nine months ended September 30, 2022 are not necessarily indicative of the consolidated statements of income and results of cash flows that might be expected for the entire year. These condensed consolidated financial statements and the accompanying notes should be read in conjunction with the audited consolidated 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.

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 revenue receivable and accrued expenses due to sellers, approximate their fair values because of the short maturity of these instruments.

Revenue Receivable

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specific accounts receivable when they become uncollectible. For the 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 is comprised of fees that were capitalized in connection to the Business Combination. Capitalized fees were $962 thousand and zero as of September 30, 2022 and December 31, 2021, respectively.

Revenue Recognition

Performance obligations are satisfied when the customer obtains control of the product, when the Partnership has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. 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. Revenue is presented net of these costs within the condensed consolidated statements of income. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in revenue receivable in the balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; however, differences have been and are insignificant.

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 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 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 nine months ended September 30, 2022 and 2021 were approximately $5,984 thousand and $6,908 thousand, respectively. Natural gas and NGL sales for the nine months ended September 30, 2022 and 2021 were approximately $1,822 thousand and $1,274 thousand, respectively.

Substantially all of the Partnership’s oil and natural gas sales come from four geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the SCOOP/STACK Basin

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(Oklahoma) 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 nine months ended September 30, 2022 and 2021.

	Nine months ended September 30, 2022
(in thousands)	Eagle Ford			Permian			SCOOP/Stack			Bakken
Revenues		$	138		$	5,356		$	—		$	2,312

	Nine months ended September 30, 2021
(in thousands)	Eagle Ford			Permian			SCOOP/Stack			Bakken
Revenues		$	1,769		$	3,072		$	702		$	2,639

Income Taxes

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 2018.

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

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include impairment testing, derivative instruments and hedging activity, and asset retirement obligations. Actual results could differ from those estimates.

Adopted and Recently Issued Accounting Pronouncements

Derivative instruments

From time to time, the Partnership may utilize derivative contracts in connection with its oil and gas operations to provide an economic hedge of the Partnership’s exposure to commodity price risk associated with anticipated future oil and gas production. The Partnership does not hold or issue derivative financial instruments for trading purposes. These derivative contracts consist of swap contracts, fixed price collar options and producer 3-way option contracts. The Partnership typically hedges approximately 50% to 75% of expected oil and 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

Swap, Collar and Producer 3-way Option Contracts

A producer 3-way contract is established with the sale of a short call option and the purchase of a long put option set to expire at a predetermined date in the future. However, the producer 3-way contract also includes the sale of a short put option set to expire at a predetermined date in the future. The options give the owner the right but not the obligation to exercise the option at the expiration date.

The fair value of open options reported in the condensed consolidated 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.

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Volume of Derivative Activities

Contract Prices

Periods

Type of Contract

(Volume/Month)

Range

Weighted Average

Oct 2022 – Sep 2023

Producer 3-way (crude oil)

2,942 – 1,223

$91.50 – $57.50

76.93

Jan 2023 – Mar 2023

Producer 3-way (natural gas)

6,363 – 6,098

$10.00 – $3.80

6.12

Nov 2022 – Dec 2022

Collar (natural gas)

6,652 – 1,223

$6.05 – $4.35

5.20

Impact of Derivatives on the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income

The following table identifies the fair value amounts of derivative instruments included in the accompanying condensed consolidated 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		$	50		$	—		$	—		$	—
Natural gas			—			—			(29)			—
Total		$	50		$	—		$	(29)		$	—

The following table identifies the net gain/(loss) amounts included in the accompanying condensed consolidated statements of income as loss on derivative contracts for the nine months ended September 30, 2022.

	Nine months ended September 30, 2022
(in thousands)	Realized loss			Change in unrealized gain			Total
Primary underlying risk
Commodity price
Crude oil		$	(367)		$	50		$	(317)
Natural gas			(259)			—			(259)
Total		$	(626)		$	50		$	(576)

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

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	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		$	—		$	—		$	—		$	—
Natural gas			—			—			(29)			—
Total		$	—		$	—		$	(29)		$	—

The following table identifies the net loss amounts included in the accompanying condensed consolidated statements of income as loss on derivative contracts for the nine months ended September 30, 2021.

	Nine months ended September 30, 2021
(in thousands)	Realized loss			Change in unrealized loss			Total
Primary underlying risk
Commodity price
Crude oil		$	(1,245)		$	(305)		$	(1,550)
Natural gas			(52)			(230)			(282)
Total		$	(1,297)		$	(535)		$	(1,832)

Fair value measurements

Fair Values — Recurring

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

(in thousands)	Level 1			Level 2			Level 3			September 30, 2022
Assets (at fair value):
Derivative contracts		$	—		$	50		$	—		$	50
Liabilities (at fair value):
Derivative contracts		$	—		$	(29)		$	—		$	(29)

The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed consolidated 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		$	—		$	—		$	1,100		$	1,100

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

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Fair Values — Non Recurring

Oil and natural gas properties

Acquisitions

Divestitures

For the nine months ended September 30, 2022, the Partnership made no divestitures of oil and natural gas properties.

Permian Basin — During the nine months ended September 30, 2021, the Partnership sold a complete unit of oil and natural gas property for approximately $22,224 thousand, eliminating approximately $21,246 thousand from property accounts, and resulting in a gain of $978 thousand. Customary post-close adjustments related to a prior period divestiture resulted in the recognition of a gain of approximately $33 thousand.

Partners’ capital

As defined by the Second Amended and restated Limited Partnership Agreement (the “LPA”), effective May 2, 2014, the General Partner Capital Commitment shall be at least one-half of one percent (0.5%) of the aggregate capital commitments to the Partnership, either through the General Partner or as limited partners. As of September 30, 2022 and December 31, 2021, the General Partner Capital Commitment, including affiliated limited partners, is $5,666 thousand, approximately twelve percent (12%) of aggregate capital commitments. Funded capital contributions through September 30, 2022 and December 31, 2021 by the General Partner, including affiliated limited partners is approximately $5,552 thousand.

Allocation of Net Profits and Losses

(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;

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(c)

(d)

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

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 nine months ended September 30, 2022, the Partnership did not make any distributions. For the nine months ended September 30, 2021, the Partnership made distributions of Investment Proceeds of approximately $21,790 thousand to the Limited Partners and approximately $210 thousand to the General Partner.

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 admitted to the Partnership on or before the initial closing date will be assessed one and one-half (1.5%) per annum of such limited partner’s aggregate capital commitment. Limited partners admitted to the Partnership after the initial closing date will be assessed two percent (2%) per annum of such limited partner’s aggregate capital commitment.

In accordance with the LPA, the General Partner provided a Notice and Request for Consent of Partnership Term Extension, dated September 23, 2020, seeking consent to extend the Term of the Partnership until October 31, 2021. The General Partner provided a Notice and Request for Consent of Partnership Term Extension, dated September 23, 2021, seeking consent to extend the Term of the Partnership until October 31, 2022. Pursuant with the LPA, because the Term has already been once extended by Grey Rock in its discretion, an extension of the Partnership’s Term for an additional twelve-month period though the Extension Date requires the consent of a Majority-In-Interest of the Limited Partners. In connection with the extension of the Term though the Extension Date, the Investment Manager has agreed to cease charging the management fee. For the nine months ended September 30, 2022 and 2021, no management fees were incurred.

As of September 30, 2022, the Partnership did not have any related party payables with the Management Company for reimbursable expenses incurred on behalf of the Partnership. As of December 31, 2021, the Partnership had related party payables with the Management Company for reimbursable expenses incurred on behalf of the Partnership of approximately $0.2 thousand.

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 gas industry. Such contingencies include differing interpretations as to the prices at which oil and 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 $157 thousand in capital expenditures that were included in accounts payable. The Partnership is not committed to any additional development capital expenditures not already incurred for wells the Partnership elected to participate in.

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9. Credit facility

Since 2015, the Partnership has maintained a revolving credit facility (the “Facility”) with an initial borrowing capacity of $10,500 thousand. Following a series of amendments to the Facility, the borrowing capacity was reduced to $1,700 thousand as of September 30, 2022 and December 31, 2021, of which $0 and $1,100 was outstanding, respectively.

The Facility is collateralized by all of the oil and natural gas properties of the Partnership 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 had no unamortized loan origination costs at September 30, 2022 and December 31, 2021.

Additionally, the Facility bears interest at an annual base rate ranging from 0% to 0.5% plus an applicable margin ranging from 2% to 3% plus LIBOR as determined by the London interbank on the interest determination date. As of September 30, 2022, and December 31, 2021 the weighted average interest rate on borrowed amounts was approximately 3.60% and 2.84%, 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

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 continues 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 consolidated financial statements for the nine months ended September 30, 2022, management has evaluated subsequent events for potential recognition and disclosure through the date November 18, 2022, which is the date the condensed consolidated 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.

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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, each of the borrower and the Required Lenders (as defined in the Credit Agreement) may request one unscheduled redetermination of the borrowing base between each scheduled redetermination. The amount of the borrowing base is determined by the lenders in their sole discretion and consistent with the oil and gas lending criteria of the lenders at the time of the relevant redetermination. The amount 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.

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Report of Independent Registered Public Accounting Firm

To the Partners
Grey Rock Energy Fund, LP
Dallas, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Grey Rock Energy Fund, LP and its subsidiaries (the “Partnership”) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits.

We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BKD, LLP

We have served as the Partnership’s auditor since 2015.

Dallas, Texas
May 16, 2022

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	December 31,
	2021			2020
ASSETS
Current assets:
Cash		$	740,353		$	1,287,022
Revenue receivable			1,198,723			1,216,502
Advances to operators			—			569,130
Prepaid expenses			14,064			—
Total current assets			1,953,140			3,072,654
Property and equipment:
Oil and gas properties, successful efforts method			44,128,011			83,121,938
Accumulated depletion			(29,081,723)			(45,411,435)
Total property and equipment, net			15,046,288			37,710,503
TOTAL ASSETS		$	16,999,428		$	40,783,157
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued expenses		$	636,568		$	593,008
Other payable			11,557			—
Derivative liabilities			29,235			93,176
Credit facilities – current portion			—			6,400,000
Total current liabilities			677,360			7,086,184
Long-term liabilities:
Credit facilities			1,100,000			—
Asset retirement obligations			247,603			487,534
Total long-term liabilities			1,347,603			487,534
Commitments and contingencies (Note 9)
Partners’ capital:
General partner			129,186			307,145
Limited partners			14,845,279			32,902,294
Total partners’ capital			14,974,465			33,209,439
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$	16,999,428		$	40,783,157

The accompanying notes are an integral part to these consolidated financial statements

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

	Year ended December 31,
	2021			2020			2019
REVENUES
Oil, natural gas, and related product sales		$	10,256,668		$	9,790,740		$	13,440,061
EXPENSES
Lease operating expenses			1,798,287			2,155,973			2,979,445
Production taxes			627,451			619,188			864,964
Depletion and accretion expense			3,037,694			9,837,019			7,261,480
Loss on Impairment			—			5,724,923			—
Professional fees			218,167			301,920			665,476
Management fees			—			584,534			700,092
General and administrative			170,843			383,472			201,985
Gain on disposal of oil and natural gas properties			(1,340,727)			(597,177)			(4,909,782)
Total expenses			4,511,715			19,009,852			7,763,660
Net operating income/(loss)			5,744,953			(9,219,112)			5,676,401
OTHER INCOME/(EXPENSE)
Gain/(loss) on derivative contracts			(1,841,779)			1,714,111			(1,370,842)
Interest expense			(138,148)			(244,797)			(665,893)
Total other income/(expense)			(1,979,927)			1,469,314			(2,036,735)
NET INCOME/(LOSS)		$	3,765,026		$	(7,749,798)		$	3,639,666

The accompanying notes are an integral part to these consolidated financial statements

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

	General Partner			Limited Partner			Total
Balance at December 31, 2018		$	392,782		$	44,167,794		$	44,560,576
Net income			36,918			3,602,748			3,639,666
Partners’ distributions			(61,600)			(7,179,405)			(7,241,005)
Balance at December 31, 2019		$	368,100		$	40,591,137		$	40,959,237
Net loss			(60,955)			(7,688,843)			(7,749,798)
Balance at December 31, 2020		$	307,145		$	32,902,294		$	33,209,439
Net income			32,029			3,732,997			3,765,026
Partners’ distributions			(209,988)			(21,790,012)			(22,000,000)
Balance at December 31, 2021		$	129,186		$	14,845,279		$	14,974,465

The accompanying notes are an integral part to these consolidated financial statements

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December,
	2021			2020			2019
Operating activities:
Net income/(loss)		$	3,765,026		$	(7,749,798)		$	3,639,666
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Depletion and accretion expense			3,037,694			9,837,019			7,261,480
Loss on impairment			—			5,724,923			—
Unrealized (gain)/loss on derivative contracts			(63,941)			(280,264)			1,213,314
Gain on disposal of oil and gas properties			(1,340,727)			(597,177)			(4,909,782)
Amortization of loan origination costs			—			—			9,782
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Revenue receivable			17,779			637,086			156,742
Accrued expenses			60,403			(527,963)			162,933
Prepaid expenses			(14,064)			—
Other receivable			—			1,107,746			(1,107,746)
Other payable			11,557			—			—
Net cash provided by operating activities			5,473,727			8,151,572			6,426,389
Investing activities:
Refund of advances to operators			237,051			—			772,522
Proceeds from the disposal of oil and gas properties			24,460,000			596,260			11,351,176
Development of oil and gas properties			(3,417,447)			(7,051,096)			(3,969,824)
Net cash provided by/(used in) investing activities			21,279,604			(6,454,836)			8,153,874
Financing activities:
Proceed from borrowing on credit facilities			—			2,000,000			3,700,000
Repayments of borrowing on credit facilities			(5,300,000)			(4,500,000)			(9,700,000)
Partners’ distributions			(22,000,000)			—			(7,241,005)
Net cash used in financing activities			(27,300,000)			(2,500,000)			(13,241,005)
Net increase/(decrease) in cash			(546,669)			(803,264)			1,339,258
Cash at beginning of year			1,287,022			2,090,286			751,028
Cash at end of year		$	740,353		$	1,287,022		$	2,090,286
Supplemental disclosure of cash flow information
Cash paid during the year for interest		$	133,537		$	234,097		$	630,609
Supplemental disclosure of non-cash investing activities
Revision of asset retirement costs		$	64,050		$	118,667		$	(99,608)
Acquired and assumed asset retirement obligations		$	—		$	15,733		$	2,639
Disposal of asset retirement obligations		$	164,179		$	—		$	—
Oil and natural gas property development costs in accrued expenses		$	288,539		$	305,382		$	30,642

The accompanying notes are an integral part to these consolidated financial statements

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GREY ROCK ENERGY FUND, LP AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of operations

Grey Rock Energy Fund, LP (“Grey Rock”) was formed on June 18, 2013 as a Delaware limited partnership and commenced operations on January 3, 2014. Grey Rock was created for the purpose of purchasing non-operated oil and gas assets in multiple basins throughout the United States, and realizing profits through participation in oil and gas wells.

Collectively, Grey Rock, Holdco, and the Underlying Entities are known as the “Partnership”.

The term of the Partnership is six years. The term may be extended by the General Partner, in its sole discretion, for one year. Thereafter, by the General Partnership with the consent of a majority-in-interest of the limited partners for the Partnership can be extended for additional one year terms.

2. Summary of significant accounting policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Grey Rock, Holdco, Aggie, Bobcat, Cavalier, and Commodore, all of which are wholly owned and controlled. All inter-company balances and transactions have been eliminated in consolidation.

Basis of Presentation

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Comprehensive income/(loss) for the Partnership is the same as net income/(loss) for all years presented. 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 of Financial Instruments

The Partnership has adopted and follows Accounting Standard Codification (“ASC”) 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in 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:

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

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 revenue receivable and accrued expenses due to sellers, approximate their fair values because of the short maturity of these instruments.

Cash

Cash represent liquid cash and investments with an original maturity of 90 days or less. The Partnership places its cash with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Partnership has not incurred any losses related to amounts in excess of FDIC limits. As of December 31, 2021 and 2020, the Partnership did not have any restrictions over its cash.

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 years ended December 31, 2021, 2020 and 2019, the Partnership had no bad debt expense, and did not record an allowance for doubtful accounts.

Advance to operators

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

Prepaid expenses

Prepaid expenses are comprised of payments made in advance for services deemed to have future value to the Partnership. At December 31, 2021 and 2020, prepaid expenses equaled approximately $14,000 and $0, respectively.

Oil and Gas Properties

The Partnership uses the successful efforts method of accounting for oil and gas producing activities, as further defined under ASC 932, Extractive Activities — Oil and Gas. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory leases that find proved reserves, and to drill and equip development leases and related asset retirement costs are capitalized. Costs to drill exploratory wells

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are capitalized pending determinations of whether the wells have proved reserves. If the Partnership determines that the wells do not have proved reserves, the costs are charged to expense.

There were no exploratory wells capitalized pending determinations of whether the wells have proved reserves at December 31, 2021 and 2020. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. The Partnership capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the years ended December 31, 2021, 2020 and 2019, no interest costs were capitalized because its exploration and development projects generally last less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves. Depletion expense for oil producing property and related equipment was $3,049,000, $9,752,000 and $7,278,000 for the years ended December 31, 2021, 2020, and 2019, respectively.

Upon the sale or retirement of a complete unit of proved property, the costs and related accumulated depletion are removed from the property accounts, and a resulting gain or loss is recognized. Upon the retirement or sale of a partial unit of proved property, the cost is charged to the property accounts without a resulting gain or loss recognized in income. The Partnership sold various units of proved oil and gas properties during the years ended December 31, 2021, 2020 and 2019, removing accumulated depletion of approximately $19,379,000, $0 and $289,000, respectively.

Capitalized costs related to proved oil properties, including wells and related support equipment and facilities, are evaluated for impairment on an analysis of undiscounted future cash flows in accordance with ASC 360, Property, Plant, and Equipment. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Partnership recognizes an impairment charge in operating income equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. The Partnership did not recognize an impairment for the year ended December 31, 2021. During the year ended December 31, 2020, the Partnership recognized an impairment of approximately $5,725,000. The Partnership did not recognize an impairment for the year ended December 31, 2019.

Upon the sale or retirement of a complete unit of proved property, the costs and related accumulated impairment are removed from the property accounts, and the resulting gain or loss is recognized. Upon the retirement or sale of a partial unit of proved property, the cost is charged to the property accounts without a resulting gain or loss recognized in income. The Partnership sold various units of proved oil and gas properties during the years ended December 31, 2021, 2020 and 2019, removing approximately $3,242,000, $0 and $289,000, respectively, of accumulated impairment.

Asset Retirement Obligation

The Partnership follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Partnership’s asset retirement obligation relates to the plugging, dismantlement, removal, site reclamation and similar activities of its oil properties.

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Revenue Recognition

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

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

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 years ended December 31, 2021, 2020 and 2019, the Partnership’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in 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 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 two 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 years ended December 31, 2021, 2020 and 2019 were approximately $8,580,000, $9,120,000 and $12,455,000, respectively. Natural gas and NGL sales for the years ended December 31, 2021, 2020 and 2019 were approximately $1,677,000, $671,000 and $985,000, respectively.

The Partnership’s disaggregated revenue has two primary sources: oil sales and natural gas sales. Substantially all of the Partnership’s oil and natural gas sales come from four geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Scoop/Stack Basin (Oklahoma) and the Bakken Basin (Montana/North Dakota). The following tables present the disaggregation of the Partnership’s oil revenues and natural gas revenues by basin for the years ended December 31, 2021, 2020 and 2019.

	Year Ended December 31, 2021
	Eagle Ford			Permian			SCOOP/STACK			Bakken
Revenues		$	2,609,559		$	2,626,345		$	831,382		$	4,189,382

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	Year Ended December 31, 2020
	Eagle Ford			Permian			SCOOP/STACK			Bakken
Revenues		$	1,934,198		$	5,194,153		$	460,290		$	2,202,099

	Year Ended December 31, 2019
	Eagle Ford			Permian			SCOOP/STACK			Bakken
Revenues		$	4,756,331		$	3,743,718		$	1,103,707		$	3,836,305

Lease Operating Expenses

Lease operating expenses represents field employees’ salaries, salt water disposal, ad valorem taxes, repairs and maintenance, expensed work overs and other operating expenses. Lease operating expenses are expensed as incurred.

Production Taxes

The Partnership incurs severance tax on the sale of its production which is generated in Texas, Oklahoma and North Dakota. These taxes are reported on a gross basis. Sales-based taxes for the years ended December 31, 2021, 2020 and 2019 were approximately $627,000, $619,000 and $865,000 respectively.

Ad Valorem Taxes

The Partnership incurs ad valorem tax on the value of its properties in Texas and Oklahoma. These taxes are included in lease operating expenses within the accompanying consolidated statements of operations. Ad valorem taxes for the years ended December 31, 2021, 2020 and 2019 were approximately $69,000, $100,000 and $123,000 respectively.

Income Taxes

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 December 31, 2021 and 2020. 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.

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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.

Use of Estimates

The preparation of consolidated 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

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 becomes effective for us beginning January 1, 2022 and we expect to adopt using a modified retrospective approach with certain available practical expedients. Oil and gas leases are excluded from the guidance. We do not expect this ASU to materially affect the consolidated financial statements and related note disclosures.

3. Derivative instruments

From time to time, the Partnership may utilize derivative contracts in connection with its oil and gas operations to provide an economic hedge of the Partnership’s exposure to commodity price risk associated with anticipated future oil and gas production. The Partnership does not hold or issue derivative financial instruments for trading purposes. These derivative contracts consist of producer 3-way option contracts. The Partnership typically hedges approximately 50% to 75% of expected oil and 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

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statements of operations. There were no derivative assets as of December 31, 2021 or 2020. Derivative liabilities are included within current liabilities in the consolidated balance sheets as of December 31, 2021 and 2020.

Swap, Collar and Producer 3-way Option Contracts

The fair value of open options reported in the consolidated 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.

Volume of Derivative Activities

Contract Prices

Year

Type of Contract

(Volume/Month)

Range

Weighted
Average

Feb 2022 – Jun 2022

Producer 3-way (natural gas)

12,436 – 10,189

$3.63 – $1.90

2.65

At December 31, 2020, the volume of the Partnership’s derivative activities based on their volume are as follows:

Contract Prices

Year

Type of Contract

(Volume/Month)

Range

Weighted
Average

Jan 2021 – Dec 2021

Producer 3-way (crude oil)

8,725 – 5,365

$57.08 – $37.53

47.59

Jan 2021 – Dec 2021

Collar (crude oil)

5,037 – 2,981

46.00 – 32.50

39.25

Feb 2021 – Apr 2022

Producer 3-way (natural gas)

12,844 – 11,468

3.63 – 2.00

2.74

Feb 2021 – Jun 2021

Collar (natural gas)

16,540 – 10,398

3.48 – 2.15

2.77

Apr 2021 – Dec 2021

Short Swaps (natural gas)

15,385 – 5,462

2.79

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At December 31, 2019, the volume of the Partnership’s derivative activities based on their volume are as follows:

Contract Prices

Year

Type of Contract

(Volume/Month)

Range

Weighted
Average

Jan 2020 – Dec 2021

Collar (crude oil)

11,583 – 4,712

$60.24 – $50.70

55.37

Jan 2020 – Dec 2021

Short Puts (crude oil)

5,739 – 2,085

42.77 – 42.00

42.23

Jan 2020 – Dec 2021

Short Swaps (crude oil)

1,735 – 1,055

56.30

Feb 2020 – Mar 2021

Collar (natural gas)

19,860 – 11,468

3.37 – 2.00

2.66

Feb 2020 – Mar 2021

Short Puts (natural gas)

14,298 – 5,964

2.40 – 1.80

1.94

Impact of Derivatives on the Consolidated Balance Sheets and Consolidated Statements of Operations

The following table identifies the fair value amounts of derivative instruments included in the accompanying consolidated balance sheets as derivative assets and liabilities categorized by primary underlying risk, at December 31, 2021. The following table also identifies the net loss amounts included in the accompanying consolidated statements of operations as gain/(loss) on derivative contracts for the year ended December 31, 2021.

	Derivative assets			Derivative liabilities			Total loss from derivative instruments
Primary underlying risk Commodity price
Crude oil		$	—		$	—		$	(1,368,686)
Natural gas			—			(29,235)			(473,093)
Total		$	—		$	(29,235)		$	(1,841,779)

	Realized loss			Unrealized gain			Total
Primary underlying risk Commodity price
Crude oil		$	(1,368,686)		$	—		$	(1,368,686)
Natural gas			(537,034)			63,941			(473,093)
Total		$	(1,905,720)		$	63,941		$	(1,841,779)

The following table identifies the gross fair value amounts of derivative instruments included in the accompanying consolidated balance sheets as derivative assets and liabilities categorized by primary underlying risk, at December 31, 2020. The following table also identifies the net gain amounts included in the accompanying consolidated statements of operations as gain/(loss) on derivative contracts for the year ended December 31, 2020.

	Derivative assets			Derivative liabilities			Total gain/(loss) from derivative instruments
Primary underlying risk Commodity price
Crude oil		$	—		$	(115,729)		$	1,734,122
Natural gas			22,553			—			(20,011)
Total		$	22,553		$	(115,729)		$	1,714,111

	Realized loss			Unrealized gain			Total
Primary underlying risk Commodity price
Crude oil		$	1,447,805		$	286,317		$	1,734,122
Natural gas			(13,958)			(6,053)			(20,011)
Total		$	1,433,847		$	280,264		$	1,714,111

The following table identifies the net loss amounts included in the accompanying consolidated statements of operations as gain/(loss) on derivative contracts for the year ended December 31, 2019.

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	Realized loss			Unrealized gain			Total
Primary underlying risk
Commodity price
Crude oil		$	(181,701)		$	(1,241,355)		$	(1,423,056)
Natural gas			24,173			28,041			52,214
Total		$	(157,528)		$	(1,213,314)		$	(1,370,842)

4. Fair value measurements

Fair Values — Recurring

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

			Level 1						Level 2						Level 3						December 31, 2021
Liabilities (at fair value): Derivative				$	—					$	(29,235)					$	—					$	(29,235)

The following table presents information about the Partnership’s recurring liabilities measured at fair value as of December 31, 2020:

	Level 1			Level 2			Level 3			December 31, 2020
Liabilities (at fair value):
Derivative		$	—		$	(93,176)		$	—		$	(93,176)

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

	December 31, 2021						December 31, 2020
	Carrying Value			Fair Value			Carrying Value			Fair Value
Liabilities (not at fair value):
Revolving credit facility		$	1,100,000		$	1,100,000		$	6,400,000		$	6,400,000

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 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.

During the year ended December 31, 2021, the carrying value of oil and natural gas properties were not impaired.

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During the year ended December 31, 2020, the carrying value of oil and natural gas properties were impaired to an estimated fair value. Further impairments could be required in the future. Under the successful efforts method of accounting, capitalized oil and gas property costs, less accumulated depletion, may not exceed their undiscounted cash flows. If the carrying value of oil and gas properties exceeds their undiscounted cash flows, impairment is recognized for the difference in the carrying value of oil and gas properties and an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves. The fair value of oil and natural gas assets impaired, based on the grouping of the oil and natural gas assets by basin, was approximately $4,921,000 as of December 31, 2020, resulting in impairment losses of approximately $5,725,000 for the year ended December 31, 2020. The grouping of oil and natural gas assets impaired included the Scoop/Stack and Bakken basins, whose fair values were approximately $1,828,000 and $3,093,000, respectively, as of December 31, 2020.

5. Oil and gas properties

Oil and gas properties consisted of only proved properties as of December 31, 2021 and 2020. The book value of the Partnership’s oil and natural gas properties consists of all acquisition costs, drilling costs and other associated capitalized costs.

Acquisitions

2021 Divestitures

Bakken Basin — For the year ended December 31, 2021, customary post-closing adjustments related to a prior period divestiture resulted in a decrease of approximately $35,000 to the property accounts.

Permian Basin — For the year ended December 31, 2021, the Partnership sold a complete unit of mineral interest assets in Texas for approximately $22,467,000 eliminating approximately $21,302,000 from the property accounts and resulting in the recognition of a gain of approximately $1,165,000. Customary post-closing adjustments related to a prior period divestiture resulted in the recognition of a gain of approximately $38,000.

SCOOP/STACK Basin — The Partnership sold a complete unit of mineral interest assets in Oklahoma for approximately $1,920,000 eliminating approximately $1,782,833 from the property accounts and resulting in the recognition of a gain of approximately $137,000.

2020 Divestitures

Permian Basin — For the year ended December 31, 2020, customary post-closing adjustments related to a prior period divestiture resulted in an increase of approximately $900 to the property accounts and the recognition of a gain of approximately $900.

Lonestar Arbitration Settlement — In the Fall of 2018, the Partnership discovered that Lonestar Resources, an operating partner, had been acquiring assets within a contractually defined Area of Mutual Interest (“AMI”) without offering the agreed upon pro-rata 20% share to the Partnership. The Partnership and Lonestar were able to come to a final settlement in April 2020 that allowed the Partnership to buy into certain properties within the AMI at cost. Because the Partnership is near the end of its fund life and does not have the capital available to purchase the assets, the Partnership proposed to have Grey Rock Energy Fund II, LP and Grey Rock Energy Fund II-B Holdings, LP (collectively “Fund II”), acquire the properties instead of the Partnership. In exchange for the right to acquire assets within the AMI, Fund II agreed to reimburse legal, brokerage, title, and deal costs borne by the Partnership related to the arbitration. Fund II also agreed to give the Partnership a 10% share of the profits equivalent to 10% of net proceeds after the assets have achieved a 10% unlevered rate of return. As of the date of close of this transaction, the fair value of the interest received was de minimus. As of December 31, 2020, the unlevered rate of return on the applicable

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properties was less than 10% and no additional profits are owed from Fund II to the Partnership. The proceeds received resulted in a recognition of a gain on disposal of oil and gas properties of approximately $596,000.

2019 Divestitures

Bakken Basin — The Partnership sold a complete unit of mineral interest assets in North Dakota for approximately $9,507,000 eliminating approximately $4,679,000 from the property accounts and resulting in the recognition of a gain of approximately $4,828,000. The Partnership sold partial units of working interest assets in North Dakota for approximately $732,000, eliminating an equivalent amount from the property accounts.

Permian Basin — The Partnership sold a complete unit in Texas for approximately $404,000 eliminating approximately $322,000 from the property accounts and resulting in the recognition of a gain of approximately $82,000.

SCOOP/STACK Basin — The Partnership sold a partial unit in Oklahoma for $725,000, eliminating the same amount from the property accounts. After the closing but prior to the end of the year, the Partnership paid approximately $1,100,000 of drilling costs on sold properties. This amount is recorded as other receivables on the accompanying balance sheet and will be reimbursed by the purchaser in a post-closing settlement.

6. Asset retirement obligations

The Partnership has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations have been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of December 31, 2021 and 2020. In 2021 the estimated liability was revised downward due to price increases which extended the useful life of the assets. In 2020, declining prices lead to a decrease in the useful life of the assets resulting in an increase to the estimate. The Partnership evaluated 269 and 358 wells, respectively, and has determined a range of abandonment dates between the years 2023 and 2059.

The following table presents the changes in the asset retirement obligations during the years ended December 31, 2021 and 2020:

	2021			2020
Asset retirement obligations, beginning of year		$	487,534		$	268,273
Liabilities incurred during the period			48			15,733
Revision of estimates			(64,098)			118,667
Accretion of discount during the period			(11,702)			84,861
Disposals or settlements			(164,179)			—
Asset retirement obligations, end of year		$	247,603		$	487,534

7. Partners’ capital

Commitments and contributions

Funded and unfunded capital commitments as of December 31, 2021 and 2020 are as follows:

	General Partner			Limited Partner			Total
Committed capital		$	416,000		$	48,485,000		$	48,901,000
Less: Unfunded committed capital			24,575			603,060			627,635
Funded Capital Contributions		$	391,425		$	47,881,940		$	48,273,365

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the aggregate capital commitments to the Partnership, either through the General Partner or as limited partners. As of December 31, 2021 and 2020, the General Partner Capital Commitment, including affiliated limited partners, is $5,666,000, approximately twelve percent (12%) of aggregate capital commitments. Funded capital contributions through December 31, 2021 and 2020 by the General Partner, including affiliated limited partners is approximately $5,552,000.

Allocation of Net Profits and Losses

(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)

(d)

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

Distributions

8. 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 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 admitted to the Partnership on or before the initial closing date will be assessed one and one-half (1.5%) per annum of such limited partner’s aggregate capital commitment. Limited partners admitted to the Partnership after the initial closing date will be assessed two percent (2%) per annum of such limited partner’s aggregate capital commitment.

In accordance with the LPA, the General Partner provided a Notice and Request for Consent of Partnership Term Extension, dated September 23, 2020, seeking consent to extend the Term of the Partnership until October 31, 2021. The General Partner provided a Notice and Request for Consent of Partnership Term Extension, dated September 23, 2021, seeking consent to extend the Term of the Partnership until October 31, 2022. Pursuant with the LPA, because the Term has already been once extended by Grey Rock in its discretion, an extension of the Partnership’s Term for an additional twelve-month period though the Extension Date requires the consent of a Majority-In-Interest of the Limited Partners. In connection with the extension of the Term though the Extension Date, the Investment Manager has agreed to cease charging the management fee effective November 1, 2020. For the years ended December 31, 2021, 2020 and 2019, annual management fees were approximately $0, $585,000 and $700,000, respectively.

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During the year ended December 31, 2020 and as a result of a successful arbitration related to an Areas of Mutual Interest (“AMI”) dispute on our Aggie I and II assets, the Partnership was granted the right to buy into certain oil and natural gas properties within the AMI at cost. The Partnership proposed, with LPAC approval, Grey Rock Energy Fund II, LP (“Fund II-A”) and Grey Rock Energy Fund II-B, LP (“Fund II-B”), entities under common control, acquire the assets from the Partnership. Fund II-A and Fund II-B agreed to reimburse the Partnership for all legal, brokerage, title and deal costs borne by the Partnership, resulting in a gain of approximately $596,000.

As of December 31, 2021 and 2020, the Partnership had related party payables with the Management Company for reimbursable expenses incurred on behalf of the Partnership of approximately $200 and $1,300, respectively.

9. 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 gas industry. Such contingencies include differing interpretations as to the prices at which oil and 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. As of December 31, 2021 there were no significant outstanding commitments.

10. Credit facility

Since 2015, the Partnership has maintained a revolving credit facility (the “Facility”) with an initial borrowing capacity of $10,500,000. Following a series amendments to the Facility, the borrowing capacity was reduced to $1,700,000 and $10,300,000 as of December 31, 2021 and 2020, of which $1,100,000 and $6,400,000 was outstanding, respectively. The most recent amendment to the Facility matures on January 31, 2023.

The Facility is collateralized by all of the oil and gas properties of the Partnership and requires compliance with certain financial covenants. As of December 31, 2021 and 2020, the Partnership, was in compliance with all covenants required by the Facility. Further, the Partnership had no unamortized loan origination costs at December 31, 2021, 2020 and 2019.

11. Risk Concentrations

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any losses from these counterparties. The outbreak of the novel coronavirus continues to significantly impact the worldwide economy and specific economic sectors. As a result, commodity prices declined precipitously, which may impact the Partnership’s performance and may lead to future losses.

12. Subsequent Events

In connection with preparing the financial statements for the year ended December 31, 2021, management has evaluated subsequent events for potential recognition and disclosure through the date May 16, 2022, which is the date the consolidated financial statements were available to be issued.

Commencing with the Eleventh Amendment to the Facility, effective January 31, 2022 the borrowing base was affirmed at $1,700,000 and will be reduced $140,000 each month for the period commencing January 31, 2022 through and including the Spring Redetermination date. The Partnership paid down the outstanding credit facility balance by $400,000 on February 3, 2022.

13. Supplemental Oil and Gas Information (unaudited) Oil and Natural Gas Exploration and Production Activities

Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts.

Oil and Natural Gas Reserves and Related Financial Data

Oil and Natural Gas Reserve Data

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	Natural Gas (MMcf)		Oil (MBbl)		MBoe
Proved Developed and Undeveloped Reserves at December 31, 2018		7,862		3,908		5,218
Revisions of Previous Estimates		(4,107)		(1,938)		(2,622)
Extensions, Discoveries and Other Additions		2,061		797		1,140
Divestiture of Reserves		(345)		(121)		(178)
Production		(616)		(232)		(334)
Proved Developed and Undeveloped Reserves at December 31, 2019		4,855		2,414		3,224
Revisions of Previous Estimates		(1,013)		(724)		(893)
Extensions, Discoveries and Other Additions		505		266		349
Production		(646)		(248)		(356)
Proved Developed and Undeveloped Reserves at December 31, 2020		3,701		1,708		2,324
Revisions of Previous Estimates		637		173		280
Extensions, Discoveries and Other Additions		27		6		11
Divestiture of Reserves		(2,302)		(1,068)		(1,452)
Production		(505)		(162)		(246)
Proved Developed and Undeveloped Reserves at December 31, 2021		1,558		657		917

Notable changes in proved reserves for the year ended December 31, 2021 included the following:

•

Extensions and discoveries. In 2021, total extensions and discoveries of 11 MBoe were primarily attributable to successful drilling in the Bakken Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 3 MBoe as a result of successful drilling in the Bakken Basin and 8 MBoe as a result of additional proved undeveloped locations.

•

Revisions to previous estimates. In 2021, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 280 MBoe. The increase was primarily driven by higher crude oil prices which increased reserves by 327 MBoe. This increase was partially offset by unfavorable adjustments related to well performance which decreased reserves by 47 MBoe.

•

Divestiture of reserves. In 2021, total divestiture of reserves of 1,452 MBoe were primarily attributable to the divestiture of oil and natural gas properties in the Permian Basin (see Note 5).

Notable changes in proved reserves for the year ended December 31, 2020 included the following:

•

Extensions and discoveries. In 2020, total extensions and discoveries of 349 MBoe were primarily attributable to successful drilling in the Permian Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 109 MBoe as a result of successful drilling in the Permian Basin and 214 MBoe as a result of additional proved undeveloped locations. Extensions from current production were 26 MBoe from the Permian Basin.

•

Revisions to previous estimates. In 2020, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 893 MBoe. The downward revision in reserves was due to a combination of lower crude oil prices and unfavorable adjustments attributable to well performance, reducing reserves by 519 MBoe and 374 MBoe, respectively.

Notable changes in proved reserves for the year ended December 31, 2019 included the following:

•

Extensions and discoveries. In 2019, total extensions and discoveries of 1,140 MBoe were primarily attributable to successful drilling in the Bakken, Eagle Ford, Permian and SCOOP Basins as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 535 MBoe as a result of successful drilling in the Bakken, Eagle Ford, Permian and SCOOP Basins and 581 MBoe as a result of additional proved undeveloped locations. Extensions from current production were 24 MBoe from the Bakken, Eagle Ford, Permian and SCOOP Basins.

•

Revisions to previous estimates. In 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,622 MBoe. The downward revision in reserves was

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due to a combination of unfavorable adjustments attributable to well performance and lower crude oil prices, reducing reserves by 1,576 MBoe and 1,046 MBoe, respectively.

•

Divestiture of reserves. In 2019, divestiture of reserves of 178 MBoe were primarily attributable to the sale of oil and natural gas properties in the Bakken Basin (see Note 5).

	Natural Gas (MMcf)		Oil (MBbl)		MBoe
Proved Developed Reserves:
December 31, 2018		3,492		1,744		2,326
December 31, 2019		2,685		1,380		1,828
December 31, 2020		2,127		1,052		1,406
December 31, 2021		1,437		630		870
Proved Undeveloped Reserves:
December 31, 2018		4,370		2,164		2,892
December 31, 2019		2,170		1,034		1,396
December 31, 2020		1,574		656		918
December 31, 2021		121		27		47

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

	December 31,
	2021			2020			2019
	(In thousands)
Future cash inflows		$	48,311		$	71,009		$	136,241
Future production costs			(20,308)			(27,973)			(45,465)
Future development costs			(1,304)			(9,338)			(22,918)
Future income tax expense			(150)			(320)			(557)
Future net cash flows			26,549			33,378			67,301
10% discount for estimated timing of cash flows			(9,975)			(13,385)			(31,211)
Standardized measure of discounted future net cash flows		$	16,574		$	19,993		$	36,090

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

	December 31,
	2021			2020			2019
	(In thousands)
Balance, beginning of period		$	19,993		$	36,090		$	75,766
Sales of oil and natural gas produced, net of production costs			(7,831)			(7,016)			(9,596)
Extensions and discoveries			172			3,986			9,877
Previously estimated development cost incurred during the period			14			3,341			3,148
Net change of prices and production costs			10,056			(12,807)			(14,153)
Change in future development costs			(289)			4,869			3,737
Revisions of quantity and timing estimates			5,660			(10,630)			(39,825)
Accretion of discount			2,018			3,637			7,622
Change in income taxes			99			93			176
Divestiture of Reserves			(13,107)			—			(1,646)
Other			(211)			(1,570)			984
Balance, end of period		$	16,574		$	19,993		$	36,090

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GREY ROCK ENERGY FUND II

Condensed Combined Balance Sheets

	(Unaudited)
(in thousands)	As of September 30, 2022			As of December 31, 2021
ASSETS
Current assets:
Cash		$	28,688		$	3,794
Revenue receivable			18,808			13,402
Related party receivable			205			—
Advances to operators			2,082			667
Other assets			2,033			42
Derivative assets			714			—
Total current assets			52,530			17,905
Property and equipment:
Oil and gas properties, successful efforts method			328,460			306,761
Accumulated depletion			(177,220)			(151,425)
Total property and equipment, net			151,240			155,336
Long-term assets:
Cash deposit			300			300
Derivative assets			340			—
Total long-term assets			640			300
TOTAL ASSETS		$	204,410		$	173,541
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued expenses		$	5,091		$	3,055
Credit facilities			—			20,000
Related party payable			—			2
Derivative liabilities			558			2,844
Total current liabilities			5,649			25,901
Long-term liabilities:
Derivative liabilities			—			229
Asset retirement obligations			2,220			1,750
Total long-term liabilities			2,220			1,979
TOTAL LIABILITIES			7,869			27,880
Commitments and contingencies (Note 8)
Partners’ capital:
General partner			15,817			1,508
Limited partners			180,724			144,153
Total partners’ capital			196,541			145,661
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$	204,410		$	173,541

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GREY ROCK ENERGY FUND II

Condensed Combined Statements of Income (Unaudited)

	Nine months ended September 30,
(in thousands)	2022				2021
REVENUES
Oil, natural gas, and related product sales		$	110,013			$	59,822
EXPENSES
Lease operating expenses			13,662				8,122
Production taxes			5,171				4,505
Depletion and accretion expense			26,038				24,109
General and administrative			2,709				2,904
Gain on disposal of oil and natural gas properties			—				(955)
Total expenses			47,580				38,685
Net operating income			62,433	��			21,137
OTHER EXPENSE
Loss on derivative contracts			(11,064)				(13,713)
Interest expense			(489)				(611)
Total other expense			(11,553)				(14,324)
NET INCOME		$	50,880			$	6,813

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GREY ROCK ENERGY FUND II

Condensed Combined Statements of Changes in Partners’ Capital (Unaudited)

(in thousands)	General Partner			Limited Partners			Total
Balance at December 31, 2021		$	1,508		$	144,153		$	145,661
Net income			380			50,500			50,880
Carried interest reallocation			13,929			(13,929)			—
Balance at September 30, 2022		$	15,817		$	180,724		$	196,541

(in thousands)	General Partner			Limited Partners			Total
Balance at December 31, 2020		$	1,553		$	157,365		$	158,918
Net (loss)/income			(380)			7,193			6,813
Partners’ distributions			(135)			(25,845)			(25,980)
Balance at September 30, 2021		$	1,038		$	138,713		$	139,751

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GREY ROCK ENERGY FUND II

Condensed Combined Statements of Cash Flows (Unaudited)

	Nine months ended September 30,
(in thousands)	2022			2021
Operating activities:
Net income		$	50,880		$	6,813
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and accretion expense			26,038			24,109
Change in unrealized (gain) loss on derivative contracts			(3,569)			8,365
Gain on disposal of oil and natural gas properties			—			(955)
Amortization of loan origination costs			—			7
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Revenue receivable			(5,406)			(3,840)
Related party receivable			(205)			—
Other assets			(1,991)			—
Other payable			—			5
Accrued expenses			1,973			(291)
Related party payable			(2)			(4)
Net cash provided by operating activities			67,718			34,209
Investing activities:
Acquisition of proved oil and natural gas properties			(1,600)			—
Refund of advances to operators			—			337
Proceeds from the disposal of oil and natural gas properties			6			2,009
Development of oil and natural gas properties			(21,230)			(13,690)
Net cash used in investing activities			(22,824)			(11,344)
Financing activities:
Proceeds from borrowings on credit facilities			—			8,000
Repayments of borrowings on credit facilities			(20,000)			(4,100)
Partners’ distributions, net of change in distributions payable			—			(25,984)
Net cash used in financing activities			(20,000)			(22,084)
Net increase in cash			24,894			781
Cash and restricted cash at beginning of period			4,094			4,583
Cash and restricted cash end of period		$	28,988		$	5,364
Supplemental disclosure of cash flow information:
Cash paid during the period for interest		$	393		$	302
Supplemental disclosure of non cash investing activities:
Revision of asset retirement costs		$	96		$	—
Acquired and assumed asset retirement obligations		$	130		$	—
Change in oil and natural gas property development costs in accounts payable and accrued expenses		$	1,412		$	952
Advances to operators applied to development of oil and natural gas properties		$	1,628		$	379
Cash and restricted cash:
Cash		$	28,688		$	5,064
Restricted cash included in cash deposit			300			300
Total cash and restricted cash		$	28,988		$	5,364

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GREY ROCK ENERGY FUND II

Notes to the Condensed Combined Financial Statements (Unaudited)

1. Nature of operations

Grey Rock Energy Fund II, LP (“Grey Rock II”) was formed on November 25, 2015 as a Delaware limited partnership. Grey Rock II 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 II-B Holdings, LP (“Grey Rock II-B Holdings”) was formed on June 28, 2016, as a Delaware limited partnership. Grey Rock II-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 II-B (as defined below), a related party, in accordance with its limited partnership agreement.

Grey Rock Energy Fund II-B, LP (“Grey Rock II-B”) was formed on June 28, 2016, as a Delaware limited partnership. Grey Rock II-B was created for the purpose of acquiring net profits interests in oil and natural gas assets from Grey Rock II-B Holdings, a related party, in multiple basins in North America, in accordance with the limited partnership agreement.

Grey Rock Preferred Limited Partner II, LP (“Grey Rock PLP”) was formed on June 28, 2016, as a Delaware limited partnership. Grey Rock PLP was created for the purpose of holding limited partnership interests in Grey Rock II-B, a related party.

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

Grey Rock Energy Partners GP II-A, LP, a Delaware limited partnership (the “General Partner”), acts as general partner of Grey Rock II. Grey Rock Energy Partners GP II-B, LP, a Delaware limited partnership (the “General Partner”), acts as general partner of Grey Rock II-B Holdings and Grey Rock II-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 eight 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 three 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 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.

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2. Summary of significant accounting policies

Principles of Combination

The accompanying condensed combined financial statements include the accounts of Grey Rock II, Grey Rock II-B Holdings, Grey Rock II-B, and Grey Rock PLP 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 nine month periods ended September 30, 2022 and 2021, provided herein have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to rules and regulations of the Securities and Exchange Commission (“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 nine months ended September 30, 2022 and the 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.

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

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

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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, and accounts payable and accrued expenses, approximate their fair values because of the short maturity of these instruments.

Cash and Restricted Cash

As of September 30, 2022 and December 31, 2021, the Partnership had $300 thousand of cash classified as restricted. This balance relates to a cash deposit for two standby letters of credit associated with oil and natural gas mining lease agreements. Restricted cash consists of cash that is stated at cost, which approximates fair market value. Classification of restricted cash is based on the nature of the restrictions associated with the underlying assets.

Revenue Receivable

Revenue receivable is comprised of accrued 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 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 $2,033 thousand and zero as of September 30, 2022 and December 31, 2021, respectively. Prepaid expenses were zero and $42 thousand as of September 30, 2022 and December 31, 2021, respectively.

Revenue Recognition

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.

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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 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 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 nine months ended September 30, 2022 and 2021 were approximately $47,772 thousand and $47,763 thousand, respectively. Natural gas and NGL sales for the nine months ended September 30, 2022 and 2021 were approximately $20,425 thousand and $8,552 thousand, respectively.

Take-in kind oil and natural gas revenues — Under certain arrangements, the Partnership has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer’s processing plant in lieu of receiving a net payment from the operator representing its proportionate share of its’ natural gas production. The Partnership currently takes certain processed gas volumes in kind in lieu of monetary settlement but does not currently take NGL volumes. When the Partnership elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Partnership will collect the consideration it is entitled to receive. Sales proceeds are generally received by the Partnership within one month after the month in which a sale has occurred. For the nine months ended September 30, 2022 and 2021, the Partnership’s revenue from in-kind agreements was approximately $41,816 thousand and $3,507 thousand, respectively. In these scenarios, the Partnership’s revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula but exclude the transportation expenses the Partnership incurs to transport the processed products to downstream customers.

Substantially all of the Partnership’s oil and natural gas sales come from four geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Haynesville Basin (Texas/Louisiana) 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 nine months ended September 30, 2022 and 2021.

	Nine months ended September 30, 2022
(in thousands)	Eagle Ford			Permian			Haynesville			Bakken
Revenues		$	10,830		$	9,561		$	52,223		$	37,399

	Nine months ended September 30, 2021
(in thousands)	Eagle Ford			Permian			Haynesville			Bakken
Revenues		$	9,113		$	8,255		$	8,080		$	34,374

Income Taxes

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

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 U.S. 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

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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 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 loss on derivative contracts in the condensed combined statements of income. Derivative assets are included within current and non-current 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 liabilities are included within current and non-current liabilities in the condensed combined balance sheets as of December 31, 2021. There were no derivative assets as of December 31, 2021.

Collar and Producer 3-way Option Contracts

A collar option is established with the sale of a call option and the purchase of a 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 options 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.

Volume of Derivative Activities

Contract Prices

Periods

Type of Contract

(Volume/Month)

Range

Weighted Average

Oct 2022 – Dec 2023

Producer 3-way (crude oil)

11,656 – 489

$113.10 – $40.00

$75.47

Oct 2022 – Dec 2022

Collar (crude oil)

6,795 – 709

$112.75 – $85.00

$95.77

Nov 2022 – Mar 2023

Producer 3-way (natural gas)

238,915 – 4,645

$17.10 – $2.50

$8.49

Nov 2022 – June 2023

Collar (natural gas)

99,132 – 41,547

$10.50 – $2.90

$6.68

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

	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		$	714		$	340		$	—		$	—
Natural gas			—			—			(558)			—
Total		$	714		$	340		$	(558)		$	—

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

	Nine months ended September 30, 2022
(in thousands)	Realized loss			Change in unrealized gain			Total
Primary underlying risk
Commodity price
Crude oil		$	(7,410)		$	3,414		$	(3,996)
Natural gas			(7,223)			155			(7,068)
Total		$	(14,633)		$	3,569		$	(11,064)

	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		$	—		$	—		$	(2,131)		$	(229)
Natural gas			—			—			(713)			—
Total		$	—		$	—		$	(2,844)		$	(229)

The following table identifies the net loss amounts included in the accompanying condensed combined statements of income as loss on derivative contracts for the nine months ended September 30, 2021.

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	Nine months ended September 30, 2021
(in thousands)	Realized loss			Change in unrealized loss			Total
Primary underlying risk
Commodity price
Crude oil		$	(4,330)		$	(4,485)		$	(8,815)
Natural gas			(1,018)			(3,880)			(4,898)
Total		$	(5,348)		$	(8,365)		$	(13,713)

4. Fair value measurements

Fair values — Recurring

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

(in thousands)	Level 1			Level 2			Level 3			September 30, 2022
Assets (at fair value):
Derivative contracts		$	—		$	1,054		$	—		$	1,054
Liabilities (at fair value):
Derivative contracts		$	—		$	(558)		$	—		$	(558)

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

(in thousands)	Level 1			Level 2			Level 3			December 31, 2021
Liabilities (at fair value):
Derivative contracts		$	—		$	(3,073)		$	—		$	(3,073)

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		$	—		$	—		$	20,000		$	20,000

Fair Values — Non Recurring

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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 $130 thousand.

5. Oil and natural gas properties

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.

Bakken Basin — During the nine months ended September 30, 2022, the Partnership acquired proved undeveloped oil and natural gas properties in the Bakken Basin of approximately $1,600 thousand.

For the nine months ended September 30, 2021, the Partnership made no acquisitions of oil and natural gas properties.

Divestitures

Permian Basin — During the nine months ended September 30, 2021, the Partnership sold a partial unit of oil and natural gas properties in the Permian Basin for approximately $1,054 thousand eliminating equivalent amounts from the property accounts. No gain or loss was recorded. Customary post-close adjustments were made during the nine months ended September 30, 2022, which resulted in a cash inflow of approximately $6 thousand.

Bakken Basin — During the nine months ended September 30, 2021, the Partnership sold a partial unit of oil and natural gas properties in the Bakken Basin for approximately $955 thousand, recognizing the full amount as a gain.

6. Partners’ capital

Allocation of Net Profits and Losses

(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)

(d)

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

In accordance with the Limited Partnership Agreement, the reallocation from Limited Partners to the General Partner was approximately $13,929 thousand for the nine months ended September 30, 2022. There

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was no reallocation between the General Partner and the Limited Partners for the 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 nine months ended September 30, 2022, the Partnership did not make any distributions. For the nine months ended September 30, 2021, the Partnership made distributions of Investment Proceeds of approximately $25,845 thousand to the Limited Partners and approximately $135 thousand to the General Partner.

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 admitted to the Partnership on or before the initial closing date will be assessed one and one-half (1.5%) per annum of such limited partner’s aggregate capital commitment. Limited partners admitted to the Partnership after the initial closing date will be assessed two percent (2%) per annum of such limited partner’s aggregate capital commitment. For the nine months ended September 30, 2022 and 2021, management fees were $1,736 thousand.

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 $1,412 thousand in capital expenditures that were included in accounts payable, and the Partnership estimates that it is committed to an additional approximately $10,623 thousand in development capital expenditures not yet incurred for wells the Partnership elected to participate in.

9. Credit facility

Since November 17, 2016, the Partnership has maintained a revolving credit facility (the “Facility”). Following a series amendments to the Facility, the borrowing capacity was amended to $40,000 thousand, of which $0 thousand and $20,000 thousand was outstanding at September 30, 2022 and December 31, 2021, respectively.

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As of September 30, 2022 and December 31, 2021, the revolving credit facility bore interest at an annual base rate equal to the Prime Rate plus the applicable margin of 0.25%. As of September 30, 2022 and December 31, 2021 the weighted average interest rate on borrowed amounts was approximately 4.10% and 3.34%, respectively. For the nine months ended September 30, 2022 and 2021, the Partnership incurred approximately $489 thousand and $611 thousand, respectively, in interest expense on related borrowings. The amount of debt issuance cost incurred related to the note totaled approximately $277 thousand. There was no amortization expense included in interest expense during the nine months ended September 30, 2022. There was approximately $7 thousand of amortization expense included in interest expense during the nine months ended September 30, 2021. There were no unamortized debt issuance costs as of September 30, 2022 and December 31, 2021. 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 statements of revenue 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 continues 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 nine months ended September 30, 2022, management has evaluated subsequent events for potential recognition and disclosure through the date November 18, 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 signed 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.

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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.

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Independent Auditor’s Report

The Partners Grey Rock Energy Fund II, L.P.
Grey Rock Energy Fund II-B, LP
Grey Rock Energy Fund II-B Holdings, L.P.
Grey Rock Preferred Limited Partner II, L.P.
Dallas, Texas

Opinion

We have audited the combined financial statements of 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. (collectively, the Partnership), which comprise the balance sheets as of December 31, 2021 and 2020, and the related statements of income, changes in partners’ capital, and cash flows for the years then ended, and the related notes to the combined financial statements.

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of 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., as of December 31, 2021 and 2020, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the “Auditor’s Responsibilities for the Audit of the combined financial statements” section of our report. We are required to be independent of 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. and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Responsibilities of Management for the Combined Financial Statements

Management is responsible for the preparation and fair presentation of the combined financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the combined financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about 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.’s ability to continue as a going concern within one year after the date that these financial statements are available to be issued.

Auditor’s Responsibilities for the Audit of the Combined Financial Statements

Our objectives are to obtain reasonable assurance about whether the combined financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a

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substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the combined financial statements.

In performing an audit in accordance with GAAS, we:

•

Exercise professional judgment and maintain professional skepticism throughout the audit.

•

Identify and assess the risks of material misstatement of the combined financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the combined financial statements.

•

Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of 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.’s internal control. Accordingly, no such opinion is expressed.

•

Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the combined financial statements.

•

Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about 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.’s ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.

Supplementary Information

Our audits were conducted for the purpose of forming an opinion on the combined financial statements that collectively comprise the Partnership’s basic financial statements. The supplemental oil and gas information listed in the table of contents is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the basic financial statements.

The supplemental oil and gas information has not been subjected to the auditing procedures applied in the audits of the combined financial statements, and accordingly, we do not express an opinion or provide any assurance on it.

/s/ BKD, LLP

Dallas, Texas
April 29, 2022

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GREY ROCK ENERGY FUND II

COMBINED BALANCE SHEETS

	December 31,
	2021			2020
ASSETS
Current assets:
Cash		$	3,794,175		$	4,282,991
Revenue receivable			13,401,534			7,979,754
Advances to operators			667,420			712,685
Other assets			41,775			—
Derivative assets			—			20,818
Total current assets			17,904,904			12,996,248
Property and equipment:
Oil and natural gas properties, successful efforts method			306,761,326			294,315,288
Accumulated depletion			(151,425,252)			(120,715,183)
Total property and equipment, net			155,336,074			173,600,105
Long-term assets:
Cash deposit			300,000			300,000
Total long-term assets			300,000			300,000
TOTAL ASSETS		$	173,540,978		$	186,896,353
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued expenses		$	3,055,246		$	3,751,309
Credit facilities – current portion			20,000,000			—
Related party payable			2,460			4,244
Derivative liabilities – current portion			2,843,968			—
Distributions payable			—			6,272
Total current liabilities			25,901,674			3,761,825
Long-term liabilities:
Credit facilities			—			22,093,476
Derivative liabilities			228,697			—
Asset retirement obligations			1,750,374			2,123,417
Total long-term liabilities			1,979,071			24,216,893
Commitments and contingencies (Note 9)
Partners’ capital:
General partner			1,507,630			1,552,748
Limited partners			144,152,603			157,364,887
Total partners’ capital			145,660,233			158,917,635
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$	173,540,978		$	186,896,353

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

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GREY ROCK ENERGY FUND II

COMBINED STATEMENTS OF OPERATIONS

	Year ended December 31,
	2021			2020
REVENUES
Oil, natural gas, and related product sales		$	82,390,919		$	49,017,143
EXPENSES
Lease operating expenses			13,128,031			13,760,216
Production taxes			5,675,224			3,564,671
Depletion and accretion expense			31,089,394			47,979,505
Professional fees			541,457			991,537
Management fees			2,315,236			2,184,827
General and administrative			671,018			495,844
Gain on disposal of oil and natural gas properties			(937,776)			(51,236)
Total expenses			52,482,584			68,925,364
Net operating income/(loss)			29,908,335			(19,908,221)
OTHER EXPENSE
Gain/(loss) on derivative contracts			(13,231,883)			8,363,451
Interest expense			(848,854)			(1,167,729)
Total other income/(expense)			(14,080,737)			7,195,722
NET INCOME/(LOSS)		$	15,827,598		$	(12,712,499)

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

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GREY ROCK ENERGY FUND II

COMBINED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

	General Partner			Limited Partner			Total
Balance at December 31, 2019		$	5,400,965		$	169,111,846		$	174,512,811
Net loss			(4,040)			(12,708,459)			(12,712,499)
Partners’ contributions			51,635			9,948,365			10,000,000
Partners’ distributions			(66,522)			(12,816,155)			(12,882,677)
Carried interest reallocation			(3,829,290)			3,829,290			—
Balance at December 31, 2020		$	1,552,748		$	157,364,887		$	158,917,635
Net income			105,062			15,722,536			15,827,598
Partners’ distributions			(150,180)			(28,934,820)			(29,085,000)
Balance at December 31, 2021		$	1,507,630		$	144,152,603		$	145,660,233

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

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GREY ROCK ENERGY FUND II

COMBINED STATEMENTS OF CASH FLOWS

	Year Ended December,
	2021			2020
Operating activities:
Net income/(loss)		$	15,827,598		$	(12,712,499)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Depletion and accretion			31,112,120			47,979,505
Unrealized (gain)/loss on derivative contracts			3,093,483			(722,525)
Gain on disposal of oil and gas properties			(937,776)			(51,236)
Amortization of loan origination costs			6,524			66,636
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Revenue receivable			(5,421,780)			9,539,182
Accrued expenses			354,037			218,628
Other receivable			—			247,142
Other assets			(41,775)			—
Related party payable			(1,784)			4,244
Net cash provided by operating activities			43,990,647			44,569,077
Investing activities:
Acquisition of proved oil and gas properties			(27,722)			(4,639,005)
Proceeds from the disposal of oil and gas properties			1,956,160			51,236
Refunds from advances to operators			333,614			—
Development of oil and gas properties			(15,550,243)			(24,832,294)
Net cash used in investing activities			(13,288,191)			(29,420,063)
Financing activities:
Proceeds from borrowing			10,000,000			8,500,000
Repayments of borrowing			(12,100,000)			(17,500,000)
Partners’ contributions			—			10,000,000
Partners’ distributions, net of change in distributions payable			(29,091,272)			(12,876,405)
Net cash used in financing activities			(31,191,272)			(11,876,405)
Net increase/(decrease) in cash			(488,816)			3,272,609
Cash and restricted cash at beginning of year			4,282,991			1,010,382
Cash and restricted cash end of year		$	3,794,175		$	4,282,991
Supplemental disclosure of cash flow information
Cash paid during the year for interest		$	762,158		$	545,730
Supplemental disclosure of non cash investing activities
Revision of asset retirement costs		$	768,348		$	(632,209)
Acquired and assumed asset retirement obligations		$	24,949		$	175,450
Oil and natural gas property development costs in accounts payable and accrued expenses		$	1,349,907		$	2,245,735
Cash and restricted cash:
Cash		$	3,794,175		$	4,282,991
Restricted cash included in Cash Deposit		$	300,000		$	300,000

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

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GREY ROCK ENERGY FUND II

NOTES TO THE COMBINED FINANCIAL STATEMENTS

1. Nature of operations

Grey Rock Energy Fund II, LP (“Grey Rock II”) was formed on November 25, 2015 as a Delaware limited partnership. Grey Rock II 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 II-B, LP (“Grey Rock II-B”) was formed on June 28, 2016, as a Delaware limited partnership. Grey Rock II-B was created for the purpose of acquiring net profits interests (“NPI”) in oil and natural gas assets from Grey Rock II-B Holdings, a related party, in multiple basins in North America, in accordance with the limited partnership agreement.

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

The term of the Partnership is up to 8 years. The investment term is 3 years and may be extended by the General Partner, in its sole discretion, for one year. The harvest period is 3 years and may be extended by the General Partner, in its sole discretion, for one year. 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.

2. Summary of significant accounting policies

Principles of Combination

The accompanying combined financial statements include the accounts of Grey Rock II, Grey Rock II-B Holdings, Grey Rock II-B, and Grey Rock PLP all of which are commonly owned and controlled. All inter-entity balances and transactions have been eliminated in combination.

Basis of Presentation

The combined financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Comprehensive income/(loss) for the Partnership is the same as net income/(loss) for all years presented. 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.

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Fair Value of Financial Instruments

The Partnership has adopted and follows Accounting Standard Codification (“ASC”) 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in 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.

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, and accounts payable and accrued expenses, approximate their fair values because of the short maturity of these instruments.

Cash and Restricted Cash

As of December 31, 2021 and 2020, the Partnership had $300,000 of cash classified as restricted. This balance relates to a cash deposit for two standby letters of credit associated with oil and gas mining lease agreements. Restricted cash consists of cash that is stated at cost, which approximates fair market value. Classification of restricted cash is based on the nature of the restrictions associated with the underlying assets.

Revenue Receivable

Revenue receivable is comprised of accrued 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 years ended December 31, 2021 and 2020, the Partnership had no bad debt expense, and did not record an allowance for doubtful accounts.

Advance to operators

The Partnership participates in the drilling of oil and natural gas wells with other working interest partners. Due to the capital intensive nature of oil and natural gas drilling activities, our partner operators may request advance payments from working interest partners for their share of the costs. The Partnership expects such advances to be applied by these operators against joint interest billings for its share of drilling

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operations within 90 days from when the advance is paid. Changes in advances to operators are presented as an investing outflow within capital expenditures for oil and natural gas properties, net on the statements of cash flows.

Other assets

Other assets is comprised of payments made in advance for services deemed to have future value to the Partnership. At December 31, 2021 prepaid expenses equaled approximately $42,000. There were no prepaid expenses as of December 31, 2020.

Oil and Natural Gas Properties

There were no exploratory wells capitalized pending determinations of whether the wells have proved reserves at December 31, 2021 and 2020. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. The Partnership capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. For the years ended December 31, 2021 and 2020, no interest costs were capitalized because exploration and development projects were less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves. Depletion for oil and natural gas producing property, and related equipment was approximately $30,710,000 and $47,689,000 for the years ended December 31, 2021 and 2020, respectively.

Effective January 1, 2019, the Partnership adopted ASU 2017-1, Business Combinations: Clarifying the Definition of Business, which provides a methodology to determine when a set of assets is not a business. The guidance requires that when substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Partnership did not make acquisitions of oil and natural gas properties during the year ended December 31, 2021. The Partnership has determined that acquisitions of oil and natural gas properties totaling approximately $3,049,000 during the year ended December 31, 2020 qualified as the purchase of a business. The Partnership has determined that all other acquisitions of oil and natural gas properties qualified as a concentrated group of similar identifiable assets. See discussions of the Partnership’s oil and natural gas asset acquisitions in Note 5, Oil and natural gas properties.

Upon the sale or retirement of a complete unit of proved property, the costs and related accumulated depletion are eliminated from the property accounts, and the resulting gain or loss is recognized. Upon the retirement or sale of a partial unit of proved property, the cost is charged to the property accounts without a resulting gain or loss recognized in income. In 2021 the Partnership sold a partial unit of the Permian Basin. The Partnership did not sell any of units of proved oil and natural gas properties during the year ended December 31, 2020.

Capitalized costs related to proved oil and natural gas properties, including wells and related support equipment and facilities, are evaluated for impairment on an analysis of undiscounted future cash flows in accordance with ASC 360, Property, Plant, and Equipment. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Partnership recognizes an impairment charge in operating income equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. The Partnership did not recognize an impairment of proved properties for the years ended December 31, 2021 and 2020.

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Asset Retirement Obligation

The Partnership follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Partnership’s asset retirement obligation relates to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.

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, when the Partnership has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable.

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 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.

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 years ended December 31, 2021 and 2020, the Partnership’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.

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December 31, 2021 and 2020 were approximately $61,027,000 and $37,887,000, respectively. Natural gas and NGL sales for the years ended December 31, 2021 and 2020 were approximately $16,116,000 and $5,892,000, respectively.

Take-in kind oil and natural gas revenues — Under certain arrangements, the Partnership has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer’s processing plant in lieu of receiving a net payment from the operator representing its proportionate share of its’ natural gas production. The Partnership currently takes certain processed gas volumes in kind in lieu of monetary settlement but does not currently take NGL volumes. When the Partnership elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Partnership will collect the consideration it is entitled to receive. Sales proceeds are generally received by the Partnership within one month after the month in which a sale has occurred. For the years ended December 31, 2021 and 2020, the Partnership’s revenue from in-kind agreements were approximately $5,247,000 and $5,238,000, respectively. In these scenarios, the Partnership’s revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula but exclude the transportation expenses the Partnership incurs to transport the processed products to downstream customers. There was no impact to the financial statement presentation as a result of the adoption of ASC 606, as the natural gas and NGL transportation costs of approximately $926,000 and $1,608,000 remained classified as lease operating expenses for the year ended December 31, 2021 and 2020, respectively.

The Partnership’s disaggregated revenue has two primary sources: oil sales and natural gas sales. Substantially all of the Partnership’s oil and natural gas sales come from four geographic areas in the United States: the Eagle Ford Basin (Texas), the Permian Basin (Texas), the Haynesville Basin (Texas/Louisiana) and the Bakken Basin (Montana/North Dakota). The following tables present the disaggregation of the Partnership’s oil revenues and natural gas revenues by basin for the years ended December 31, 2021 and 2020.

	Year Ended December 31, 2021
	Eagle Ford			Permian			Haynesville			Bakken
Net Revenues		$	12,196,699		$	10,751,034		$	12,039,176		$	47,404,010

	Year Ended December 31, 2020
	Eagle Ford			Permian			Haynesville			Bakken
Net Revenues		$	7,012,502		$	10,103,716		$	9,109,651		$	22,791,274

Lease Operating Expenses

Lease operating expenses represent field employees’ salaries, salt water disposal, ad valorem taxes, repairs and maintenance, expensed work overs and other operating expenses. Lease operating expenses are expensed as incurred.

Production Taxes

The partnership incurs severance tax on the sale of its production which is generated in Texas, Louisiana, and North Dakota. These taxes are reported on a gross basis within the accompanying combined statements of operations. Sales-based taxes for the years ended December 31, 2021 and December 31, 2020, were approximately $5,675,000 and $3,565,000, respectively, an increase of approximately $2,110,000.

Ad Valorem Taxes

The Partnership incurs ad valorem tax on the value of its properties in Texas and Louisiana. These taxes are included in lease operating expenses within the accompanying combined statements of operations. Ad valorem taxes for the years ended December 31, 2021 and 2020 were approximately $399,000 and $493,000, respectively, a decrease of approximately $94,000.

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Income Taxes

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 December 31, 2021 and 2020. 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.

Use of Estimates

Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and natural gas prices, future operating costs, severance taxes, development costs and work over costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic.

For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the

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assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Partnership’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.

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 becomes effective for us beginning January 1, 2022 and we expect to adopt using a modified retrospective approach with certain available practical expedients. Oil and gas leases are excluded from the guidance. We do not expect this ASU to materially affect the combined financial statements and related note disclosures.

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 collar options. 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 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/(loss) on derivative contracts in the combined statements of operations. Derivative liabilities are included within current and non-current liabilities in the combined balance sheets as of December 31, 2021. Derivative assets are included within current assets in the combined balance sheets as of December 31, 2020.

Swap, Collar and Producer 3-way Option Contracts

The fair value of options reported in the 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 swap or 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.

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Volume of Derivative Activities

Contract Prices

Year

Type of Contract

(Volume/Month)

Range

Weighted
Average

Jan 2022 – Mar 2023

Producer 3-way (crude oil)

36,873 – 3,405

$80.00 – $40.00

56.42

Feb 2022 – Dec 2022

Producer 3-way (natural gas)

13,5470 – 12,768

9.40 – 1.90

2.93

Feb 2022 – Dec 2022

Collar (natural gas)

105,611 – 56,304

4.95 – 2.90

3.90

Year

Type of Contract

(Volume/Month)

Contract Prices

Range

Weighted
Average

Jan 2021 – Dec 2021

Producer 3-way (crude oil)

21,997 – 11,245

$58.25 – $38.41

47.57

Jan 2021 – Dec 2021

Collar (crude oil)

26,828 – 13,852

46.00 – 32.50

39.25

Feb 2021 – Apr 2021

Producer 3-way (natural gas)

186,000 – 119,524

3.63 – 2.00

2.71

Feb 2021 – Jun 2021

Collar (natural gas)

176,337 – 132,245

3.30 – 2.15

2.55

Jul 2021 – Dec 2021

Short swaps (natural gas)

177,244 – 133,798

2.81

Impact of Derivatives on the Combined Balance Sheets and Combined Statements of Operations

	Derivative Assets			Derivative liabilities			Total loss from derivative instruments
Primary underlying risk Commodity price
Crude oil		$	—		$	(2,359,833)		$	(9,579,070)
Natural gas			—			(712,832)			(3,652,813)
Total		$	—		$	(3,072,665)		$	(13,231,883)

	Realized loss			Unrealized loss			Total
Primary underlying risk Commodity price
Crude oil		$	(7,314,940)		$	(2,264,130)		$	(9,579,070)
Natural gas			(2,823,460)			(829,353)			(3,652,813)
Total		$	(10,138,400)		$	(3,093,483)		$	(13,231,883)

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The following table identifies the fair value amounts of derivative instruments included in the accompanying combined balance sheets as derivative assets categorized by primary underlying risk, at December 31, 2020. The following table also identifies the net gain amounts included in the accompanying combined statements of operations as gain/(loss) on derivative contracts for the year ended December 31, 2020.

	Derivative Assets			Derivative liabilities			Total gain from derivative instruments
Primary underlying risk Commodity price
Crude oil		$	—		$	(95,703)		$	7,247,779
Natural gas			116,521			—			1,115,672
Total		$	116,521		$	(95,703)		$	8,363,451

	Realized gain			Unrealized gain			Total
Primary underlying risk Commodity price
Crude oil		$	6,196,918		$	1,050,861		$	7,247,779
Natural gas			1,444,008			(328,336)			1,115,672
Total		$	7,640,926		$	722,525		$	8,363,451

4. Fair value measurements

Fair values — Recurring

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

	Level 1			Level 2			Level 3			December 31, 2021
Liabilities (at fair value):
Derivative		$	—		$	(3,072,665)		$	—		$	(3,072,665)

The following table presents information about the Partnership’s recurring assets measured at fair value as of December 31, 2020:

	Level 1			Level 2			Level 3			December 31, 2021
Assets (at fair value):
Derivative		$	—		$	20,818		$	—		$	20,818

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

	December 31, 2021						December 31, 2020
	Carrying Value			Fair Value			Carrying Value			Fair Value
Liabilities (not at fair value):
Revolving credit facility		$	20,000,000		$	20,000,000		$	22,093,476		$	22,093,476

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Fair Values — Non Recurring

5. Oil and natural gas properties

2021 Acquisitions

Permian Basin — The Partnership paid lease extension fees of approximately $28,000 in November 2021 to hold previously acquired properties.

2021 Divestitures

Bakken Basin — For the year ended December 31, 2021, Customary post-closing adjustments in June and December of 2021 resulted in a decrease to the property accounts of approximately $7,000. In March 2021, the Partnership sold a partial unit of oil and natural gas properties in the Bakken Basin for approximately $933,000, recognizing the full amount as a gain. In December 2021, the Partnership sold a partial unit of oil and natural gas properties in the Bakken Basin for approximately $12,000, eliminating equivalent amounts from the property accounts.

Permian Basin — For the year ended December 31, 2021, the Partnership sold a partial unit of oil and natural gas properties in the Permian Basin for approximately $1,004,000, eliminating equivalent amounts from the property accounts.

2020 Acquisitions

Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. For the year ended December 31, 2020, the Partnership acquired various producing oil and natural gas properties and proved oil and natural gas properties, which included working interests ranging from 3.00% – 22.58% and net revenue interests ranging from 2.22% – 20.14%, in Texas and North Dakota. In certain acquisitions, the oil and natural gas properties have ongoing development, and as the nonoperator, the Partnership is committed to fund future costs associated with the assumed authorization for expenditures (AFE). The consideration exchanged for the assets acquired and liabilities assumed was derived using ASU 2017-1 to calculate the fair-value shortly before the acquisition dates and was completed to provide a return to the investors of the Partnership. Certain acquisitions of these oil and natural gas properties meet the definition of a business combination under the ASC 805, Business Combinations.

Bakken Basin — The Partnership acquired proved developed nonproducing oil and natural gas properties in the Bakken Basin of approximately $264,000 in February 2020. The Partnership acquired proved undeveloped properties of approximately $200,000 in March and $95,000 in April of 2020.

Eagle Ford Basin — The Partnership paid lease extension fees of approximately $37,000 in March 2020 to hold previously acquired properties. The Partnership acquired proved oil and natural gas properties in the Eagle Ford Basin of approximately $3,049,000 in April 2020 that included proved developed producing properties. This acquisition met the definition of a business combination. The fair value of assets acquired and liabilities assumed is outlined in the table below.

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Permian Basin — Customary post close adjustments related to prior period acquisitions were made during the year end December 31, 2020 which resulted in cash outflows of approximately $994,000.

The following table presents a summary of the fair value of the assets acquired and the liabilities assumed in acquisitions that met the definition of a business combination:

	December 31, 2020
Fair value of proved assets acquired and liabilities assumed
Proved oil and gas properties(1)		$	3,176,122
Less: Asset retirement obligations			(126,691)
Net assets acquired			3,049,431
Consideration transferred (including liabilities assumed)		$	3,049,431

(1)

Amount includes asset retirement costs of $126,691 for 2020

2020 Divestitures

Bakken Basin — For the year ended December 31, 2020, customary post-closing adjustments related to prior period divestitures resulted in the recognition of a gain of approximately $51,000.

6. Asset retirement obligations

The Partnership has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations have been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of December 31, 2021 and 2020. In 2021 the estimated liability was revised downward due to price increases which extended the useful life of the assets. In 2020, declining prices lead to a decrease in the useful life of the assets resulting in an increase to the estimate. The Partnership evaluated 1,107 and 1,036 wells, respectively, and has estimated a range of abandonment dates between the years 2023 and 2066.

The following table presents the changes in the asset retirement obligations for the years ended December 31, 2021 and 2020:

	2021			2020
Asset retirement obligations, beginning of year		$	2,123,417		$	1,024,948
Additions to capitalized asset retirement obligations			24,949			175,449
Revisions to asset retirement costs			(768,348)			632,209
Accretion of discount			402,050			290,811
Disposals and settlements			(31,694)			—
Asset retirement obligations, end of year		$	1,750,374		$	2,123,417

7. Partners’ capital

Commitments and contributions

Funded and unfunded capital commitments as of December 31, 2021 are as follows:

	General Partner			Limited Partner			Total
Committed capital		$	750,000		$	144,500,000		$	145,250,000
Less: Unfunded committed capital			64,802			6,685,238			6,750,040
Funded Capital Contributions		$	685,198		$	137,814,762		$	138,499,960

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

Allocation of Net Profits and Losses

(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)

(d)

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

In accordance with the Limited Partnership Agreement, there was no reallocation from the general partner to the limited partners for the year ended December 31, 2021. The reallocation from the general partner to the limited partners was approximately $3,829,000, for the year ended December 31, 2020. The allocation of carried interest will remain provisional until the final liquidation of the Partnership.

Distributions

In accordance with the 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 year ended December 31, 2021, the Partnership made distributions of Investment Proceeds of approximately $28,935,000 to the Limited Partners and approximately $150,000 in distributions to the General Partner. For the year ended December 31, 2020, the Partnership made distributions of Investment Proceeds of approximately $12,820,000 to the Limited Partners and approximately $62,000 in distributions to the General Partner. As of December 31, 2021 and 2020, the Partnership had distributions payable to the Limited Partners of approximately $0 and $6,000, respectively.

8. 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 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 admitted to the Partnership on or before the initial closing date will be assessed one and one-half (1.5%) per annum of such limited partner’s aggregate capital commitment. Limited partners admitted to the Partnership after the initial closing date will be assessed two percent (2%) per annum of such limited partner’s aggregate capital commitment. For the years ended December 31, 2021 and 2020, the Partnership paid approximately $2,315,000 and $2,185,000 in management fees, respectively.

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9. 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. As of December 31, 2021 there were no significant outstanding commitments.

10. Credit facility

Since November 17, 2016, the Partnership has maintained a revolving credit facility (the “Facility”). Following a series amendments to the Facility, the borrowing capacity was amended to $40,000,000 and $35,000,000, of which $20,000,000 and $22,100,000 was outstanding at December 31, 2021 and 2020, respectively. The Tenth and most recent amendment to Credit Agreement affirmed the maturity date of November 17, 2022.

As of December 31, 2021, the revolving credit facility bears interest at an annual base rate equal to the Prime Rate plus the applicable margin of 0.25%. As of December 31, 2020 the facility bore interest at an annual base rate ranging from 0.00% to 0.75% plus an applicable margin ranging from 2.00% to 3.00% plus LIBOR as determined by the London interbank on the interest determination date. As of December 31, 2021 and 2020, the weighted average interest rate on borrowed amounts was approximately 3.34% and 3.87%, respectively. For the years ended December 31, 2021 and 2020, the Partnership incurred approximately $849,000, and $1,168,000, respectively, in interest expense on related borrowings. The amount of debt issuance cost incurred related to the note totaled approximately $277,000. There was approximately $7,000 and $66,000 of amortization expense included in interest expense during the years ended December 31, 2021 and 2020, respectively, leaving approximately $7,000, of unamortized debt issuance cost as of December 31, 2020, respectively. There were no unamortized debt issuance costs as of December 31, 2021.

11. Risk concentrations

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the worldwide economy and specific economic sectors. As a result, commodity prices declined precipitously, which may impact the Partnership’s performance and may lead to future losses.

12. Subsequent events

In connection with preparing the combined financial statements for the year ended December 31, 2021, management has evaluated subsequent events for potential recognition and disclosure through the date April 29, 2022, which is the date the combined financial statements were available to be issued.

The Partnership paid down the revolving credit facility by approximately $3,000,000 on February 3, 2022.

13. Supplemental Oil and Gas Information (unaudited)

Oil and Natural Gas Exploration and Production Activities

Oil and Natural Gas Reserves and Related Financial Data

Oil and Natural Gas Reserve Data

	Natural Gas (MMcf)		Oil (MBbl)		MBoe
Proved Developed and Undeveloped Reserves at December 31, 2019		86,158		8,733		23,093
Revisions of Previous Estimates		(31,805)		(2,742)		(8,043)
Extensions, Discoveries and Other Additions		1,379		365		595
Divestiture of Reserves		(95)		(65)		(81)
Acquisition of Reserves		62		135		145
Production		(7,142)		(1,021)		(2,211)
Proved Developed and Undeveloped Reserves at December 31, 2020		48,557		5,405		13,498
Revisions of Previous Estimates		16,489		292		3,041
Extensions, Discoveries and Other Additions		888		589		737
Divestiture of Reserves		(51)		(30)		(39)
Production		(5,595)		(956)		(1,889)
Proved Developed and Undeveloped Reserves at December 31, 2021		60,288		5,300		15,348

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•

Notable changes in proved reserves for the year ended December 31, 2021 included the following:

•

Extensions and discoveries. In 2021, total extensions and discoveries of 737 MBoe were primarily attributable to successful drilling in the Bakken and Eagle Ford Basins as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 98 MBoe as a result of successful drilling in the Bakken and Eagle Ford Basins and 631 MBoe as a result of additional proved undeveloped locations. Extensions from current production were 8 MBoe from the Eagle Ford, Haynesville and Permian Basins.

•

Revisions to previous estimates. In 2021, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 3,041 MBoe. The upward revision in reserves was due to a combination of favorable adjustments attributable to well performance and higher crude oil prices, increasing reserves by 2,282 MBoe and 759 MBoe, respectively.

•

Divestiture of reserves. In 2021, total divestiture of reserves of 39 MBoe were primarily attributable to the divestiture of oil and natural gas properties in the Permian Basin (see Note 5).

•

Notable changes in proved reserves for the year ended December 31, 2020 included the following:

•

Extensions and discoveries. In 2020, total extensions and discoveries of 595 MBoe were primarily attributable to successful drilling in the Permian Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 11 MBoe as a result of successful drilling in the Permian Basin and 555 MBoe as a result of additional proved undeveloped locations. Extensions from current production were 29 MBoe from the Permian Basin.

•

Revisions to previous estimates. In 2020, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 8,043 MBoe. The downward revision in reserves was due to a combination of unfavorable adjustments attributable to well performance and lower crude oil prices, reducing reserves by 5,037 MBoe and 3,006 MBoe, respectively.

•

Divestiture of reserves. In 2020, divestiture of reserves of 81 MBoe were primarily attributable to the divestiture of oil and natural gas properties in the Bakken Basin (see Note 5).

•

Acquisition of reserves. In 2020, acquisition of reserves of 145 MBoe were primarily attributable to acquisitions of oil and natural gas properties in the Eagle Ford Basin (see Note 5).

	Natural Gas (MMcf)		Oil (MBbl)		MBoe
Proved Developed Reserves:
December 31, 2019		29,636		5,947		10,886
December 31, 2020		18,979		3,745		6,908
December 31, 2021		22,110		4,213		7,898
Proved Undeveloped Reserves:
December 31, 2019		56,522		2,786		12,207
December 31, 2020		29,578		1,660		6,590
December 31, 2021		38,178		1,087		7,450

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

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Gas (“ASC 932”). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our oil and natural gas reserves and for asset retirement obligations, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Partnership’s proved oil and natural gas reserves. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Partnership. Material revisions to estimates of proved reserves may occur in the future; development and production of reserves may not occur in the period assumed; actual prices realized are expected to vary significantly from those used and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Partnership’s proved oil and natural gas reserves as of December 31, 2021 and 2020:

	December 31,
	2021			2020
	(In thousands)
Future cash inflows		$	530,180		$	251,346
Future production costs			(164,426)			(98,309)
Future development costs			(45,962)			(39,413)
Future income tax expense			(801)			(420)
Future net cash flows			318,991			113,204
10% discount for estimated timing of cash flows			(113,779)			(43,514)
Standardized measure of discounted future net cash flows		$	205,212		$	69,690

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

	December 31,
	2021			2020
	(In thousands)
Balance, beginning of period		$	69,690		$	189,835
Sales of oil and natural gas produced, net of production costs			(63,588)			(31,692)
Extensions and discoveries			14,236			3,010
Previously estimated development cost incurred during the period			9,483			5,981
Net change of prices and production costs			136,694			(68,907)
Change in future development costs			(667)			6,028
Revisions of quantity and timing estimates			28,644			(48,496)
Accretion of discount			6,994			19,037
Change in income taxes			(220)			279
Acquisition of Reserves			—			2,272
Divestiture of Reserves			(482)			(1,094)
Other			4,428			(5,663)
Balance, end of period		$	205,212		$	69,690

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Annex A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this prospectus, which are commonly used in the oil and natural gas industry:

“3-D seismic” (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.

“Basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl” One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

“Boe” One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil and at a ratio of one Bbl of NGL to one Bbl of oil.

“Boe/d” One Boe per day.

“Bopd” One barrel of oil per day.

“Btu” or “British thermal unit” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Condensate.” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

“Development project” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

“Development well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Differential” An adjustment to the price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

“Dry hole” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“EUR” or “Estimated ultimate recovery” The sum of reserves remaining as of a given date and cumulative production as of that date.

“Exploratory well” An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined by the SEC.

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“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation” A layer of rock which has distinct characteristics that differs from nearby rocks.

“Gross wells” The total wells in which a working interest is owned.

“Held by production” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.

“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Hydraulic fracturing” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“Lease operating expenses” The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, marketing and transportation costs, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.

“MBoe” One thousand Boe.

“MBoe/d” One thousand Boe per day.

“Mcf” One thousand cubic feet of natural gas.

“MMBoe” One million Boe.

“MMBtu” One million Btus.

“MMcf” One million cubic feet of natural gas.

“Net acres” The percentage of total acres an owner has out of a particular number of acres or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Net production” Production that is owned by us, less royalties and production due others.

“NGLs” or “natural gas liquids” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX” The New York Mercantile Exchange.

“Operator” The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

“Pay” A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as a minimum porosity, permeability and hydrocarbon saturation) are net pay.

“PDP” Proved developing producing reserves.

“Play” A geographic area with hydrocarbon potential.

“Plug” A downhole tool that is set inside the casing to isolate the lower part of the wellbore.

“Pooling” The bringing together of small tracts or fractional mineral interests in one or more tracts to form a drilling and production unit for a well under applicable spacing rules.

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“Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

“Productive well” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proration unit” A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction.

“Prospect” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“Proved developed reserves” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate.

“Proved reserves” The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

“PUD” or “Proved undeveloped reserves” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having PUDs only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five (5) years, unless specific circumstances justify a longer time.

“PV-10” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

“Realized price” The cash market price less all expected quality, transportation and demand adjustments.

“Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserves” Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Resources” Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

“Royalty” An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof) but does not require the

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owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

“Service well” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Spot market price” The cash market price without reduction for expected quality, transportation and demand adjustments.

“Standardized measure” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Wellbore” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

“Workover” Operations on a producing well to restore or increase production.

The terms “condensate,” “development costs,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery (EUR),” “exploratory well,” “production costs,” “reserves,” “reservoir,” “resources,” “service wells” and “stratigraphic test well” are defined by the SEC. Except as noted, the terms defined in this section are not the same as SEC definitions.

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Annex B

May 6, 2022

Mr. Ryan Riggelson
Grey Rock Energy Management, LLC
2911 Turtle Creek Boulevard, Suite 1150
Dallas, Texas 75219

Dear Mr. Riggelson:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2021, to the Grey Rock Energy Fund, LP (referred to herein as “Grey Rock Energy Fund I”) interest in certain oil and gas properties located in North Dakota and Texas. Grey Rock Energy Management, LLC (GREP) provides management services for Grey Rock Energy Fund I. We completed our evaluation on March 1, 2022. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Grey Rock Energy Fund I. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Granite Ridge Resources Inc.’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Grey Rock Energy Fund I interest in these properties, as of December 31, 2021, to be:

	Net Reserves				Future Net Revenue (M$)
Category	Oil (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		599.4		1,319.3		24,854.7		15,397.1
Proved Developed Non-Producing		31.0		118.0		1,222.2		726.5
Proved Undeveloped		26.8		121.1		1,072.6		626.6
Total Proved		657.2		1,558.4		27,149.5		16,750.3

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

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Gross revenue is Grey Rock Energy Fund I’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Grey Rock Energy Fund I’s share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2021. For oil volumes, the average West Texas Intermediate spot price of $66.55 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.598 per MMBTU is adjusted for energy content, transportation fees, and market differentials. When applicable, gas prices have been adjusted to include the value for natural gas liquids. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $61.86 per barrel of oil and $4.912 per MCF of gas.

Operating costs used in this report are based on operating expense records of GREP. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses are not included. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by GREP and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Grey Rock Energy Fund I interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Grey Rock Energy Fund I receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by GREP, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

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For the purposes of this report, we used technical and economic data including, but not limited to, well location and acreage maps, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from GREP, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Nathan C. Shahan, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2007 and has over 5 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

By:

/s/ C.H. (Scott) Rees III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer

By:

/s/ Nathan C. Shahan

Nathan C. Shahan, P.E. 102389
Vice President

Date Signed: May 6, 2022

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves — Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

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Developed Non-Producing Reserves — Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)

Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)

Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)

Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)

Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

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(iii)

Dry hole contributions and bottom hole contributions.

(iv)

Costs of drilling and equipping exploratory wells.

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)

Oil and gas producing activities include:

(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)

The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)

Lifting the oil and gas to the surface; and

(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)

Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)

Oil and gas producing activities do not include:

(A)

Transporting, refining, or marketing oil and gas;

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(B)

Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)

Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

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(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)

Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)

Costs of labor to operate the wells and related equipment and facilities.

(B)

Repairs and maintenance.

(C)

Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)

Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)

Severance taxes.

(ii)

Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)

The area of the reservoir considered as proved includes:

(A)

The area identified by drilling and limited by fluid contacts, if any, and

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

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Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily

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take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

•

The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

•

The company’s historical record at completing development of comparable long-term projects;

•

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

•

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

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Annex C

May 9, 2022

Mr. Ryan Riggelson
Grey Rock Energy Management, LLC
2911 Turtle Creek Boulevard, Suite 1150
Dallas, Texas 75219

Dear Mr. Riggelson:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2021, to the interest of Grey Rock Energy Fund II, LP; Grey Rock Energy Fund II-B, LP; and Grey Rock Energy Fund II-B Holdings, LP (collectively referred to herein as “Grey Rock Energy Fund II et al.”) in certain oil and gas properties located in Louisiana, Montana, North Dakota, Texas, and Wyoming. Grey Rock Energy Management, LLC (GREP) provides management services for Grey Rock Energy Fund II et al. We completed our evaluation on March 1, 2022. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Grey Rock Energy Fund II et al. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Granite Ridge Resources Inc.’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Grey Rock Energy Fund II et al. interest in these properties, as of December 31, 2021, to be:

	Net Reserves				Future Net Revenue (M$)
Category	Oil (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		4,182.4		17,615.1		205,271.3		133,019.7
Proved Developed Non-Producing		31.1		4,494.4		11,445.9		9,443.7
Proved Undeveloped		1,086.8		38,178.3		105,869.4		63,824.3
Total Proved		5,300.3		60,287.8		322,586.6		206,287.7

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Gross revenue is Grey Rock Energy Fund II et al.’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Grey Rock Energy Fund II et al.’s share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2021. For oil volumes, the average West Texas Intermediate spot price of $66.55 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.598 per MMBTU is adjusted for energy content, transportation fees, and market differentials; for certain properties, gas prices are negative after adjustments. When applicable, gas prices have been adjusted to include the value for natural gas liquids. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $62.58 per barrel of oil and $3.293 per MCF of gas.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Grey Rock Energy Fund II et al. interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Grey Rock Energy Fund II et al. receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field-level accounting statements.

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For the purposes of this report, we used technical and economic data including, but not limited to, well location and acreage maps, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

By:

/s/ C.H. (Scott) Rees III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer

By:

/s/ Nathan C. Shahan

Nathan C. Shahan, P.E. 102389
Vice President

Date Signed: May 9, 2022

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Supplemental definitions from the 2018 Petroleum Resources Management System:

(i)

(ii)

(iii)

(iv)

Provide improved recovery systems.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(i)

Costs of topographical, geographical and geophysical studies, rights of access to properties to

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conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)

Dry hole contributions and bottom hole contributions.

(iv)

Costs of drilling and equipping exploratory wells.

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(16) Oil and gas producing activities.

(i)

Oil and gas producing activities include:

(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)

(1)

Lifting the oil and gas to the surface; and

(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the

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natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

(ii)

Oil and gas producing activities do not include:

(A)

Transporting, refining, or marketing oil and gas;

(B)

(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)

Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)

(ii)

(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)

(v)

(vi)

(i)

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic

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methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)

(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(20) Production costs.

(i)

(A)

Costs of labor to operate the wells and related equipment and facilities.

(B)

Repairs and maintenance.

(C)

Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)

Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)

Severance taxes.

(ii)

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(i)

The area of the reservoir considered as proved includes:

(A)

The area identified by drilling and limited by fluid contacts, if any, and

(B)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to

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be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

(iii)

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

(23) Proved properties. Properties with proved reserves.

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

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Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

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(i)

(ii)

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

•

The company’s historical record at completing development of comparable long-term projects;

•

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•

(iii)

(32) Unproved properties. Properties with no proved reserves.

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Annex D

May 10, 2022

Mr. Ryan Riggelson
Grey Rock Energy Management, LLC
2911 Turtle Creek Boulevard, Suite 1150
Dallas, Texas 75219

Dear Mr. Riggelson:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2021, to the interest of Grey Rock Energy Fund III-A, LP; Grey Rock Energy Fund III-B, LP; and Grey Rock Energy Fund III-B Holdings, LP (collectively referred to herein as “Grey Rock Energy Fund III et al.”) in certain oil and gas properties located in Colorado, New Mexico, North Dakota, and Texas. Grey Rock Energy Management, LLC (GREP) provides management services for Grey Rock Energy Fund III et al. We completed our evaluation on March 1, 2022. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Grey Rock Energy Fund III et al. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Granite Ridge Resources Inc.’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Grey Rock Energy Fund III et al. interest in these properties, as of December 31, 2021, to be:

	Net Reserves				Future Net Revenue (M$)
Category	Oil (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		5,871.2		28,095.6		350,251.9		247,307.0
Proved Developed Non-Producing		944.2		2,614.5		56,625.2		38,785.0
Proved Undeveloped		10,045.9		32,790.6		468,689.8		270,209.2
Total Proved		16,861.3		63,500.8		875,566.7		556,301.1

Totals may not add because of rounding.

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Gross revenue is Grey Rock Energy Fund III et al.’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Grey Rock Energy Fund III et al.’s share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Grey Rock Energy Fund III et al. interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Grey Rock Energy Fund III et al. receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field-level accounting statements.

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For the purposes of this report, we used technical and economic data including, but not limited to, well location and acreage maps, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

By:

/s/ C.H. (Scott) Rees III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer

By:

/s/ Nathan C. Shahan

Nathan C. Shahan, P.E. 102389
Vice President

Date Signed: May 10, 2022

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:

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(i)

(ii)

(iii)

(iv)

Provide improved recovery systems.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(i)

(ii)

Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

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(iii)

Dry hole contributions and bottom hole contributions.

(iv)

Costs of drilling and equipping exploratory wells.

(v)

Costs of drilling exploratory-type stratigraphic test wells.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(16) Oil and gas producing activities.

(i)

Oil and gas producing activities include:

(A)

The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B)

The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)

(1)

Lifting the oil and gas to the surface; and

(2)

Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)

The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

(ii)

Oil and gas producing activities do not include:

(A)

Transporting, refining, or marketing oil and gas;

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(B)

(C)

Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)

Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)

(ii)

(iii)

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)

(v)

(vi)

(i)

(ii)

(iii)

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

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(iv)

See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(20) Production costs.

(i)

(A)

Costs of labor to operate the wells and related equipment and facilities.

(B)

Repairs and maintenance.

(C)

Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D)

Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)

Severance taxes.

(ii)

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(i)

The area of the reservoir considered as proved includes:

(A)

The area identified by drilling and limited by fluid contacts, if any, and

(B)

(ii)

(iii)

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(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

(23) Proved properties. Properties with proved reserves.

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

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Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(i)

(ii)

Undrilled locations can be classified as having undeveloped reserves only if a development plan

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has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

•

The company’s historical record at completing development of comparable long-term projects;

•

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•

(iii)

(32) Unproved properties. Properties with no proved reserves.

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Granite Ridge Resources (GRNT) 424B3Prospectus supplement