As filed with the Securities and Exchange Commission on October 28, 2021

Registration No. 333-260166

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1 to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Desert Peak Minerals Inc.

(Exact name of registrant as specified in its charter)

Delaware	1311	83-4460942
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification No.)

1144 15^th Street

Suite 2650

Denver, Colorado 80202

(720) 640-7620

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Christopher L. Conoscenti

Chief Executive Officer

1144 15^th Street

Suite 2650

Denver, Colorado 80202

(720) 640-7620

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Douglas E. McWilliams
Scott D. Rubinsky
Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2500
Houston, Texas 77002
(713) 758-2222 Ryan J. Maierson
Thomas G. Brandt
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400

Approximate date of commencement of proposed sale of the securities to the public:

As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee(3)
Class A Common Stock, par value $0.01 per share	$264,500,000	$24,519.15

(1) Includes shares issuable upon exercise of the underwriters’ option to purchase additional shares.

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(3) Calculated pursuant to Rule 457(o) under the Securities Act of 1933, as amended. We previously paid $9,270.00 of the total registration fee in connection with the previous filing of this registration statement.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated October 28, 2021

PROSPECTUS

10,000,000 Shares

Desert Peak Minerals Inc.

Class A Common Stock

This is the initial public offering of 10,000,000 shares of Class A common stock of Desert Peak Minerals Inc. We are offering 10,000,000 shares of Class A common stock.

We expect the public offering price to be between $20.00 and $23.00 per share. Prior to this offering, there has been no public market for our Class A common stock. We have been approved to list our Class A common stock on the New York Stock Exchange (“NYSE”) under the symbol “DPM.”

We are an “emerging growth company” as defined under the U.S. federal securities laws, and as such may elect to comply with reduced public company reporting requirements. See “Risk Factors” and “Summary—Emerging Growth Company Status.”

Investing in our Class A common stock involves risks that are described in the “Risk Factors” section beginning on page 29 of this prospectus.

Christopher L. Conoscenti, our Chief Executive Officer and Director Nominee, has indicated an interest in purchasing shares of our Class A common stock in this offering at the initial public offering price and, except as described below, on the same terms as the other purchasers in this offering. Because indications of interest are not binding agreements or commitments to purchase, Mr. Conoscenti may determine to purchase more, fewer or no shares in this offering. The underwriters will not receive any underwriting discounts or commissions on any shares purchased by Mr. Conoscenti and will allocate any such shares as directed by us as the issuer. Any shares of Class A common stock purchased by Mr. Conoscenti will be subject to the lock-up restrictions described in the section titled “Underwriting (Conflicts of Interest).”

	Price to Public	Underwriting Discounts and Commissions(1)	Proceeds to Issuer
Per Share	$	$	$
Total	$	$	$

(1) See “Underwriting (Conflicts of Interest)” for additional information regarding underwriting compensation.

We have granted the underwriters an option to purchase up to an additional 1,500,000 shares of Class A common stock from us at the public offering price, less underwriting discounts and commissions, for 30 days after the date of this prospectus.

At our request, the underwriters have reserved up to 5% of the Class A common stock for sale at the public offering price through a directed share program to certain individuals associated with us. See “Underwriting (Conflicts of Interest)—Directed Share Program.”

Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares of Class A common stock against payment on or about                     , 2021.

Barclays Credit Suisse UBS Investment Bank

Capital One Securities Citigroup Evercore ISI RBC Capital Markets

Maxim Group LLC Stephens Inc. Tudor, Pickering, Holt & Co. Tuohy Brothers

Prospectus dated                , 2021.

DPM Asset Summary Basin Delaware Midland Total NRAs (1/8ths)(1) ~83,000 ~21,000 ~104,000 Gross Normalized Developed Wells(2)(3) 3,656 2,947 6,602Net Normalized Developed Wells(2)(3) 42.5 9.5 52.0Avg. NRI on Developed Wells 1.16% 0.32% 0.79%

(1) As of September 30, 2021.

(2) Includes our wells and wells attributable to the Source Assets as of June 30, 2021.

(3) We ratably convert our horizontal well inventory for modeling purposes to 5,000-foot lateral length equivalents in order to estimate the amount of reservoir footage that is accessed by horizontal wells of varying lateral lengths drilled on our properties.

TABLE OF CONTENTS

SUMMARY	1
RISK FACTORS	29
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	65
USE OF PROCEEDS	67
DIVIDEND POLICY	68
CAPITALIZATION	70
DILUTION	72
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA	73
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	76
BUSINESS	104
MANAGEMENT	131
EXECUTIVE COMPENSATION	137
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	146

CORPORATE REORGANIZATION	148
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	152
DESCRIPTION OF CAPITAL STOCK	156
SHARES ELIGIBLE FOR FUTURE SALE	161
CERTAIN ERISA CONSIDERATIONS	163
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS	166
UNDERWRITING (CONFLICTS OF INTEREST)	170
LEGAL MATTERS	179
EXPERTS	179
CHANGE IN INDEPENDENT ACCOUNTANT	179
WHERE YOU CAN FIND ADDITIONAL INFORMATION	180
INDEX TO FINANCIAL STATEMENTS	F-1
ANNEX A—GLOSSARY OF OIL AND NATURAL GAS TERMS	A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or the information to which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of Class A common stock and seeking offers to buy shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Through and including                 , 2021 (25 days after the date of this prospectus), all dealers effecting transactions in our Class A common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. Some data are also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a

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variety of factors, including those described in the section titled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

This prospectus may contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, the right of the applicable licensor to these trademarks, service marks and trade names.

Basis of Presentation

Unless otherwise indicated, the historical financial and operating information presented in this prospectus is that of Kimmeridge Mineral Fund, LP, our predecessor for financial reporting purposes, and its consolidated subsidiaries (our “predecessor,” “KMF” or the “Partnership”). Unless otherwise indicated, historical information presented in this prospectus as of June 30, 2021 is that of KMF and includes the assets acquired in the Chambers Acquisition (as defined herein), the Rock Ridge Acquisition (as defined herein) and the Recent Acquisitions (as defined herein), each of which was completed on or prior to June 30, 2021.

Unless otherwise indicated, references in this prospectus to our financial information on a “pro forma basis” refer to the historical financial information of KMF, as adjusted to give pro forma effect to (i) the Chambers Acquisition, (ii) the Rock Ridge Acquisition, (iii) the Source Acquisition (as defined herein), (iv) the reorganization transactions described under “Corporate Reorganization,” including the contribution to us of substantially all of the assets of KMF, excluding certain surface rights, and (v) this offering and the application of the net proceeds therefrom, in each case as if the transaction occurred on January 1, 2020 (other than the Chambers Acquisition, for which pro forma effect is given as if it occurred on October 1, 2020, the date on which the Chambers ORRI (as defined herein) was created). Unless otherwise indicated, references in this prospectus to our operating information on a “pro forma basis” refer to the historical operating information of KMF, as adjusted to give pro forma effect to (i) the Chambers Acquisition, (ii) the Rock Ridge Acquisition, (iii) the Source Acquisition and (iv) the Recent Acquisitions, in each case as if such acquisitions occurred on January 1, 2020 (other than the Chambers Acquisition, for which pro forma effect is given as if it occurred on October 1, 2020, the date on which the Chambers ORRI was created). Prior to October 1, 2020, the Chambers ORRI did not exist as a standalone asset, and no financial information with respect to the Chambers ORRI is available for periods prior to October 1, 2020.

Unless otherwise indicated, none of the historical or pro forma information included in this prospectus gives effect to the July 2021 Acquisition (as defined herein). Unless otherwise indicated, all industry data relating to oil and gas wells presented in this prospectus is derived from IHS Markit.

Certain monetary amounts, percentages and other figures included in this prospectus have been subject to rounding adjustments. Percentage amounts included in this prospectus have not in all cases been calculated on the basis of such rounded figures but on the basis of such amounts prior to rounding. For this reason, percentage amounts in this prospectus may vary from those obtained by performing the same calculations using the figures in our consolidated financial statements. Certain other amounts that appear in this prospectus may not sum due to rounding.

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SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our Class A common stock. You should read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements, before investing in our Class A common stock. The information presented in this prospectus assumes an initial public offering price of $21.50 per share of Class A common stock (the midpoint of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters’ option to purchase additional shares of Class A common stock is not exercised. You should read “Risk Factors” for information about important risks that you should consider before buying our Class A common stock.

Except as otherwise indicated or required by the context, all references in this prospectus to the “Company,” “we,” “us,” “our” or similar terms, when referring to periods prior to our corporate reorganization described in this prospectus, refer to Kimmeridge Mineral Fund, LP, our predecessor for financial reporting purposes and the owner of certain assets that will be contributed to Desert Peak Minerals Inc. (“Desert Peak Minerals”) in connection with this offering, and its consolidated subsidiaries (our “predecessor” or “KMF”), and, following the corporate reorganization described in this prospectus, to Desert Peak Minerals and its consolidated subsidiaries.

This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus.

Estimates of our proved reserves as of December 31, 2020 and 2019 have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent reserve engineers. Summaries of CG&A’s reports are included as exhibits to the registration statement of which this prospectus forms a part.

Desert Peak Minerals Inc.

Overview

We acquire, own and manage mineral and royalty interests in the Permian Basin with the objective of generating cash flow from operations that can be distributed to shareholders as dividends and reinvested to expand our base of cash flow generating assets. Our assets are exclusively focused in the Permian Basin. We benefit from cash flow growth through continued development of our mineral and royalty interests, free of capital costs and lease operating expenses. As of June 30, 2021, we owned mineral and royalty interests representing 75,602 net royalty acres (“NRAs”) when adjusted to a 1/8th royalty. Subsequent to June 30, 2021, we completed additional acquisitions that brought our total amount of NRAs to over 104,000 as of September 30, 2021. For the six months ended June 30, 2021, on a pro forma basis the average net daily production associated with our mineral and royalty interests was 8,946 barrels of oil equivalent per day (“BOE/d”), consisting of 4,706 Bbls/d of oil, 16,173 Mcf/d of natural gas and 1,544 Bbls/d of natural gas liquids (“NGLs”). For the month of September 2021, the average net daily production associated with our mineral and royalty interests was 9,189 BOE/d, consisting of 4,685 Bbls/d of oil, 16,851 Mcf/d of natural gas and 1,695 Bbls/d of NGLs. September 2021 production reflects the actual production of our predecessor, which includes production attributable to the assets acquired in each of the Chambers Acquisition, the Rock Ridge Acquisition, the Source Acquisition, the Recent Acquisitions and the July 2021 Acquisition for the full month. Since our formation in November 2016, we have accumulated our acreage position by making 177 acquisitions. We expect to continue to grow our acreage position by making acquisitions that meet our investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

As of June 30, 2021, approximately 99% of our NRAs were located in West Texas where there are no federal lands, which means that operators on our acreage are not subject to leasing, permitting, or easement

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authority from the federal government. The remaining 1% of our NRAs are located in southeastern New Mexico. We believe the Permian Basin offers some of the most compelling rates of return for oil and gas exploration and production (“E&P”) companies and significant potential for mineral and royalty income growth. As a result of these compelling rates of return, development activity in the Permian Basin has outpaced all other onshore U.S. oil and gas basins since the end of 2016. This development activity has driven basin-level production to grow faster than production in the rest of the United States. The following tables show the average daily production according to Wood Mackenzie and total number of horizontal well spuds according to Enverus, respectively, in the Delaware Basin and the Midland Basin compared to the Eagle Ford, SCOOP / STACK, Bakken and DJ Basin during 2016 and 2020, respectively.

Our mineral and royalty interests entitle us to receive a fixed percentage of the revenue from crude oil, natural gas and NGLs produced from the acreage underlying our interests. Unlike owners of working interests in oil and gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production. As a mineral and royalty owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs. Accordingly, our business generates strong margins, requires very low overhead and is highly scalable. For the six months ended June 30, 2021, on a pro forma basis our production and ad valorem taxes were approximately $2.52 per barrel of oil equivalent (“BOE”), relative to an average realized price of $40.27 per BOE. As a result, our operating margin and cash flows are higher, as a percentage of revenue, than those of traditional E&P companies. On a pro forma basis, during the six months ended June 30, 2021, we generated net income of $18.2 million and Adjusted EBITDA of $56.9 million. We do not anticipate engaging in any activities, other than acquisitions, that will incur capital costs. We believe our cost structure and business model will allow us to return a significant amount of our cash flows to our stockholders.

We have built our acreage position through the consummation of 177 acquisitions since November 2016. In addition to completing numerous small transactions, we have completed a total of 14 transactions larger than 1,500 NRAs that account for approximately 85% of our NRAs, including the Chambers Acquisition of approximately 7,200 NRAs, the Rock Ridge Acquisition of approximately 18,500 NRAs and the Source Acquisition of approximately 24,500 NRAs. During the four years ended December 31, 2019, we evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 167 acquisitions from landowners and other mineral interest owners, representing 47,920 NRAs, to our asset base. During 2020, our acquisition activity saw a significant decline following the onset of the COVID-19 global pandemic. Following the associated decline in oil prices during the onset of the pandemic, we experienced a meaningful difference in sellers’ pricing expectations and the prices we were willing to offer for assets. We evaluated approximately 197,416 NRAs and submitted formal offers on 56,658 NRAs but did not consummate any acquisitions subsequent to the first quarter of 2020 through the end of the first quarter of 2021. However, we utilized our significant free cash flow during 2020 to reduce our indebtedness from $66 million as of March 31, 2020 to $25.0 million as of March 31, 2021. Beginning in the second quarter of 2021, we saw a meaningful increase in our acquisition activity as evidenced

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by the approximately 26,000 NRAs we acquired in the second quarter and the approximately 28,000 NRAs we acquired in the third quarter. The following table summarizes our completed acquisitions from November 2016 through September 30, 2021.

Year	Number of Acquisitions		Total NRAs Acquired
2016		2		4,060
2017		50		18,037
2018		48		14,778
2019		67		11,045
2020		4		1,614
2021 (through September 30)(1)		6		54,141
Total		177		103,675

(1) Includes approximately 24,500 NRAs attributable to the Source Acquisition that are still in the title due diligence period. Accordingly, these NRAs are subject to change.

We are led by a management team with extensive oil and gas engineering, geologic and land expertise, mergers and acquisitions and capital markets experience, long-standing industry relationships and a history of successfully acquiring and managing a portfolio of leasehold interests, producing crude oil, natural gas and NGL assets, and mineral and royalty interests. We intend to capitalize on our management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in the Permian Basin designed to increase our cash flows per share.

We were founded by Kimmeridge Energy Management Company, LLC (collectively with its affiliates, “Kimmeridge”). Kimmeridge is a private equity firm based in New York and Denver that is differentiated by its strategy of direct investment in unconventional oil and gas assets, leveraging its in-house expertise in geological evaluation, land acquisition and engineering. Kimmeridge and several members of our management team founded and managed two Delaware Basin-focused E&P companies, Arris Petroleum Corporation (“Arris Petroleum”) and 299 Resources LLC (“299 Resources”), and successfully monetized those companies in 2016 by selling Kimmeridge’s ownership interests in those companies to PDC Energy. Additionally, in October 2020, another private equity fund managed by Kimmeridge acquired a 2.0% (on an 8/8ths basis) overriding royalty interest in all of Callon Petroleum Company’s (“Callon”) operated assets in the Delaware, Midland and Eagle Ford Basins, proportionately reduced to Callon’s net revenue interest (the “Chambers ORRI”). Subsequent to the transaction, our management team managed the acquired overriding royalty interest. We have leveraged Kimmeridge’s extensive Permian Basin experience and relationships with mineral and royalty owners in the region as we have grown our acreage position, and we expect to continue to do so in the future. Furthermore, Kimmeridge has established itself as a thought leader in the oil and gas industry, particularly around environmental, social and governance (“ESG”) matters, and our philosophy is consistent with Kimmeridge’s views on, among other things, aligning management compensation with the interests of shareholders and maintaining strong governance practices. See “Summary—ESG Philosophy.”

Our Key Producing Region

As of June 30, 2021, all of our properties were located exclusively within the Permian Basin. As of June 30, 2021, the Permian Basin had the highest level of horizontal drilling activity in the United States, according to Baker Hughes. The Permian Basin includes three geologic provinces: the Delaware Basin to the west, the Midland Basin to the east and the Central Basin Platform in between. The Delaware Basin is identified by an abundant amount of oil-in-place, stacked pay potential across an approximately 3,900 foot hydrocarbon column, attractive well economics, favorable operating environment, well developed network of oilfield service providers and significant midstream infrastructure in place or actively under construction. The Midland Basin is also identified by an abundant amount of oil-in-place stacked pay potential across an approximately 3,500 foot hydrocarbon column, attractive well economics, favorable operating environment, well developed network of oilfield service providers and significant midstream infrastructure in place. There are no federal lands on the

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Texas side of the Delaware Basin, where approximately 99% of our NRAs were located as of June 30, 2021, and therefore the acreage underlying our Texas NRAs is not subject to federal government involvement in or regulation of leasing, permitting or easements. According to the United States Geological Survey (“USGS”), the Delaware Basin contains the largest recoverable reserves among all unconventional basins in the United States.

We believe the stacked-pay potential of the Delaware Basin combined with favorable drilling economics support continued production growth as E&P operators continue to develop their positions and improve well-spacing and completion techniques. Relative to other unconventional basins in the continental United States, we believe the Delaware Basin is in an earlier stage of horizontal well development and that per-well returns will improve as E&P operators continue to employ advanced horizontal drilling and completion technologies on multi-well pads in the region. We believe these factors will continue to support development activity in the region and in the areas where we hold mineral and royalty interests, leading to increasing cash flows free of lease operating expenses. The Delaware Basin has attracted an outsized portion of the capital deployed in unconventional basins, resulting in a larger proportional share of the total U.S. onshore horizontal rig count and oil and gas production. According to Enverus, 11,830 horizontal wells were spud in the Delaware Basin between November 2016 and June 2021, representing 20% of total horizontal onshore wells spud in the United States over that same time frame. This growth in drilling activity has resulted in substantial production growth in the Delaware Basin. Full year average total production in the Delaware Basin has grown at a compound annual growth rate (“CAGR”) of 32% from 2016 to 2020, outpacing the U.S. total production growth CAGR by approximately 4.8 times during the same period, according to Wood Mackenzie. Wood Mackenzie estimates that full year average Delaware Basin oil production is expected to increase to an average of approximately 3,110 MBbls/d during 2025, which represents a CAGR of 18% when compared to full year average oil production in 2016.

We believe the stacked-pay potential of the Midland Basin combined with low cost supply driven by enhancements in drilling efficiency supports continued production growth. The Midland Basin is in a more mature phase of horizontal well development relative to other unconventional basins in the United States. We believe these factors will continue to support development activity in the region and in the areas where we hold mineral and royalty interests, leading to increasing cash flows free of lease operating expenses. According to Enverus, 91 million lateral feet were drilled in the Midland Basin between November 2016 and May 2021, representing 21% of total horizontal onshore lateral feet drilled in the United States over that same period. Full year average lateral feet drilled per rig in the Midland Basin has grown at a CAGR of 11% from 2016 to 2020. Furthermore, in 2020, the total feet drilled per rig in the Midland Basin was approximately 9% greater than the total feet drilled per rig in the United States. We expect Midland Basin drilling efficiency to continue to improve as drilling days further compress and lateral lengths keep expanding.

According to Baker Hughes, the Permian Basin has steadily increased its market share of total active onshore horizontal drilling rigs in the United States, increasing from 40% as of November 30, 2016 to 53% as of June 30, 2021. The charts below summarize annual average oil equivalent horizontal production for the total onshore United States and Permian Basin from 2016 through 2020, according to Wood Mackenzie, and the corresponding CAGRs over that period.

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Our Mineral and Royalty Interests

Our interests consist of mineral and royalty interests. Mineral interests, which represent approximately 85% of our NRAs as of June 30, 2021, are real property interests that are typically perpetual and grant ownership of the crude oil and natural gas underlying a tract of land and the rights to explore for, drill for and produce crude oil and natural gas on that land or to lease those exploration and development rights to a third party. When we lease those rights, usually for a one- to three-year term, we typically receive an upfront cash payment, known as a lease bonus, and we retain a mineral royalty, which entitles us to a percentage (typically up to 25%) of production or revenue from production free of lease operating expenses. A lessee can extend the lease beyond the initial lease term with continuous drilling, production or other operating activities or through negotiated contractual lease extension options. When production and drilling cease, the lease terminates, allowing us to lease the exploration and development rights to another party and receive another lease bonus. As of June 30, 2021, other types of royalty interests, non-participating royalty interests (“NPRIs”) and overriding royalty interests (“ORRIs”), comprised approximately 2% and 13%, respectively, of our NRAs. As of June 30, 2021, approximately 94% of our ORRIs are currently leased or held by production, and we did not lose any ORRIs during the period of low activity and high shut ins during the year ended December 31, 2020. Also, as of June 30, 2021, approximately 82% of our NRAs were leased to E&P operators and other working interest owners. As of June 30, 2021, approximately 99% of our mineral and royalty interests are located in Texas and do not require federal approval to permit and drill oil and gas wells or to obtain easements or rights of way for operators to deliver their oil and gas to market. We refer to our mineral interests, NPRIs and ORRIs collectively as our “mineral and royalty interests.”

We generate a substantial majority of our revenues and cash flows from our mineral and royalty interests when crude oil, natural gas and NGLs are produced from our acreage and sold by the applicable E&P operators and other working interest owners. Our predecessor’s pro forma revenue generated from these mineral and royalty interests was approximately $77.4 million for the year ended December 31, 2020 and $65.2 million for the six months ended June 30, 2021. Approximately 91% of 2020 and 82% of first half 2021 revenue was derived from the sale of oil and NGLs on a pro forma basis.

Currently, our mineral and royalty interests reside entirely in the Permian Basin, which we believe is one of the premier unconventional crude oil, natural gas and NGL producing regions in the United States. As of June 30, 2021, our interests covered 41,298 net mineral acres, approximately 82% of which have been leased to E&P operators and other working interest owners with us retaining an average 19.4% royalty. Typically, within the mineral and royalty industry, owners standardize ownership of NRAs to a 12.5%, or a 1/8^th, royalty interest, representing the number of equivalent acres earning a 12.5% royalty, which is referred to as an NRA. When adjusted to a 1/8^th royalty, our mineral interests represent 64,040 NRAs, and our NPRIs and ORRIs represent an additional 11,563 NRAs, totaling 75,602 NRAs in the aggregate. Our drilling spacing units (“DSUs”), in the aggregate, consist of a total of 753,130 gross acres, which we refer to as our “gross DSU acreage.” We expect to have an ownership interest in all wells that will be drilled within our gross DSU acreage in the future. The following table summarizes our mineral and royalty interest position and the conversion of our interests from net mineral acres to NRAs and 100% royalty acres as of June 30, 2021.

Net Mineral         Acres	Average Royalty			NRAs (Mineral Interests)(1)		NRAs (NPRIs)		NRAs (ORRIs)		Total NRAs		100% NRAs(2)		Gross DSU Acres		Implied Average Net Revenue Interest per Well(3)
41,298		19.4	%		64,040		1,505		10,058		75,602		9,450		753,130		1.3	%

(1) Our mineral interests are based on our average royalty interests across our net mineral acreage position normalized to reflect a 1/8th royalty interest per net mineral acre (i.e., NRAs from mineral and royalty

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interests are calculated by multiplying 41,298 net mineral acres multiplied by an average royalty of 19.4% and then divided by 12.5%).

(2) Calculated as 75,602 NRAs multiplied by 12.5%.

(3) Calculated as 9,450 100% royalty acres divided by 753,130 gross DSU acres.

As of June 30, 2021, we have interests in 266 gross (2.822 net) horizontal wells on which drilling has commenced but are not yet producing in paying quantities, which we refer to as spud wells, and 233 gross (2.227 net) wells for which permits have been issued to the operators, but on which drilling has not yet commenced, which we refer to as permitted wells. For the three months ended June 30, 2021, our permitted wells converted into spud wells within an average of 4.5 months and our spud wells converted into producing wells within an average of 7.7 months. The total time from permit to first production on our producing wells was 10.5 months on average as compared to a total time of 13.9 months for the Delaware Basin on average.

Our Reserves and Production

As of December 31, 2020, the estimated proved crude oil, natural gas and NGLs reserves attributable to our interests in our underlying acreage were 11,800 MBOE (67% liquids, consisting of 43% crude oil and 24% NGLs), based on a reserve report prepared by CG&A. Of these reserves, 78% were classified as proved developed producing (“PDP”) reserves, 1% were classified as proved developed non-producing (“PDNP”) reserves and 21% were classified as proved undeveloped (“PUD”) reserves. As of June 30, 2021, the estimated proved crude oil, natural gas and NGLs reserves attributable to our interests in our underlying acreage were 13,875 MBOE (66% liquids, consisting of 45% crude oil and 22% NGLs), based on internal estimates of management. The estimated proved reserves as of June 30, 2021 have been prepared on the same basis as the estimated proved reserves as of December 31, 2020, but they have not been prepared or audited by an independent reserve engineer. Of these reserves, 80% were classified as PDP reserves and 20% were classified as PUD reserves. PUD reserves included in these estimates relate solely to wells that were spud but not yet producing in paying quantities as of December 31, 2020 and June 30, 2021, respectively.

We believe our production and discretionary cash flows will grow significantly as E&P operators drill the substantial undeveloped inventory of horizontal drilling locations located on our gross DSU acreage. As of June 30, 2021, we had production from 2,278 gross (27.9 net) horizontal wells, and we have identified 9,692 gross (118.0 net) undeveloped horizontal drilling locations based on our assessment of current geological, engineering and land data, which is equivalent to 12.4 gross undeveloped horizontal drilling locations per one mile-wide DSU, which is the area designated in a spacing order or unit designation as a “unit” and within which E&P operators and other working interest owners drill wells to develop our oil and gas rights. Furthermore, we believe there is potential for additional drilling activity through drilling efforts by our current E&P operators and through development of additional horizontal formations, including the Woodford/Barnett formations.

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The following table provides a summary of our inventory of gross and net developed and undeveloped wells by horizon and total gross wells per DSU on a one mile wide DSU basis as of June 30, 2021.

Productive Horizon	Gross Wells						Number of DSUs		Total Gross Wells/DSU (one mile wide DSU basis(1)		Net Wells
	Developed		Undeveloped		Total						Developed		Undeveloped		Total
Avalon/1st Bone Spring		38		396		434		103		5.80		0.20		1.82		2.02
2nd Bone Spring		47		702		749		204		4.60		0.75		5.59		6.34
3rd Bone Spring		236		1,691		1,927		716		3.59		2.54		15.38		17.91
Wolfcamp X/Y		282		753		1,035		348		4.06		2.60		9.76		12.37
Wolfcamp A		1,203		2,190		3,393		986		4.45		14.93		29.64		44.58
Wolfcamp B		316		2,279		2,595		919		3.61		4.64		29.35		33.99
Wolfcamp C		62		1,429		1,491		552		3.69		0.97		24.86		25.83
Wolfcamp D		21		252		273		107		3.69		0.64		1.60		2.24
Other Wells and Intervals		73		—		73		50		1.63		0.57		—		0.57
Total		2,278		9,692		11,970		1,058		15.3		27.85		118.00		145.85

(1) The number of DSUs in each horizon and locations per DSU in each horizon do not total due to differing prospectivity of each horizon across each DSU (i.e., not all horizons are booked in all DSUs). We assume an average of 15.3 drilling locations per DSU across horizons on a 5,000 foot wide basis. Though the average width of our DSUs is less than one mile wide, we standardize our gross wells per DSU to a one mile wide equivalent for comparison purposes.

Our horizontal well inventory contains a range of lateral lengths, the substantial majority of which are from 5,000 feet to 10,000 feet. We ratably convert our horizontal well inventory for modeling purposes to 5,000-foot lateral length equivalents in order to estimate the amount of reservoir footage that is accessed by horizontal wells of varying lateral lengths drilled on our properties. The table below reflects our gross and net developed and undeveloped wells on that basis as of June 30, 2021.

	Gross Wells (5,000 foot lateral length basis)						Net Developed Wells		Net Undeveloped Wells		Total Net Wells
Productive Horizon	Developed		Undeveloped		Total(1)
Avalon/1st Bone Spring		55		533		588		0.31		2.03		2.35
2nd Bone Spring		60		1,010		1,069		0.76		8.14		8.91
3rd Bone Spring		335		2,422		2,757		3.17		21.43		24.60
Wolfcamp X/Y		384		1,103		1,488		3.13		13.40		16.54
Wolfcamp A		1,931		3,028		4,959		23.01		36.84		59.85
Wolfcamp B		515		3,276		3,792		7.54		38.65		46.19
Wolfcamp C		98		2,117		2,215		1.69		33.31		35.00
Wolfcamp D		27		349		377		0.66		1.95		2.61
Other Wells and Intervals		124		—		124		0.88		—		0.88
Total		3,529		13,839		17,368		41.16		155.76		196.92

(1) The numbers may not compute exactly due to rounding.

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The following table provides a summary of our gross and net developed and undeveloped wells, along with the percentage of undeveloped wells that are currently either spud or permitted wells, as of June 30, 2021.

	Gross Wells		Net Wells
Developed		2,278		27.9
Undeveloped		9,692		118.0
Total		11,970		145.9
Undeveloped Spud and Permitted Wells		499		5.0
% Undeveloped Spud and Permitted Wells		5%		4%

Our mineral interest investment strategy anticipates E&P operators shifting drilling activity from a focus on drilling single wells to hold acreage towards more drilling in each DSU, particularly on multi-well pads. As of June 30, 2021, our position has an average of 2.91 gross producing horizontal wells per 5,000 foot wide DSU, compared to our spacing assumption of 15.3 gross wells per DSU. Furthermore, we expect to see increases in our production, revenue and discretionary cash flows from the development of 266 spud wells and 233 permitted wells across our interests as of June 30, 2021, compared to 171 gross wells completed on our acreage in the year ended December 31, 2020. If all of our spud wells were completed and all of our permitted wells were drilled and completed, we expect that our gross producing horizontal wells per 5,000 foot wide DSU would increase from 2.91 to 3.55. We believe our current interests provide the potential for significant long-term organic revenue growth as E&P operators develop our acreage and utilize advancements in drilling and completion techniques to increase crude oil, natural gas and NGL production.

Our E&P Operators

In addition to utilizing technical analysis to identify attractive mineral and royalty interests in the prolific Permian Basin, our management team strives to acquire mineral and royalty interests in properties with top-tier E&P operators. We seek E&P operators that are well-capitalized, have a strong operational track record, and that we believe will continue to increase production through the application of the latest drilling and completion techniques across our mineral and royalty interests. Approximately 50 horizontal E&P operators are currently producing oil and gas from our acreage. The chart below summarizes the E&P operators of our acreage based on the percentage of NRAs held by production in our portfolio as of June 30, 2021.

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Financial Philosophy

We aim to balance the return of capital to investors with the selective allocation of capital toward acquisitions that we believe will be accretive to shareholder value while preserving a strong balance sheet through varying commodity price environments. In order to effect this approach, we intend to return capital to our shareholders through quarterly dividends, after retaining cash for our working capital needs and acquisition activities. We initially intend to make dividends of a significant amount of our discretionary cash flow, which we define as our Adjusted EBITDA less interest expense and cash taxes. Specifically, following the completion of this offering, we expect that our board of directors will initially target distributing to holders of shares of Class A common stock and Opco Units approximately $65 million on an aggregate annualized basis (or $1.05 per share of Class A common stock and per Opco Unit assuming the underwriters’ option to purchase additional shares of Class A common stock is not exercised).

While we expect to pay quarterly dividends in accordance with this financial philosophy, we have not adopted a formal written dividend policy to pay a fixed amount of cash each quarter or to pay any particular quarterly amount based on the achievement of, or derivable from, any specific financial metrics, including discretionary cash flow. Specifically, while we initially expect to make distributions of our discretionary cash flow in the targeted amounts described above, the actual amount of any dividends we pay may fluctuate depending on our cash flow needs, which may be impacted by potential acquisition opportunities and the availability of financing alternatives, the need to service our indebtedness or other liquidity needs, and general industry and business conditions, including the impact of commodity prices and the pace of the development of our properties by exploration and production companies. Our payment of dividends will be at the sole discretion of our board of directors, which may change our dividend philosophy at any time. See “Dividend Policy.”

ESG Philosophy

Since our inception, Kimmeridge and we have been committed to all three elements of ESG and are in the process of developing appropriate ESG policies, including strong governance policies. Our fully staffed, experienced team will be dedicated solely to our business of pursuing and consummating acquisitions and returning significant capital to shareholders. We intend to implement an executive compensation program designed to align our management and the board of directors directly with absolute total stockholder returns. For example, management’s incentive compensation is expected to be 100% equity-based, with approximately 75% of total compensation dependent on absolute total stockholder return. Our management team’s initial equity awards will be at the same basis as investors in this offering, and there are no legacy stock compensation or incentive units crystallizing upon the consummation of this offering.

Furthermore, the majority of our board of directors will be independent immediately upon the closing of this offering. Our board of directors and employee base are reflective of a culture that values diversity, with approximately one-half of our employees being women or minorities.

We believe our shareholders’ interests are aligned with environmental interests as both constituencies are harmed by the economic waste and environmental harm of flaring and venting of methane. We target minerals under operators with strong environmental track records. We prioritize responsible environmental practices and we endeavor to prohibit flaring by the operator in each lease. As we continue to gain additional scale, we intend to further pressure operators to eliminate flaring and venting of methane.

Recent Developments

Chambers Acquisition

On June 7, 2021, we completed the acquisition of the Delaware Basin portion of the Chambers ORRI from Chambers Minerals, LLC, an affiliate of Kimmeridge (the “Chambers Acquisition”), which represents

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approximately 7,200 NRAs consisting of a 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to Callon’s net revenue interest, in substantially all Callon-operated oil and gas leasehold in the Delaware Basin.

Rock Ridge Acquisition

On June 30, 2021, we completed the acquisition of approximately 18,500 NRAs in the Delaware Basin from Rock Ridge Royalty Company, LLC (“Rock Ridge” and such acquisition, the “Rock Ridge Acquisition”), a limited liability company formed by investment funds affiliated with Blackstone Inc. (“Blackstone”). In connection with the closing, we granted Blackstone certain registration and director designation rights. Please see “Certain Relationships and Related Party Transactions—Director Designation Agreement.”

Source Acquisition

On August 31, 2021, we completed the acquisition of approximately 24,500 NRAs (the “Source Assets”) in the Midland and Delaware Basins from Source Energy Leasehold, LP and Permian Mineral Acquisitions, LP (together, “Source” and such acquisition, the “Source Acquisition”), limited partnerships backed by investment funds affiliated with Oaktree Capital Management, L.P. (“Oaktree”).

The Source Assets consist of approximately 21,000 NRAs located in the Midland Basin and 3,500 NRAs located in the Delaware Basin. For the six months ended June 30, 2021, production associated with the Source Assets was 1,612 BOE/d. As of June 30, 2021, in the Midland Basin, there were 1,490 gross (4.71 net) developed wells, 296 gross (0.93 net) spud wells, 132 gross (0.29 net) permitted wells and 3,492 gross (16.55 net) undeveloped wells associated with the Source Assets. Also as of June 30, 2021, in the Delaware Basin, there were 212 gross (0.88 net) developed wells, 18 gross (0.04 net) spud wells, 10 gross (0.10 net) permitted wells and 839 gross (3.90) undeveloped wells associated with the Source Assets.

In connection with the closing of the Source Acquisition, we granted Source certain registration and director designation rights. Please see “Certain Relationships and Related Party Transactions.”

Other Acquisitions

Subsequent to December 31, 2020, in addition to the Chambers Acquisition, the Rock Ridge Acquisition and the Source Acquisition, we have (i) completed multiple acquisitions totaling approximately 146 NRAs in the Delaware Basin from private, unrelated sellers, each of which closed prior to June 30, 2021 (together, the “Recent Acquisitions”), and (ii) on July 26, 2021, acquired approximately 3,500 additional NRAs from a private third-party seller unaffiliated with us (the “July 2021 Acquisition”). The information in this prospectus does not give effect to any NRAs, production, well counts or locations related to the Recent Acquisitions or the July 2021 Acquisition unless indicated otherwise.

Business Strategies

Our primary business objective is to provide an attractive return to stockholders by acquiring mineral and royalty interests in the Permian Basin with the most significant potential rates of return for upstream E&P operators to maximize the likelihood that drilling and production will occur and distributing a meaningful portion of our cash flow to stockholders as dividends. We intend to accomplish this objective by executing the following strategies:

• Provide sustained return of capital to stockholders through strong discretionary cash flow generation and cash dividends. Our board of directors will prioritize returning capital to our stockholders through

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dividends while also opportunistically pursuing acquisitions. While we do not expect to adopt a formal dividend policy and the amount of dividends that we pay will be at the sole discretion of our board of directors, we expect initially to pay dividends of a significant amount of our discretionary cash flows and any additional cash flows not returned to stockholders will be used for additional acquisitions that meet our investment criteria outlined below, to reduce indebtedness, to pay special dividends or to buy back our stock. As mineral and royalty interest owners, we benefit from the continued organic development of our acreage in the Permian Basin and are able to convert a high percentage of our revenue to discretionary cash flow, which we define as our Adjusted EBITDA less interest expense and cash taxes. We do not incur operating costs for the production of crude oil and natural gas or capital costs for the drilling and completion of wells on our acreage. Our only cash operating costs related to our mineral and royalty business consist of certain taxes, gathering, processing and transportation costs, and general and administrative expenses. For the six months ended June 30, 2021, on a pro forma basis our production and ad valorem taxes were approximately $2.52 per BOE, relative to an average realized price of $40.27 per BOE. We believe that our royalty interests are positioned for discretionary cash flow growth as E&P operator focus continues to shift to the Permian Basin, as evidenced by the increase in the percentage of total U.S. onshore rigs located in the Permian Basin over the last three years.

• Focus primarily on the Permian Basin. All of our mineral and royalty interests are currently located in the Permian Basin, one of the most prolific oil and gas basins in the United States. We believe the Permian Basin provides an attractive combination of highly-economic and oil-weighted geologic and reservoir properties, opportunities for development with significant inventory of drilling locations and zones to be delineated and top-tier, well-funded E&P operators. According to Baker Hughes, the Permian Basin, where all of our assets are currently located, has witnessed a significant growth in the market share of active onshore horizontal drilling rigs in the United States, increasing from 40% of active onshore horizontal drilling rigs as of our formation in November 2016 to 53% of active onshore horizontal drilling rigs as of June 30, 2021.

• Leverage expertise and relationships to continue acquiring Permian Basin mineral and royalty interests associated with top-tier E&P operators. We have a history of evaluating, pursuing and consummating acquisitions of crude oil and natural gas mineral and royalty interests in the Permian Basin. Since November 2016, we have completed 177 acquisitions, demonstrating our ability to add scale quickly and effectively. Our management team intends to continue to apply this experience in a disciplined manner when identifying and acquiring mineral and royalty interests. We believe that the current market environment is favorable for the consolidation of mineral and royalty interests, as the disaggregated nature of asset packages from numerous sellers presents attractive opportunities for assets that meet our target investment criteria. With sellers seeking to monetize their investments but lacking the scale to do so in the public markets, we intend to continue to acquire mineral and royalty interests that have substantial resource potential in the Permian Basin, an area that we expect to continue to experience a relatively high rate of development, with E&P operators incentivized to economically deploy capital to delineate and develop their positions over the underlying mineral interests. This E&P operator activity creates an opportunity for organic growth free of lease operating and capital expenses. We expect to focus on acquisitions that complement our current footprint in the Permian Basin while targeting mineral and royalty interests underlying the acreage of well-capitalized E&P operators that have a history of high conversion rates of permits issued to wells completed on large contiguous acreage positions. Furthermore, we seek to maximize our return on capital by targeting acquisitions that meet the following criteria:

• sufficient visibility to production growth;

• attractive economics;

• de-risked geology supported by offsetting production;

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• top-tier E&P operators; and

• a geographic footprint that we believe is complementary to our diverse portfolio of Permian Basin assets and maximizes our potential for upside reserve and production growth.

• Maintain conservative and flexible capital structure to support our business and facilitate long-term operations. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. Upon completion of this offering, we will have no outstanding funded indebtedness. We believe that proceeds from this offering, internally generated cash flows from operations, available borrowing capacity under our revolving credit facility, and access to capital markets will provide us with sufficient liquidity and financial flexibility to continue to acquire attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. We intend to maintain a conservative leverage profile and utilize a mix of cash flows from operations and issuance of debt and equity securities to finance future acquisitions.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

• Differentiated energy investment opportunity. As opposed to traditional E&P operators who require significant capital, our business requires no drilling and completion capital, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life and accordingly represents a differentiated energy investment opportunity. In addition, we are not responsible for environmental or other operational liabilities in connection with oil and gas production associated with our interests, and our only operating cash costs related to our mineral and royalty business consist of certain production taxes, gathering, processing and transportation costs and general and administrative expenses. For example, for the six months ended June 30, 2021, on a pro forma basis our production and ad valorem taxes were approximately $2.52 per BOE, relative to an average realized price of $40.27 per BOE. Furthermore, we have significantly reduced our indebtedness during the COVID-19 pandemic, while many other energy companies struggled with indebtedness and leverage issues during 2020. We believe our low capital requirements and financial discipline will result in an ability to distribute a meaningful amount of cash flow to stockholders.

• Permian Basin focused public minerals company positioned as a preferred buyer in the basin. We believe that our status as a public company focused exclusively on the Permian Basin will position us as a preferred buyer of Permian Basin mineral and royalty interests, as we will be able to offer sellers an opportunity to own an equity interest in a company that is solely focused on the Permian Basin. Currently, all of the acreage underlying our mineral interests is located in the Permian Basin, one of the most prolific oil plays in the United States, and the majority of our current properties are well positioned in areas with proven results from multiple stacked productive zones. Our properties in the Permian Basin are high-quality, high-margin, and oil- and liquids-weighted, and we believe they will be viewed favorably by sellers interested in receiving equity consideration in exchange for their assets as compared to equity consideration diluted by lower quality assets located in less prolific basins.

• Favorable and stable operating environment in the Permian Basin. With over 400,000 wells drilled in the Permian Basin since 1900, the region features a reliable and predictable geological and regulatory environment, according to Enverus. We believe that the impact of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities as compared to other, emerging hydrocarbon basins. As of June 30, 2021, approximately 99% of our acreage was located in Texas, and does not require federal

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approval to permit and drill oil and gas wells or to grant easements to allow E&P operators to deliver their production to market.

• Experienced management team with an extensive track record of minerals acquisitions. The members of our management team have grown our acreage position through the consummation of over 177 acquisitions since November 2016 ranging in size from small transactions of less than 25 NRAs to large transactions in excess of 1,500 NRAs, including the Chambers Acquisition of approximately 7,200 NRAs, the Rock Ridge Acquisition of approximately 18,500 NRAs and the Source Acquisition of approximately 24,500 NRAs. Notably, we have acquired nearly 85% of our NRAs through 14 large acquisitions, using both cash and equity consideration to suit the needs of sellers. Our management team has deep industry experience focused on resource play development in the Permian Basin and has a track record of identifying mineral and royalty acquisition targets, negotiating agreements, and successfully consummating acquisitions. We plan to continue to evaluate and pursue acquisitions of all sizes. We expect to benefit from the industry relationships fostered by our management team’s decades of experience in the oil and natural gas industry with a focus on the Permian Basin, in addition to leveraging our relationship with Kimmeridge.

• Board structure and compensation model aligned with stockholder interests. We intend to implement industry-leading governance practices for board structure and director and officer compensation. For example, at the closing of this offering, all of our directors will be elected annually and there will be no special voting classes of stock. In addition, our directors will receive a significant portion of their compensation in deferred equity awards and a significant portion of our management team’s compensation will depend on absolute total stockholder return metrics instead of operational metrics (e.g., production) that may not necessarily be aligned with the interests of our stockholders.

• Development potential of the properties underlying our Permian Basin mineral and royalty interests. Our assets consist of mineral and royalty interests located in the Permian Basin, and we expect production from our mineral and royalty interests to increase as E&P operators continue to actively drill and develop our acreage. Relative to other unconventional basins in the continental United States, we believe the Permian Basin is in an earlier stage of development and that the average number of producing wells per section in the Permian Basin will increase as E&P operators continue to optimize drilling locations and delineate additional zones, which would allow us to achieve higher realized cash flows per net mineral acre. Additionally, according to Baker Hughes, the Permian Basin has steadily increased its market share of total active onshore horizontal drilling rigs in the United States, increasing from 40% as of November 30, 2016 to 53% as of June 30, 2021. We expect to benefit from this focus of development activity in the Permian Basin and believe any resulting increase in our revenues will enable us to return capital to our stockholders.

We target acquisitions of properties that are relatively undeveloped in the core of the Delaware Basin, and we believe the organic development of our acreage will result in substantial production growth regardless of acquisition activity. From January 1, 2016 to December 31, 2020, production attributable to our properties increased at a CAGR of 51% assuming our NRAs as of December 31, 2020 were owned on January 1, 2016, as compared to a CAGR of 33% for Delaware Basin production growth generally and a CAGR of 7% for total U.S. onshore production growth for the same period.

• Diverse group of blue-chip E&P operators on our mineral and royalty interests driving production growth. Our mineral and royalty interests consist of properties operated by established E&P companies, such as Occidental Petroleum Corporation, BP plc, Cimarex Energy Co., Conoco Phillips and Chevron Corporation. Our blue-chip E&P operators provide a diversified source of revenues, as no single E&P operator provided greater than 15% of our total revenues for the six months ended June 30, 2021.

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Corporate Reorganization

Desert Peak Minerals was incorporated as a Delaware corporation in April 2019 by KMF. Following this offering and the reorganization transactions described below (our “corporate reorganization”), we will be a holding company whose sole material asset will consist of a 16% interest in Desert Peak LLC (“Opco”). Opco will continue to wholly own all of our operating assets. After the consummation of the transactions contemplated by this prospectus, we will be the sole managing member of Opco and will be responsible for all operational, management and administrative decisions relating to Opco’s business.

In connection with this offering:

• on October 8, 2021, we amended and restated our revolving credit facility to, among other things, provide for the transactions contemplated by our corporate reorganization and this offering as well as to provide for an increased borrowing base;

• on October 27, 2021, we made a distribution of approximately $128 million to the Existing Owners using borrowings under the revolving credit facility and cash on hand;

• Opco and the indirect owners of our initial assets (our “Existing Owners”) will enter into a merger agreement pursuant to which Opco will acquire our initial assets (which will not include our predecessor’s water business) and the Existing Owners will acquire 52,000,000 common units in Opco (the “Opco Units”) in the aggregate and will be admitted as members of Opco;

• we will issue 10,000,000 shares of our Class A common stock to purchasers in this offering in exchange for the proceeds of this offering;

• we will contribute all of the net proceeds of this offering and shares of our Class B common stock to Opco in exchange for a number of Opco Units equal to the number of shares of our Class A common stock outstanding following this offering, and Opco will then distribute a number of shares of our Class B common stock to our Existing Owners equal to the number of Opco Units held by them; and

• Opco will use the net proceeds from this offering to (i) repay all of the outstanding borrowings under our revolving credit facility and (ii) fund future acquisitions of mineral and royalty interests.

To the extent the underwriters’ option to purchase additional shares is exercised in full or in part, we will contribute the net proceeds therefrom to Opco in exchange for an additional number of Opco Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Opco will use any such net proceeds to fund future acquisitions of mineral and royalty interests.

Following this offering, our Existing Owners may distribute all or a portion of their respective Opco Units and a corresponding number of shares of Class B common stock to their partners or members, as applicable (the “Existing Owner Distribution”), subject to customary lock-up restrictions. Unless otherwise indicated, the information set forth in this prospectus does not give effect to the Existing Owner Distribution.

After giving effect to these transactions and this offering, without giving effect to the Existing Owner Distribution and assuming the underwriters’ option to purchase additional shares is not exercised:

• our Existing Owners will own, in the aggregate, 100% of our Class B common stock, representing 84% of our capital stock;

• investors in this offering will own, in the aggregate, 10,000,000 shares, or 100%, of our Class A common stock, representing 16% of our capital stock;

• we will own an approximate 16% interest in Opco; and

• our Existing Owners will own, in the aggregate, an approximate 84% interest in Opco.

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If the underwriters’ option to purchase additional shares is exercised in full, without giving effect to the Existing Owner Distribution:

• our Existing Owners will own, in the aggregate, 100% of our Class B common stock, representing 82% of our capital stock;

• investors in this offering will own, in the aggregate, 11,500,000 shares, or 100%, of our Class A common stock, representing 18% of our capital stock;

• we will own an approximate 18% interest in Opco; and

• our Existing Owners will own, in the aggregate, an approximate 82% interest in Opco.

Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list our Class B common stock on any exchange.

Following this offering, under the amended and restated limited liability company agreement of Opco (the “Opco LLC Agreement”), each holder of Opco Units (an “Opco Unit Holder”) will, subject to certain limitations, have the right (the “Redemption Right”) to cause Opco to acquire all or a portion of its Opco Units (together with a corresponding number of shares of Class B common stock) for, at Opco’s election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Opco Unit (and corresponding share of Class B common stock) redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions, or (ii) an equivalent amount of cash. We will determine whether to issue shares of Class A common stock or cash based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A common stock (including trading prices for the Class A common stock at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of preferred stock) to acquire the Opco Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, Desert Peak Minerals (instead of Opco) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered Opco Unit (and corresponding share of Class B common stock) directly from the redeeming Opco Unit Holder for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash. In connection with any redemption or acquisition of Opco Units together with a corresponding number of shares of Class B common stock pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. See “Certain Relationships and Related Party Transactions—Opco LLC Agreement.” Kimmeridge, Blackstone, Source and certain of their permitted transferees will have the right, under certain circumstances, to cause us to register the offer and resale of their shares of Class A common stock issuable upon redemption of Opco Units together with a corresponding number of shares of Class B common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

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The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised and without giving effect to the Existing Owner Distribution):

(1) Our Existing Owners will own, in the aggregate, 100% of our Class B common stock and approximately 84% of the Opco Units.

(2) Includes any shares of our Class A common stock that may be purchased by Christopher L. Conoscenti, our Chief Executive Officer and Director Nominee, in this offering.

We have granted the underwriters a 30-day option to purchase up to an aggregate of 1,500,000 additional shares of Class A common stock. Any net proceeds received from the exercise of this option will be contributed to Opco in exchange for an additional number of Opco Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Opco will use any such net proceeds to redeem from the Existing Owners on a pro rata basis a number of Opco Units (together with an equivalent number of shares of our Class B common stock) equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option to purchase additional shares.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (“JOBS Act”). For as long as we are an emerging growth company, we may take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise generally applicable to other public companies. These exemptions include:

• an exemption from providing an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

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• an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board (“PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

• an exemption from compliance with any other new auditing standards adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise; and

• reduced disclosure of executive compensation.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

We will cease to be an “emerging growth company” upon the earliest of (i) when we have $1.07 billion or more in annual revenues; (ii) when we issue more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) when we have qualified as a “large accelerated filer,” which refers to when we (1) have an aggregate worldwide market value of voting and non-voting shares of common equity securities held by our non-affiliates of $700 million or more, as of the last business day of our most recently completed second fiscal quarter, (2) have been subject to the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for a period of at least 12 calendar months, (3) have filed at least one annual report pursuant to Section 13(a) or 15(d) of the Exchange Act, and (4) are no longer eligible to use the requirements for “smaller reporting companies,” as defined in the Exchange Act, for our annual and quarterly reports.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1144 15^th Street, Suite 2650, Denver, Colorado 80202, and our telephone number at that address is (720) 640-7620.

Our website address is www.desertpeak.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

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Risk Factors

An investment in our Class A common stock involves risks. You should carefully consider the following considerations, the risks described in “Risk Factors” and the other information in this prospectus, before decidingwhether to invest in our Class A common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our Class A common stock and a loss of all or part of your investment.

Risks Related to Our Business

• Our producing properties are located in the Permian Basin, making us vulnerable to risks associated with operating in a single geographic area.

• We depend on various unaffiliated E&P operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these E&P operators. A reduction in the expected number of wells to be drilled on our acreage by these E&P operators or the failure of our E&P operators to adequately and efficiently develop and operate the wells on our acreage could have an adverse effect on our results of operations and cash flows.

• Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could materially and adversely affect our growth, results of operations and cash flows.

• We may acquire properties that do not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.

• Our E&P operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

• Acquisitions and our E&P operators’ development of our leases will require substantial capital, and we and our E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

• The development of our PUDs may take longer and may require higher levels of capital expenditures from the E&P operators of our properties than we or they currently anticipate.

• The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

• Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

• Estimates of proved reserves that have not been prepared or audited by an independent reserve engineering firm may not be as reliable or accurate as estimates of proved reserves that have been prepared or audited by an independent reserve engineering firm.

Risks Related to our Industry

• A substantial majority of our revenues from the crude oil and gas producing activities of our E&P operators are derived from royalty payments that are based on the price at which crude oil, natural gas and NGLs produced from the acreage underlying our interests are sold. Prices of crude oil, natural gas and NGLs are volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect our business, financial condition, results of operations and cash flows.

• If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.

• The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for E&P operators related to developing and operating our properties.

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• The marketability of crude oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our E&P operators control. Any limitation in the availability of those facilities could interfere with our or our E&P operators’ ability to market our or our E&P operators’ production and could harm our business.

• Drilling for and producing crude oil, natural gas and NGLs are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash flows.

• Conservation measures, technological advances and increasing attention to ESG matters could materially reduce demand for crude oil, natural gas and NGLs, availability of capital and adversely affect our results of operations and the trading market for shares of our Class A common stock.

Risks Related to Environmental and Regulatory Matters

• Crude oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our E&P operators, and failure to comply could result in our E&P operators incurring significant liabilities, either of which may impact our E&P operators’ willingness to develop our interests.

• Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause our E&P operators to incur increased costs, additional operating restrictions or delays and fewer potential drilling locations.

• Our operations, and those of our E&P operators, are subject to a series of risks arising from climate change. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other “greenhouse gases.” There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors.

Risks Related to Our Financial and Debt Arrangements

• Restrictions in our current and future debt agreements and credit facilities could limit our growth and our ability to engage in certain activities.

• Any significant contraction in the reserve-based lending syndication market may negatively impact our ability to obtain increased borrowing base capacity under our credit facility and may negatively impact our ability to fund our operations.

Risks Related to this Offering and Our Class A Common Stock

• We are a holding company. Our sole material asset after completion of this offering will be our equity interest in Opco and we are accordingly dependent upon distributions from Opco to pay taxes, cover our corporate and other overhead expenses and pay any dividends on our Class A common stock.

• If we fail to develop or maintain an effective system of internal controls over financial reporting, we may not be able to report our financial results accurately and timely or prevent fraud, which may result in material misstatements in our financial statements or failure to meet our periodic reporting obligations. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

• Our Existing Owners will initially have the ability to direct the voting of a majority of the voting power of our common stock, and their interests may conflict with those of our other stockholders.

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THE OFFERING

Issuer Desert Peak Minerals Inc.

Class A common stock offered by us 10,000,000 shares (or 11,500,000 shares, if the underwriters exercise in full their option to purchase additional shares).

Option to purchase additional shares We have granted the underwriters a 30-day option to purchase up to an aggregate of 1,500,000 additional shares of our Class A common stock to the extent the underwriters sell more than 10,000,000 shares of Class A common stock in this offering.

Class A common stock outstanding immediately after this offering 10,000,000 shares (or 11,500,000 shares, if the underwriters exercise in full their option to purchase additional shares).

Class B common stock outstanding immediately after this offering 52,000,000 shares, or one share for each Opco Unit held by the Opco Unit Holders immediately following this offering. Shares of Class B common stock are non-economic and are not entitled to receive dividends. In connection with any redemption of Opco Units pursuant to the Redemption Right or acquisition pursuant to our Call Right, the corresponding number of shares of Class B common stock will be cancelled.

Voting power of Class A common stock after giving effect to this offering 16% (or 100% if all outstanding Opco Units held by the Opco Unit Holders were redeemed (along with a corresponding number of shares of our Class B common stock) for newly issued shares of Class A common stock on a one-for-one basis).

Voting power of Class B common stock after giving effect to this offering 84% (or 0% if all outstanding Opco Units held by the Opco Unit Holders were redeemed (along with a corresponding number of shares of our Class B common stock) for newly issued shares of Class A common stock on a one-for-one basis). Upon completion of this offering and without giving effect to the Existing Owner Distribution, our Existing Owners, as the sole Opco Unit Holders other than us, will initially own, in the aggregate, 52,000,000 shares of Class B common stock, representing approximately 84% of the voting power of the Company.

Voting rights Each share of our Class A common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. Each share of our Class B common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our

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amended and restated certificate of incorporation. See “Description of Capital Stock.”

Use of proceeds We expect to receive approximately $199 million of net proceeds, based upon the assumed initial public offering price of $21.50 per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $9.5 million.

We intend to contribute all of the net proceeds from this offering to Opco in exchange for Opco Units. Opco will use the net proceeds from this offering to (i) repay all $135 million of outstanding borrowings under our revolving credit facility, and (ii) fund future acquisitions of mineral and royalty interests. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds of this offering. Please read “Use of Proceeds.”

If the underwriters exercise their option to purchase additional shares of Class A common stock in full, the additional net proceeds to us would be approximately $30.5 million (based on an assumed initial offering price of $21.50 per share, the midpoint of the price range set forth on the cover page of this prospectus), after deducting the underwriting discounts and estimated offering expenses payable by us. We intend to contribute all of the net proceeds therefrom to Opco in exchange for an additional number of Opco Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option to purchase additional shares. Opco will use any such proceeds to fund future acquisitions of mineral and royalty interests.

Conflicts of Interest Because affiliates of Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Capital One Securities Inc. and RBC Capital Markets LLC are lenders under our revolving credit facility and each will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings thereunder, each of them is deemed to have a conflict of interest within the meaning of Rule 5121 of the Financial Industry Regulatory Authority, Inc. (“FINRA”). Accordingly, this offering is being conducted in accordance with Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. UBS Securities LLC has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, including specifically those inherent in Section 11 thereof. UBS Securities LLC will not receive any additional fees for serving as a qualified independent underwriter in connection with this

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offering. We have agreed to indemnify UBS Securities LLC against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. See “Underwriting (Conflicts of Interest)—Conflicts of Interest.”

Dividend policy We expect initially to pay dividends of a significant portion of our discretionary cash flow on our Class A common stock, after assessing on a quarterly basis the amount of cash necessary for our working capital needs and potential acquisitions. While we expect to pay quarterly dividends in accordance with this financial philosophy, we have not adopted a formal written dividend policy to pay a fixed amount of cash each quarter or to pay any particular quarterly amount based on the achievement of, or derivable from, any specific financial metrics, including discretionary cash flow. Specifically, while we initially expect to make distributions of our discretionary cash flow in the targeted amounts outlined in the section “Dividend Policy,” the actual amount of any dividends we pay may fluctuate depending on our cash flow needs, which may be impacted by potential acquisition opportunities and the availability of financing alternatives, the need to service our indebtedness or other liquidity needs, and general industry and business conditions, including the impact of commodity prices and the pace of the development of our properties by exploration and production companies. The declaration and payment of any dividends will be at the sole discretion of our board of directors, which may change our dividend philosophy at any time. Future dividend levels will depend on the earnings of our subsidiaries, including Opco, their financial condition, cash requirements, regulatory restrictions, any restrictions in financing agreements (including our revolving credit facility) and other factors deemed relevant by the board. Please read “Dividend Policy.”

Redemption Rights of Opco Unit Holders Under the Opco LLC Agreement, each Opco Unit Holder will, subject to certain limitations, have the right, pursuant to the Redemption Right, to cause Opco to acquire all or a portion of its Opco Units (together with a corresponding number of shares of our Class B common stock) for, at Opco’s election (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Opco Unit (and corresponding share of Class B common stock) redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, we (instead of Opco) will have the right, pursuant to the Call Right, to acquire each tendered Opco Unit directly from the redeeming Opco Unit Holder for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash. In connection with any redemption of Opco Units pursuant to the Redemption Right or acquisition pursuant our Call Right, the corresponding number of shares of Class B common stock will be cancelled. See “Certain Relationships and Related Party Transactions—Opco LLC Agreement.”

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Directed share program At our request, the underwriters have reserved up to 5% of the Class A common stock being offered by this prospectus for sale at the initial public offering price to our directors, officers, employees and other individuals associated with us and members of their families. The sales will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, an underwriter of this offering, through a directed share program. See “Underwriting (Conflicts of Interest).” We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares of Class A common stock.

Insider Participation in the Offering Christopher L. Conoscenti, our Chief Executive Officer and Director Nominee, has indicated an interest in purchasing shares of our Class A common stock in this offering at the initial public offering price and, except as described below, on the same terms as the other purchasers in this offering. Because indications of interest are not binding agreements or commitments to purchase, Mr. Conoscenti may determine to purchase more, fewer or no shares in this offering. The underwriters will not receive any underwriting discounts or commissions on any shares purchased by Mr. Conoscenti and will allocate any such shares as directed by us as the issuer. Any shares of Class A common stock purchased by Mr. Conoscenti will be subject to the lock-up restrictions described in the section titled “Underwriting (Conflicts of Interest).”

Listing and trading symbol We have been approved to list our Class A common stock on the NYSE under the symbol “DPM.”

Risk factors You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A common stock.

The information above excludes 6,350,000 shares of Class A common stock reserved for issuance under our equity incentive plan.

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Summary Historical and Pro Forma Financial Data

Desert Peak Minerals was formed in April 2019 and has limited historical financial and operating results. The following table presents summary historical consolidated financial data of our predecessor and summary pro forma financial data of Desert Peak Minerals for the periods and as of the dates indicated. The summary historical consolidated financial data of our predecessor as of and for the years ended December 31, 2020 and 2019 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary historical unaudited condensed consolidated financial information as of June 30, 2021, and for the six months ended June 30, 2021 and 2020, was derived from the historical unaudited condensed consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary pro forma financial data of Desert Peak Minerals were derived from the unaudited pro forma financial statements included elsewhere in this prospectus.

The summary unaudited pro forma statement of operations for the year ended December 31, 2020 and the six months ended June 30, 2021 has been prepared to give pro forma effect to (i) the Chambers Acquisition, (ii) the Rock Ridge Acquisition, (iii) the Source Acquisition, (iv) the reorganization transactions described under “Corporate Reorganization” and (v) this offering and the application of the net proceeds therefrom, as if each had been completed on January 1, 2020 (other than the Chambers Acquisition, for which pro forma effect is given as if it occurred on October 1, 2020, the date on which the Chambers ORRI was created). The summary unaudited pro forma balance sheet data as of June 30, 2021 has been prepared to give pro forma effect to (i) the Source Acquisition, (ii) the reorganization transactions described under “Corporate Reorganization” and (iii) this offering and the application of the net proceeds therefrom, as if each had been completed on June 30, 2021. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial data is presented for informational purposes only, should not be considered indicative of actual results of operations that would have been achieved had such transactions been consummated on the dates indicated and does not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and “Corporate Reorganization” and the historical financial statements of our predecessor and the pro forma financial statements of Desert Peak Minerals included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

	Desert Peak Minerals Predecessor Historical												Desert Peak Minerals Pro  Forma
	Six Month Ended June 30,						Year Ended December  31,						Six Month Ended June 30, 2021			Year Ended December 31, 2020
	2021			2020			2020			2019
							(in thousands)
Statement of Operations Data:
Revenue:
Total Revenue	$	36,719		$	19,711		$	43,126		$	59,680		$	66,651		$	76,534
Operating Expenses:
Management fees to affiliates		3,740			3,740			7,480			7,480			3,740			7,480
Depreciation, depletion and amortization		15,801			15,695			32,049			26,201			29,633			57,163
General and administrative		1,278			5,241			4,981			2,349			2,467			7,629
General and administrative—affiliates		3,217			540			4,407			8,167			3,217			4,407
Production costs, ad valorem taxes and operating expense		2,557			2,007			3,151			5,249			4,076			4,508
Deferred offering costs write off		—			2,742			2,747			—			—			2,747
Impairment of oil and natural gas properties		—			812			812			—			—			64,340
Gain on sale of other property		—			(41	)		(42	)		—			—			—
Bad debt expense (recovered)		—			(181	)		(251	)		405			—			—
Total operating expenses		26,593			30,555			55,334			49,851			43,133			148,274
Net income (loss) from operations		10,126			(10,844	)		(12,208	)		9,829			23,518			(71,740	)
Other income (expense):
Other income		—			—			—			—			—			156
Interest expense (net)(1)		(524	)		(1,185	)		(1,968	)		(868	)		(308	)		(586	)
Net income (loss) before income tax expense		9,602			(12,029	)		(14,176	)		8,961			23,210			(72,170	)
Income tax (expense) benefit		(107	)		(124	)		(38	)		(171	)		(5,041	)		15,675
Net income (loss) including noncontrolling interests		9,495			(12,153	)		(14,214	)		8,790			18,169			(56,495	)
Net income attributable to noncontrolling interests		28			—			—			—			—			—
Net income (loss)	$	9,467			(12,153	)	$	(14,214	)	$	8,790		$	18,169		$	(56,495	)
Less: Net income (loss) attributable to temporary equity														15,239			(47,383	)
Net income (loss) attributable to Desert Peak Minerals Inc.														2,930		$	(9,112	)
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	23,662		$	16,026		$	26,016		$	34,791
Investing activities	$	(4,306	)	$	(20,359	)	$	(21,557	)	$	(248,627	)
Financing activities	$	(20,699	)	$	(2,022	)	$	(15,061	)	$	221,954
Other Financial Data:
Adjusted EBITDA(2)	$	29,667		$	12,104		$	30,838		$	43,510		$	56,891		$	60,146

	Desert Peak Minerals Predecessor Historical						Desert Peak Minerals Pro Forma
	As of June 30,		As of December 31,				As of June 30, 2021
	2021		2020		2019
Selected Balance Sheet Data:
Cash and cash equivalents	$	6,188	$	7,531	$	16,507	$	64,175
Total assets	$	909,548	$	598,628	$	631,805	$	1,220,331
Long-term debt	$	9,900	$	33,500	$	60,000	$	—
Total liabilities	$	16,966	$	36,231	$	68,194	$	5,587
Noncontrolling interests	$	298,940	$	—	$	—	$	—
Temporary equity	$	—	$	—	$	—	$	1,013,852
Permanent equity	$	593,642	$	562,397	$	563,611	$	200,892

(1) Interest expense is presented net of interest income.

(2) Adjusted EBITDA is a non-GAAP financial measure. Please read “—Non-GAAP Financial Measure” below for additional information.

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Non-GAAP Financial Measure

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP supplemental financial measure used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard to financing methods, capital structure or historical cost basis.

We define Adjusted EBITDA as net income (loss) including noncontrolling interests plus (i) interest expense, (ii) provisions for taxes, (iii) depreciation, depletion and amortization, (iv) share-based compensation expense, (v) impairment of oil and natural gas properties, (vi) gains or losses on unsettled derivative instruments, (vii) write off of deferred offering costs, (viii) gains or losses on sale of other property, and (ix) management fee to affiliates. Adjusted EBITDA is not a measure determined by accounting principles generally accepted in the United States of America (“GAAP”).

These non-GAAP financial measures do not represent and should not be considered an alternative to, or more meaningful than, their most directly comparable GAAP financial measures or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods indicated.

	Desert Peak Minerals Predecessor Historical										Desert Peak Minerals Pro Forma
	Six Months Ended June 30,					Year Ended December 31,					Six Months Ended June 30, 2021		Year  Ended December 31, 2020
	2021		2020			2020			2019
						(in thousands)
Net income (loss) including noncontrolling interests	$	9,495	$	(12,153	)	$	(14,214	)	$	8,790	$	18,169	$	(56,495	)
Interest expense (net)		524		1,185			1,968			868		308		586
Income tax expense (benefit)		107		124			38			171		5,041		(15,675	)
Depreciation, depletion and amortization		15,801		15,695			32,049			26,201		29,633		57,163
EBITDA		25,927		4,851			19,841			36,030		53,151		(14,421	)
Share-based compensation expense		—		—			—			—		—		—
Impairment of oil and natural gas properties		—		812			812			—		—		64,340
Write off of deferred offering costs		—		2,742			2,747			—		—		2,747
Gain on sale of other property		—		(41	)		(42	)		—		—		—
Management fee to affiliates		3,740		3,740			7,480			7,480		3,740		7,480
Adjusted EBITDA	$	29,667	$	12,104		$	30,838		$	43,510	$	56,891	$	60,146

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Summary Reserve Data

The following table sets forth estimates of our proved crude oil, natural gas and NGL reserves as of December 31, 2020 based on a reserve report prepared by CG&A and June 30, 2021 based on internal estimates of management. The estimated proved reserves as of June 30, 2021 have been prepared on the same basis as the estimated proved reserves as of December 31, 2020, but they have not been prepared or audited by an independent reserve engineer. The reserve report was prepared in accordance with the rules and regulations of the SEC. You should refer to “Risk Factors,” “Business—Crude Oil, Natural Gas and NGL Data—Proved Reserves,” “Business—Crude Oil, Natural Gas and NGL Production Prices and Costs—Production and Price History,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and notes thereto included elsewhere in this prospectus in evaluating the material presented below. The following table provides our estimated proved reserves as of December 31, 2020 and June 30, 2021, using the provisions of the SEC rule regarding reserve estimation regarding a historical twelve-month pricing average applied prospectively. These estimates are presented on an actual basis, without giving pro forma effect to transactions completed after such dates. As such, estimates of proved reserves (i) as of December 31, 2020 do not include reserves attributable to the Chambers Acquisition, the Rock Ridge Acquisition, the Source Acquisition, the Recent Acquisitions or the July 2021 Acquisition and (ii) as of June 30, 2021 include reserves attributable to the Chambers Acquisition, the Rock Ridge Acquisition and the Recent Acquisitions.

	Desert Peak Minerals
	December 31, 2020(1)		June 30, 2021(2)
Estimated proved developed reserves:
Crude oil (MBbls)		3,731		4,608
Natural gas (MMcf)		19,505		23,808
NGLs (MBbls)		2,352		2,526
Total (MBOE)		9,334		11,102
Estimated proved undeveloped reserves:
Crude oil (MBbls)		1,344		1,573
Natural gas (MMcf)		3,897		4,395
NGLs (MBbls)		473		466
Total (MBOE)		2,467		2,772
Estimated proved reserves:
Crude oil (MBbls)		5,075		6,182
Natural gas (MMcf)		23,402		28,203
NGLs (MBbls)		2,825		2,993
Total (MBOE)		11,800		13,875

(1) Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For crude oil and NGL volumes, the average West Texas Intermediate (“WTI”) posted price of $39.57 per Bbl as of December 31, 2020 was adjusted for quality, transportation fees and a regional price differential. NGL price was modeled at 27.8% of the WTI posted price. For natural gas volumes, the average Henry Hub spot price of $1.985 per MMBtu as of December 31, 2020 was adjusted for energy content, transportation fees and a regional price differential. The average adjusted product prices weighted by production over the remaining lives of the proved properties are $36.28 per Bbl of crude oil, $11.01 per Bbl of NGL and $1.02 per Mcf of natural gas as of December 31, 2020.

(2) Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For crude oil and NGL volumes, the average West Texas Intermediate (“WTI”) posted price of $49.78 per Bbl as of June 30, 2021 was adjusted for quality,

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transportation fees and a regional price differential. NGL price was modeled at 35.53% of the WTI posted price. For natural gas volumes, the average Henry Hub spot price of $2.428 per MMBtu as of June 30, 2021 was adjusted for energy content, transportation fees and a regional price differential. The average adjusted product prices weighted by production over the remaining lives of the proved properties are $46.38 per Bbl of crude oil, $17.69 per Bbl of NGL and $2.10 per Mcf of natural gas as of June 30, 2021.

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RISK FACTORS

Investing in our Class A common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

Our producing properties are located in the Permian Basin, making us vulnerable to risks associated with operating in a single geographic area.

All of our producing properties are currently geographically concentrated in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of the processing or transportation of crude oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic crude oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

As a result of our exclusive focus on the Permian Basin, we may be less competitive than other companies in bidding to acquire assets that include properties both within and outside of that basin. Although we are currently focused on the Permian Basin, we may from time to time evaluate and consummate the acquisition of asset packages that include ancillary properties outside of that basin, which may result in the dilution of our geographic focus.

If the E&P operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash flows may be adversely affected.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. In connection with these acquisitions, record title to mineral and royalty interests are conveyed to us or our subsidiaries by asset assignment, and we or our subsidiaries become the record owner of these interests. Upon such a change in ownership of mineral interests, and at regular intervals pursuant to routine audit procedures at each of our E&P operators otherwise at its discretion, the E&P operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the E&P operator may suspend payment of the related royalty. If an E&P operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest. Certain of our E&P operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an E&P operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. If a significant amount of our royalty interests are placed in suspense, our results of operations may be reduced significantly.

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Title to the properties in which we have an interest may be impaired by title defects.

We are not required to, and under certain circumstances we may elect not to, incur the expense of retaining lawyers to examine the title to our royalty and mineral interests. In such cases, we would rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring a specific royalty or mineral interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of operations, financial condition and cash flows. In addition, the 24,500 NRAs we acquired in the Source Acquisition are in the title review period and we may discover title defects. No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has a greater risk of title defects than developed acreage. If there are any title defects in properties in which we hold an interest, we may suffer a financial loss.

We may experience delays in the payment of royalties and be unable to replace E&P operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the E&P operators on those leases declare bankruptcy.

We may experience delays in receiving royalty payments from our E&P operators, including as a result of delayed division orders received by our E&P operators. A failure on the part of the E&P operators to make royalty payments typically gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement E&P operator. However, we might not be able to find a replacement E&P operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing E&P operator could be subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt E&P operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another E&P operator. For example, certain of our E&P operators have recently commenced bankruptcy proceedings under the Bankruptcy Code and their future operations and ability to make royalty payments to us may be adversely affected by such proceedings. In the event that the E&P operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new E&P operator, the replacement E&P operator may not achieve the same levels of production or sell crude oil or natural gas at the same price as the E&P operator it replaced.

We depend on various unaffiliated E&P operators for all of the exploration, development and production on the properties underlying our mineral and royalty interests. Substantially all of our revenue is derived from royalty payments made by these E&P operators. A reduction in the expected number of wells to be drilled on our acreage by these E&P operators or the failure of our E&P operators to adequately and efficiently develop and operate the wells on our acreage could have an adverse effect on our results of operations and cash flows.

Our assets consist of mineral and royalty interests. Because we depend on third-party E&P operators for all of the exploration, development and production on our properties, we have little to no control over the operations related to our properties. For the six months ended June 30, 2021, we received revenue from 68 E&P operators, with approximately 68% coming from the top ten E&P operators on our properties, two of which each accounted for more than 10% of such royalty revenues. The failure of our E&P operators to adequately or efficiently perform operations or an E&P operator’s failure to act in ways that are in our best interests could reduce production and revenues. Furthermore, in response to the significant decrease in prices for crude oil in 2020, many of our E&P operators substantially reduced their development activities in 2020 and have announced substantial reductions in their estimated capital expenditures, rig count and completion crews for 2021 and

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beyond. Additionally, certain investors have requested that operators adopt initiatives to return capital to investors, which could also reduce the capital available to our E&P operators for investment in exploration, development and production activities. Our E&P operators may further reduce capital expenditures devoted to exploration, development and production on our properties in the future, which could negatively impact revenues we receive. The number of new wells drilled has decreased, and such slower development pace may continue in the future, especially as a consequence of the reductions in our E&P operators’ capital expenditures. Moreover, over the last year, many of our E&P operators have announced that they plan to drill fewer wells per section than previously anticipated, due in part to greater well-interference between parent and child wells than previously anticipated and an increased focus on overall capital efficiency in a low commodity price environment.

If production on our mineral and royalty interests decreases due to decreased development activities, as a result of the low commodity price environment, limited availability of development capital, production-related difficulties or otherwise, our results of operations may be adversely affected. For example, the amount of royalty payments we received in 2020 from our E&P operators decreased due to the lower prices at which our E&P operators were able to sell production from our properties and reduced production activities by our E&P operators. Further, depressed commodity prices caused some of our E&P operators to voluntarily shut in and curtail production from wells on our properties in 2020. Although most of these have come back online, an additional or extended period of depressed commodity prices may cause additional E&P operators to take similar action or even to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under more favorable pricing conditions, both of which would decrease the amount of royalty payments we receive from our E&P operators. Our E&P operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion (subject to certain implied obligations to develop imposed by the laws of some states). Our E&P operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the E&P operators elect to drill any additional wells on our acreage, depends on a number of factors that are largely outside of our control, including:

• the capital costs required for drilling activities by our E&P operators, which could be significantly more than anticipated;

• the ability of our E&P operators to access capital;

• prevailing commodity prices;

• the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

• the availability of storage for hydrocarbons,

• the E&P operators’ expertise, operating efficiency and financial resources;

• approval of other participants in drilling wells;

• the E&P operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

• the selection of technology;

• the selection of counterparties for the marketing and sale of production; and

• the rate of production of the reserves.

The E&P operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash flows. Sustained reductions in production by the E&P operators on our properties may also adversely affect our results

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of operations and cash flows. Additionally, if an E&P operator were to experience financial difficulty, the E&P operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on our cash flows.

Our future success depends on replacing reserves through acquisitions and the exploration and development activities of our E&P operators.

Producing crude oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil, natural gas and NGL reserves and our E&P operators’ production thereof and our cash flows are highly dependent on the successful development and exploitation of our current reserves and our ability to successfully acquire additional reserves that are economically recoverable. Moreover, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire or develop additional reserves to replace the current and future production of our properties at economically acceptable terms. Aside from acquisitions, we have little to no control over the exploration and development of our properties. If we are not able to replace or grow our oil, natural gas and NGL reserves, our business, financial condition and results of operations would be adversely affected.

Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could materially and adversely affect our growth, results of operations and cash flows.

We depend in part on acquisitions to grow our reserves, production and cash flows. Our 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 data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

• recoverable reserves;

• future crude oil, natural gas and NGL prices and their applicable differentials;

• development plans;

• operating costs our E&P operators would incur to develop and operate the properties; and

• potential environmental and other liabilities that E&P operators may incur.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are often not performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Unless our E&P operators further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time. For example, in connection with the COVID-19 pandemic and resulting market and commodity price challenges, our acquisition activity saw a significant decline as we experienced a meaningful difference in sellers’ pricing expectations and the prices we were willing to offer. Our ability to complete acquisitions is

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dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, potential future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired assets into our existing operations successfully or to minimize any unforeseen difficulties could materially and adversely affect our financial condition, results of operations and cash flows. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations and cash flows.

We may acquire properties that do not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.

Acquiring crude oil, natural gas and NGL properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash flows. Any acquisition involves potential risks, including, among other things:

• the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, the operating expenses and costs our E&P operators would incur to develop the minerals;

• a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

• mistaken assumptions about the overall cost of equity or debt;

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• our ability to obtain satisfactory title to the assets we acquire;

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

• the occurrence of other significant changes, such as impairment of crude oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our E&P operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of our E&P operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of and limitations on access to infrastructure, inclement weather, regulatory changes and approvals, crude oil, natural gas and NGL prices, costs, drilling results and the availability of water. Further, our E&P operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our E&P operators to know conclusively prior to drilling whether crude oil, natural gas or NGLs will be present or, if present, whether crude oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of crude oil or natural gas exist, our E&P operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our E&P operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

There is no guarantee that the conclusions our E&P operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other E&P operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Additionally, actual production from wells may be less than expected. For example, a number of E&P operators have recently announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. Because of these uncertainties, we do not know if the potential drilling locations our E&P operators have identified will ever be drilled or if our E&P operators will be able to produce crude oil, natural gas or NGLs from these or any other potential drilling locations. As such, the actual drilling activities of our E&P operators may materially differ from those presently identified, which could adversely affect our business, results of operation and cash flows.

Finally, the potential drilling locations we have identified are based on the geologic and other data available to us and our interpretation of such data. As a result, our E&P operators may have reached different conclusions about the potential drilling locations on our properties, and our E&P operators control the ultimate decision as to where and when a well is drilled.

We are unable to determine with certainty which E&P operators will ultimately operate our properties.

When we evaluate acquisition opportunities and the likelihood of the successful and complete development of our properties, we consider which companies we expect to operate our properties. Historically, many of our properties have been operated by active, well-capitalized E&P operators that have expressed their intent to execute multi-year, pad-focused development programs. There is no guarantee, however, that such E&P operators will become or remain the E&P operators on our properties or that their development plans will not change. To the extent our E&P operators fail to perform at the levels projected or the E&P operator of our properties or sell their working interests to, are merged with, or are acquired by, another E&P operator that lacks the same level of capitalization or experience, it could adversely affect our business and expected cash flows.

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We rely on our E&P operators, third parties and government databases for information regarding our assets and, to the extent that information is incorrect or incomplete, our financial and operational information and projections may be incorrect.

As an owner of mineral and royalty interests, we rely on the E&P operators of the properties to notify us of information regarding production on our properties in a timely and complete manner, as well as the accuracy of information obtained from third parties and government databases. We use this information to evaluate our operations and cash flows, as well as to predict our expected production and possible future locations. To the extent we do not timely receive this information or the information is incomplete or incorrect, our results may be incorrect and our ability to project potential growth may be materially adversely affected. Furthermore, to the extent we have to update any publicly disclosed results or projections made in reliance on this incorrect or incomplete information, investors could lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.

We have completed numerous acquisitions of mineral and royalty interests for which separate financial information is not required or provided.

As of June 30, 2021 we have completed 175 acquisitions of mineral and royalty interests that are not “significant” under Rule 3-05 of Regulation S-X (“Rule 3-05”). Therefore, we are not required to, and have elected not to, provide separate historical financial information in this prospectus relating to those acquisitions. While these acquisitions are not individually or collectively significant for purposes of Rule 3-05, they have or will have an impact on our financial results and their aggregated effect on our business and results of operations may be material.

Acquisitions and our E&P operators’ development of our leases will require substantial capital, and we and our E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

The crude oil and natural gas industry is capital intensive. We make and may continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, we have financed capital expenditures primarily with funding from capital contributions and cash generated by operations. In addition, we expect to finance capital expenditures with borrowings under our revolving credit facility.

In the future, we may need capital in excess of the amounts we retain in our business or borrow under our revolving credit facility. The level of borrowing base available under our revolving credit facility is largely based on our estimated proved reserves and our lenders’ price decks and underwriting standards in the reserve-based lending space and will be reduced to the extent commodity prices decrease or remain depressed, underwriting standards tighten or the lending syndication market is not sufficiently liquid to obtain lender commitments to a full borrowing base in an amount appropriate for our assets. Furthermore, we cannot assure you that we will be able to access other external capital on terms favorable to us or at all. For example, given the recent significant decline in prices for crude oil and the broader economic turmoil, our ability to secure financing in the capital markets on terms favorable to us may be adversely impacted. Additionally, our ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and free cash flow.

Most of our E&P operators are also dependent on the availability of external debt, equity financing sources and operating cash flows to maintain their drilling programs. If those financing sources are not available to the E&P operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests may decline.

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The development of our PUDs may take longer and may require higher levels of capital expenditures from the E&P operators of our properties than we or they currently anticipate.

As of December 31, 2020 and June 30, 2021, approximately 21% and 20%, respectively, of our total estimated proved reserves were PUDs and may not be ultimately developed or produced by the E&P operators of our properties. Recovery of PUDs requires significant capital expenditures and successful drilling operations by the E&P operators of our properties. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by the E&P operators of our properties are required to develop such reserves. We typically do not have access to the estimated costs of development of these reserves or the scheduled development plans of our E&P operators. Even when we do have such information, we cannot be certain that the estimated costs of the development of these reserves are accurate, that our E&P operators will develop the properties underlying our royalties as scheduled or that the results of such development will be as estimated. The development of such reserves may take longer and may require higher levels of capital expenditures from the E&P operators than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical for the E&P operators of our properties. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as PUDs.

The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. For example, the COVID-19 pandemic, has caused a disruption to the oil and natural gas industry and to our business. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. Furthermore, the COVID-19 pandemic has affected our operations by (i) rendering our personnel unable to access company facilities for an extended period of time, (ii) contributing to a steep decline in commodities prices in 2020, which has reduced activity by our operators and the amounts of royalty payments we receive, (iii) causing some of the Company’s operators to temporarily shut in or curtail production from wells and (iv) reducing the level of potential acquisition opportunities, limiting our ability to execute on our growth strategy of acquiring additional mineral and royalty interests. Additionally, the steps taken by national, state and local governments to curb the spread of the COVID-19 pandemic, including stay-at-home orders, quarantines, travel restrictions and business shutdowns, and the implications on our operators’ workforce of a COVID-19 infection, have limited our operators’ ability to maintain production from our properties. Such orders and the other impacts of the COVID-19 pandemic may have limited the ability of our operators to access our properties and maintain their existing production and development activities, and any similar or more restrictive measures taken in the future could have similar effects.

While our business and operations have experienced certain effects of the COVID-19 pandemic as described above, the full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to operating production activities by our operators and the impact of potential governmental restrictions on travel, transportation and operations. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our operations, financial results and dividend policy will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the pandemic, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. While we expect this

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matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

We do not currently plan to enter into hedging arrangements with respect to the crude oil, natural gas and NGL production from our properties, and we will be exposed to the impact of decreases in the price of crude oil, natural gas and NGLs.

We do not currently plan to enter into hedging arrangements to establish, in advance, a price for the sale of the crude oil, natural gas and NGLs produced from our properties. As a result, although we may realize the benefit of any short-term increase in the price of crude oil, natural gas and NGLs, we will not be protected against decreases in the price of crude oil, natural gas and NGLs or prolonged periods of low commodity prices, which, in combination with our producing properties being located solely in the Delaware Basin, could materially adversely affect our business, results of operation and cash available for distribution. If we enter into hedging arrangements in the future, it may limit our ability to realize the benefit of rising prices and may result in hedging losses.

In the future, we may enter into hedging transactions, which may not be effective in reducing the volatility of our cash flows.

In the future, we may enter into hedging transactions with the intent of reducing volatility in our cash flows due to fluctuations in the price of crude oil, natural gas and NGLs. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we may be limited in receiving the full benefit of increases in crude oil, natural gas and NGLs prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulation of crude oil, natural gas or NGLs in an exact way. Crude oil, natural gas and NGL reserve engineering is not an exact science and requires subjective estimates of underground accumulations of crude oil, natural gas and NGLs and assumptions concerning future crude oil, natural gas and NGL prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may turn out to be incorrect. Estimates of our proved reserves and related valuations as of December 31, 2020 and 2019 were prepared by CG&A. CG&A conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. In addition, certain assumptions regarding future crude oil, natural gas and NGL prices, production levels and operating and development costs may prove incorrect. For example, due to the deterioration in commodity prices and operator activity in 2020 as a result of the COVID-19 pandemic and other factors, the commodity price assumptions used to calculate our reserves estimates declined, which in turn lowered our proved reserve estimates. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve

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estimates are based, as described above, often result in the actual quantities of crude oil, natural gas and NGLs that are ultimately recovered being different from our reserve estimates.

Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (the “FASB”), we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use 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 us or the crude oil and natural gas industry in general.

Estimates of proved reserves that have not been prepared or audited by an independent reserve engineering firm may not be as reliable or accurate as estimates of proved reserves that have been prepared or audited by an independent reserve engineering firm.

Estimates of proved oil and natural gas reserves are inherently uncertain, and any material inaccuracies in our reserve estimates will materially affect the quantities and values of our reserves. The estimates of our proved reserves as of June 30, 2021 and the proved reserves attributable to the Source Assets as of December 31, 2020 included in this prospectus were prepared by our internal reserve engineers and professionals and have not been reviewed or audited by an independent reserve engineering firm. Our internal estimates of proved reserves may differ materially from independent proved reserve estimates as a result of the estimation process employed by an independent reserve engineering firm. Our internal proved reserve estimates are based upon various assumptions, including assumptions required by the SEC related to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our internal proved reserve estimates may not be indicative of or may differ materially from the estimates of our proved reserves as of December 31, 2020 that were prepared by CG&A.

We rely on a small number of key individuals whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on members of our executive management team for their knowledge of the crude oil and natural gas industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions, especially in the Permian Basin. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our E&P operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities. In addition, our ORRIs may be lost if the underlying acreage is not drilled before the expiration of the applicable lease or if the lease otherwise terminates.

Leases on crude oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. In addition, even if production or drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically terminates, subject to certain exceptions.

Any reduction in our E&P operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the expiration of existing leases. If the lease governing any of

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our mineral interests expires or terminates, all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests. If the lease underlying any of our ORRIs expires or terminates, our ORRIs that are derived from such lease will also terminate. Any such expirations or terminations of our leases or our ORRIs could materially and adversely affect the growth of our financial condition, results of operations and cash flows.

If an owner of working interests burdened by our ORRIs declares bankruptcy and a court determines that all or a portion of such ORRIs were part of the bankruptcy estate, we could be treated as an unsecured creditor with respect to such ORRIs.

In determining whether ORRIs may be treated as part of a bankruptcy estate, a court may take into consideration a variety of factors including, among others, whether ORRIs are typically characterized as a real property interest under applicable state law, the terms conveying the ORRIs and related working interests and the applicable state law procedures required to perfect the interests such parties intend to create. We believe that our ORRIs would be treated as an interest in real property in the states where they are located and, therefore, would not likely be considered a part of the bankruptcy estate. Nevertheless, the outcome is not certain. As such, if an owner of working interests burdened by our ORRIs declares bankruptcy, a court may determine that all or a portion of such ORRIs are part of the bankruptcy estate. In that event, we would be treated as a creditor in the bankruptcy case. Although holders of ORRIs may be entitled to statutory liens and/or other protections under applicable state law that could be enforceable in bankruptcy, there is no guarantee that such security interests or other protections would apply. Therefore, we could be treated as an unsecured creditor of the debtor working interest holder and could lose the entire value of such ORRI.

Operating hazards and uninsured risks may result in substantial losses to us or our E&P operators, and any losses could adversely affect our results of operations and cash flows.

The operations of our E&P operators will be subject to all of the hazards and operating risks associated with drilling for and production of crude oil, natural gas and NGLs, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of crude oil, natural gas, NGLs and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as crude oil and NGL spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our E&P operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

Loss of our or our E&P operators’ information and computer systems, including as a result of cyber attacks, could materially and adversely affect our business.

We and our E&P operators rely on electronic systems and networks to control and manage our respective businesses. If any of such programs or systems were to fail for any reason, including as a result of a cyber attack, or create erroneous information in our or our E&P operators’ hardware or software network infrastructure, possible consequences could be significant, including loss of communication links and inability to automatically process commercial transaction or engage in similar automated or computerized business activities. Although we have multiple layers of security to mitigate risks of cyber attacks, cyber attacks on business have escalated in recent years. Moreover, our E&P operators are becoming increasingly dependent on digital technologies to conduct certain exploration, development, production and processing activities, including interpreting seismic data, managing drilling rigs, production activities and gathering systems, conducting reservoir modeling and estimating reserves. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. If our E&P operators become the target of cyber attacks of information

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security breaches, their business operations may be substantially disrupted, which could have an adverse effect on our results of operations. In addition, our and our E&P operators, efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, and there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for crude oil, natural gas and NGLs, potentially putting downward pressure on demand for our E&P operators’ services and causing a reduction in our revenues. Crude oil, natural gas and NGL related facilities, including those of our operators, could be direct targets of terrorist attacks, and, if infrastructure integral to our E&P operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash flows. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to Our Industry

A substantial majority of our revenues from the crude oil and gas producing activities of our E&P operators are derived from royalty payments that are based on the price at which crude oil, natural gas and NGLs produced from the acreage underlying our interests are sold. Prices of crude oil, natural gas and NGLs are volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect our business, financial condition, results of operations and cash flows.

Our revenues, operating results, discretionary cash flows and the carrying value of our mineral and royalty interests depend significantly upon the prevailing prices for crude oil, natural gas and NGLs. Historically, crude oil, natural gas and NGL prices and their applicable basis differentials have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

• the domestic and foreign supply of and demand for crude oil, natural gas and NGLs;

• the level of prices and market expectations about future prices of crude oil, natural gas and NGLs;

• the level of global crude oil, natural gas and NGL exploration and production;

• the cost of exploring for, developing, producing and delivering crude oil, natural gas and NGLs;

• the price and quantity of foreign imports and U.S. exports of crude oil, natural gas and NGLs;

• the level of U.S. domestic production;

• political and economic conditions in oil producing regions, including the Middle East, Africa, South America and Russia;

• global or national health concerns, including the outbreak of an illness pandemic (like COVID-19), which may reduce demand for crude oil, natural gas and NGLs due to reduced global or national economic activity;

• the ability of members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations to agree to and maintain crude oil price and production controls;

• speculative trading in crude oil, natural gas and NGL derivative contracts;

• the level of consumer product demand;

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• weather conditions and other natural disasters, such as hurricanes and winter storms, the frequency and impact of which could be increased by the effects of climate change;

• technological advances affecting energy consumption, energy storage and energy supply;

• domestic and foreign governmental regulations and taxes;

• the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran;

• the proximity, cost, availability and capacity of crude oil, natural gas and NGL pipelines and other transportation facilities;

• the price and availability of alternative fuels; and

• overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future crude oil, natural gas and NGL price movements with any certainty. For example, during the past five years, the posted price for WTI light sweet crude oil has ranged from a historic, record low price of negative ($36.98) per Bbl in April 2020 to a high of $84.65 per Bbl in October 2021, and the Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. Certain actions by OPEC+ in the first half of 2020, combined with the impact of the continued outbreak of the COVID-19 pandemic and a shortage in available storage for hydrocarbons in the U.S., contributed to the historic low price for crude oil in April 2020. While the prices for crude oil have begun to stabilize and also increase, such prices have historically remained volatile, which has adversely affected the prices at which production from our properties is sold as well as the production activities of operators on our properties and may continue to do so in the future. This, in turn, has and will materially affect the amount of royalty payments that we receive from such operators.

Any substantial decline in the price of crude oil, natural gas and NGLs or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash flows. In addition, lower crude oil, natural gas and NGL prices may reduce the amount of crude oil, natural gas and NGLs that can be produced economically by our E&P operators, which may reduce our E&P operators’ willingness to develop our properties. This may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact the borrowing base under our revolving credit facility and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, the successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our crude oil and natural gas properties. Our E&P operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce crude oil, natural gas or NGLs in commercially paying quantities. We may choose to use various derivative instruments in connection with anticipated crude oil, natural gas and NGL sales to minimize the impact of commodity price fluctuations. However, we cannot hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews,

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production data, economics and other factors, we may be required to write down the carrying value of our properties. The Company evaluates the carrying amount of its proved oil, natural gas and NGL properties for impairment whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates and a commensurate discount rate. Because estimated undiscounted future cash flows have exceeded the carrying value of the Company’s proved properties to date, it has not been necessary for the Company to estimate the fair value of its properties under GAAP for successful efforts accounting. As a result, the Company has not recorded any impairment expenses associated with its proved properties. While the Company did not record any impairment during the six months ended June 30, 2021, for the year ended December 31, 2020, the Company recorded an impairment charge of $812,000 in connection with capitalized acquisition costs for a prospective mineral interest acquisition that it did not complete. The risk that we will be required to recognize impairments of our crude oil, natural gas and NGL properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for E&P operators related to developing and operating our properties.

The crude oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our E&P operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our E&P operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, hydraulic fracturing and completion services and production equipment could delay or restrict our E&P operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows.

The marketability of crude oil, natural gas and NGL production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our E&P operators control. Any limitation in the availability of those facilities could interfere with our or our E&P operators’ ability to market our or our E&P operators’ production and could harm our business.

The marketability of our or our E&P operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. Neither we nor our E&P operators control these third party transportation facilities and our E&P operators’ access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third party transportation facilities or other production facilities could adversely impact our E&P operators’ ability to deliver, to market or produce oil and natural gas and thereby cause a significant interruption in our operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of crude oil that can be produced and sold is subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical

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damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the construction of pipeline facilities, and the shipment of our or our E&P operators’ crude oil, natural gas and NGLs on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our E&P operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity, or an inability to obtain favorable terms for delivery of the crude oil and natural gas produced from our acreage, could reduce our or our E&P operators’ ability to market the production from our properties and have a material adverse effect on our financial condition, results of operations and cash flows. Our or our E&P operators’ access to transportation options and the prices we or our E&P operators receive can also be affected by federal and state regulation—including regulation of crude oil, natural gas and NGL production, transportation and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our E&P 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 our business.

Drilling for and producing crude oil, natural gas and NGLs are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash flows.

The drilling activities of the E&P operators of our properties will be subject to many risks. For example, we will not be able to assure our stockholders that wells drilled by the E&P operators of our properties will be productive. Drilling for crude oil, natural gas and NGLs often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient crude oil, natural gas or NGLs to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that crude oil, natural gas or NGLs are present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our E&P operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

• unusual or unexpected geological formations;

• loss of drilling fluid circulation;

• title problems;

• facility or equipment malfunctions;

• unexpected operational events;

• shortages or delivery delays of equipment and services;

• compliance with environmental and other governmental requirements; and

• adverse weather conditions, including the recent winter storms in February 2021 that adversely affected operator activity and production volumes in the southern United States, including in the Delaware Basin.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash flows may be materially adversely affected.

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Competition in the crude oil and natural gas industry is intense, which may adversely affect our and our E&P operators’ ability to succeed.

The crude oil and natural gas industry is intensely competitive, and the E&P operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce crude oil, natural gas and NGLs, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low crude oil, natural gas and NGL market prices. Our E&P operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our E&P operators can, which would adversely affect our E&P operators’ competitive position. Our E&P operators may have fewer financial and human resources than many companies in our E&P operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing crude oil and natural gas properties. Furthermore, the crude oil and natural gas industry has experienced recent consolidation amongst some operators, which has resulted in certain instances of combined companies with larger resources. Such combined companies may compete against our E&P operators or, in the case of consolidation amongst our E&P operators, may choose to focus their operations on areas outside of our properties. In addition, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transaction in a highly competitive environment.

A deterioration in general economic, business, political or industry conditions would materially adversely affect our results of operations, financial condition and cash flows.

Concerns over global economic conditions, energy costs, geopolitical issues, the impacts of the COVID-19 pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. Additionally, acts of protest and civil unrest have caused economic and political disruption in the United States. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. An oversupply of crude oil in 2020 led to a severe decline in worldwide crude oil prices in 2020. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which crude oil, natural gas and NGLs from our properties are sold, affect the ability of our E&P operators to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash flows.

Conservation measures, technological advances and increasing attention to ESG matters could materially reduce demand for crude oil, natural gas and NGLs, availability of capital and adversely affect our results of operations and the trading market for shares of our Class A common stock.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy-generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own shares of our Class A common stock, adversely affecting the market price of our Class A common stock. For example, certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Furthermore, organizations that provide information to investors on

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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, and unfavorable ESG ratings may lead to increased negative investor sentiment toward us. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours and also adversely affect our availability of capital.

Risks Related to Environmental and Regulatory Matters

Crude oil, natural gas and NGL operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our E&P operators, and failure to comply could result in our E&P operators incurring significant liabilities, either of which may impact our E&P operators’ willingness to develop our interests.

Our E&P operators’ activities on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity to conserve supplies of crude oil, natural gas and NGLs. For example, in January 2021, President Biden signed an Executive Order that, among other things, instructed the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices; however, in June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued a nationwide preliminary injunction against the pause of new oil and natural gas leases while litigation challenging the Executive Order and its implementation is ongoing. Substantially all of our interests are located on private lands, but we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. President Biden also issued an Executive Order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions during the prior administration that may be inconsistent with the current administration’s policies. Further actions of President Biden, and the Biden Administration, including actions focused on addressing climate change, may negatively impact oil and gas operations and favor renewable energy projects in the United States, which may negatively impact the demand for oil and natural gas.

In addition, the production, handling, storage and transportation of crude oil, natural gas and NGLs, as well as the remediation, emission and disposal of crude oil, natural gas and NGL wastes, by-products thereof and other substances and materials produced or used in connection with crude oil, natural gas and NGL operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of worker health and safety, natural resources and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our E&P operators, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our E&P operators’ operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, species protection, and waste management, among other matters.

Laws and regulations governing exploration and production may also affect production levels. Our E&P operators must comply with federal and state laws and regulations governing conservation matters, including, but not limited to:

• provisions related to the unitization or pooling of the crude oil and natural gas properties;

• the establishment of maximum rates of production from wells;

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• the spacing of wells;

• the plugging and abandonment of wells; and

• the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which may require increased capital costs for third-party crude oil, natural gas and NGL transporters. These transporters may attempt to pass on such costs to our E&P operators, which in turn could affect profitability on the properties in which we own mineral and royalty interests.

Our E&P operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the E&P operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

Our E&P operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. Please read “Business—Regulation” for a description of the laws and regulations that affect our E&P operators and that may affect us. These and other potential regulations could increase the operating costs of our E&P operators and delay production and may ultimately impact our E&P operators’ ability and willingness to develop our properties.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause our E&P operators to incur increased costs, additional operating restrictions or delays and fewer potential drilling locations.

Our E&P operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the Underground Injection Control program of the U.S. Safe Drinking Water Act (“SDWA”) and is typically regulated by state oil and gas commissions or similar agencies.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. This or other federal legislation related to hydraulic fracturing may be considered again in the future, though we cannot predict the extent of any such legislation at this time.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. For example, Texas, among others, has adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.

Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water gathered from drilling and production activities, could lead to greater opposition to, and litigation concerning, crude oil, natural gas and NGL production activities using hydraulic fracturing techniques in areas

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where we own mineral and royalty interests. Additional legislation or regulation could also lead to operational delays or increased operating costs for our E&P operators in the production of crude oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult for our E&P operators to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in our E&P operators’ completion of new crude oil and natural gas wells on our properties and an associated decrease in the production attributable to our interests, which could have a material adverse effect on our business, financial condition and results of operations.

Legislation or regulatory initiatives intended to address seismic activity could restrict our E&P operators’ drilling and production activities, as well as our operators’ ability to dispose of produced water gathered from such activities, which could have a material adverse effect on their future business, which in turn could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including New Mexico, Oklahoma and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.

In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission published a new 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 produced water or other 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 agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in.

Our operators will likely dispose of large volumes of produced water gathered from its drilling and production operations by injecting it into wells pursuant to permits issued by governmental authorities overseeing such disposal activities. While these permits will be issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our E&P operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

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As a result of judicial interpretation of the Relinquishment Act, certain of our surface rights entitle us to receive a fixed, lease operating expense and capital cost-free percentage of any oil and natural gas produced from reserves underlying the property. If the Relinquishment Act were to be amended or repealed or we were subject to an unfavorable ruling under the Relinquishment Act, we may no longer be able to derive additional rights to production from our ownership of surface rights, which may have a material adverse effect on our results of operations and cash flows.

Under the Relinquishment Act, the State of Texas owns mineral rights in certain lands. As a result of judicial interpretation of the Relinquishment Act, the surface owner of such lands may act as an agent for the state in negotiating and executing mineral leases, and, if the state approves the lease terms, the applicable surface owner receives an interest in the resulting royalty interest. Approximately 19% of our NRAs as of December 31, 2020 were from the rights we received in this manner. However, if the Relinquishment Act were to be amended or repealed or if we were subject to an unfavorable ruling under the Relinquishment Act, we may no longer be able to derive revenue from the corresponding mineral rights, which may have a material adverse effect on our results of operations and cash flows.

Restrictions on the ability of our E&P operators to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of crude oil, natural gas and NGL production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of the country, and in particular Texas, have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Such conditions may be exacerbated by climate change. If our E&P operators are unable to obtain water to use in their operations from local sources, or if our E&P operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce crude oil, natural gas and NGLs from our properties, which could have an adverse effect on our financial condition, results of operations and cash flows.

Our operations, and those of our E&P operators, are subject to a series of risks arising from climate change.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other “greenhouse gases” (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several Executive Orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, as discussed above, President Biden issued an Executive Order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. The Executive Order specifically called on the EPA to consider a proposed rule suspending, revising or rescinding the September 2020 deregulatory amendments by

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September 2021. The Executive Order also called on the EPA to propose new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments, by September 2021. Additionally, in April 2021, the U.S. Senate approved a resolution under the Congressional Review Act to repeal the September 2020 revisions. The U.S. House of Representatives passed the resolution and President Biden signed it into law in June 2021, effectively vacating the September 2020 revisions and reinstating the prior standards.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, New Mexico has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. The impacts of these orders, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in public office. On January 27, 2021, President Biden issued an Executive Order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also issued orders temporarily suspending the issuance of authorizations, and suspending the issuance of new leases pending a study, for oil and gas development on federal lands. Substantially all of our interests are located on private lands, but we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an Executive Order calling for the development of a “climate finance plan” and, separately, the Federal Reserve announced that is has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or

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generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our E&P operators’ operations and the production on our properties.

Increased attention to ESG matters and conservation measures may adversely impact our business or the business of our operators.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our operators’ products (and thus in our mineral interests), reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.

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 us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our or operators’ access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our or our operators’ access to capital for potential growth projects.

Our or our E&P operators’ results of operations may be materially impacted by efforts to transition to a lower-carbon economy.

Concerns over the risk of climate change have increased the focus by global, regional, national, state and local regulators on GHG emissions, including carbon dioxide emissions, and on transitioning to a lower-carbon future. A number of countries and states have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These regulatory measures may include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency standards, prohibitions on the sales of new automobiles with internal combustion engines, and incentives or mandates for battery-powered automobiles and/or wind, solar or other forms of alternative energy. Compliance with changes in laws, regulations and obligations relating to

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climate change could result in increased costs of compliance for our E&P operators or costs of consuming crude oil, natural gas and NGLs for such products, and thereby reduce demand, which could reduce the profitability of our interests. For example, our E&P operators may be required to install new emission controls, acquire allowances or pay taxes related to their greenhouse gas emissions, or otherwise incur costs to administer and manage a GHG emissions program. Additionally, we or our operators could incur reputational risk tied to changing customer or community perceptions of our, our E&P operators’ or our E&P operators’ customers contribution to, or detraction from, the transition to a lower-carbon economy. These changing perceptions could lower demand for oil and gas products, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries, and could also pressure banks and investment managers to shift investments and reduce lending.

Separately, banks and other financial institutions, including investors, may decide to adopt policies that restrict or prohibit investment in, or otherwise funding, us or our operators based on climate change -related concerns, which could affect our or our E&P operators’ access to capital for potential growth projects.

Approaches to climate change and transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our or our operators’ financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows.

Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our E&P operators’ ability to conduct drilling activities.

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where our E&P operators operate, our E&P operators’ abilities to conduct or expand operations could be limited, or our E&P operators could be forced to incur material additional costs. Moreover, our E&P operators’ drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. For example, in June 2021, the U.S. Fish & Wildlife Service (the “FWS”) proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA. Recently, there have also been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, and to reconsider listing the species under the ESA.

In addition, as a result of one or more settlements approved by the FWS, the agency was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The FWS did not meet that deadline, but continues to evaluate whether to take action with respect to those species. The designation of previously unidentified endangered or threatened species could cause our E&P operators’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands.

Risks Related to Our Financial and Debt Arrangements

Restrictions in our current and future debt agreements and credit facilities could limit our growth and our ability to engage in certain activities.

KMF Land, LLC (“KMF Land”), an indirect subsidiary of KMF that will become a wholly owned direct subsidiary of Opco in connection with our corporate reorganization, entered into a $750 million revolving credit

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facility on September 26, 2019 (as amended, restated, amended and restated, or otherwise modified prior to October 8, 2021, the “original credit facility”), which we amended and restated on October 8, 2021 (as so amended and restated, the “revolving credit facility”), among other things, provide for the transactions contemplated by our corporate reorganization and this offering as well as to provide for an increased borrowing base.

Our revolving credit facility is available for working capital, acquisitions and general company purposes and is secured by substantially all of the assets of KMF Land, its direct parent and its subsidiaries. The revolving credit facility contains certain customary representations and warranties and various covenants and restrictive provisions that limit KMF Land’s, its direct parent’s and its subsidiaries’ ability to, among other things:

• incur or guarantee additional debt;

• pay dividends on, or redeem or repurchase, their equity interests, return capital to the holders of their equity interests, or make other distributions to holders of their equity interests;

• enter into certain swap arrangements;

• make certain investments and acquisitions;

• incur certain liens or permit them to exist;

• enter into certain types of transactions with affiliates;

• merge or consolidate with another company;

• transfer, sell or otherwise dispose of assets;

• enter into certain other lines of business; and

• repay or redeem certain debt.

Our revolving credit facility also contains covenants requiring KMF Land, its direct parent and its subsidiaries to maintain certain financial ratios or to reduce its indebtedness if they are unable to comply with such ratios. Their ability to meet those financial ratios and tests can be affected by events beyond our control. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our revolving credit facility impose on it.

A failure to comply with the provisions of our revolving credit facility could result in an event of default, which could enable the lenders to declare, subject to the terms and conditions of our revolving credit facility, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, cash flows from our operations may be insufficient to repay such debt in full. Our revolving credit facility contains events of default customary for transactions of this nature, including the occurrence of a change of control. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Revolving Credit Facility.”

Any significant reduction in the borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, will unilaterally determine on a regular basis based in part upon projected revenues from the oil and natural gas properties securing the loans issued thereunder. If the borrowing base is reduced, we may not have access to capital needed to fund our expenditures and we would be required to repay outstanding borrowings in excess of the borrowing base after applicable grace periods. We may not have other collateral or the financial resources in the future to make mandatory principal prepayments required under our revolving credit facility, which could lead to a default.

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Any significant contraction in the reserve-based lending syndication market may negatively impact our ability to fund our operations.

Lending institutions have significantly curtailed reserved-based lending or entirely exited the reserve-based lending market. In the prevailing market, it may be difficult for the arrangers under the revolving credit facility, or under any other potential future reserve-based credit facility, to obtain sufficient commitments for the borrowing base or to do so on terms favorable or acceptable to us. We have funded our operations since inception primarily through capital contributions and cash generated from operations, and we may finance acquisitions, and potentially other working capital needs, with borrowings under our revolving credit facility. We intend to continue to make significant acquisitions to support our business growth. If the arrangers under our revolving credit facility, or under any other potential future reserve-based credit facility, are unable to obtain sufficient commitments for the borrowing base, we may not have sufficient funds to finance our operations and future growth. If adequate funds are not available, we may be required to reduce expenditures, including curtailing our growth strategies or forgoing acquisitions.

In addition, during previous periods of economic instability, it has been difficult for many companies to obtain financing in the public markets or to obtain debt financing, and during any future period of economic instability we may not be able to obtain additional financing on commercially reasonable terms, if at all. If we are unable to obtain adequate financing or financing on terms satisfactory to us, we could experience a material adverse effect on our business, financial condition and results of operations.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Our existing and any future indebtedness could have important consequences to us, including:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to us;

• covenants in our revolving credit facility require, and in any future credit and debt arrangement may require, KMF Land or us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

• our access to the capital markets may be limited;

• our borrowing costs may increase;

• we will use a portion of our discretionary cash flows to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payment of dividends to our stockholders; and

• our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

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Risks Related to this Offering and Our Class A Common Stock

We are a holding company. Our sole material asset after completion of this offering will be our equity interest in Opco and we are accordingly dependent upon distributions from Opco to pay taxes, cover our corporate and other overhead expenses and pay any dividends on our Class A common stock.

We are a holding company and will have no material assets other than our equity interest in Opco. Please see “Corporate Reorganization.” We have no independent means of generating revenue. To the extent Opco has available cash, Opco is generally required to make pro rata cash distributions (which we refer to as “tax distributions”) to all its unitholders, including to us, in an amount sufficient to allow us to pay our U.S. federal, state, local and non-U.S. tax liabilities. We also expect Opco may make non-pro rata cash distributions periodically to enable us to cover our corporate and other overhead expenses. In addition, as the sole managing member of Opco, we intend to cause Opco to make pro rata cash distributions to all of its unitholders, including to us, in an amount sufficient to allow us to fund dividends to our stockholders, to the extent our board of directors declares such dividends. Therefore, although we expect to pay dividends on our Class A common stock in amounts determined from time to time by our board of directors as further described in “Dividend Policy”, our ability to do so may be limited to the extent Opco and its subsidiaries are limited in their ability to make these and other distributions to us. To the extent that we need funds and Opco or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

If we fail to develop or maintain an effective system of internal controls over financial reporting, we may not be able to report our financial results accurately and timely or prevent fraud, which may result in material misstatements in our financial statements or failure to meet our periodic reporting obligations. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Prior to the completion of this offering, we were a private entity. We have not completed an assessment of the effectiveness of our internal controls over financial reporting, and our independent registered public accounting firm was not required to, and did not, conduct an audit of our internal controls over financial reporting as of December 31, 2020 or 2019. Our internal controls over financial reporting do not currently meet all the standards contemplated by Section 404 of the Sarbanes-Oxley Act. Accordingly, we cannot assure you that we have identified all, or that we will not in the future have additional, material weaknesses. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance at the time required, this may cause us to be unable to report on a timely basis and thereby subject us to adverse regulatory consequences, including sanctions by the SEC or violations of applicable stock exchange listing rules.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results may be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet

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our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. Additional material weaknesses may be identified in the future. If we identify such issues or if we are unable to produce accurate and timely financial statements, the trading price of our Class A common stock may decline and we may be unable to maintain compliance with the NYSE listing standards.

We will incur increased costs as a result of operating as a public company, including the cost of compliance with securities laws, and our management will be required to devote substantial time to compliance efforts.

As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. Our management and other personnel will need to devote a substantial amount of time and financial resources to comply with obligations related to being a publicly traded corporation. We currently estimate that we will incur approximately $3.4 million annually in additional operating expenses as a publicly traded corporation that we have not previously incurred, including costs associated with compliance under the Exchange Act, annual and quarterly reports to common stockholders, registrar and transfer agent fees, audit fees, incremental director and officer liability insurance costs and director and officer compensation.

In addition, we will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act as early as our annual report for the fiscal year ending December 31, 2022, Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify as an emerging growth company under the JOBS Act. We are evaluating our existing controls over financial reporting and we will design enhanced processes and controls to the extent warranted based on our review. We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our independent registered public accounting firm will not identify any additional material weaknesses in our internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our independent registered public accounting firm identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the stock price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

There is no existing market for our Class A common stock, and a trading market that will provide you with adequate liquidity may not develop. The price of our Class A common stock may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our Class A common stock. After this offering, there will be only 10,000,000 publicly traded shares of Class A common stock held by our public common stockholders (11,500,000 shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock). We do not know the extent to which investor interest will lead to the development of an active trading market or how liquid that market might be. You may not be able to resell your Class A common stock at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the Class A common stock and limit the number of investors who are able to buy the Class A common stock.

The initial public offering price for the Class A common stock offered hereby will be determined by negotiations between us and the representative of the underwriters and may not be indicative of the market price of the Class A common stock that will prevail in the trading market. The market price of our Class A common stock may decline below the initial public offering price.

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Our Existing Owners will initially have the ability to direct the voting of a majority of the voting power of our common stock, and their interests may conflict with those of our other stockholders.

Holders of shares of our Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation. Upon completion of this offering, our Existing Owners will beneficially own, in the aggregate, 100% of our Class B common stock, representing 84% of our combined voting power (or approximately 82% if the underwriters exercise in full their option to purchase additional shares of Class A common stock). As a result, our Existing Owners will initially be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of our Existing Owners with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders.

Given this concentrated ownership, our Existing Owners would have to approve any potential acquisition of us. In addition, certain of our directors and director nominees are currently employees of our Existing Owners or their affiliates. These directors’ duties as employees of our Existing Owners or their affiliates may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. Finally, the existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Our Existing Owners’ concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

Future sales of shares of our Class A common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

Subject to certain limitations and exceptions, our Existing Owners, who hold Opco Units, may require Opco to redeem their Opco Units for shares of Class A common stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions), and our Existing Owners may sell any of such shares of Class A common stock. Additionally, after the expiration or waiver of the lock-up provision contained in the underwriting agreement entered into in connection with this offering, we may sell additional shares of Class A common stock in subsequent public offerings or may issue additional shares of Class A common stock or convertible securities. After the completion of this offering, and assuming full exercise of the underwriters’ option to purchase additional shares, we will have outstanding 11,500,000 shares of Class A common stock and 52,000,000 shares of Class B common stock. This number includes 10,000,000 shares of Class A common stock that we are selling in this offering and 1,500,000 shares of Class A common stock that we may sell in this offering if the underwriters exercise their option to purchase additional shares in full, which shares may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters’ option to purchase additional shares, our Existing Owners will own, in the aggregate, 52,000,000 shares of Class B common stock, representing approximately 82% of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in “Underwriting (Conflicts of Interest),” but may be sold into the market in the future. Each of Kimmeridge, Blackstone and Source will be party to a registration rights agreement, which will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. See “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

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In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 6,350,000 shares of our Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up restrictions, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

Our Existing Owners and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable our Existing Owners and their affiliates to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents will provide that our Existing Owners and their affiliates (including portfolio investments of our Existing Owners and their affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us and that we renounce any interest or expectancy in any business opportunity that may be from time to time presented to our Existing Owners or their affiliates. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things:

• permit our Existing Owners and their affiliates and our directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

• provide that if our Existing Owners or their affiliates or any director or officer of one of our affiliates, our Existing Owners or their affiliates who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Our Existing Owners or their affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, our Existing Owners and their affiliates may dispose of crude oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Existing Owners and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read “Description of Capital Stock—Corporate Opportunity.”

Our Existing Owners and their affiliates are established participants in the crude oil and natural gas industry and have resources greater than ours, which may make it more difficult for us to compete with our Existing Owners and their affiliates with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and our Existing Owners and their affiliates, on the other hand, will be resolved in our favor. As a result, competition from our Existing Owners and their affiliates could adversely impact our results of operations.

A significant reduction by our Existing Owners of their ownership interests in us could adversely affect us.

We believe that our Existing Owners’ ownership interests in us provide them with an economic incentive to assist us to be successful. Upon the expiration of the lock-up restrictions on transfers or sales of our securities

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following the completion of this offering, none of our Existing Owners will be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. Furthermore, as described under “Corporate Reorganization,” our Existing Owners may distribute all or a portion of their ownership in us to their partners or members, as applicable, in the Existing Owner Distribution. In the event our Existing Owners reduce their ownership interest in us, our Existing Owners and their affiliates may have less incentive to assist in our success and the individuals initially appointed to our board of directors by our Existing Owners may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our business, financial condition and results of operations.

Our amended and restated certificate of incorporation and amended and restated bylaws will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation will authorize our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

• establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders;

• provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

• provide that the authorized number of directors constituting our board of directors may be changed only by resolution of the board of directors;

• provide that all vacancies, including newly created directorships, shall, except as otherwise required by law or, if applicable, the rights of holders of a series of our preferred stock and subject to the director designation agreement (to the extent it remains in effect), be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum;

• provide that our bylaws can be amended by the board of directors;

• provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of not less than 66 2/3% of our then outstanding shares of common stock entitled to vote on such matter;

• provide that special meetings of our stockholders may only be called by our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the members of the board of directors serving at the time of such vote; and

• prohibit cumulative voting on all matters.

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Our amended and restated certificate of incorporation will designate 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 our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our amended and restated bylaws or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. In the event the Delaware Court of Chancery lacks subject matter jurisdiction, then the sole and exclusive forum for such action or proceeding shall be the federal district court for the District of Delaware. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Investors in this offering will experience immediate and substantial dilution of $1.91 per share.

Based on an assumed initial public offering price of $21.50 per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of shares of our Class A common stock in this offering will experience an immediate and substantial dilution of $1.91 per share in the as adjusted net tangible book value per share of Class A common stock from the initial public offering price, and our as adjusted net tangible book value as of June 30, 2021 after giving effect to this offering would be $19.59 per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

Our ability to pay dividends to our stockholders may be limited by our holding company structure, contractual restrictions and regulatory requirements.

After this offering, we will be a holding company and will have no material assets other than our ownership of Opco Units, and we will not have any independent means of generating revenue. To the extent Opco has available cash, Opco is generally required to make (i) pro rata tax distributions to all its unitholders, including to us, in an amount sufficient to allow us to pay our U.S. federal, state, local and non-U.S. tax liabilities and (ii) non-pro rata distributions to us in an amount sufficient to cover its corporate and other overhead expenses. In addition, as the sole managing member of Opco, we intend to cause Opco to make pro rata distributions to all of its unitholders, including to us, in an amount sufficient to allow us to fund dividends to our stockholders, to the extent our board of directors declares such dividends. Opco is a distinct legal entity and may be subject to legal or contractual restrictions that, under certain circumstances, may limit our ability to obtain cash from it. If Opco is unable to make distributions, we may not receive adequate distributions, which could materially and adversely affect our cash flows and financial position and our ability to fund any dividends.

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Although we expect to pay dividends on our Class A common stock, our board of directors will take into account general economic and business conditions, including our financial condition and results of operations, capital requirements, contractual restrictions, including restrictions and covenants contained in our debt agreements, business prospects and other factors that our board of directors considers relevant in determining whether, and in what amounts, to pay such dividends.

In addition, the agreement governing our revolving credit facility limits the amount of distributions that KMF Land and its direct parent can make to us and the purposes for which distributions can be made. Under KMF Land’s existing Amended and Restated Credit Agreement, dated as of October 8, 2021 (as amended, supplemented or otherwise modified from time to time prior to the date hereof, the “Existing Credit Agreement”), the direct parent of KMF Land is permitted to make unlimited distributions to its equity holders so long as, (i) such distribution is paid within 30 days after the date of declaration thereof, (ii) as of the date of such declaration, if such distribution had been paid as of such date of declaration, both immediately before, and immediately after giving pro forma effect to, any such distribution, (A) no event of default would have occurred and be continuing under the Existing Credit Agreement, (B) no borrowing base deficiency exists or would exist under the Existing Credit Agreement, (C) liquidity (e.g, the sum of unused commitments under the Existing Credit Agreement as of such date plus the aggregate amount of unrestricted cash as of such date minus the amount of any borrowing base deficiency on such date) (x) until the date that is seven days after the public filing of this prospectus with the SEC, of at least 25% of the total commitments (e.g, the lesser of the maximum credit amount of each lender, the aggregate elected commitments and the then effective borrowing base) under the Existing Credit Agreement and (y) thereafter, of at least 10% of the total commitments (e.g, the lesser of the maximum credit amount of each lender, the aggregate elected commitments and the then effective borrowing base) under the Existing Credit Agreement and (iii) the leverage ratio would not exceed 3.00 to 1.00 after giving effect to such distribution as of the date of such declaration. Accordingly, we may not be able to pay dividends even if our board of directors would otherwise deem it appropriate. On an actual and pro forma basis assuming the Chambers Acquisition, the Rock Ridge Acquisition and the Source Acquisition were completed on January 1, 2020, during the year ended December 31, 2020, we would not have generated sufficient discretionary cash flow to allow us to make $65 million of aggregate annualized distributions. On an actual basis during such period, we would have been limited to an aggregate of approximately $40.0 million of distributions by the restrictive covenants in the Existing Credit Agreement. See “Dividend Policy,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Description of Capital Stock.”

The U.S. federal income tax treatment of distributions on our Class A common stock to a holder will depend upon our tax attributes and the holder’s tax basis in our stock, which are not necessarily predictable and can change over time.

Distributions of cash or property on our Class A common stock, if any, 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. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the holder’s tax basis in our Class A common stock and thereafter as capital gain from the sale or exchange of such common stock. Also, if any holder sells our Class A common stock, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in such Class A common stock.

To the extent that the amount of our distributions is treated as a non-taxable return of capital as described above, such distribution will reduce a holder’s tax basis in the Class A common stock. Consequently, such excess distributions will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A common stock or subsequent distributions with respect to such stock. Additionally, with regard to U.S. corporate holders of our Class A shares, to the extent that a distribution on our Class A shares exceeds both our current and accumulated earnings and profits and such holder’s tax basis in such shares, such holders would be unable to utilize the corporate dividends-received deduction (to the extent it would otherwise be applicable to such holder) with respect to the gain resulting from such excess distribution.

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Prospective investors in our Class A common stock are encouraged to consult their tax advisors as to the tax consequences of receiving distributions on our Class A shares that are not treated as dividends for U.S. federal income tax purposes.

If Opco were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and Opco might be subject to potentially significant tax inefficiencies.

Section 7704 of the Code generally provides that a publicly traded partnership will be treated as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership, the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. However, if 90% or more of a partnership’s gross income for every taxable year consists of “qualifying income,” the partnership may continue to be treated as a partnership for U.S. federal income tax purposes. Qualifying income generally includes income earned from royalty interests and other passive ownership interests in oil and gas properties. There can be no assurance that there will not be future changes to U.S. federal income tax laws or the Treasury Department’s interpretations of the qualifying income rules in a manner that could impact Opco’s ability to qualify as a partnership for federal income tax purposes. However, we believe that substantially all of Opco’s gross income will constitute qualifying income for purposes of Section 7704(d) and intend to operate such that Opco does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. In addition, the Opco Agreement provides for limitations on the ability of unitholders of Opco to transfer their Opco Units and will provide us, as managing member of Opco, with the right to impose restrictions (in addition to those already in place) on the ability of unitholders of Opco to exchange their Opco Units pursuant to a Redemption Right to the extent we believe it is necessary to ensure that Opco will continue to be treated as a partnership for U.S. federal income tax purposes.

If Opco were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and for Opco. In particular, Opco would pay U.S. federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 21%. Distributions to us would generally be taxed again as corporate distributions. Because a tax would be imposed on Opco as a corporation, the amount of cash distributions to us would be substantially reduced, which may cause a substantial reduction in the value of our Class A common stock.

The underwriters of this offering may release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.

We, our Existing Owners and all of our directors and executive officers have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our Class A common stock for a period of 180 days following the date of this prospectus, Barclays Capital Inc. at any time and without notice, may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. See “Underwriting (Conflicts of Interest)” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the Class A common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital.

Our organizational structure confers certain benefits upon the Opco Unit Holders that will not benefit the holders of our Class A common stock to the same extent as it will benefit the Opco Unit Holders.

Our organizational structure confers certain benefits upon the Opco Unit Holders that will not benefit the holders of our Class A common stock to the same extent as it will benefit the Opco Unit Holders. We will be a holding company and will have no material assets other than our ownership of Opco Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock will be subject to the ability of Opco to provide distributions to us. If Opco makes such distributions, the Opco Unit Holders will be entitled

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to receive equivalent distributions from Opco on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends to holders of our Class A common stock are expected to be less on a per-share basis than the amounts distributed by Opco to our Existing Owners on a per-unit basis. This and other aspects of our organizational structure may adversely impact the future trading market for our Class A common stock.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation will authorize our board of directors to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of a class or series of our preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our Class A common stock.

Certain underwriters have interests in this offering beyond customary underwriting discounts and have conflicts of interest with respect to this offering.

Barclays Bank PLC, Credit Suisse AG, Cayman Islands Branch, Capital One National Association and Royal Bank of Canada, affiliates of Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Capital One Securities Inc. and RBC Capital Markets LLC, underwriters in this offering, are also lenders under the revolving credit facility. Because each of Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Capital One Securities Inc. and RBC Capital Markets LLC is an underwriter and will receive more than 5% of the net proceeds of this offering as a result of our intention to repay borrowings under the revolving credit facility, each of them has a “conflict of interest” under the applicable provisions of Rule 5121 of FINRA. Accordingly, this offering will be made in compliance with the applicable provisions of FINRA Rule 5121 regarding the underwriting of securities of a company with a member that has a conflict of interest within the meaning of that rule. Pursuant to Rule 5121, UBS Securities LLC is serving as the “qualified independent underwriter,” as defined by FINRA. See “Underwriting.” In addition, we have agreed to indemnify for acting as qualified independent underwriter against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that UBS Securities LLC may be required to make for those liabilities.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosure regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We have also elected to use the extended transition period to delay adoption of new or revised accounting pronouncements applicable to public companies until such pronouncements are made applicable to

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private companies. Accordingly, our financial statements may not be comparable to the financial statements of public companies that comply with such new or revised accounting standards. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our Class A common stock to be less attractive as a result, there may be a less active trading market for our Class A common stock and our stock price may be more volatile.

We may become a “controlled company” following this offering. In such event, we would not intend to take advantage of the “controlled company” exemptions to the corporate governance for publicly listed companies but may do so in the future.

Funds affiliated with Kimmeridge will beneficially own, in the aggregate, 49.7% of the voting power of our capital stock following the completion of this offering (assuming the underwriters do not exercise their option to purchase additional shares). If in the future they beneficially own over 50% of the voting power of our capital stock, we may be eligible to elect the “controlled company” exemptions to the corporate governance rules for publicly listed companies. If we are a “controlled company,” we would not be required to have a majority of our board of directors be independent, nor would we be required to have a compensation committee or an independent nominating function. We do not intend to avail ourselves of the exemptions if we become a “controlled company.” However, if we chose to take advantage of controlled company status in the future, our status as a controlled company could cause our Class A common stock to be less attractive to certain investors or otherwise have a material adverse effect on our trading price.

If securities or industry analysts do not publish research or reports or publish unfavorable research about our business, the price and trading volume of our Class A common stock could decline.

The trading market for our Class A common stock will depend in part on the research and reports that securities or industry analysts publish about us or our business. We do not currently have and may never obtain research coverage by securities and industry analysts. If no securities or industry analysts commence coverage of us, the trading price for our Class A common stock and other securities would be negatively affected. In the event we obtain securities or industry analyst coverage, if one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. If one or more of these analysts ceases to cover us or fails to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our Class A common stock and other securities and their trading volume to decline.

General Risk Factors

Increased costs of capital could adversely affect our business.

Our business and ability to make acquisitions could be harmed by factors such as the availability, terms, and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, and place us at a competitive disadvantage. A significant reduction in the availability of capital could materially and adversely affect our ability to achieve our planned growth and operating results.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many crude oil and natural gas companies, we may from time to time be involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal

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injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact, included in this prospectus regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “may,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions and the negative of such words and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus.

The following important factors, in addition to those discussed elsewhere in this prospectus, could affect the future results of the energy industry in general, and our company in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

• our ability to execute on our business strategies;

• the effect of change in commodity prices;

• the level of production on our properties;

• risks associated with the drilling and operation of crude oil and natural gas wells;

• the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;

• legislative or regulatory actions pertaining to hydraulic fracturing, including restrictions on the use of water;

• the availability of pipeline capacity and transportation facilities;

• the effect of existing and future laws and regulatory actions;

• conditions in the capital markets and our ability to obtain capital on favorable terms or at all;

• the overall supply and demand for crude oil and natural gas, and regional supply and demand factors, delays, or interruptions of production;

• operator budget constraints and their ability to obtain capital on favorable terms or at all;

• the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other significant producers and governments and the ability of such producers to agree to and maintain oil price and production controls;

• competition from others in the energy industry;

• global or national health events, including the ongoing outbreak and resulting economic effects of the COVID-19 pandemic;

• the impact of reduced drilling activity in our focus areas and uncertainty in whether development projects will be pursued;

• uncertainty of estimates of crude oil and natural gas reserves and production;

• the cost of developing the crude oil and natural gas underlying our properties;

• our ability to replace our crude oil and natural gas reserves;

• our ability to identify and complete acquisitions;

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• title defects in the properties in which we invest;

• the cost of inflation;

• technological advances;

• weather conditions, natural disasters and other matters beyond our control; and

• general economic, business or industry conditions.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas that are ultimately recovered.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

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USE OF PROCEEDS

We expect to receive approximately $199 million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the Class A common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to contribute all of the net proceeds from this offering to Opco in exchange for Opco Units. Opco will use the net proceeds to (i) repay all $135 million of outstanding borrowings under our revolving credit facility, and (ii) fund future acquisitions of mineral and royalty interests. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds of this offering. The following table illustrates our anticipated use of the net proceeds from this offering:

Sources of Funds			Uses of Funds
(in millions)
Net proceeds from this offering	$	199	Repayment of revolving credit facility borrowings	$	135
		—	Funding of our future mineral and royalty acquisitions		64
Total sources of funds	$	199	Total uses of funds	$	199

Our revolving credit facility has a maturity date of September 26, 2024. The average annual interest rate on borrowings under our original credit facility during the six months ended June 30, 2021 was 2.61%, and such borrowings were incurred primarily to fund acquisition costs. On October 8, 2021, we amended and restated our original credit facility to, among other things, provide for the transactions contemplated by our corporate reorganization and this offering as well as to provide for an increased borrowing base of $150 million. On October 27, 2021, we made a distribution to the Existing Owners of approximately $128 million using borrowings from our revolving credit facility and cash on hand.

A $1.00 increase or decrease in the assumed initial public offering price of $21.50 per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $9.5 million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. Any increase in net proceeds retained by Opco as a result of any increase in the initial public offering price would impact the amount of proceeds that we could use to fund future acquisitions of mineral and royalty interests. Any decrease in proceeds retained by Opco as a result of any decrease in the initial public offering price would first reduce the amount of proceeds that we could use to fund future acquisitions of mineral and royalty interests and then reduce the amount of borrowings under our revolving credit facility we will be able to repay.

If the underwriters exercise in full their option to purchase additional shares of Class A common stock, the additional net proceeds to us would be $30.5 million (assuming the midpoint of the price range set forth on the cover of this prospectus) after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We intend to contribute all of the net proceeds therefrom to Opco in exchange for an additional number of Opco Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Opco will use any such net proceeds to fund future acquisitions of mineral and royalty interests.

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DIVIDEND POLICY

We aim to balance the return of capital to investors with the selective allocation of capital toward acquisitions that we believe will be accretive to shareholder value while preserving a strong balance sheet through varying commodity price environments. In order to effect this approach, we intend to return capital to our shareholders through quarterly dividends, after retaining cash for our working capital needs and acquisition activities. We initially intend to make dividends of a significant portion of our discretionary cash flow, which we define as our Adjusted EBITDA less interest expense and cash taxes. Specifically, following the completion of this offering, we expect that our board of directors will initially target distributing to holders of shares of Class A common stock and Opco Units approximately $65 million on an aggregate annualized basis (or $1.05 per share of Class A common stock and per Opco Unit assuming the underwriters’ option to purchase additional shares of Class A common stock is not exercised).

On an actual basis and pro forma basis, during the year ended December 31, 2020 and, on an actual basis, during the six months ended June 30, 2021, we would not have generated sufficient discretionary cash flow to allow us to make $65 million of aggregate annualized distributions. However, on a pro forma basis, assuming the Chambers Acquisition, the Rock Ridge Acquisition and the Source Acquisition were completed on January 1, 2020, we would have generated sufficient distributable cash flow during the six months ended June 30, 2021 to allow us to make distributions consistent with the aggregate annualized $65 million of distributions we intend to target following the completion of this offering.

While we expect to pay quarterly dividends in accordance with this financial philosophy, we have not adopted a formal written dividend policy to pay a fixed amount of cash each quarter or to pay any particular quarterly amount based on the achievement of, or derivable from, any specific financial metrics, including discretionary cash flow. Specifically, while we initially expect to make distributions of our discretionary cash flow in the targeted amounts described above, the actual amount of any dividends we pay may fluctuate depending on our cash flow needs, which may be impacted by potential acquisition opportunities and the availability of financing alternatives, the need to service our indebtedness or other liquidity needs and general industry and business conditions, including the impact of commodity prices and the pace of the development of our properties by exploration and production companies. Our payment of dividends will be at the sole discretion of our board of directors, which may change our dividend philosophy at any time. Our board of directors will take into account:

• general economic and business conditions;

• our financial condition and operating results;

• our cash flows from operations and current and anticipated cash needs;

• our capital requirements;

• legal, tax, regulatory and contractual restrictions and implications on the payment of dividends by us to our stockholders or by our subsidiaries (including Opco) to us, including any restrictions under our credit agreements; and

• such other factors as our board of directors may deem relevant.

Our board of directors will determine the amount of dividends, if any, that will be paid. However, we will be a holding company and will have no material assets other than our ownership of Opco Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock will be subject to the ability of Opco to provide distributions to us. For information regarding certain restrictions on our ability to pay dividends, please see “Risk Factors—Our ability to pay dividends to our stockholders may be limited by our holding company structure, contractual restrictions and regulatory requirements.” If Opco makes such distributions, the Opco Unit Holders will be entitled to receive equivalent distributions from Opco on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends to holders of our Class A common stock are expected to be less on a per share basis than the amounts distributed by Opco to the Opco Unit Holders on a per unit basis.

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Assuming Opco makes distributions to us and the Opco Unit Holders in any given year, we expect to pay dividends in respect of our Class A common stock out of the portion, if any, of such distributions remaining after our payment of taxes and our expenses (any such portion, an “excess distribution”). However, because our board of directors may determine to pay or not pay dividends in respect of shares of our Class A common stock based on the factors described above, our holders of Class A common stock may not necessarily receive dividend distributions relating to excess distributions, even if Opco makes such distributions to us.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2021:

• on an actual basis for our predecessor; and

• on an as adjusted basis to give effect to (i) the transactions described under “Corporate Reorganization,” (ii) the sale of shares of our Class A common stock in this offering at the assumed initial offering price of $21.50 per share (which is the midpoint of the range set forth on the cover of this prospectus) and (iii) the application of the net proceeds from this offering as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only, assumes no exercise of the option to purchase additional shares of our Class A common stock by the underwriters, and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with “Use of Proceeds” and the financial statements and accompanying notes included elsewhere in this prospectus.

	As of June 30, 2021
	Predecessor(1)		As Adjusted(2)
	(in thousands, except number of shares and par value)
Cash and cash equivalents(3)	$	6,188	$	64,175
Long-term debt, including current maturities:
Revolving credit facility(3)		9,900		—
Total long-term debt	$	9,900	$	—
Temporary equity		—		1,013,852
Permanent equity:
Partners’ capital		593,642		—
Class A common stock ($0.01 par value; no shares authorized, issued or outstanding, actual; 400,000,000 shares authorized, 10,000,000 shares issued and outstanding, as adjusted)		—		100
Class B common stock ($0.001 par value; no shares authorized, issued or outstanding, actual; 250,000,000 shares authorized, 52,000,000 shares issued and outstanding, as adjusted)		—		52
Additional paid-in capital		—		200,740
Noncontrolling interest		298,940		—
Total permanent equity	$	892,582	$	200,892
Total capitalization	$	902,482	$	1,214,744

(1) The data in this table has been derived from the historical consolidated financial statements included in this prospectus which pertain to the assets, liabilities, revenues and expenses of our predecessor.

(2) A $1.00 increase (decrease) in the assumed initial public offering price of $21.50 per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) each of additional paid-in capital, total equity and total capitalization by approximately $9.5 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at an assumed offering price of $21.50 per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) each of additional paid-in capital, total equity and total capitalization each by approximately $20.3 million, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

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(3) On October 8, 2021, we amended and restated our original credit facility to, among other things, increase the borrowing base to $150 million. As of October 22, 2021, the borrowing base was $150.0 million, our outstanding borrowings totaled $11.9 million and our available borrowing capacity was approximately $138.1 million under our revolving credit facility, and we had cash and cash equivalents of $12.7 million. On October 25, 2021, we borrowed an additional $123.1 million under our revolving credit facility to fund a portion of the approximately $128 million distribution we paid to the Existing Owners on October 27, 2021.

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DILUTION

Purchasers of our Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of our Class A common stock for accounting purposes. Our net tangible book value as of June 30, 2021, after giving pro forma effect to the Source Acquisition and our corporate reorganization, was approximately $1,016.0 million, or $19.54 per share of Class A common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of Class A common stock that will be outstanding immediately prior to the closing of this offering including giving effect to the Source Acquisition and our corporate reorganization. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of June 30, 2021 would have been approximately $1,214.7 million, or $19.59 per share of Class A common stock. This represents an immediate increase in the net tangible book value of $0.05 per share of Class A common stock to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $1.91 per share of Class A common stock. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of the shares of our Class B common stock have been cancelled in connection with a redemption of Opco Units for Class A common stock):

Initial public offering price per share			$	21.50
Pro forma net tangible book value per share as of June 30, 2021 (after giving effect to the corporate reorganization)	$	19.54
Increase per share attributable to new investors in this offering	$	0.05
As adjusted pro forma net tangible book value per share (after giving effect to the corporate reorganization and this offering)				19.59
Dilution in pro forma net tangible book value per share to new investors in this offering			$	1.91

A $1.00 increase (decrease) in the assumed initial public offering price of $21.50 per share of Class A common stock, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after this offering by $0.15 and increase (decrease) the dilution to new investors in this offering by $0.85 per share of Class A common stock, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, on an adjusted pro forma basis as of June 30, 2021, the total number of shares of Class A common stock owned by existing stockholders (assuming that 100% of our Class B common stock has been redeemed for Class A common stock) and to be owned by new investors, the total consideration paid, and the average price per share of Class A common stock paid by our existing stockholders and to be paid by new investors in this offering at $21.50, calculated before deduction of estimated underwriting discounts and commissions and estimated offering expenses.

	Shares Purchased					Total Consideration					Average Price Per Share
	Number		Percent			Amount		Percent
						(in millions)
Existing Stockholders		52,000,000		84	%	$	1,014		83	%	$	19.50
New investors		10,000,000		16	%	$	215		17	%	$	21.50
Total		62,000,000		100	%	$	1,229		100	%	$	19.82

The data in the table excludes 6,350,000 shares of Class A common stock initially reserved for issuance under our equity incentive plan.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

Desert Peak Minerals was formed in April 2019 and has limited historical financial and operating results. The following table presents selected historical consolidated financial data of our predecessor and selected pro forma financial data of Desert Peak Minerals for the periods and as of the dates indicated. The selected historical consolidated financial data of our predecessor as of and for the years ended December 31, 2020 and 2019 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary historical unaudited condensed consolidated financial information as of June 30, 2021, and for the six months ended June 30, 2021 and 2020, was derived from the historical unaudited condensed consolidated financial statements of our predecessor included elsewhere in this prospectus. The selected pro forma financial data of Desert Peak Minerals were derived from the unaudited pro forma financial statements included elsewhere in this prospectus.

The selected unaudited pro forma statement of operations for the year ended December 31, 2020 and the six months ended June 30, 2021 has been prepared to give pro forma effect to (i) the Chambers Acquisition, (ii) the Rock Ridge Acquisition, (iii) the Source Acquisition, (iv) the reorganization transactions described under “—Corporate Reorganization” and (v) this offering and the application of the net proceeds therefrom, as if each had been completed on January 1, 2020 (other than the Chambers Acquisition, for which pro forma effect is given as if it occurred on October 1, 2020, the date on which the Chambers ORRI was created). The summary unaudited pro forma balance sheet data as of June 30, 2021 has been prepared to give pro forma effect to (i) the Source Acquisition, (ii) the reorganization transactions described under “Corporate Reorganization” and (iii) this offering and the application of the net proceeds therefrom, as if each had been completed on June 30, 2021. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The selected unaudited pro forma financial data is presented for informational purposes only, should not be considered indicative of actual results of operations that would have been achieved had such transactions been consummated on the dates indicated and does not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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For a detailed discussion of the selected historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and “Corporate Reorganization” and the historical financial statements of our predecessor and the pro forma financial statements of Desert Peak Minerals included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

	Desert Peak Minerals Predecessor Historical												Desert Peak Minerals Pro  Forma
	Six Month Ended June 30,						Year Ended December 31,						Six Month  Ended June 30, 2021			Year Ended December 31, 2020
	2021			2020			2020			2019
							(in thousands)
Statement of Operations Data:
Revenue:
Total Revenue	$	36,719		$	19,711		$	43,126		$	59,680		$	66,651		$	76,534
Operating Expenses:
Management fees to affiliates		3,740			3,740			7,480			7,480			3,740			7,480
Depreciation, depletion and amortization		15,801			15,695			32,049			26,201			29,633			57,163
General and administrative		1,278			5,241			4,981			2,349			2,467			7,629
General and administrative—affiliates		3,217			540			4,407			8,167			3,217			4,407
Production costs, ad valorem taxes and operating expense		2,557			2,007			3,151			5,249			4,076			4,508
Deferred offering costs write off		—			2,742			2,747			—			—			2,747
Impairment of oil and natural gas properties		—			812			812			—			—			64,340
Gain on sale of other property		—			(41	)		(42	)		—			—			—
Bad debt expense (recovered)		—			(181	)		(251	)		405			—			—
Total operating expenses		26,593			30,555			55,334			49,851			43,133			148,274
Net income (loss) from operations		10,126			(10,844	)		(12,208	)		9,829			23,518			(71,740	)
Other income (expense):
Other income		—			—			—			—			—			156
Interest expense (net)(1)		(524	)		(1,185	)		(1,968	)		(868	)		(308	)		(586	)
Net income (loss) before income tax expense		9,602			(12,029	)		(14,176	)		8,961			23,210			(72,170	)
Income tax (expense) benefit		(107	)		(124	)		(38	)		(171	)		(5,041	)		15,675
Net income (loss) including noncontrolling interests		9,495			(12,153	)		(14,214	)		8,790			18,169			(56,495	)
Net income attributable to noncontrolling interests		28			—			—			—			—			—
Net income (loss)	$	9,467		$	(12,153	)	$	(14,214	)	$	8,790		$	18,169		$	(56,495	)
Less: Net income (loss) attributable to temporary equity														15,239			(47,383	)
Net income (loss) attributable to Desert Peak Minerals Inc.													$	2,930		$	(9,112	)
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	23,662		$	16,026		$	26,016		$	34,791
Investing activities	$	(4,306	)	$	(20,359	)	$	(21,557	)	$	(248,627	)
Financing activities	$	(20,699	)	$	(2,022	)	$	(15,061	)	$	221,954
Other Financial Data:
Adjusted EBITDA(2)	$	29,667		$	12,104		$	30,838		$	43,510		$	56,891		$	60,146

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	Desert Peak Minerals Predecessor Historical						Desert Peak Minerals Pro Forma
	As of June 30,		As of December 31,				As of June 30, 2021
	2021		2020		2019
Selected Balance Sheet Data:
Cash and cash equivalents	$	6,188	$	7,531	$	16,507	$	64,175
Total assets		909,548		598,628		631,805		1,220,331
Long-term debt		9,900		33,500		60,000		—
Total liabilities		16,966		36,231		68,194		5,587
Noncontrolling interests		298,940		—		—		—
Temporary equity		—		—		—		1,013,852
Permanent equity		593,642		562,397		563,611		200,892

(1) Interest expense is presented net of interest income.

(2) Adjusted EBITDA is a non-GAAP financial measure. Please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measure” for additional information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Selected Historical and Pro Forma Financial Data”, the audited consolidated financial statements and notes thereto for the year ended December 31, 2020 and 2019 of our predecessor and the interim unaudited condensed consolidated financial statements and notes thereto for the six months ended June 30, 2021 and 2020 presented elsewhere in this prospectus. Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of our predecessor prior to the Corporate Reorganization.

The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to several factors which include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital for mineral acquisitions, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

As of June 30, 2021, we owned mineral and royalty interests representing 75,602 net royalty acres (“NRAs”) when adjusted to a 1/8th royalty. Subsequent to June 30, 2021, we completed additional acquisitions that brought our total amount of NRAs to over 104,000 as of September 30, 2021. For the six months ended June 30, 2021, on a pro forma basis the average net daily production associated with our mineral and royalty interests was 8,946 barrels of oil equivalent per day (“BOE/d”), consisting of 4,706 Bbls/d of oil, 16,173 Mcf/d of natural gas and 1,544 Bbls/d of natural gas liquids (“NGLs”). Since our formation in November 2016, we have accumulated our acreage position by making 177 acquisitions. We expect to continue to grow our acreage position by making acquisitions that meet our investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

Our mineral and royalty interests entitle us to receive a fixed percentage of the revenue from crude oil, natural gas and NGLs produced from the acreage underlying our interests. Unlike owners of working interests in oil and gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production. As a mineral and royalty owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs which reduce the amount of revenue we recognize. For the six months ended June 30, 2021, on a pro forma basis our production and ad valorem taxes were approximately $2.52 per BOE, relative to an average realized price before derivatives of $40.27 per BOE. As a result, our operating margin and cash flows are higher, as a percentage of revenue, than those of traditional E&P companies. We do not anticipate engaging in any activities, other than acquisitions, that will incur capital costs. We believe our cost structure and business model will allow us to return a significant amount of our cash flows to our stockholders.

We have historically had two reportable segments: Oil and Gas Producing Activities and Water Service Operations.

The Oil and Gas Producing Activities segment is comprised of managing our mineral and royalty interests and related revenue streams, which principally consist of royalties from crude oil, natural gas and NGLs producing activities and revenues from lease bonuses, delay rentals and easements. We are not a producer, and our crude oil, natural gas and NGLs revenue is derived from a fixed percentage of the crude oil, natural gas and NGLs produced by E&P operators from the acreage underlying our interests, net of post-production expenses and taxes.

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The Water Service Operations segment is comprised of our water supply assets and revenues. The income of this segment consists of the sale of water to various Permian Basin E&P operators produced from our water supply assets. In connection with the corporate reorganization that will occur in connection with this offering, our predecessor will not contribute the Water Service Operations business or assets to us, and we will have one reportable segment after completion of this offering.

Recent Developments

Acquisitions

As of June 30, 2021, we have evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 175 acquisitions from landowners and other mineral interest owners. We intend to capitalize on our management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in the Delaware Basin designed to increase our cash flows per share. In connection with the market conditions resulting from the COVID-19 pandemic, our acquisition activity saw a significant decline during 2020 but has rebounded in the first half of 2021. See “—COVID-19 Pandemic.”

Production and Operations

Our average daily production during the six months ended June 30, 2021 and 2020 was 5,112 BOE/d (45% crude oil) and 5,909 BOE/d (46% crude oil), respectively. For the six months ended June 30, 2021, we received an average of $59.19 per Bbl of crude oil, $3.22 per Mcf of natural gas and $27.45 per Bbl of NGLs, for an average realized price before derivatives of $38.98 per BOE, and for the six months ended June 30, 2020, we received an average of $35.90 per Bbl of crude oil, $0.81 per Mcf of natural gas and $8.41 per Bbl of NGLs, for an average realized price before derivatives of $19.82 per BOE.

Our average daily production during the years ended December 31, 2020 and 2019 was 5,764 BOE/d (44% crude oil) and 4,793 BOE/d (47% crude oil), respectively. For the year ended December 31, 2020, we received an average of $37.40 per Bbl of crude oil, $1.03 per Mcf of natural gas and $10.32 per Bbl of NGLs, for an average realized price before derivatives of $20.95 per BOE, and for the year ended December 31, 2019, we received an average of $52.90 per Bbl of crude oil, $0.74 per Mcf of natural gas and $13.48 per Bbl of NGLs, for an average realized price before derivatives of $29.09 per BOE.

During the six months ended June 30, 2021, the operators of our mineral interests brought online 92 gross (1.375 net) horizontal wells. Additionally, as of June 30, 2021, there were 266 gross (2.822 net) horizontal wells in various stages of drilling or completion on our acreage. As of June 30, 2021, we had 2,278 gross (27.85 net) horizontal wells producing on our acreage with 106 active drilling permits filed in the preceding six months.

During the year ended December 31, 2020, the operators of our mineral interests brought online 171 gross (1.086 net) horizontal wells. Additionally, as of December 31, 2020, there were 147 gross (1.533 net) horizontal wells in various stages of drilling or completion on our acreage. As of December 31, 2020, we had 1,568 gross (16.0 net) horizontal wells producing on our acreage with 127 active drilling permits filed in the preceding six months. During the year ended December 31, 2019, the operators of our mineral interests brought online 393 gross (4.070 net) horizontal wells. Additionally, as of December 31, 2019, there were 189 gross (1.264 net) horizontal wells in various stages of drilling or completion on our acreage. As of December 31, 2019, we had 1,366 gross (14.570 net) horizontal wells producing on our acreage with 409 active drilling permits filed in the preceding six months.

COVID-19 Pandemic

The outbreak of COVID-19 caused a continuing disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil in 2020. This disruption has somewhat been alleviated in the first half of 2021. In March 2020, Saudi

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Arabia and Russia failed to agree to and maintain oil price and production controls within OPEC and Russia. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at which they sell oil. While OPEC, Russia, and other oil and gas producing countries (“OPEC+”) subsequently agreed to collectively decrease production, these events, combined with the macro-economic impact of the continued outbreak of the COVID-19 pandemic and declining availability of hydrocarbon storage, exacerbated the decline in commodity prices, including the historic, record low price of negative $36.98 per barrel that occurred in April 2020. Since then, OPEC+ and Saudi Arabia have agreed to continued production decreases; however, OPEC+ and Saudi Arabia began easing production cuts starting in May 2021. The decline in commodity prices adversely affected the revenues we received for our mineral and royalty interests and could impact our ability to access capital markets on terms favorable to us. Market volatility has continued, and we expect it will continue for the foreseeable future.

Additionally, many E&P operators of our mineral and royalty interests announced reductions to their capital budgets for 2021 and beyond, which has and will adversely affect the near-term development pace of our properties. However, many operators have resumed or increased drilling and completion activities compared to activity levels in 2020 in connection with the increase in commodity prices in late 2020 and the early months of 2021. In connection with the market and commodity price challenges resulting from the COVID-19 pandemic, our acquisition activity saw a significant decline in 2020 as we experienced a meaningful difference in sellers’ pricing expectations and the prices we were willing to offer for assets. We cannot predict the extent and potential duration of these and other impacts on our business from the COVID-19 pandemic, efforts to fight the pandemic and other market events.

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:

• volumes of oil, natural gas and NGLs produced;

• number of rigs on our acreage and number of producing wells, spud wells and permitted wells;

• commodity prices; and

• Adjusted EBITDA.

Volumes of Oil, Natural Gas and NGLs Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from our mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Number of Rigs on our Acreage, Spud Wells and Permitted Wells

In order to track and assess the performance of our assets, we monitor and analyze the number of rigs currently drilling our properties. We also constantly monitor the number of permitted wells, spud wells, completions, and producing wells on our mineral and royal interests in an effort to evaluate near-term production growth.

Commodity Prices

Historically, oil, natural gas and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a low of negative ($36.98) per barrel in April 2020 to a high of $84.65 per barrel in October 2021. The Henry Hub spot market price for natural gas has

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ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas and NGLs that our operators can produce economically.

Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

Natural Gas. The New York Mercantile Exchange, Inc. (“NYMEX”) price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGLs. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP supplemental financial measure used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard to financing methods, capital structure or historical cost basis.

We define Adjusted EBITDA as net income (loss) including noncontrolling interests plus (i) interest expense, (ii) provisions for taxes, (iii) depreciation, depletion and amortization, (iv) share-based compensation expense, (v) impairment of oil and natural gas properties, (vii) gains or losses on unsettled derivative instruments, (viii) write off of deferred offering costs, and (ix) management fee to affiliates. Adjusted EBITDA is not a measure determined by GAAP.

These non-GAAP financial measures do not represent and should not be considered an alternative to, or more meaningful than, their most directly comparable GAAP financial measures or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA may differ from computations of similarly titled measures of other companies.

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Please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measure” for additional information.

Sources of Revenue

Our revenues are primarily derived from mineral royalty payments received from our E&P operators based on the sale of crude oil, natural gas and NGLs production from our interests. We also include the proceeds or losses from our commodity derivatives in revenue. Our revenues may vary significantly from period to period because of changes in commodity prices, production mix and volumes of production sold by our E&P operators. For the six months ended June 30, 2021 and 2020, mineral and royalty revenue made up 98% and 108%, respectively, of our total revenue. For the years ended December 31, 2020 and 2019, mineral and royalty revenue made up 102% and 85%, respectively, of our total revenue. Mineral and royalty revenues made up more than 100% of our total revenues in 2020 due to the impact of commodity derivative losses on our total revenues. As a result of our royalty income production mix, our income is more sensitive to fluctuations in crude oil prices than it is to fluctuations in natural gas or NGLs prices.

Royalties received related to crude oil sales constituted 69% and 83% of total mineral and royalty revenue for the six months ended June 30, 2021 and 2020, respectively. Royalties received related to crude oil sales constituted 79% and 85% of total mineral and royalty revenue for the years ended December 31, 2020 and 2019, respectively. Crude oil, natural gas and NGL prices have historically been volatile, and we expect this volatility to continue.

Additionally, we earn lease bonus income by leasing our mineral interests to exploration and production companies and income from delay rentals and easements. Lease bonus and other income constituted 2% and 5%, respectively, of our total revenue for the six months ended June 30, 2021 and 2020. Lease bonus and other income constituted 2% and 9%, respectively, of our total revenue for the years ended December 31, 2020 and 2019.

Further, we earned revenue through the provision of water to various Permian Basin E&P operators produced from our water supply assets. For the year ended December 31, 2020, there were no water sales. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. Contingent rental income earned under this arrangement was $205,000 and $0, respectively, for the six months ended June 30, 2021 and 2020. Contingent rental income earned under this arrangement was $13,000 for the year ended December 31, 2020. Water sales were $3.5 million for the year ended December 31, 2019.

Principal Components of Our Cost Structure

The following is a description of the principal components of our cost structure. As a mineral and royalty owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs which reduce the amount of revenue we recognize. Unlike E&P operators and owners of working interests in oil and gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production.

Production and Ad Valorem Taxes

Production taxes are paid at fixed rates on produced crude oil and natural gas based on a percentage of revenues from products sold, established by federal, state or local taxing authorities. The E&P companies who operate on our interests withhold and pay our pro rata share of production taxes on our behalf. We directly pay ad valorem taxes in the counties where our properties are located. Ad valorem taxes are generally based on the appraised value of our crude oil, natural gas and NGLs properties.

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Gathering, Processing and Transportation Costs

Gathering, processing and transportation costs are representative of the costs to process and transport our respective volumes to applicable sales points. The terms of the lease with the applicable E&P operator on our interests determine if the operator is able to pass through these costs to us by deducting a pro rata portion of such costs from our production revenues.

General and Administrative

General and administrative expenses consist of costs incurred related to overhead, including executive and other employee compensation and related benefits, office expenses and fees for professional services such as audit, tax, legal and other consulting services. Some of those costs were incurred on our predecessor’s behalf by our predecessor’s general partner and its affiliates and reimbursed by our predecessor. For example, our predecessor reimburses an affiliate of our predecessor’s general partner for personnel costs relating to the performance of land and administrative services on our predecessor’s behalf. As a result of becoming a public company, we anticipate incurring incremental general and administrative expenses relating to SEC reporting requirements, including annual and quarterly reports, tax return preparation and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A common stock on the NYSE, independent auditor fees, legal expenses and investor relations expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor or the unaudited pro forma financial statements included elsewhere in this prospectus.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of capitalized costs. Under the successful efforts method of accounting, capitalized costs of our proved crude oil, natural gas and NGLs mineral interest properties are depleted on a unit-of-production basis based on proved crude oil, natural gas and NGLs reserve quantities. Our estimates of crude oil, natural gas and NGLs 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. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the rate of depletion related to our crude oil, natural gas and NGLs properties. DD&A also includes the expensing of office leasehold costs and water wells and equipment.

Income Tax Expense

We are subject to the Texas margin tax, which is a state franchise tax. We incurred $0.1 million for the six months ended June 30, 2021 and 2020 for Texas state franchise tax. For the years ended December 31, 2020 and 2019, we incurred $38,000 and $0.2 million, respectively, for state franchise tax payable to the Texas Comptroller of Public Accounts. Our predecessor did not record a provision for U.S. federal income taxes because the partners reported their respective share of our predecessor’s income or loss on their income tax returns. Following the transactions comprising the corporate reorganization described in this prospectus, we will be subject to U.S. federal income taxes as a corporation. We will also continue to be subject to the Texas margin tax as a corporation.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to the historical results of operations of our predecessor, KMF, for the periods presented, primarily for the reasons described below.

Corporate Reorganization

The historical consolidated financial statements included in this prospectus are based on the financial statements of our predecessor prior to our corporate reorganization. Our initial assets will not include KMF’s

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surface rights, which generate revenue from the sale of water, payments for rights-of-way and other rights associated with the ownership of the surface acreage, which are included in our historical financial statements but will be retained by KMF following the closing of this offering. As a result, the historical consolidated financial data may not give you an accurate indication of what our actual results would have been if the corporate reorganization had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

Management Fees

Our predecessor incurred and paid annual fees under an investment management agreement with Kimmeridge Energy Management Company, LLC, an affiliate of Kimmeridge, of which Benjamin P. Dell, a Director Nominee, and Noam Lockshin, our Director, are managing members. Fees incurred under the agreement totaled approximately $3.7 million for the six months ended June 30, 2021 and 2020. Fees incurred under the agreement totaled approximately $7.5 million for the years ended December 31, 2020 and 2019. As a result of the corporate reorganization, we will not incur future expense under the agreement upon completion of this offering. Additionally, certain other expenses associated with the limited partnership structure of our predecessor will not be incurred by us in future periods.

Acquisitions

Our predecessor’s historical financial statements as of and for the years ended December 31, 2020 and 2019 do not include the results of operations for the assets acquired in the Chambers and Rock Ridge Acquisitions. As a result, our predecessor’s historical financial data does not give an accurate indication of what our actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results are likely to be. For additional information, please see the unaudited pro forma condensed financial statements and related notes included elsewhere in this prospectus.

In addition, we plan to pursue potential accretive acquisitions of additional mineral and royalty interests. We believe we will be well positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to pay dividends to our stockholders.

Debt and Interest Expense

Our predecessor had no debt until September 26, 2019, when we established our original credit facility. We intend to repay all of the borrowings outstanding under our revolving credit facility, if any, with a portion of the net proceeds of this offering. As a public company, we may finance a portion of our acquisitions with borrowings under our revolving credit facility. As a result, we will incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

Public Company Expenses

Following the closing of this offering, we anticipate incurring incremental general and administrative expenses as a result of Kimmeridge no longer providing services to us and as a result of operating as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A common stock on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor. Additionally, in anticipation of this offering, we have hired additional employees, including accounting, engineering and legal personnel, in order to prepare for the requirements of being a publicly traded company.

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Income Taxes

We will be subject to U.S. federal and state income taxes as a corporation. Our predecessor, KMF, was generally not subject to U.S. federal income tax at the entity level. As such, the financial statements of our predecessor do not contain a provision for U.S. federal income taxes. The only tax expense that appeared in the financial statements of our predecessor was the Texas margin tax, to which we will continue to be subject as a corporation.

Results of Operations

Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020

Consolidated Results

The following table summarizes our consolidated revenue and expenses and production data for the six months ended June 30, 2021 and 2020 (in thousands):

	For the six months ended June 30,
	2021			2020
Statement of Operations Data:
Revenue:
Total Revenue	$	36,719		$	19,711
Operating Expenses:
Management fees to affiliates	$	3,740		$	3,740
Depreciation, depletion and amortization		15,801			15,695
General and administrative		1,278			5,241
General and administrative—affiliates		3,217			540
Impairment of oil and natural gas properties		—			812
Severance and ad valorem taxes		2,557			2,007
Deferred offering costs write off		—			2,742
Bad debt recovered		—			(181	)
Gain on sale of other property		—			(41	)
Total operating expenses		26,593			30,555
Net income (loss) from operations		10,126			(10,844	)
Interest expense (net)(1)		(524	)		(1,185	)
Net income (loss) before income tax expense		9,602			(12,029	)
Income tax expense		(107	)		(124	)
Net income (loss) including noncontrolling interests		9,495			(12,153	)
Net income attributable to noncontrolling interests		28			—
Net income (loss)	$	9,467		$	(12,153	)

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	For the six months ended June 30,
	2021		2020
Production Data:
Crude oil (Mbbls)		420		491
Natural gas (Mmcf)		1,954		2,039
NGLs (Mbbls)		180		245
Total (BOE)(6:1)		925		1,076
Average daily production (BOE/d)(6:1)		5,112		5,909
Average Realized Prices:
Crude oil (per Bbl)	$	59.19	$	35.90
Natural gas (per Mcf)	$	3.22	$	0.81
NGLs (per Bbl)	$	27.45	$	8.41
Combined (per BOE)	$	38.98	$	19.82
Average Realized Prices After Effects of Derivative Settlements:
Crude oil (per Bbl)	$	59.19	$	35.55
Natural gas (per Mcf)	$	3.22	$	0.81
NGLs (per Bbl)	$	27.45	$	8.41
Combined (per BOE)	$	38.98	$	19.67

(1) Interest expense is presented net of interest income.

Revenue

Our consolidated revenues for the six months ended June 30, 2021 totaled $36.7 million as compared to $19.7 million for the six months ended June 30, 2020, an increase of 86%. The increase in revenues was due to an increase of $14.7 million in mineral and royalty revenue, partially offset by a decrease of $0.4 million in lease bonus and other income, and a commodity derivative loss of $2.6 million in 2020. The increase in mineral and royalty revenue was primarily due to increased commodity prices. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. Contingent rental income earned under this arrangement was $205,000 for the six months ended June 30, 2021. There was no income earned under this arrangement for the six months ended June 30, 2020.

Our Oil and Gas Producing Activities segment generated 99% and 100% of our total revenues for the six months ended June 30, 2021 and 2020, respectively, with our Water Service Operations segment representing the remaining 1% for the six months ended June 30, 2021.

Oil revenue for the six months ended June 30, 2021 was $24.8 million as compared to $17.6 million for the six months ended June 30, 2020, an increase of $7.2 million. An increase of $23.29/Bbl in our average price received for oil production, from $35.90/Bbl for the six month ended June 30, 2020 to $59.19/Bbl for the six months ended June 30, 2021, accounted for an approximate $9.8 million increase in our year-over-year oil revenue, which was partially offset by a $2.6 million decrease in year-over-year oil revenue due to a 14% decrease in oil production volumes, which decreased from 491 Mbbls for the six months ended June 30, 2020 to 420 Mbbls for the six months ended June 30, 2021.

Natural gas revenue for the six months ended June 30, 2021 was $6.3 million as compared to $1.7 million for the six months ended June 30, 2020, an increase of $4.6 million. An increase of $2.41/Mcf in our average price received for gas production, from $0.81/Mcf for the six months ended June 30, 2020 to $3.22/Mcf for the six months ended June 30, 2021, accounted for an approximate $4.7 million increase in our year-over-year gas revenue, which was partially offset by a $0.1 million decrease in year-over-year gas revenue due to a 4%

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decrease in gas production volumes, which decreased from 2,039 MMcf for the six months ended June 30, 2020 to 1,954 MMcf for the six months ended June 30, 2021.

NGLs revenue for the six months ended June 30, 2021 was $4.9 million as compared to $2.0 million for the six months ended June 30, 2020, an increase of $2.9 million. An increase of $19.04/Bbl in our average price received for NGLs production, from $8.41/Bbl for the six months ended June 30, 2020 to $27.45/Bbl for the six months ended June 30, 2021, accounted for an approximate $3.4 million increase in our year-over-year NGLs revenue, which was partially offset by a $0.5 million decrease in year-over-year NGLs revenue due to a 27% decrease in NGLs production volumes, which decreased from 245 MBbls for the six months ended June 30, 2020 to 180 MBbls for the six months ended June 30, 2021.

Lease bonus revenue for the six months ended June 30, 2021 was $86,000 as compared to $507,000 for the six months ended June 30, 2020. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues for the six months ended June 30, 2021 were $564,000 as compared to $524,000 for the six months ended June 30, 2020, which include payments for right-of-way and surface damages, which are also subject to significant variability.

Operating Expenses

Management fees to affiliates expense remained consistent at $3.7 million for the six months ended June 30, 2021 and 2020.

Depreciation, depletion and amortization expense was $15.8 million for the six months ended June 30, 2021 as compared to $15.7 million for the six months ended June 30, 2020, an increase of $0.1 million, or 1%. The increase was primarily due to a higher depletion rate, which increased from $14.30/Boe for the six months ended June 30, 2020 to $16.76/Boe for the six months ended June 30, 2021 due to reserves increasing at a slower rate than our net depletable capitalized costs from June 30, 2020 to June 30, 2021. The higher depletion rate was partially offset by a 14% decrease in year-over-year production.

General and administrative expense was $1.3 million for the six months ended June 30, 2021 as compared to $5.2 million for the six months ended June 30, 2020, a decrease of $3.9 million, or 76%. The decrease was primarily due to decreased personnel costs captured here for the first half of 2021 as noted below and professional services costs.

General and administrative—affiliates expense was $3.2 million for the six months ended June 30, 2021 as compared to $0.5 million for the six months ended June 30, 2020, an increase of $2.7 million, or 496%. The increase was primarily as a result of increased reimbursement of our predecessor’s general partner for services provided on our predecessor’s behalf, including personnel costs and costs relating to the performance of land and administrative services in respect of our acquisition of mineral and royalty interests. These costs were captured in the General and administrative expense line item for the first half of 2020.

On a combined basis, the General and administrative expense and General and administrative expense—affiliates expense was $4.5 million for the six months ended June 30, 2021 as compared to $5.8 million for the six months ended June 30, 2020, a decrease of $1.3 million, or 22%, primarily due to the continuation of cost-saving measures into 2021, which were enacted in mid-2020, in connection with the depressed commodity price environment.

Impairment of oil and gas properties of approximately $0.8 million for the six months ended June 30, 2020 was recognized in connection with capitalized acquisition costs for a prospective mineral interest acquisition that we did not complete.

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Severance and ad valorem taxes was $2.6 million for the six months ended June 30, 2021 as compared to $2.0 million for the six months ended June 30, 2020, an increase of $0.6 million or 27%. The increase was primarily due to an increase in severance taxes in conjunction with the year-over-year increase in commodity prices.

During the six months ended June 30, 2020, we recognized approximately $2.7 million of expense in connection with the temporary postponement of an initial public offering. No such charges were incurred during the six months ended June 30, 2021.

During the six months ended June 30, 2020, we reversed approximately ($0.2) million of bad debt expense due to the collection of accounts receivable of KMF Water for which an allowance had previously been established. No such charges or benefits were recorded during the six months ended June 30, 2021.

Interest expense of approximately $0.5 million and $1.2 million during the six months ended June 30, 2021 and 2020, respectively, relates to interest incurred on borrowings under our revolving credit facility. The decrease in interest expense was due to lower average borrowings under the facility during the six months ended June 30, 2021 as we continued to make payments to reduce the outstanding balance throughout 2020 and into 2021.

Income tax expense primarily relates to state franchise taxes, and totaled approximately $0.1 million for the six months ended June 30, 2021 and 2020.

Segment Results

The following table sets forth certain financial information with respect to our reportable segments (in thousands):

	For the six months ended June 30, 2021
	Oil and Gas Producing Activities			Water Service Operations		Partnership			Consolidated Total
Revenues	$	36,514		$	205	$	—		$	36,719
Depreciation, depletion and amortization		15,658			143		—			15,801
Income tax expense		(107	)		—		—			(107	)
Interest expense		(543	)		—		—			(543	)
Segment profit (loss)		13,279			61		(3,864	)		9,476
Total assets as of June 30, 2021		904,404			3,457		1,687			909,548
Capital expenditures, including mineral acquisitions		1,918			—		—			1,918

A reconciliation of segment profit (loss) to net income is as follows:

Segment profit	$	9,476
Interest income		19
Net income attributable to noncontrolling interests		(28	)
Net income		9,467

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	For the six months ended June 30, 2020
	Oil and Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	19,711		$	—		$	—		$	19,711
Depreciation, depletion and amortization		15,536			159			—			15,695
Income tax expense		(124	)		—			—			(124	)
Interest expense		(1,234	)		—			—			(1,234	)
Segment loss		(8,181	)		(80	)		(3,941	)		(12,202	)
Total assets as of June 30, 2020		605,339			4,435			8,803			618,577
Capital expenditures, including mineral acquisitions		34,657			—			—			34,657

A reconciliation of segment loss to net loss is as follows:

Segment loss	$	(12,202	)
Interest income		49
Net loss		(12,153	)

Oil and Gas Producing Activities

Oil revenue for the six months ended June 30, 2021 was $24.8 million as compared to $17.6 million for the six months ended June 30, 2020, an increase of $7.2 million. An increase of $23.29/Bbl in our average price received for oil production, from $35.90/Bbl for the six months ended June 30, 2020 to $59.19/Bbl for the six months ended June 30, 2021, accounted for an approximate $9.8 million increase in our year-over-year oil revenue, which was partially offset by a $2.6 million decrease in year-over-year oil revenue due to a 14% decrease in oil production volumes, which decreased from 491 Mbbls for the six months ended June 30, 2020 to 420 Mbbls for the six months ended June 30, 2021.

Natural gas revenue for the six months ended June 30, 2021 was $6.3 million as compared to $1.7 million for the six months ended June 30, 2020, an increase of $4.6 million. An increase of $2.41/Mcf in our average price received for gas production, from $0.81/Mcf for the six months ended June 30, 2020 to $3.22/Mcf for the six months ended June 30, 2021, accounted for an approximate $4.7 million increase in our year-over-year gas revenue, which was partially offset by a $0.1 million decrease in year-over-year gas revenue due to a 4% decrease in gas production volumes, which decreased from 2,039 MMcf for the six months ended June 30, 2020 to 1,954 MMcf for the six months ended June 30, 2021.

NGLs revenue for the six months ended June 30, 2021 was $4.9 million as compared to $2.0 million for the six months ended June 30, 2020, an increase of $2.9 million. An increase of $19.04/Bbl in our average price received for NGLs production, from $8.41/Bbl for the six months ended June 30, 2020 to $27.45/Bbl for the six months ended June 30, 2021, accounted for an approximate $3.4 million increase in our year-over-year NGLs revenue, which was partially offset by a $0.5 million decrease in year-over-year NGLs revenue due to a 27% decrease in NGLs production volumes, which decreased from 245 MBbls for the six months ended June 30, 2020 to 180 MBbls for the six months ended June 30, 2021.

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The following table presents the breakdown of our royalty revenues attributable to sales of crude oil, natural gas and NGLs totaling approximately $36.1 million and $21.3 million for the six months ended June 30, 2021 and 2020, respectively:

	Six months ended June 30,
	2021			2020
Royalty Revenue
Crude oil sales		69	%		83	%
Natural gas sales		17	%		7	%
NGLs sales		14	%		10	%
Total Royalty Revenue		100	%		100	%

Our oil and gas producing activities segment revenues are primarily a function of crude oil, natural gas, and NGLs production volumes sold and average prices received for those volumes, each of which can vary significantly from period to period. Despite such variability, we expect our royalty revenues to continue to be primarily attributable to crude oil sales.

Lease bonus and other income, which totaled approximately $0.7 million and $1.0 million for the six months ended June 30, 2021 and 2020, respectively, is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues include payments for right-of-way and surface damages, which are also subject to significant variability.

Commodity derivatives losses totaled $2.6 million for the six months ended June 30, 2020, whereas there were no derivatives gains or losses for the six months ended June 30, 2021. In 2020, we entered into oil fixed price swaps and oil basis swaps to manage commodity price risks associated with our production. In October 2020, we terminated all of our outstanding oil and basis swap derivative contracts. We were not party to any derivative contracts as of June 30, 2021.

Operating expenses for the oil and gas producing activities segment totaled approximately $22.6 million for the six months ended June 30, 2021, and consisted primarily of depreciation, depletion and amortization of $15.7 million, employee compensation and benefits of $3.2 million, general and administrative of $1.1 million, and production and ad valorem taxes of $2.6 million.

Operating expenses for the oil and gas producing activities segment totaled approximately $26.5 million for the six months ended June 30, 2020, and consisted primarily of depreciation, depletion and amortization of $15.5 million, production and ad valorem taxes of $2.0 million, employee compensation and benefits of $3.6 million, general and administrative of $1.9 million, write off of deferred offering costs of $2.7 million, and impairment of unproved oil and gas properties of $0.8 million.

Income tax expense attributable to the oil and gas producing activities segment primarily relate to state franchise taxes, and totaled approximately $107,000 and $124,000 for the six months ended June 30, 2021 and 2020, respectively.

Water Service Operations

For the six months ended June 30, 2020, there were no water sales. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement constitutes a leasing arrangement under which we are a lessor. Under the terms of the agreement, we are not entitled to any income until the lessee has completed a water sale and received payment from its customer. Contingent rental income earned under this arrangement was $205,000 for the six months ended June 30, 2021. There was no income earned under this arrangement for the six months ended June 30, 2020.

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Operating expenses totaled approximately $144,000 and $80,000 for the six months ended June 30, 2021 and 2020, respectively, and consisted primarily of depreciation, depletion and amortization and employee compensation.

Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019

Consolidated Results

The following table summarizes our consolidated revenue and expenses and production data for the years ended December 31, 2020 and 2019 (in thousands):

	For the year ended December 31,
	2020			2019
Statement of Operations Data:
Revenue:
Total Revenue	$	43,126		$	59,680
Operating Expenses:
Management fees to affiliates	$	7,480		$	7,480
Depreciation, depletion and amortization		32,049			26,201
General and administrative		4,981			2,349
General and administrative—affiliates		4,407			8,167
Impairment of oil and natural gas properties		812			—
Production costs, ad valorem taxes and operating expense		3,151			5,249
Deferred offering costs write off		2,747			—
Bad debt expense (recovered)		(251	)		405
Gain on sale of other property		(42	)		—
Total operating expenses		55,334			49,851
Net income (loss) from operations		(12,208	)		9,829
Interest expense (net)(1)		(1,968	)		(868	)
Net income (loss) before income tax expense		(14,176	)		8,961
Income tax expense		(38	)		(171	)
Net income (loss)	$	(14,214	)	$	8,790

	For the year ended December 31,
	2020		2019
Production Data:
Crude oil (Mbbls)		933		816
Natural gas (Mmcf)		4,134		3,237
NGLs (Mbbls)		488		393
Total (BOE)(6:1)		2,110		1,749
Average daily production (BOE/d)(6:1)		5,764		4,793
Average Realized Prices:
Crude oil (per Bbl)	$	37.40	$	52.90
Natural gas (per Mcf)	$	1.03	$	0.74
NGLs (per Bbl)	$	10.32	$	13.48
Combined (per BOE)	$	20.95	$	29.09
Average Realized Prices After Effects of Derivative Settlements:
Crude oil (per Bbl)	$	34.64	$	52.90
Natural gas (per Mcf)	$	1.03	$	0.74
NGLs (per Bbl)	$	10.32	$	13.48
Combined (per BOE)	$	19.73	$	29.09

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(1) Interest expense is presented net of interest income.

Revenue

Our consolidated revenues for the year ended December 31, 2020 totaled $43.1 million as compared to $59.7 million for the year ended December 31, 2019, a decrease of 28%. The decrease in revenues was due to a decrease of $6.7 million in mineral and royalty revenue, a decrease of $3.8 million in lease bonus and other income, a $3.5 million decrease in water sales revenue, and a commodity derivative loss of $2.6 million in 2020. The decrease in mineral and royalty revenue was primarily due to decreased commodity prices. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. For the year ended December 31, 2020, there were no water sales, whereas we generated total water revenues of $3.5 million for the year ended December 31, 2019. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. Contingent rental income earned under this arrangement was $13,000 for the year ended December 31, 2020, as compared to the $3.5 million of water sales revenue for the year ended December 31, 2019, primarily due to a decreased need for water use in drilling and completion operations due to the slowdown in industry activity as a result of the depressed commodity price environment in 2020.

Our Oil and Gas Producing Activities segment generated 100% and 94% of our total revenues for the years ended December 31, 2020 and 2019, respectively, with our Water Service Operations segment representing the remaining 0% and 6%, respectively.

Oil revenue for the year ended December 31, 2020 was $34.9 million as compared to $43.2 million for the year ended December 31, 2019, a decrease of $8.3 million. A decrease of $15.50/Bbl in our average price received for oil production, from $52.90/Bbl for the year ended December 31, 2019 to $37.40/Bbl for the year ended December 31, 2020, accounted for an approximate $14.5 million decrease in our year-over-year oil revenue, which was partially offset by an approximate $6.2 million increase in year-over-year oil revenue due to a 14% increase in oil production volumes, which increased from 816 Mbbls for the year ended December 31, 2019 to 933 Mbbls for the year ended December 31, 2020.

Natural gas revenue for the year ended December 31, 2020 was $4.3 million as compared to $2.4 million for the year ended December 31, 2019, an increase of $1.9 million. A 28% increase in gas production volumes, from 3,238 MMcf for the year ended December 31, 2019 to 4,134 MMcf for the year ended December 31, 2020, accounted for an approximate $0.7 million increase in year-over-year gas revenue and an increase of $0.29/Mcf in our average price received for gas production, from $0.74/Mcf for the year ended December 31, 2019 to $1.03 for the year ended December 31, 2020, accounted for an approximate $1.2 million increase in our year-over-year gas revenue.

NGLs revenue for the year ended December 31, 2020 was $5.0 million as compared to $5.3 million for the year ended December 31, 2019, a decrease of $0.3 million. A decrease of $3.16/Bbl in our average price received for NGLs production, from $13.48/Bbl for the year ended December 31, 2019 to $10.32/Bbl for the year ended December 31, 2020, accounted for an approximate $1.5 million decrease in our year-over-year NGLs revenue, which was partially offset by an approximate $1.2 million increase in year-over-year NGLs revenue due to a 24% increase in NGLs production volumes, which increased from 393 Mbbls for the year ended December 31, 2019 to 488 Mbbls for the year ended December 31, 2020.

Lease bonus revenue for the year ended December 31, 2020 was $742,000 as compared to $2.8 million for the year ended December 31, 2019. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues for the year ended December 31, 2020 was $763,000 as compared to $2.5 million for the year ended December 31, 2019 which include payments for right-of-way and surface damages, which are also subject to significant variability.

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Operating Expenses

Management fees to affiliates expense remained consistent at $7.5 million for the years ended December 31, 2020 and 2019.

Depreciation, depletion and amortization expense was $32.0 million for the year ended December 31, 2020 as compared to $26.2 million for the year ended December 31, 2019, an increase of $5.8 million, or 22%. The increase was primarily due to a 21% increase in year-over-year production with the remaining 1% increase due to a higher depletion rate, which increased from $14.68/Boe for the year ended December 31, 2019 to $14.90/Boe for the year ended December 31, 2020 due to reserves decreasing at a higher rate than our net depletable capitalized costs from December 31, 2019 to December 31, 2020.

General and administrative expense was $5.0 million for the year ended December 31, 2020 as compared to $2.3 million for the year ended December 31, 2019, an increase of $2.7 million, or 112%. The increase was primarily due to increased personnel costs captured here for the first half of 2020 as noted below and professional services costs.

General and administrative—affiliates expense was $4.4 million for the year ended December 31, 2020 as compared to $8.2 million for the year ended December 31, 2019, a decrease of $3.8 million, or 46%. The decrease was primarily as a result of decreased reimbursement of our predecessor’s general partner for services provided on our predecessor’s behalf, including personnel costs and costs relating to the performance of land and administrative services in respect of our acquisition of additional mineral and royalty interests. These costs were captured in the General and administrative expense line item for the first half of 2020. On a combined basis, the General and administrative expense and General and administrative expense—affiliates expense was $9.4 million for the year ended December 31, 2020 as compared to $10.5 million for the year ended December 31, 2019, a decrease of $1.1 million, or 11%, primarily due to decreased employee compensation and other cost-saving measures enacted in 2020 in connection with the depressed commodity price environment.

Impairment of oil and gas properties of approximately $0.8 million during the year ended December 31, 2020 was recognized in connection with capitalized acquisition costs for a prospective mineral interest acquisition that we did not complete.

Production costs, ad valorem taxes and operating expense was $3.2 million for the year ended December 31, 2020 as compared to $5.2 million for the year ended December 31, 2019, a decrease of $2.0 million or 40%. The decrease was primarily due to decreased operating expense for the water service operations segment, which was primarily due to a decreased need for water use in drilling and completion operations due to the slowdown in industry activity as a result of the depressed commodity price environment in 2020.

During the year ended December 31, 2020, we recognized approximately $2.7 million of expense in connection with the temporary postponement of an initial public offering. No such charges were incurred during the year ended December 31, 2019.

During the year ended December 31, 2020, we reversed approximately ($0.3) million of bad debt expense due to the collection of accounts receivable of KMF Water for which an allowance had previously been established. During the year ended December 31, 2019, we recognized approximately $0.4 million of bad debt expense associated with accounts receivable for KMF Water which we no longer believed were collectible.

Interest expense of approximately $2.0 million and $0.9 million during the years ended December 31, 2020 and 2019, respectively, relates to interest incurred on borrowings under our original credit facility. The increase in interest expense is primarily due to borrowings outstanding under our original credit facility for all of 2020, whereas we had no outstanding borrowings in 2019 until our entry into the original credit facility on September 26, 2019.

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Income tax expense primarily relates to state franchise taxes, and totaled approximately $38,000 and $0.2 million for the years ended December 31, 2020 and 2019, respectively.

Segment Results

The following table sets forth certain financial information with respect to our reportable segments (in thousands):

	For the year ended December 31, 2020
	Oil and Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	43,113		$	13		$	—		$	43,126
Depreciation, depletion and amortization		31,746			303			—			32,049
Income tax expense		(38	)		—			—			(38	)
Interest expense		(2,021	)		—			—			(2,021	)
Segment loss		(6,253	)		(165	)		(7,849	)		(14,267	)
Total assets as of December 31, 2020		591,140			3,602			3,886			598,628
Capital expenditures, including mineral acquisitions		35,836			—			—			35,836

A reconciliation of segment profit (loss) to net income is as follows:

Segment loss	$	(14,267	)
Interest income		53
Net loss		(14,214	)

	For the year ended December 31, 2019
	Oil and Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	56,205		$	3,475		$	—		$	59,680
Depreciation, depletion and amortization		25,730			471			—			26,201
Income tax (expense) benefit		(166	)		3			(8	)		(171	)
Interest expense		(1,099	)		(10	)		—			(1,109	)
Segment profit (loss)		19,559			537			(11,547	)		8,549
Total assets as of December 31, 2019		608,170			5,445			18,190			631,805
Capital expenditures, including mineral acquisitions		266,942			637			—			267,579

A reconciliation of segment profit (loss) to net income is as follows:

Segment profit	$	8,549
Interest income		241
Net income		8,790

Oil and Gas Producing Activities

Oil revenue for the year ended December 31, 2020 was $34.9 million as compared to $43.2 million for the year ended December 31, 2019, a decrease of $8.3 million. A decrease of $15.50/Bbl in our average price received for oil production, from $52.90/Bbl for the year ended December 31, 2019 to $37.40/Bbl for the year ended December 31, 2020, accounted for an approximate $14.5 million decrease in our year-over-year oil revenue, which was partially offset by an approximate $6.2 million increase in year-over-year oil revenue due to a 14% increase in oil production volumes, which increased from 816 Mbbls for the year ended December 31, 2019 to 933 Mbbls for the year ended December 31, 2020.

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Natural gas revenue for the year ended December 31, 2020 was $4.3 million as compared to $2.4 million for the year ended December 31, 2019, an increase of $1.9 million. A 28% increase in gas production volumes, from 3,238 Mmcf for the year ended December 31, 2019 to 4,134 Mcf for the year ended December 31, 2020, accounted for an approximate $0.7 million increase in year-over-year gas revenue and an increase of $0.29/Mcf in our average price received for gas production, from $0.74/Mcf for the year ended December 31, 2019 to $1.03 for the year ended December 31, 2020, accounted for an approximate $1.2 million increase in our year-over-year gas revenue.

NGLs revenue for the year ended December 31, 2020 was $5.0 million as compared to $5.3 million for the year ended December 31, 2019, a decrease of $0.3 million. A decrease of $3.16/Bbl in our average price received for NGLs production, from $13.48/Bbl for the year ended December 31, 2019 to $10.32/Bbl for the year ended December 31, 2020, accounted for an approximate $1.5 million decrease in our year-over-year NGLs revenue, which was partially offset by an approximate $1.2 million increase in year-over-year NGLs revenue due to a 24% increase in NGLs production volumes, which increased from 393 Mbbls for the year ended December 31, 2019 to 488 Mbbls for the year ended December 31, 2020.

The following table presents the breakdown of our royalty revenues attributable to sales of crude oil, natural gas and NGLs totaling approximately $44.2 million and $50.9 million for the years ended December 31, 2020 and 2019, respectively:

	Year ended December 31,
	2020			2019
Royalty Revenue
Crude oil sales		79	%		85	%
Natural gas sales		10	%		5	%
NGLs sales		11	%		10	%
Total Royalty Revenue		100	%		100	%

Our oil and gas producing activities segment revenues are primarily a function of crude oil, natural gas, and NGLs production volumes sold and average prices received for those volumes, each of which can vary significantly from period to period. Despite such variability, we expect our royalty revenues to continue to be primarily attributable to crude oil sales.

Lease bonus and other income, which totaled approximately $1.5 million and $5.3 million for the years ended December 31, 2020 and 2019, respectively, is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues include payments for right-of-way and surface damages, which are also subject to significant variability.

Commodity derivatives losses totaled $2.6 million for the year ended December 31, 2020, whereas there were no derivatives gains or losses for the year ended December 31, 2019. In 2020, we entered into oil fixed price swaps and oil basis swaps to manage commodity price risks associated with our production. In October 2020, we terminated all of our outstanding oil and basis swap derivative contracts. We were not party to any derivative contracts as of December 31, 2020.

Operating expenses for the oil and gas producing activities segment totaled approximately $47.3 million for the year ended December 31, 2020, and consisted primarily of depreciation, depletion and amortization of $31.7 million, employee compensation and benefits of $6.1 million, general and administrative of $2.8 million, write off of deferred offering costs of $2.7 million, impairment of unproved oil and gas properties of $0.8 million, and production and ad valorem taxes of $3.2 million.

Operating expenses for the oil and gas producing activities segment totaled approximately $35.4 million for the year ended December 31, 2019, and consisted primarily of depreciation, depletion and amortization of

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$25.7 million, production and ad valorem taxes of $3.8 million, employee compensation and benefits of $5.7 million, and general and administrative of $0.1 million.

Income tax expense attributable to the oil and gas producing activities segment primarily relate to state franchise taxes, and totaled approximately $38,000 and $0.2 million for the years ended December 31, 2020 and 2019, respectively.

Water Service Operations

For the year ended December 31, 2020, there were no water sales. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement constitutes a leasing arrangement under which we are a lessor. Under the terms of the agreement, we are not entitled to any income until the lessee has completed a water sale and received payment from its customer. Contingent rental income earned under this arrangement was $13,000 for the year ended December 31, 2020. For the year ended December 31, 2019, we sold approximately 6.2 million Bbls of water, generating revenue totaling approximately $3.5 million, or $0.56/Bbl. The decrease in overall income from the Water Service Operations segment was primarily due to a decreased need for water use in drilling and completion operations due to the slowdown in industry activity as a result of the depressed commodity price environment in 2020.

Operating expenses totaled approximately $0.2 million and $2.9 million for the years ended December 31, 2020 and 2019, respectively, and consisted primarily of gathering and hauling costs, electricity and fuel, depreciation, depletion and amortization and employee compensation.

Liquidity and Capital Resources

Overview

Prior to the completion of this offering, our primary sources of liquidity have been contributions of capital from our limited partners, cash flows from operations and borrowings under our revolving credit facility. Subsequent to the completion of this offering, our sources of liquidity will be cash flows from operations, borrowings under our revolving credit facility and proceeds from any primary issuances of equity securities. Future sources of liquidity may also include other credit facilities we may enter into in the future and additional issuances of debt or equity securities. Our primary uses of cash have been, and are expected to continue to be, the acquisition of mineral and royalty interests. We also expect to pay dividends to our stockholders. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, legislative, regulatory and other factors.

We believe that proceeds from this offering, internally generated cash flows from operations, available borrowing capacity under our revolving credit facility, and access to capital markets will provide us with sufficient liquidity and financial flexibility to continue to acquire attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. As an owner of mineral and royalty interests, we incur the initial cost to acquire our interests but thereafter do not incur any development or maintenance capital expenditures, which are entirely borne by the E&P operator and the other working interest owners. As a result, our only capital expenditures are related to our acquisition of additional mineral and royalty interests, and we have no other capital expenditure requirements. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities and our ability to integrate acquisitions. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather general economic, financial and competitive, legislative, regulatory and other factors. If we require additional

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capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us.

As of June 30, 2021, our liquidity was $108.8 million, comprised of $6.2 million of cash and cash equivalents, $65.1 million of revolving credit facility availability and $37.5 million of unused capital commitments.

Cash Flows Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020 (in thousands):

	For the Six Months Ended June 30,
	2021			2020
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	23,662		$	16,026
Investing activities		(4,306	)		(20,359	)
Financing activities		(20,699	)		(2,022	)
Net decrease in cash	$	(1,343	)	$	(6,355	)

Operating Activities

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators and timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the six months ended June 30, 2021 were $23.7 million as compared to $16.0 million for the six months ended June 30, 2020, primarily as a result of increases in realized prices from our oil and gas producing activities segment.

Investing Activities

Cash flows used in investing activities totaled $4.3 million for the six months ended June 30, 2021 as compared to $20.4 million for the six months ended June 30, 2020, a decrease of $16.1 million. Our expenditures for crude oil and gas properties and proceeds from sale of oil and gas properties decreased by $32.6 million and $14.3 million, respectively, in 2021 as compared to 2020. Although we completed several acquisitions during the six months ended June 30, 2021, the two largest acquisitions were completed through the issuance of equity in one of our consolidated subsidiaries with no cash consideration provided. The properties acquired through these acquisitions increased the balance of our oil and gas properties by $319.2 million. See our unaudited condensed consolidated financial statements for the six months ended June 30, 2021 and 2020 included elsewhere in this prospectus for additional information. During the six months ended June 30, 2021, we made an advance deposit of $2.3 million for an acquisition of crude oil and gas properties, which was reclassified to oil and gas properties upon completion of the acquisition in July 2021.

Financing Activities

Cash flows used in financing activities for the six months ended June 30, 2021 totaled $20.7 million as compared to $2.0 million for the six months ended June 30, 2020, an increase of $18.7 million. Capital contributions from our partners totaled $13.0 million during the six months ended June 30, 2020, which were primarily used for the acquisition of mineral and royalty interests. During the six months ended June 30, 2021,

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we received $1.5 million of partners’ capital contributions in advance of their due date, which were recorded as liabilities as of June 30, 2021. Borrowings on our credit facility for the six months ended June 30, 2020 totaled $10.0 million, which were also used for the acquisition of mineral and royalty interests. There were no additional borrowings on our original credit facility during the six months ended June 30, 2021. Repayments on our original credit facility for the six months ended June 30, 2021 and 2020 were $23.6 million and $24.5 million, respectively, largely provided by cash flows from operations as well as the sale of certain properties to another mineral owner during the six months ended June 30, 2020.

Cash Flows Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019 (in thousands):

	For the Year Ended December 31,
	2020			2019
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	26,016		$	34,791
Investing activities		(21,557	)		(248,627	)
Financing activities		(15,061	)		221,954
Net (decrease) increase in cash	$	(10,602	)	$	8,118

Operating Activities

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators and timeliness and accuracy of payments from our E&P operators. Additionally, revenues and operating expenses within our Water Service Operations segment are subject to significant variability due to fluctuations in market pricing, demand and competition. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2020 were $26.0 million as compared to $34.8 million for the year ended December 31, 2019, primarily as a result of decreases in realized prices from our oil and gas producing activities segment as well as $2.6 million of commodity derivative losses incurred for the year ended December 31, 2020.

Investing Activities

Cash flows used in investing activities totaled $21.6 million for the year ended December 31, 2020 as compared to $248.6 million for the year ended December 31, 2019, a decrease of $227.0 million. Our expenditures for crude oil and gas properties and proceeds from sale of oil and gas properties decreased by $231.0 million and $8.0 million respectively in 2020 as compared to 2019. Although we continued to evaluate and pursue acquisitions of attractive mineral and royalty interests during 2020, we were unable to reach agreeable terms, which resulted in a significant decline in our acquisition activity. During the year ended December 31, 2019, we placed $3.1 million in an escrow account for an acquisition of crude oil and gas properties, which was reclassified to oil and gas properties during the year ended December 31, 2020.

Financing Activities

Cash flows used in financing activities for the year ended December 31, 2020 totaled $15.1 million as compared to cash flows provided by financing activities for the year ended December 31, 2019 of $222.0 million. Capital contributions from our partners totaled $13.0 million and $164.7 million for the years ended December 31, 2020 and 2019, respectively, which were primarily used for the acquisition of mineral and royalty interests. Borrowings on our credit facility for the years ended December 31, 2020 and 2019 totaled

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$10.0 million and $60.0 million, respectively, which were also used for the acquisition of mineral and royalty interests. Credit facility borrowings during the year ended December 31, 2020 were offset by repayments of $36.5 million, largely provided by cash flows from operations as well as the sale of certain properties to another mineral owner. There were no repayments on our credit facility during the year ended December 31, 2019.

Our Revolving Credit Facility

KMF Land, LLC (“KMF Land”), an indirect subsidiary of KMF that will become a wholly owned direct subsidiary of Opco in connection with this offering, entered into a $750 million revolving credit facility on September 26, 2019 (as amended, restated, amended and restated, or otherwise modified prior to October 8, 2021, the “original credit facility”). As of June 30, 2021, the stated principal amount of outstanding borrowings under the original credit facility was $9.9 million. On October 8, 2021, KMF amended and restated the original credit facility (as so amended and restated, the “revolving credit facility”) to, among other things, provide for the transactions contemplated by our corporate reorganization and this offering as well as to provide for an increased borrowing base. The revolving credit facility is available for working capital, acquisitions and general company purposes and is secured by substantially all of the assets of KMF Land, its direct parent and its subsidiaries. The current borrowing base under the revolving credit facility is $150 million and any outstanding borrowings are expected to be repaid in full with the proceeds of this offering. The revolving credit facility matures on September 26, 2024 and the borrowings thereunder bear interest at, in the case of base rate borrowings, a base rate plus an applicable margin ranging from 1.50% to 2.50% and, in the case of Eurodollar rate borrowings, at LIBOR plus an applicable margin ranging from 2.50% to 3.50%, in each case as determined based on the borrowing base utilization percentage. Our revolving credit facility contains certain customary representations and warranties and various covenants and restrictive provisions that limit KMF Land’s, its direct parent’s and its subsidiaries’ ability to, among other things:

• incur or guarantee additional debt;

• pay dividends on, or redeem or repurchase, their equity interests, return capital to the holders of their equity interests, or make other distributions to holders of their equity interests;

• enter into certain swap arrangements;

• make certain investments and acquisitions;

• incur certain liens or permit them to exist;

• enter into certain types of transactions with affiliates;

• merge or consolidate with another company;

• transfer, sell or otherwise dispose of assets;

• enter into certain other lines of business; and

• repay or redeem certain debt.

In addition, our revolving credit facility restricts KMF Land’s, its direct parent’s and its subsidiaries’ ability to make distributions on, or redeem or repurchase, their equity interests, except for, among other things, distributions if (i) such distribution is paid within 30 days after the date of declaration thereof, (ii) as of the date of such declaration, if such distribution had been paid as of such date of declaration, both immediately before, and immediately after giving pro forma effect to, any such distribution, (A) no event of default would have occurred and be continuing under the revolving credit facility, (B) no borrowing base deficiency exists or would exist under the revolving credit facility, (C) liquidity (e.g, the sum of unused commitments under the revolving credit facility as of such date plus the aggregate amount of unrestricted cash as of such date minus the amount of any borrowing base deficiency on such date) (x) until the date that is seven days after the public filing of this prospectus with the SEC, of at least 25% of the total commitments (e.g., the lesser of the maximum credit amount of each lender, the aggregate elected commitments and the then effective borrowing base) under the Existing Credit Agreement and (y) thereafter, of at least 10% of the total commitments (e.g, the lesser of the

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maximum credit amount of each lender, the aggregate elected commitments and the then effective borrowing base) under the revolving credit facility and (iii) the leverage ratio would not exceed 3.00 to 1.00 after giving effect to such distribution as of the date of such declaration. Our revolving credit facility also requires KMF Land, its direct parent and its subsidiaries to maintain certain financial covenants.

Our revolving credit facility also contains events of default customary for credit facilities of this nature, including, but not limited, to:

• events of default resulting from KMF Land’s, its parent’s or its subsidiaries’ failure to comply with any applicable covenants and financial ratios;

• the occurrence of a change of control;

• the institution of bankruptcy, insolvency or similar proceedings against us, KMF Land its parent or its subsidiaries; and

• a cross-default to certain other material debt of us, KMF Land, its parent and its subsidiaries.

Upon the occurrence and during the continuation of an event of default, subject to the terms and conditions of our revolving credit facility, lenders will be able to declare any outstanding principal balance of our revolving credit facility, together with accrued and unpaid interest, to be immediately due and payable and exercise other remedies.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules related to the implementation of Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, systems, processes and procedures.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.

New and Revised Financial Accounting Standards

Refer to “Recent Accounting Pronouncements” in Note 2, “Basis of Presentation and Summary of Significant Accounting Policies” to our audited consolidated financial statements for the years ended December 31, 2020 and 2019, and in Note 2 included elsewhere in this prospectus for a discussion of recent accounting pronouncements.

We qualify as an “emerging growth company” under the provisions of the JOBS Act, enacted on April 5, 2012, which allows us to have an extended transition period for complying with new or revised accounting standards pursuant to Section 107(b) of the JOBS Act. We are choosing to take advantage of this extended transition period and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

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Critical Accounting Policies and Related Estimates

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations.

We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. There can be no assurance that actual results will not differ from those estimates and assumptions. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this prospectus.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Changes in estimates are accounted for prospectively.

Our estimates and classification 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. 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. These factors and assumptions include 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. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas and estimates of the future net cash flows may vary substantially.

Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of our oil and natural gas properties and/or the rate of depletion related to oil and natural gas properties.

Oil and Gas Properties

We use the successful efforts method of accounting for oil and natural gas producing properties, as further defined under ASC 932, Extractive Activities - Oil and Natural Gas. Under this method, costs to acquire mineral interests in oil and natural gas properties are capitalized. The costs of non-producing mineral interests and associated acquisition costs are capitalized as unproved properties pending the results of leasing efforts and drilling activities of E&P operators on our interests. As unproved properties are determined to have proved reserves, the related costs are transferred to proved oil and gas properties. Capitalized costs for proved oil and natural gas mineral interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved oil and gas properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions.

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Impairment of Oil and Gas Properties

We evaluate our producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Unproved oil and gas properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed based on when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include but are not limited to commodity price outlooks, current and future operator activity in the Delaware Basin, and analysis of recent mineral transactions in the surrounding area.

Crude Oil, Natural Gas and NGLs Reserve Quantities and Standardized Measure of Oil and Gas

Our estimates of crude oil, natural gas and NGLs reserves and associated future net cash flows are prepared by our independent reservoir engineers. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGLs reserves. Crude oil, natural gas and NGLs reserve engineering is a process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify positive or negative revisions of reserve estimates.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGL, less production taxes and post-production expenses. The prices of oil, natural gas, and NGL from the properties in which we own a mineral or royalty interest are primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no working interest or operational control over the volumes and methods of sale of the oil, natural gas, and NGL produced and sold from our properties. We do not explore, develop, or operate the properties and, accordingly, do not incur any of the associated costs.

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Oil, natural gas, and NGL revenues from our mineral and royalty interests are recognized when control transfers at the wellhead.

Water sales for the year ended December 31, 2019 were recognized when control of the water was transferred to an E&P operator and collectability was reasonably assured. In April 2020, we entered into an agreement with a third-party water services company to manage our water assets and operations. The agreement constitutes a leasing arrangement under which we are a lessor. Under the terms of the agreement, we are not entitled to any income until the lessee has completed a water sale and received payment from its customer.

We also earn revenue related to lease bonuses by leasing our mineral interests to E&P companies. We recognize lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible. We do not accrue this contingent rental income until the lessee has received payment.

Temporary Equity

We will account for the Existing Owners’ 84% interest in Opco as temporary equity as a result of certain redemption rights held by the Existing Owners as discussed in “Certain Relationships and Related Party Transactions—Opco LLC Agreement.” As such, we will adjust temporary equity to its maximum redemption amount at the balance sheet date, if higher than the carrying amount. The redemption amount is based on the ten-day volume-weighted average closing price of shares of Class A common stock at the end of the reporting period. We expect changes in the redemption value to be recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to additional paid-in capital.

Off Balance Sheet Arrangements

As of June 30, 2021, we did not have any off-balance sheet arrangements other than an operating lease for office space. Please see Note 10 to our interim unaudited condensed consolidated financial statements for the six months ended June 30, 2021 and 2020 included elsewhere in this prospectus for our commitment under this agreement.

Contractual Obligations

As of June 30, 2021, we did not have any long-term debt, capital lease obligations, operating lease obligations or long-term liabilities, other than borrowings under our original credit facility, an operating lease agreement for office space, and an obligation to pay Kimmeridge an annual fee under an investment management agreement. Please see “—Our Revolving Credit Facility” for a description of our revolving credit facility, and Note 10 to our interim unaudited condensed consolidated financial statements for the six months ended June 30, 2021 and 2020 included elsewhere in this prospectus for our contractual obligations under the office lease agreement. Fees incurred under the management services arrangement totaled approximately $3.7 million for the six months ended June 30, 2021 and 2020. We do not expect to incur future expense under the management services arrangement following the completion of this offering.

As of December 31, 2020, we did not have any long-term debt, capital lease obligations, operating lease obligations or long-term liabilities, other than borrowings under our original credit facility, an operating lease agreement for office space, and an agreement to pay Kimmeridge an annual fee under a management services arrangement for, among other things, administrative support. Fees incurred under the agreement totaled $7.5 million for the years ended December 31, 2020 and 2019.

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Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the crude oil, natural gas and NGLs production of our E&P operators, which affects the royalty payments we receive from our E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil, natural gas and NGLs production has been volatile historically and we expect this volatility to continue in the future. The prices that our E&P operators receive for production depend on many factors outside of our or their control.

A $1.00 per Bbl change in our realized oil price would have resulted in a $0.4 million change in our oil revenues for the six months ended June 30, 2021. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.2 million change in our natural gas revenues for the six months ended June 30, 2021. A $1.00 per Bbl change in NGL prices would have resulted in a $0.2 million change in our NGL revenues for the six months ended June 30, 2021. Royalties on oil sales contributed 69% of our mineral and royalty revenues for the six months ended June 30, 2021. Royalties on natural gas sales contributed 17% and royalties on NGL sales contributed 14% of our total mineral and royalty revenues for the six months ended June 30, 2021.

A $1.00 per Bbl change in our realized oil price would have resulted in a $0.9 million change in our oil revenues for the year ended December 31, 2020. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.4 million change in our natural gas revenues for the year ended December 31, 2020. A $1.00 per Bbl change in NGL prices would have resulted in a $0.5 million change in our NGL revenues for the year ended December 31, 2020. Royalties on oil sales contributed 79% of our mineral and royalty revenues for the year ended December 31, 2020. Royalties on natural gas sales contributed 10% and royalties on NGL sales contributed 11% of our total mineral and royalty revenues for the year ended December 31, 2020.

Credit Risk

The collectability of our royalty revenue is dependent upon the financial condition of our E&P operators, as well as general economic conditions in the industry.

For the six months ended June 30, 2021, in the Oil and Gas Producing Activities segment, revenue from Diamondback Energy, Inc and Oxy USA Inc represented approximately 15% and 10% of total revenue, respectively. These figures are the same as total revenues due to the fact that revenues attributable to the Water Services Operations segment for the six months ended June 30, 2021 were de minimis.

For the year ended December 31, 2020, in the Oil and Gas Producing Activities segment, revenue from Diamondback Energy, Inc, Cimarex Energy, and Oxy USA Inc represented approximately 15%, 12% and 10% of total revenue, respectively. These figures are the same as total revenues due to the fact that revenues attributable to the Water Services Operations segment for the year ended December 31, 2020 were de minimis.

For the year ended December 31, 2019, in the Oil and Gas Producing Activities segment, revenue from Cimarex Energy, Oxy USA Inc and PDC Energy represented approximately 16%, 10% and 10% of total revenue, respectively. In the Water Services Operations segment PDC Energy, WPX Energy, Oxy USA Inc. and BTA Oil Producers represented 37%, 24%, 20% and 16% of total revenue, respectively. Combining both the Water Services Operations and Oil and Gas Producing Activities segments, Cimarex Energy, PDC Energy, and Oxy USA Inc represented approximately 15%, 12% and 11% of total revenue, respectively.

Although we are exposed to a concentration of credit risk, we do not believe the loss of any single purchaser would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. If multiple purchasers were to cease making purchases at or

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around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving our E&P operators have stipulated that royalty owners must still be paid for oil, gas and NGLs extracted from their mineral acreage during the bankruptcy process. In light of this, we do not expect the entry of one of our operators into bankruptcy proceedings to materially affect our operating results.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our revolving credit facility, which has a floating interest rate. The average annual interest rate incurred on our borrowings under the original credit facility during the six months ended June 30, 2021 was 2.61%. We estimate that an increase of 1.0% in the average interest rate during the six months ended June 30, 2021 would have resulted in an approximately $0.1 million increase in interest expense. The average annual interest rate incurred on our borrowings under the original credit facility during the year ended December 31, 2020 was 3.35%. We estimate that an increase of 1.0% in the average interest rate during the year ended December 31, 2020 would have resulted in an approximately $0.5 million increase in interest expense.

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BUSINESS

Overview

We acquire, own and manage mineral and royalty interests in the Permian Basin with the objective of generating cash flow from operations that can be distributed to shareholders as dividends and reinvested to expand our base of cash flow generating assets. Our assets are exclusively focused in the Permian Basin. We benefit from cash flow growth through continued development of our mineral and royalty interests, free of capital costs and lease operating expenses. As of June 30, 2021, we owned mineral and royalty interests representing 75,602 NRAs when adjusted to a 1/8^th royalty. Subsequent to June 30, 2021, we completed additional acquisitions that brought our total amount of NRAs to over 104,000 as of September 30, 2021. For the six months ended June 30, 2021, on a pro forma basis the average net daily production associated with our mineral and royalty interests was 8,946 BOE/d consisting of 4,706 Bbls/d of oil, 16,173 Mcf/d of natural gas and 1,544 Bbls/d of NGLs. For the month of September 2021, the average net daily production associated with our mineral and royalty interests was 9,189 BOE/d, consisting of 4,685 Bbls/d of oil, 16,851 Mcf/d of natural gas and 1,695 Bbls/d of NGLs. September 2021 production reflects the actual production of our predecessor, which includes production attributable to the assets acquired in each of the Chambers Acquisition, the Rock Ridge Acquisition, the Source Acquisition, the Recent Acquisitions and the July 2021 Acquisition for the full month. Since our formation in November 2016, we have accumulated our acreage position by making 177 acquisitions. We expect to continue to grow our acreage position by making acquisitions that meet our investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

As of June 30, 2021, approximately 99% of our NRAs were located in West Texas where there are no federal lands, which means that operators on our acreage are not subject to leasing, permitting, or easement authority from the federal government. The remaining 1% of our NRAs are located in southeastern New Mexico. We believe the Permian Basin offers some of the most compelling rates of return for oil and gas E&P companies and significant potential for mineral and royalty income growth. As a result of these compelling rates of return, development activity in the Permian Basin has outpaced all other onshore U.S. oil and gas basins since the end of 2016. This development activity has driven basin-level production to grow faster than production in the rest of the United States. The following tables show the average daily production according to Wood Mackenzie and total number of horizontal well spuds according to Enverus, respectively, in the Delaware Basin and the Midland Basin compared to the Eagle Ford, SCOOP / STACK, Bakken and DJ Basin during 2016 and 2020, respectively.

Our mineral and royalty interests entitle us to receive a fixed percentage of the revenue from crude oil, natural gas and NGLs produced from the acreage underlying our interests. Unlike owners of working interests in oil and gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production. As a mineral and royalty owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs. Accordingly, our business generates strong margins, requires very low overhead and is highly scalable. For the six months ended June 30, 2021, on a pro forma basis our

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production and ad valorem taxes were approximately $2.52 per BOE, relative to an average realized price of $40.27 per BOE. As a result, our operating margin and cash flows are higher, as a percentage of revenue, than those of traditional E&P companies. On a pro forma basis, during the six months ended June 30, 2021, we generated net income of $18.2 million and Adjusted EBITDA of $56.9 million. We do not anticipate engaging in any activities, other than acquisitions, that will incur capital costs. We believe our cost structure and business model will allow us to return a significant amount of our cash flows to our stockholders.

We have built our acreage position through the consummation of 177 acquisitions since November 2016. In addition to completing numerous small transactions, we have completed a total of 14 transactions larger than 1,500 NRAs that account for approximately 85% of our NRAs, including the Chambers Acquisition of approximately 7,200 NRAs, the Rock Ridge Acquisition of approximately 18,500 NRAs and the Source Acquisition of approximately 24,500 NRAs. During the four years ended December 31, 2019, we evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 167 acquisitions from landowners and other mineral interest owners, representing 47,920 NRAs, to our asset base. During 2020, our acquisition activity saw a significant decline following the onset of the COVID-19 global pandemic. Following the associated decline in oil prices during the onset of the pandemic, we experienced a meaningful difference in sellers’ pricing expectations and the prices we were willing to offer for assets. We evaluated approximately 197,416 NRAs and submitted formal offers on 56,658 NRAs but did not consummate any acquisitions subsequent to the first quarter of 2020 through the end of the first quarter of 2021. However, we utilized our significant free cash flow during 2020 to reduce our indebtedness from $66 million as of March 31, 2020 to $25.0 million as of March 31, 2021. Beginning in the second quarter of 2021, we saw a meaningful increase in our acquisition activity as evidenced by the approximately 26,000 NRAs we acquired in the second quarter and the approximately 28,000 NRAs we acquired in the third quarter. The following table summarizes our completed acquisitions from November 2016 through September 30, 2021.

Year	Number of Acquisitions		Total NRAs Acquired
2016		2		4,060
2017		50		18,037
2018		48		14,778
2019		67		11,045
2020		4		1,614
2021 (through September 30)(1)		6		54,141
Total		177		103,675

(1) Includes approximately 24,500 NRAs attributable to the Source Acquisition that are still in the title due diligence period. Accordingly, these NRAs are subject to change.

We are led by a management team with extensive oil and gas engineering, geologic and land expertise, mergers and acquisitions and capital markets experience, long-standing industry relationships and a history of successfully acquiring and managing a portfolio of leasehold interests, producing crude oil, natural gas and NGL assets, and mineral and royalty interests. We intend to capitalize on our management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in the Permian Basin designed to increase our cash flows per share.

We were founded by Kimmeridge. Kimmeridge is a private equity firm based in New York and Denver that is differentiated by its strategy of direct investment in unconventional oil and gas assets, leveraging its in-house expertise in geological evaluation, land acquisition and engineering. Kimmeridge and several members of our management team founded and managed two Delaware Basin-focused E&P companies, Arris Petroleum and 299 Resources, and successfully monetized those companies in 2016 by selling Kimmeridge’s ownership interests in those companies to PDC Energy. Additionally, in October 2020 another private equity fund managed by Kimmeridge acquired the Chambers ORRI. Subsequent to the transaction, our management team managed the acquired overriding royalty interest. We have leveraged Kimmeridge’s extensive Permian Basin experience and

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relationships with mineral and royalty owners in the region as we have grown our acreage position, and we expect to continue to do so in the future. Furthermore, Kimmeridge has established itself as a thought leader in the oil and gas industry, particularly around environmental, social and governance (“ESG”) matters, and our philosophy is consistent with Kimmeridge’s views on, among other things, aligning management compensation with the interests of shareholders and maintaining strong governance practices. See “Summary—ESG Philosophy.”

Our Key Producing Region

As of June 30, 2021, all of our properties were located exclusively within the Permian Basin. As of June 30, 2021, the Permian Basin had the highest level of horizontal drilling activity in the United States, according to Baker Hughes. The Permian Basin includes three geologic provinces: the Delaware Basin to the west, the Midland Basin to the east and the Central Basin Platform in between. The Delaware Basin is identified by an abundant amount of oil-in-place, stacked pay potential across an approximately 3,900 foot hydrocarbon column, attractive well economics, favorable operating environment, well developed network of oilfield service providers and significant midstream infrastructure in place or actively under construction. The Midland Basin is also identified by an abundant amount of oil-in-place stacked pay potential across an approximately 3,500 foot hydrocarbon column, attractive well economics, favorable operating environment, well developed network of oilfield service providers and significant midstream infrastructure in place. There are no federal lands on the Texas side of the Delaware Basin, where approximately 99% of our NRAs were located as of June 30, 2021, and therefore the acreage underlying our Texas NRAs is not subject to federal government involvement in or regulation of leasing, permitting or easements. According to the USGS, the Delaware Basin contains the largest recoverable reserves among all unconventional basins in the United States.

We believe the stacked-pay potential of the Delaware Basin combined with favorable drilling economics support continued production growth as E&P operators continue to develop their positions and improve well-spacing and completion techniques. Relative to other unconventional basins in the continental United States, we believe the Delaware Basin is in an earlier stage of horizontal well development and that per-well returns will improve as E&P operators continue to employ advanced horizontal drilling and completion technologies on multi-well pads in the region. We believe these factors will continue to support development activity in the region and in the areas where we hold mineral and royalty interests, leading to increasing cash flows free of lease operating expenses. The Delaware Basin has attracted an outsized portion of the capital deployed in unconventional basins, resulting in a larger proportional share of the total U.S. onshore horizontal rig count and oil and gas production. According to Enverus, 11,830 horizontal wells were spud in the Delaware Basin between November 2016 and June 2021, representing 20% of total horizontal onshore wells spud in the United States over that same time frame. This growth in drilling activity has resulted in substantial production growth in the Delaware Basin. Full year average total production in the Delaware Basin has grown at a CAGR of 32% from 2016 to 2020, outpacing the U.S. total production growth CAGR by approximately 4.8 times during the same period, according to Wood Mackenzie. Wood Mackenzie estimates that full year average Delaware Basin oil production is expected to increase to an average of approximately 3,110 MBbls/d during 2025, which represents a CAGR of 18% when compared to full year average oil production in 2016.

We believe the stacked-pay potential of the Midland Basin combined with low cost supply driven by enhancements in drilling efficiency supports continued production growth. The Midland Basin is in a more mature phase of horizontal well development relative to other unconventional basins in the United States. We believe these factors will continue to support development activity in the region and in the areas where we hold mineral and royalty interests, leading to increasing cash flows free of lease operating expenses. According to Enverus, 91 million lateral feet were drilled in the Midland Basin between November 2016 and May 2021, representing 21% of total horizontal onshore lateral feet drilled in the United States over that same time frame. Full year average lateral feet drilled per rig in the Midland Basin has grown at a CAGR of 11% from 2016 to 2020. Furthermore, in 2020, the total feet drilled per rig in the Midland Basin was approximately 9% greater than the total feet drilled per rig in the United States. We expect Midland Basin drilling efficiency to continue to improve as drilling days further compress and lateral lengths keep expanding.

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According to Baker Hughes, the Permian Basin has steadily increased its market share of total active onshore horizontal drilling rigs in the United States, increasing from 40% as of November 30, 2016 to 53% as of June 30, 2021. The charts below summarize annual average oil equivalent horizontal production for the total onshore United States and Permian Basin from 2016 through 2020, according to Wood Mackenzie, and the corresponding CAGRs over that period.

Our Mineral and Royalty Interests

Our interests consist of mineral and royalty interests. Mineral interests, which represent approximately 85% of our NRAs as of June 30, 2021, are real property interests that are typically perpetual and grant ownership of the crude oil and natural gas underlying a tract of land and the rights to explore for, drill for and produce crude oil and natural gas on that land or to lease those exploration and development rights to a third party. When we lease those rights, usually for a one- to three-year term, we typically receive an upfront cash payment, known as a lease bonus, and we retain a mineral royalty, which entitles us to a percentage (typically up to 25%) of production or revenue from production free of lease operating expenses. A lessee can extend the lease beyond the initial lease term with continuous drilling, production or other operating activities or through negotiated contractual lease extension options. When production and drilling cease, the lease terminates, allowing us to lease the exploration and development rights to another party and receive another lease bonus. As of June 30, 2021, other types of royalty interests, NPRIs and ORRIs, comprised approximately 2% and 13%, respectively, of our NRAs. As of June 30, 2021, approximately 94% of our ORRIs are currently leased or held by production, and we did not lose any ORRIs during the period of low activity and high shut ins during the year ended December 31, 2020. Also, as of June 30, 2021, approximately 82% of our NRAs were leased to E&P operators and other working interest owners. As of June 30, 2021, approximately 99% of our mineral and royalty interests are located in Texas and do not require federal approval to permit and drill oil and gas wells or to obtain easements or rights of way for operators to deliver their oil and gas to market. We refer to our mineral interests, NPRIs and ORRIs collectively as our “mineral and royalty interests.” We generate a substantial majority of our revenues and cash flows from our mineral and royalty interests when crude oil, natural gas and NGLs are produced from our acreage and sold by the applicable E&P operators and other working interest owners. Our predecessor’s pro forma revenue generated from these mineral and royalty interests was approximately $77.4 million for the year ended December 31, 2020 and $65.2 million for the six months ended June 30, 2021. Approximately 91% of 2020 and 82% of first half 2021 revenue was derived from the sale of oil and NGLs on a pro forma basis.

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Currently, our mineral and royalty interests reside entirely in the Permian Basin, which we believe is one of the premier unconventional crude oil, natural gas and NGL producing regions in the United States. As of June 30, 2021, our interests covered 41,298 net mineral acres, approximately 82% of which have been leased to E&P operators and other working interest owners with us retaining an average 19.4% royalty. Typically, within the mineral and royalty industry, owners standardize ownership of NRAs to a 12.5%, or a 1/8^th, royalty interest, representing the number of equivalent acres earning a 12.5% royalty, which is referred to as an NRA. When adjusted to a 1/8^th royalty, our mineral interests represent 64,040 NRAs, and our NPRIs and ORRIs represent an additional 11,563 NRAs, totaling 75,602 NRAs in the aggregate. Our DSUs, in the aggregate, consist of a total of 753,130 gross acres, which we refer to as our “gross DSU acreage.” We expect to have an ownership interest in all wells that will be drilled within our gross DSU acreage in the future. The following table summarizes our mineral and royalty interest position and the conversion of our interests from net mineral acres to NRAs and 100% royalty acres as of June 30, 2021.

Net Mineral Acres	Average Royalty			NRAs (Mineral Interests)(1)		NRAs (NPRIs)		NRAs (ORRIs)		Total NRAs		100% NRAs(2)		Gross DSU Acres		Implied Average Net Revenue Interest per Well(3)
41,298		19.4	%		64,040		1,505		10,058		75,602		9,450		753,130		1.3	%

(1) Our mineral interests are based on our average royalty interests across our net mineral acreage position normalized to reflect a 1/8^th royalty interest per net mineral acre (i.e., NRAs from mineral and royalty interests are calculated by multiplying 41,298 net mineral acres multiplied by an average royalty of 19.4% and then divided by 12.5%).

(2) Calculated as 75,602 NRAs multiplied by 12.5%.

(3) Calculated as 9,450, 100% royalty acres divided by 753,130 gross DSU acres.

As of June 30, 2021, we have interests in 266 gross (2.822 net) horizontal wells on which drilling has commenced but are not yet producing in paying quantities, which we refer to as spud wells, and 233 gross (2.227 net) wells for which permits have been issued to the operators, but on which drilling has not yet commenced, which we refer to as permitted wells. For the three months ended June 30, 2021, our permitted wells converted into spud wells within an average of 4.5 months and our spud wells converted into producing wells within an average of 7.7 months. The total time from permit to first production on our producing wells was 10.5 months on average as compared to a total time of 13.9 months for the Delaware Basin on average.

Our Reserves and Production

As of December 31, 2020, the estimated proved crude oil, natural gas and NGLs reserves attributable to our interests in our underlying acreage were 11,800 MBOE (67% liquids, consisting of 43% crude oil and 24% NGLs), based on a reserve report prepared by CG&A. Of these reserves, 78% were classified as PDP reserves, 1% were classified as PDNP reserves and 21% were classified as PUD reserves. As of June 30, 2021, the estimated proved crude oil, natural gas and NGLs reserves attributable to our interests in our underlying acreage were 13,875 MBOE (66% liquids, consisting of 45% crude oil and 22% NGLs), based on internal estimates of management. The estimated proved reserves as of June 30, 2021 have been prepared on the same basis as the estimated proved reserves as of December 31, 2020, but they have not been prepared or audited by an independent reserve engineer. Of these reserves, 80% were classified as PDP reserves and 20% were classified as PUD reserves. PUD reserves included in these estimates relate solely to wells that were spud but not yet producing in paying quantities as of December 31, 2020 and June 30, 2021, respectively. Estimated proved reserves included in this “Business” section are presented on an actual basis, without giving pro forma effect to transactions completed after such dates. As such, estimates of proved reserves (i) as of December 31, 2020 do not include reserves attributable to the Chambers Acquisition, the Rock Ridge Acquisition, the Source Acquisition, the Recent Acquisitions or the July 2021 Acquisition and (ii) as of June 30, 2021 include reserves attributable to

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the Chambers Acquisition, the Rock Ridge Acquisition and the Recent Acquisitions. The increase in total proved reserves between December 31, 2020 and June 30, 2021 is primarily attributable to acquisitions completed during the six months ended June 30, 2021.

We believe our production and discretionary cash flows will grow significantly as E&P operators drill the substantial undeveloped inventory of horizontal drilling locations located on our gross DSU acreage. As of June 30, 2021, we had production from 2,278 gross (27.9 net) horizontal wells, and we have identified 9,692 gross (118.0 net) undeveloped horizontal drilling locations based on our assessment of current geological, engineering and land data, which is equivalent to 12.4 gross undeveloped horizontal drilling locations per one mile-wide DSU. Furthermore, we believe there is potential for additional drilling activity through drilling efforts by our current E&P operators and through development of additional horizontal formations, including the Woodford/Barnett formations.

The following table provides a summary of our inventory of gross and net developed and undeveloped wells by horizon and total gross wells per DSU on a one mile wide DSU basis as of June 30, 2021.

	Gross Wells								Total Gross Wells/DSU (one mile wide DSU basis)(1)		Net Wells
Productive Horizon	Developed		Undeveloped		Total		Number of DSUs				Developed		Undeveloped		Total
Avalon/1st Bone Spring		38		396		434		103		5.80		0.20		1.82		2.02
2nd Bone Spring		47		702		749		204		4.60		0.75		5.59		6.34
3rd Bone Spring		236		1,691		1,927		716		3.59		2.54		15.38		17.91
Wolfcamp X/Y		282		753		1,035		348		4.06		2.60		9.76		12.37
Wolfcamp A		1,203		2,190		3,393		986		4.45		14.93		29.64		44.58
Wolfcamp B		316		2,279		2,595		919		3.61		4.64		29.35		33.99
Wolfcamp C		62		1,429		1,491		552		3.69		0.97		24.86		25.83
Wolfcamp D		21		252		273		107		3.69		0.64		1.60		2.24
Other Wells and Intervals		73		—		73		50		1.63		0.57		—		0.57
Total		2,278		9,692		11,970		1,058		15.3		27.85		118.00		145.85

(1) The number of DSUs in each horizon and locations per DSU in each horizon do not total due to differing prospectivity of each horizon across each DSU (i.e., not all horizons are booked in all DSUs). We assume an average of 15.3 drilling locations per DSU across horizons on a 5,000 foot wide basis. Though the average width of our DSUs is less than one mile wide, we standardize our gross wells per DSU to a one mile wide equivalent for comparison purposes.

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Our horizontal well inventory contains a range of lateral lengths, the substantial majority of which are from 5,000 feet to 10,000 feet. We ratably convert our horizontal well inventory for modeling purposes to 5,000-foot lateral length equivalents in order to estimate the amount of reservoir footage that is accessed by horizontal wells of varying lateral lengths drilled on our properties. The table below reflects our gross and net developed and undeveloped wells on that basis as of June 30, 2021.

	Gross Wells (5,000 foot lateral length basis)						Net Developed Wells		Net Undeveloped Wells		Total Net Wells
Productive Horizon	Developed		Undeveloped		Total(1)
Avalon/1st Bone Spring		55		533		588		0.31		2.03		2.35
2nd Bone Spring		60		1,010		1,069		0.76		8.14		8.91
3rd Bone Spring		335		2,422		2,757		3.17		21.43		24.60
Wolfcamp X/Y		384		1,103		1,488		3.13		13.40		16.54
Wolfcamp A		1,931		3,028		4,959		23.01		36.84		59.85
Wolfcamp B		515		3,276		3,792		7.54		38.65		46.19
Wolfcamp C		98		2,117		2,215		1.69		33.31		35.00
Wolfcamp D		27		349		377		0.66		1.95		2.61
Other Wells and Intervals		124		—		124		0.88		—		0.88
Total		3,529		13,839		17,368		41.16		155.76		196.92

(1) The numbers may not compute exactly due to rounding.

The following table provides a summary of our gross and net developed and undeveloped wells, along with the percentage of undeveloped wells that are currently either spud or permitted wells, as of June 30, 2021.

	Gross Wells		Net Wells
Developed		2,278		27.9
Undeveloped		9,698		118.0
Total		11,976		145.9
Undeveloped Spud and Permitted Wells		499		5.0
% Undeveloped Spud and Permitted Wells		5%		4%

Our mineral interest investment strategy anticipates E&P operators shifting drilling activity from a focus on drilling single wells to hold acreage towards more drilling in each DSU, particularly on multi-well pads. As of June 30, 2021, our position has an average of 2.91 gross producing horizontal wells per 5,000 foot wide DSU, compared to our spacing assumption of 15.3 gross wells per DSU. Furthermore, we expect to see increases in our production, revenue and discretionary cash flows from the development of 266 spud wells and 233 permitted wells across our interests as of June 30, 2021, compared to 171 gross wells completed on our acreage in the year ended December 31, 2020. If all of our spud wells were completed and all of our permitted wells were drilled and completed, we expect that our gross producing horizontal wells per 5,000 foot wide DSU would increase from 2.91 to 3.55. We believe our current interests provide the potential for significant long-term organic revenue growth as E&P operators develop our acreage and utilize advancements in drilling and completion techniques to increase crude oil, natural gas and NGL production.

Our E&P Operators

In addition to utilizing technical analysis to identify attractive mineral and royalty interests in the prolific Permian Basin, our management team strives to acquire mineral and royalty interests in properties with top-tier E&P operators. We seek E&P operators that are well-capitalized, have a strong operational track record, and that

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we believe will continue to increase production through the application of the latest drilling and completion techniques across our mineral and royalty interests. Approximately 50 horizontal E&P operators are currently producing oil and gas from our acreage. The chart below summarizes the E&P operators of our acreage based on the percentage of NRAs held by production in our portfolio as of June 30, 2021.

Financial Philosophy

We aim to balance the return of capital to investors with the selective allocation of capital toward acquisitions that we believe will be accretive to shareholder value while preserving a strong balance sheet through varying commodity price environments. In order to effect this approach, we intend to return capital to our shareholders through quarterly dividends, after retaining cash for our working capital needs and acquisition activities. We initially intend to make dividends of a significant amount of our discretionary cash flow, which we define as our Adjusted EBITDA less interest expense and cash taxes. Specifically, following the completion of this offering, we expect that our board of directors will initially target distributing to holders of shares of Class A common stock and Opco Units approximately $65 million on an aggregate annualized basis (or $1.05 per share of Class A common stock and per Opco Unit assuming the underwriters’ option to purchase additional shares of Class A common stock is not exercised).

While we expect to pay quarterly dividends in accordance with this financial philosophy, we have not adopted a formal written dividend policy to pay a fixed amount of cash each quarter or to pay any particular quarterly amount based on the achievement of, or derivable from, any specific financial metrics, including discretionary cash flow. Specifically, while we initially expect to make distributions of our discretionary cash flow in the targeted amounts described above, the actual amount of any dividends we pay may fluctuate depending on our cash flow needs, which may be impacted by potential acquisition opportunities and the availability of financing alternatives, the need to service our indebtedness or other liquidity needs, and general industry and business conditions, including the impact of commodity prices and the pace of the development of our properties by exploration and production companies. Our payment of dividends will be at the sole discretion of our board of directors, which may change our dividend philosophy at any time. See “Dividend Policy.”

ESG Philosophy

Since our inception, Kimmeridge and we have been committed to all three elements of ESG and are in the process of developing appropriate ESG policies, including strong governance policies. Our fully staffed,

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experienced team will be dedicated solely to our business of pursuing and consummating acquisitions and returning significant capital to shareholders. We intend to implement an executive compensation program designed to align our management and the board of directors directly with absolute total stockholder returns. For example, management’s incentive compensation is expected to be 100% equity-based, with approximately 75% of total compensation dependent on absolute total stockholder return. Our management team’s initial equity awards will be at the same basis as investors in this offering, and there are no legacy stock compensation or incentive units crystallizing upon the consummation of this offering.

Furthermore, the majority of our board of directors will be independent immediately upon the closing of this offering. Our board of directors and employee base are reflective of a culture that values diversity, with approximately one-half of our employees being women or minorities.

We believe our shareholders’ interests are aligned with environmental interests as both constituencies are harmed by the economic waste and environmental harm of flaring and venting of methane. We target minerals under operators with strong environmental track records. We prioritize responsible environmental practices and we endeavor to prohibit flaring by the operator in each lease. As we continue to gain additional scale, we intend to further pressure operators to eliminate flaring and venting of methane.

Business Strategies

Our primary business objective is to provide an attractive return to stockholders by acquiring mineral and royalty interests in the Permian Basin with the most significant potential rates of return for upstream E&P operators to maximize the likelihood that drilling and production will occur and distributing a meaningful portion of our cash flow to stockholders as dividends. We intend to accomplish this objective by executing the following strategies:

• Provide sustained return of capital to stockholders through strong discretionary cash flow generation and cash dividends. Our board of directors will prioritize returning capital to our stockholders through dividends while also opportunistically pursuing acquisitions. While we do not expect to adopt a formal dividend policy and the amount of dividends that we pay will be at the sole discretion of our board of directors, we expect initially to pay dividends of a significant amount of our discretionary cash flows and any additional cash flows not returned to stockholders will be used for additional acquisitions that meet our investment criteria outlined below, to reduce indebtedness, to pay special dividends or to buy back our stock. As mineral and royalty interest owners, we benefit from the continued organic development of our acreage in the Permian Basin and are able to convert a high percentage of our revenue to discretionary cash flow, which we define as our Adjusted EBITDA less interest expense and cash taxes. We do not incur operating costs for the production of crude oil and natural gas or capital costs for the drilling and completion of wells on our acreage. Our only cash operating costs related to our mineral and royalty business consist of certain taxes, gathering, processing and transportation costs, and general and administrative expenses. For the six months ended June 30, 2021, on a pro forma basis our production and ad valorem taxes were approximately $2.52 per BOE, relative to an average realized price of $40.27 per BOE. We believe that our royalty interests are positioned for discretionary cash flow growth as E&P operator focus continues to shift to the Permian Basin, as evidenced by the increase in the percentage of total U.S. onshore rigs located in the Permian Basin over the last three years.

• Focus primarily on the Permian Basin. All of our mineral and royalty interests are currently located in the Permian Basin, one of the most prolific oil and gas basins in the United States. We believe the Permian Basin provides an attractive combination of highly-economic and oil-weighted geologic and reservoir properties, opportunities for development with significant inventory of drilling locations and zones to be delineated and top-tier, well-funded E&P operators. According to Baker Hughes, the

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Permian Basin, where all of our assets are currently located, has witnessed a significant growth in the market share of active onshore horizontal drilling rigs in the United States, increasing from 40% of active onshore horizontal drilling rigs as of our formation in November 2016 to 53% of active onshore horizontal drilling rigs as of June 30, 2021.

• Leverage expertise and relationships to continue acquiring Permian Basin mineral and royalty interests associated with top-tier E&P operators. We have a history of evaluating, pursuing and consummating acquisitions of crude oil and natural gas mineral and royalty interests in the Permian Basin. Since November 2016, we have completed 177 acquisitions, demonstrating our ability to add scale quickly and effectively. Our management team intends to continue to apply this experience in a disciplined manner when identifying and acquiring mineral and royalty interests. We believe that the current market environment is favorable for the consolidation of mineral and royalty interests, as the disaggregated nature of asset packages from numerous sellers presents attractive opportunities for assets that meet our target investment criteria. With sellers seeking to monetize their investments but lacking the scale to do so in the public markets, we intend to continue to acquire mineral and royalty interests that have substantial resource potential in the Permian Basin, an area that we expect to continue to experience a relatively high rate of development, with E&P operators incentivized to economically deploy capital to delineate and develop their positions over the underlying mineral interests. This E&P operator activity creates an opportunity for organic growth free of lease operating and capital expenses. We expect to focus on acquisitions that complement our current footprint in the Permian Basin while targeting mineral and royalty interests underlying the acreage of well-capitalized E&P operators that have a history of high conversion rates of permits issued to wells completed on large contiguous acreage positions. Furthermore, we seek to maximize our return on capital by targeting acquisitions that meet the following criteria:

• sufficient visibility to production growth;

• attractive economics;

• de-risked geology supported by offsetting production;

• top-tier E&P operators; and

• a geographic footprint that we believe is complementary to our diverse portfolio of Permian Basin assets and maximizes our potential for upside reserve and production growth.

• Maintain conservative and flexible capital structure to support our business and facilitate long-term operations. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. Upon completion of this offering, we will have no outstanding funded indebtedness. We believe that proceeds from this offering, internally generated cash flows from operations, available borrowing capacity under our revolving credit facility, and access to capital markets will provide us with sufficient liquidity and financial flexibility to continue to acquire attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. We intend to maintain a conservative leverage profile and utilize a mix of cash flows from operations and issuance of debt and equity securities to finance future acquisitions.

Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our primary business objective:

• Differentiated energy investment opportunity. As opposed to traditional E&P operators who require significant capital, our business requires no drilling and completion capital, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life and accordingly represents a

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differentiated energy investment opportunity. In addition, we are not responsible for environmental or other operational liabilities in connection with oil and gas production associated with our interests, and our only operating cash costs related to our mineral and royalty business consist of certain production taxes, gathering, processing and transportation costs and general and administrative expenses. For example, for the six months ended June 30, 2021, on a pro forma basis our production and ad valorem taxes were approximately $2.52 per BOE, relative to an average realized price of $40.27 per BOE. Furthermore, we have significantly reduced our indebtedness during the COVID-19 pandemic, while many other energy companies struggled with indebtedness and leverage issues during 2020. We believe our low capital requirements and financial discipline will result in an ability to distribute a meaningful amount of cash flow to stockholders.

• Permian Basin focused public minerals company positioned as a preferred buyer in the basin. We believe that our status as a public company focused exclusively on the Permian Basin will position us as a preferred buyer of Permian Basin mineral and royalty interests, as we will be able to offer sellers an opportunity to own an equity interest in a company that is solely focused on the Permian Basin. Currently, all of the acreage underlying our mineral interests is located in the Permian Basin, one of the most prolific oil plays in the United States, and the majority of our current properties are well positioned in areas with proven results from multiple stacked productive zones. Our properties in the Permian Basin are high-quality, high-margin, and oil- and liquids-weighted, and we believe they will be viewed favorably by sellers interested in receiving equity consideration in exchange for their assets as compared to equity consideration diluted by lower quality assets located in less prolific basins.

• Favorable and stable operating environment in the Permian Basin. With over 400,000 wells drilled in the Permian Basin since 1900, the region features a reliable and predictable geological and regulatory environment, according to Enverus. We believe that the impact of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities as compared to other, emerging hydrocarbon basins. As of June 30, 2021, approximately 99% of our acreage was located in Texas, and does not require federal approval to permit and drill oil and gas wells or to grant easements to allow E&P operators to deliver their production to market.

• Experienced management team with an extensive track record of minerals acquisitions. The members of our management team have grown our acreage position through the consummation of over 177 acquisitions since November 2016 ranging in size from small transactions of less than 25 NRAs to large transactions in excess of 1,500 NRAs, including the Chambers Acquisition of approximately 7,200 NRAs, the Rock Ridge Acquisition of approximately 18,500 NRAs and the Source Acquisition of approximately 24,500 NRAs. Notably, we have acquired nearly 85% of our NRAs through 14 large acquisitions, using both cash and equity consideration to suit the needs of sellers. Our management team has deep industry experience focused on resource play development in the Permian Basin and has a track record of identifying mineral and royalty acquisition targets, negotiating agreements, and successfully consummating acquisitions. We plan to continue to evaluate and pursue acquisitions of all sizes. We expect to benefit from the industry relationships fostered by our management team’s decades of experience in the oil and natural gas industry with a focus on the Permian Basin, in addition to leveraging our relationship with Kimmeridge.

• Board structure and compensation model aligned with stockholder interests. We intend to implement industry-leading governance practices for board structure and director and officer compensation. For example, at the closing of this offering, all of our directors will be elected annually and there will be no special voting classes of stock. In addition, our directors will receive a significant portion of their compensation in deferred equity awards and a significant portion of our management team’s compensation will depend on absolute total stockholder return metrics instead of operational metrics (e.g., production) that may not necessarily be aligned with the interests of our stockholders.

• Development potential of the properties underlying our Permian Basin mineral and royalty interests. Our assets consist of mineral and royalty interests located in the Permian Basin, and we expect

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production from our mineral and royalty interests to increase as E&P operators continue to actively drill and develop our acreage. Relative to other unconventional basins in the continental United States, we believe the Permian Basin is in an earlier stage of development and that the average number of producing wells per section in the Permian Basin will increase as E&P operators continue to optimize drilling locations and delineate additional zones, which would allow us to achieve higher realized cash flows per net mineral acre. Additionally, according to Baker Hughes, the Permian Basin has steadily increased its market share of total active onshore horizontal drilling rigs in the United States, increasing from 40% as of November 30, 2016 to 53% as of June 30, 2021. We expect to benefit from this focus of development activity in the Permian Basin and believe any resulting increase in our revenues will enable us to return capital to our stockholders.

We target acquisitions of properties that are relatively undeveloped in the core of the Delaware Basin, and we believe the organic development of our acreage will result in substantial production growth regardless of acquisition activity. From January 1, 2016 to December 31, 2020, production attributable to our properties increased at a CAGR of 51% assuming our NRAs as of December 31, 2020 were owned on January 1, 2016, as compared to a CAGR of 33% for Delaware Basin production growth generally and a CAGR of 7% for total U.S. onshore production growth for the same period.

• Diverse group of blue-chip E&P operators on our mineral and royalty interests driving production growth. Our mineral and royalty interests consist of properties operated by established E&P companies, such as Occidental Petroleum Corporation, BP plc, Cimarex Energy Co., Conoco Phillips and Chevron Corporation. Our blue-chip E&P operators provide a diversified source of revenues, as no single E&P operator provided greater than 15% of our total revenues for the six months ended June 30, 2021.

Crude Oil, Natural Gas and NGLs Data

The information included in “—Crude Oil, Natural Gas and NGLs Data” and “—Crude Oil, Natural Gas and NGL Production Prices and Costs” presents our reserves and operating data as of and for the years ended December 31, 2020 and 2019 on an actual basis, without giving pro forma effect to transactions completed after such dates. As such, the reserves and operating data presented in these sections does not give effect to the Chambers Acquisition, the Rock Ridge Acquisition, the Source Acquisition, the Recent Acquisitions or the July 2021 Acquisition. However, elsewhere in this prospectus, we include estimates of reserves associated with the assets acquired in the Rock Ridge Acquisition as of December 31, 2020 and 2019. Such reserve estimates are based on evaluations prepared by the independent petroleum engineering firm of Netherland, Sewell & Associates, Inc. (“NSAI”) in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC.

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 persons primarily responsible for preparing the estimates set forth in such reports are Michael J. Kingrey and William Knights. Mr. Kingrey, a Licensed Professional Engineer in the State of Texas (No. 128848), has been practicing consulting petroleum engineering at NSAI since 2015 and has over 6 years of prior industry experience. He graduated from Texas A&M University in 2009 with a Bachelor of Science Degree in Chemical Engineering. Mr. Knights, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 1532), has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and in 1984 with a Master of Science Degree in Geology. Both technical principals meet or exceed 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; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

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Elsewhere in the prospectus, we also include estimates of reserves associated with the Source Assets as of December 31, 2020. Such estimates are based on internal evaluations prepared by our management and have not been prepared or audited by an independent reserve engineer.

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2020 and 2019 included in this prospectus are based on evaluations prepared by the independent petroleum engineering firm of CG&A in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. We selected CG&A as our independent reserve engineer for its historical experience and geographic expertise in engineering similar resources. Our reserve estimates as of June 30, 2021 included in this prospectus are based on internal evaluations prepared by our management and have not been prepared or audited by an independent reserve engineer.

In accordance with rules and regulations of the SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude oil and natural 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. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our proved reserves were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable crude oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods, (ii) material balance-based methods; (iii) volumetric-based methods and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUDs for our properties due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core data, and historical well cost and operating expense data.

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Internal Controls

Our internal staff of petroleum engineers and geoscience professionals work closely with our independent reserve engineer to ensure the integrity, accuracy and timeliness of data furnished to such independent reserve engineer in their preparation of reserve estimates. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “Risk Factors” appearing elsewhere in this prospectus. Our engineering group is responsible for the internal review of reserve estimates and includes the Vice President of Engineering and Acquisitions. Our Vice President of Engineering and Acquisitions is primarily responsible for overseeing the preparation of our reserve estimates and has more than 16 years of experience as an engineer. Our Chief Executive Officer is directly responsible for overseeing the engineering group.

No portion of our engineering group’s compensation is directly dependent on the quantity of reserves booked. The engineering group reviews the estimates with the third-party petroleum consultant, CG&A, an independent petroleum engineering firm.

CG&A is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. The lead evaluator that prepared our reserve report was Zane Meekins at CG&A. Mr. Meekins has been a practicing consulting petroleum engineer at CG&A since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 34 years of practical experience in petroleum engineering, with over 32 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins 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 reserve definitions and guidelines.

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Summary of Reserves

The following table presents our estimated proved reserves as of December 31, 2020 and 2019. The reserve estimates presented in the table below are based on reports prepared by CG&A, our independent petroleum engineers, which reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting:

	December 31, 2020(1)		December 31, 2019(2)
Estimated proved developed reserves:
Crude oil (MBbls)		3,731		4,223
Natural gas (MMcf)		19,505		20,293
NGLs (MBbls)		2,352		2,298
Total (MBOE)		9,334		9,903
Estimated proved undeveloped reserves:
Crude oil (MBbls)		1,344		1,616
Natural gas (MMcf)		3,897		4,200
NGLs (MBbls)		473		476
Total (MBOE)		2,467		2,792
Estimated proved reserves:
Crude oil (MBbls)		5,075		5,839
Natural gas (MMcf)		23,402		24,493
NGLs (MBbls)		2,825		2,774
Total (MBOE)		11,800		12,695

(1) Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For crude oil and NGL volumes, the average WTI posted price of $39.57 per Bbl as of December 31, 2020 was adjusted for quality, transportation fees and a regional price differential. NGL price was modeled at 27.8% of the WTI posted price. For natural gas volumes, the average Henry Hub spot price of $1.985 per MMBtu as of December 31, 2020 was adjusted for energy content, transportation fees and a regional price differential. The average adjusted product prices weighted by production over the remaining lives of the proved properties are $36.28 per Bbl of crude oil, $11.01 per Bbl of NGL and $1.02 per Mcf of natural gas as of December 31, 2020.

(2) Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For crude oil and NGL volumes, the average WTI posted price of $50.92 per Bbl as of December 31, 2019 was adjusted for quality, transportation fees and a regional price differential. NGL price was modeled at 27% of the WTI posted price. For natural gas volumes, the average Henry Hub spot price of $0.69 per MMBtu as of December 31, 2019 was adjusted for energy content, transportation fees and a regional price differential. The average adjusted product prices weighted by production over the remaining lives of the proved properties are $50.92 per Bbl of crude oil, $14.897 per Bbl of NGL and $0.69 per Mcf of natural gas as of December 31, 2019.

Reserve engineering is a process of estimating volumes of economically recoverable crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of economically recoverable crude oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Risk Factors.”

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Additional information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in this prospectus and our proved reserve reports, which are included as exhibits to the registration statement of which this prospectus forms a part.

PUDs

As of December 31, 2020, we estimated our PUD reserves to be 1,344 MBbls of crude oil, 3,897 MMcf of natural gas and 473 MBbls of NGLs, for a total of 2,467 MBOE. As of December 31, 2019, we estimated our PUD reserves to be 1,616 MBbls of crude oil, 4,200 MMcf of natural gas and 476 MBbls of NGLs, for a total of 2,792 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. PUD reserves included in these estimates relate solely to wells that have been spud but are not yet producing as of the date of the report.

The following tables summarize our changes in PUD reserves during the year ended December 31, 2020 (in MBOE):

	Proved Undeveloped Reserves (MBOE)
Balance, December 31, 2019		2,792
Acquisitions of Reserves		148
Extensions and Discoveries		1,614
Revisions of Previous Estimates		(181	)
Transfers to Estimated Proved Developed		(1,906	)
Balance, December 31, 2020		2,467

Changes in our PUD reserves that occurred during the year ended December 31, 2020 were primarily due to the following:

• the acquisition of additional mineral and royalty interests located in the Delaware Basin in multiple transactions, which included 148 MBOE of additional PUDs;

• well additions, extensions and discoveries of approximately 1,614 MBOE, as 104 horizontal well locations were converted to proved undeveloped;

• negative volume revisions of 181 MBOE due to adjustments in expected well ownership; and

• the conversion of approximately 1,906 MBOE in PUD reserves into proved developed reserves as 202 horizontal locations were drilled and completed.

As mineral and royalty interests owners, we do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by the E&P operator. As a result, during the twelve months ended December 31, 2020, we had no expenditures to convert PUDs to proved developed reserves.

We identify drilling locations based on our assessment of current geologic, engineering and land data. This includes DSU formation and current well spacing information derived from state agencies and the operations of the exploration and production companies drilling our mineral and royalty interests. We limit our PUDs solely to wells that have been spud but are not yet producing. As of December 31, 2020, approximately 21% of our total proved reserves were classified as PUDs.

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Crude Oil, Natural Gas and NGL Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of crude oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

	Year Ended December 31,
	2020		2019
Production data:
Crude oil (MBbls)		933		816
Natural gas (MMcf)		4,134		3,237
NGLs (MBbls)		488		393
Total (MBOE)		2,110		1,749
Average realized prices:
Crude oil (per Bbl)	$	37.40	$	52.90
Natural gas (per Mcf)	$	1.03	$	0.74
NGLs (per Bbl)	$	10.32	$	13.48
Total (per BOE)(1)	$	20.95	$	29.09
Average cost (per BOE):
Production and ad valorem taxes	$	1.49	$	2.16

(1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per Bbl of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between crude oil and natural gas.

Drilling Results

Productive wells consist of producing horizontal wells, wells capable of production and exploratory, development or extension wells that are not dry wells. As of December 31, 2020, we owned mineral and royalty interests in 1,568 productive horizontal wells.

We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.

We do not own any working interests in any wells other than in one plugged and abandoned well. Accordingly, we do not own any net wells as such term is defined by Item 1208(c)(2) of Regulation S-K.

Acreage

The following table sets forth information relating to our acreage for our mineral and royalty interests as of December 31, 2020:

Basin	Gross DSU Acreage		Total NRAs		100% NRAs		Gross DSU Developed Acreage		Gross DSU Undeveloped Acreage		NRAs (Developed)		NRAs (Undeveloped)
Delaware		542,058		49,534		6,192		116,564		425,494		12,086		37,448

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Regulation

The following disclosure describes regulation directly associated with E&P operators of crude oil and natural gas properties, including our current E&P operators, and other owners of working interests in crude oil and natural gas properties.

Crude oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the crude oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business.

Environmental Matters

Crude oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the properties in which we own mineral interests, which could materially adversely affect our business and our prospects. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the E&P operators of our properties regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our business and prospects.

Non-Hazardous and Hazardous Waste

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with exploration and production of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. On May 4, 2016, a coalition of environmental groups filed a lawsuit against EPA in the U.S. District Court for the District of Columbia for failing to update its RCRA Subtitle D criteria regulations governing the disposal of

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certain crude oil and natural gas drilling wastes. In December 2016, EPA and the environmental groups entered into a consent decree to address EPA’s alleged failure. In response to the consent decree, in April 2019, EPA signed a determination that revision of the regulations is not necessary at this time. However, any changes in the laws and regulations could have a material adverse effect on the E&P operators of our properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.

Remediation

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and analogous state laws generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, 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 owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Water Discharges

The Clean Water Act (“CWA”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act of 1990 (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into regulated waters. The definition of regulated waters has been the subject of significant controversy in recent years, with different definitions proposed under the Obama and Trump administrations. Both of these definitions have been subject to litigation, and the Biden administration has announced plans to develop its own definition for such waters. To the extent any future rule expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our operators. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.

The OPA is the primary federal law for crude oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to

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cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of crude oil into surface waters.

Noncompliance with the CWA, the SDWA, or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the E&P operators of the acreage underlying our mineral interests.

Air Emissions

The federal Clean Air Act (“CAA”), and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in June 2016, the EPA established criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for crude oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests. In addition federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of crude oil and natural gas projects.

Climate Change

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other “greenhouse gases” (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised regulations initially promulgated in June 2016 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, as discussed in the Risk Factors section above, shortly after taking office President Biden issued an Executive Order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. The Executive Order specifically called on the EPA to consider a proposed rule suspending, revising or rescinding the September 2020 deregulatory amendments by September 2021. The Executive Order also called on the EPA to propose new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments, by September 2021. Additionally, in April 2021, the U.S. Senate approved a resolution under

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the Congressional Review Act to repeal the September 2020 revisions. The U.S. House of Representatives approved the resolution and President Biden signed it into law in June 2021, effectively vacating the September 2020 revisions and reinstating the prior standards.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, New Mexico has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as Nationally Determined Contributions every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. The impacts of these orders, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, cannot be predicted at this time.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in public office. On January 27, 2021, President Biden issued an Executive Order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also issued orders temporarily suspending the issuance of authorizations, and suspending the issuance of new leases pending a study, for oil and gas development on federal lands. Substantially all of our interests are located on private lands, but we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve announced that is has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing

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their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects that could have an adverse effect on our E&P operators’ operations and the production on our properties. One potential consequence of climate change could be increased severity of extreme weather conditions such as more intense hurricanes, thunderstorms, tornados, droughts and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their crude oil and natural gas regulatory programs. However, several agencies have asserted regulatory authority over certain aspects of the process. For example, in August 2012, the EPA finalized regulations under the federal CAA that establish new air emission controls for crude oil and natural gas production and natural gas processing operations. In June 2016, the EPA published similar rules that impose volatile organic compound emissions limits on certain crude oil and natural gas operations that were previously unregulated, including hydraulically fractured crude oil wells, as well as methane emissions limits for certain new or modified crude oil and natural gas emissions sources. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, on January 20, 2021, President Biden signed an Executive Order calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. For more information, see our risk factor titled “Our operations, and those of our E&P operators, are subject to a series of risks arising from climate change.”

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water under certain limited circumstances.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the

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increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. For example, in October 2014, the Texas Railroad Commission published a new 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 produced water or other 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 agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including New Mexico, Oklahoma and Texas. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the E&P operators of our properties and on their waste disposal activities.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause E&P operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by E&P operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Endangered Species Act

The Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, and to reconsider listing the species under the ESA. For example, in October 2019 environmental groups filed a lawsuit against the FWS seeking to compel the agency to list the species under the ESA, and in July 2020, FWS agreed to initiate a 12-month review to determine whether listing the species was warranted. Additionally, in June 2021, the FWS proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Employee Health and Safety

Operations on our properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community

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right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Other Regulation of the Crude Oil and Natural Gas Industry

The crude oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the crude oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the crude oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the crude oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and conditions and cost of transportation significantly affect sales of crude oil and natural gas. The interstate transportation of crude oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to crude oil and natural gas pipeline transportation. FERC’s regulations for interstate crude oil and natural gas transmission in some circumstances may also affect the intrastate transportation of crude oil and natural gas.

We cannot predict whether new legislation to regulate crude oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices.

Drilling and Production

The operations of the E&P operators of our properties are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the timing of construction or drilling activities, including seasonal wildlife closures;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells,

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generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of crude oil and natural gas that the E&P operators of our properties can produce from our wells or limit the number of wells or the locations at which E&P operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of crude oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of crude oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations E&P operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the E&P operators of our properties operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the E&P operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues the E&P operators of our properties receive for release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third party sellers other than pipelines.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the E&P operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the E&P operators of our properties produce.

Historically, the natural gas industry was more heavily regulated; therefore, we cannot guarantee that the regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Crude Oil Sales and Transportation

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of crude oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act and intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and

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the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier crude 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. When crude oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services by E&P operators of our properties will not materially differ from our competitors’ access to crude oil pipeline transportation services.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, crude oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of crude oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of crude oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowables from crude oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of crude oil and natural gas that may be produced from wells on our properties and the number of wells or locations the E&P operators of our properties can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our business.

Title to Properties

Prior to completing an acquisition of mineral and royalty interests, we perform a title review on each tract to be acquired. Our title review is meant to confirm the quantum of mineral and royalty interest owned by a prospective seller, the property’s lease status and royalty amount as well as encumbrances or other related burdens. As a result, title examinations have been obtained on a significant portion of our properties.

In addition to our initial title work, E&P operators often will conduct a thorough title examination prior to leasing and/or drilling a well. Should an E&P operator’s title work uncover any further title defects, either we or the E&P operator will perform curative work with respect to such defects. An E&P operator generally will not commence drilling operations on a property until any material title defects on such property have been cured.

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in connection with the acquisition of crude oil and gas interests, non-participating royalty interests and other burdens, easements, restrictions or minor encumbrances customary in the crude oil and natural gas industry, we believe that none of these encumbrances will materially detract from the value of these properties or from our interest in these properties.

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Competition

The crude oil and natural gas business is highly competitive; we primarily compete with companies for the acquisition of mineral and royalty interests and acquisition of minerals and crude oil and natural gas leases. Many of our competitors not only own and acquire mineral and royalty interests but also explore for and produce crude oil and natural gas and, in some cases, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. By engaging in such other activities, our competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

In addition, crude oil and natural gas products compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of crude oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for crude oil and natural gas.

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Additionally, some of the areas in which our properties are located are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, our E&P operators may be unable to move their equipment between locations, thereby reducing their ability to operate our wells, reducing the amount of crude oil and natural gas produced from the wells on our properties during such times. Additionally, extended drought conditions in the areas in which our properties are located could impact our E&P operators’ ability to source sufficient water or increase the cost for such water. Furthermore, demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other crude oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Employees

We and our predecessor do not have any employees. As of December 31, 2020, an affiliate of our predecessor employed approximately 23 full-time equivalent individuals who provided direct support to our operations pursuant to a management services arrangement. None of these employees are covered by collective bargaining agreements. Immediately after the closing of this offering, we expect to employ approximately 29 individuals, none of which are expected to be covered by collective bargaining agreements.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.

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MANAGEMENT

The following table sets forth the names, ages and titles of our directors, director nominees and executive officers.

Name	Age		Position
Christopher L. Conoscenti		46	Chief Executive Officer and Director Nominee
Carrie L. Osicka		43	Chief Financial Officer
Britton L. James		39	Vice President of Land
Jarret J. Marcoux		39	Vice President of Engineering and Acquisitions
Brett S. Riesenfeld		36	General Counsel and Secretary
Noam Lockshin		37	Director
Morris R. Clark		54	Director Nominee
Benjamin P. Dell		44	Director Nominee
Scott S. Nyquist		62	Director Nominee
Alice E. Gould		60	Director Nominee
Erik C. Belz		36	Director Nominee
Allen W. Li		31	Director Nominee

Set forth below is a description of the backgrounds of our directors, director nominees and executive officers. Unless otherwise indicated, references to positions held at Desert Peak Minerals or our company include positions at Opco.

Directors, Director Nominees and Executive Officers

Christopher L. Conoscenti—Chief Executive Officer and Director Nominee. Mr. Conoscenti joined Kimmeridge as the Chief Executive Officer of its mineral and royalty interest business in March 2019 following an eighteen year career in oil and gas investment banking, most recently as a Managing Director in the Oil & Gas Investment Banking and Capital Markets Group at Credit Suisse Securities (USA) LLC from July 2014 to March 2019. Previously, Mr. Conoscenti worked in Oil & Gas Investment Banking at J.P. Morgan from January 2004 where he served as a Managing Director from May 2012 until his departure in April 2014. His clients at Credit Suisse included large and mid-cap upstream E&P operators and minerals companies. During his investment banking career, Mr. Conoscenti advised on numerous mergers and acquisition transactions and served as an active bookrunner on equity, equity-linked and debt transactions. Mr. Conoscenti holds a Bachelor of Arts degree from the University of Notre Dame and a JD and an MBA from Tulane University.

We believe that Mr. Conoscenti’s significant experience in the oil and gas industry and financial expertise makes him well qualified to serve as a member of our board of directors.

Carrie L. Osicka—Chief Financial Officer. Ms. Osicka joined Kimmeridge as the Chief Financial Officer of its mineral and royalty interest business in April 2019 following a ten year career at Resolute Energy Corporation, where she served as the Senior Director of Finance from November 2017 to February 2019 and previously as Manager of Business Analytics from November 2010 to October 2017. While at Resolute Energy Corporation, Ms. Osicka focused on strategy, financial planning, analysis and mergers and acquisition transactions. Ms. Osicka holds a Master of Business Administration from the Kellogg School of Management at Northwestern University and Bachelor of Science in Accounting from Metropolitan State University.

Britton L. James—Vice President of Land. Mr. James joined Kimmeridge as Vice President of Land of its mineral and royalty interest business in December 2018 following a twelve year career in land management as part of teams covering the Bakken, Delaware Basin, Powder River Basin and several other basins throughout the United States, most recently as a Land Manager for Rockies Resources LLC from June 2018 until November 2018. Previously, Mr. James was an independent land consultant for multiple upstream companies from March

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2018 until June 2018, and a Managing Partner, Vice President-Land and member of the Board of Directors for Clear Creek E&P, LLC from January 2017 until its sale in February 2018. Mr. James was also Land Manager for Arris Petroleum from May 2015 until its sale to PDC Energy in December 2016, Senior Landman for American Eagle Energy from January 2012 until May 2015, and Senior Landman for Whiting Petroleum Corporation for over five years. Mr. James was also involved in Kimmeridge’s investment in 299 Resources until its sale to PDC Energy. During his career, Mr. James advised on acquisitions/divestitures, grassroots leasing, managing drilling programs and all other facets of land management. In addition to his career in oil and gas, Mr. James served as a Non-Commissioned Officer in the Colorado Army National Guard for six years. Mr. James holds a B.S. in Business from the University of Montana.

Jarret J. Marcoux—Vice President of Engineering and Acquisitions. Mr. Marcoux joined Kimmeridge in January 2015 as Reservoir Engineer, became Vice President of Reservoir Engineering in September 2015 and Vice President of Engineering and Acquisitions of its mineral and royalty interest business in May 2019. Mr. Marcoux was involved in Kimmeridge’s investments in Arris Petroleum and 299 Resources and the subsequent sale of Kimmeridge’s ownership interests in those companies to PDC Energy. Prior to Kimmeridge, Mr. Marcoux spent two years at Baker Hughes, first consulting on various unconventional plays as a Reservoir Engineer from May 2013 until May 2014, and later held the title of Product Line Manager, overseeing all subsurface consulting in the Permian Basin from June 2014 until December 2014. Additionally, Mr. Marcoux has eight years of engineering experience working for IBM, Samsung and AMD within the electronics industry. Mr. Marcoux holds a Master of Engineering from Texas A&M University in Petroleum Engineering as well as a Bachelor of Science from the University of Massachusetts Amherst in Chemical Engineering with a secondary major in Economics.

Brett S. Riesenfeld—General Counsel and Secretary. Mr. Riesenfeld joined Kimmeridge as the General Counsel of its mineral and royalty interest business in June 2019 and will become Secretary in connection with this offering. From October 2010 to June 2019, Mr. Riesenfeld served as an attorney at Vinson & Elkins, L.L.P. While at Vinson & Elkins, L.L.P., Mr. Riesenfeld represented public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. Mr. Riesenfeld holds a Bachelor of Arts degree from The University of Texas and a Juris Doctor from The University of Texas School of Law.

Noam Lockshin—Director. Mr. Lockshin was appointed to our board of directors on April 17, 2019. Mr. Lockshin is a Partner of Kimmeridge and has been with the firm since its founding in May 2012. Mr. Lockshin is a member of the firm’s investment team, and serves in various capacities including research, analysis, and diligence of investment opportunities as well as the negotiation and execution of investment strategies. Most recently, Mr. Lockshin led the firm’s investment efforts in the mineral and royalty interests business focused on the Delaware basin in Texas and New Mexico. Prior to joining Kimmeridge, Mr. Lockshin served as a Vice President, Energy Investing for AllianceBernstein Holding L.P., a leading global asset management firm, from July 2010 to May 2012,. Prior to that, Mr. Lockshin was an Equity Research Associate for E&P at Sanford C. Bernstein & Co. LLC from July 2007 to July 2010. Mr. Lockshin holds a Bachelor of Arts degree in Mathematics from York University.

We believe Mr. Lockshin’s experience covering the E&P industry, his specialized knowledge of the minerals and royalty interests business, history of building successful working relationships with landowners in the Delaware Basin to acquire land, and mineral and royalty interests, and leading the KMF team that manages those assets, uniquely qualify him to serve as a member of our board of directors.

Morris R. Clark—Director Nominee. Mr. Clark has been nominated to serve on our board of directors, commencing on the effective date of the registration statement of which this prospectus is a part. From January 2014 to July 2019, Mr. Clark served as Vice President and Treasurer of Marathon Oil Corporation (“Marathon Oil”). From 2007 until January 2014, Mr. Clark served as Assistant Treasurer of Marathon Oil. Mr. Clark was responsible for managing all treasury related matters, including corporate finance, cash and banking/operations, insurance, pensions, enterprise risk management and credit and counterparty risk. During his tenure, Mr. Clark

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led financing transactions, including bond and equity issuances, revolving credit and receivables facilities, merger and acquisition financings and major corporate restructurings (public spin-offs). Prior to joining Marathon Oil, Mr. Clark served as Senior Tax Counsel at Enron North America, a Tax Attorney at Bracewell & Patterson in Houston and a Senior Accountant with Touche Ross & Company (Deloitte & Touche) in Los Angeles. Mr. Clark currently serves as a Director and Chair of the Audit Committee of the Board of Directors of Extraction Oil & Gas, Inc. (NYSE: XOG), a position he has held since January 2021. Additionally, Mr. Clark has been involved with several non-profit and educational boards and continues to evaluate additional potential opportunities. Mr. Clark holds a Bachelor of Science degree in Accounting from Southern University, a Juris Doctorate degree from Tulane Law School, and a Master of Laws degree (LL.M.) from New York University School of Law.

We believe that Mr. Clark’s significant experience in the oil and gas industry with multiple public companies will bring extensive financial expertise and proven leadership to the board of directors and us. Furthermore, Mr. Clark’s leadership with multiple community based and educational organizations will provide the board of directors with a welcomed perspective. For example, Mr. Clark served on the Board of Directors for Dress for Success Houston from 2015 to 2020 and has served on the University of St. Thomas Board of Trustees since 2017 (currently serving as Vice-Chair of the Audit & Finance Committee).

Benjamin P. Dell—Director Nominee. Mr. Dell has been nominated to serve on our board of directors, commencing on the effective date of the registration statement of which this prospectus is a part, and will serve as chairman of the board. Mr. Dell has served as the Managing Partner of Kimmeridge since founding the firm in May 2012 where Mr. Dell has led the firm’s focus on investing directly in low cost oil and gas assets, managing a team with significant in-house expertise and experience in geological evaluation, land acquisition and engineering. Mr. Dell directly oversees the screening and diligence of new geological opportunities as well as the negotiation and execution of investment strategies. Prior to founding Kimmeridge, Mr. Dell served as Co-Head of Energy Investments for AllianceBernstein Holding L.P., a leading global asset management firm, from July 2010 to May 2012. Prior to June 2010, Mr. Dell was a Senior Equity Research Analyst for Oil and Gas Exploration and Production (E&P) at Sanford C. Bernstein & Co. LLC (“Bernstein”), which Mr. Dell joined in March 2003. Prior to joining Bernstein, Mr. Dell was employed at British Petroleum (BP) in its M&A and finance group. Mr. Dell also held positions as an exploration geologist and geophysicist across several of BP’s regional business units starting in August 1998. Mr. Dell currently serves as the Chairman of the Board of Directors of Extraction Oil & Gas, Inc. (NYSE: XOG), a position he has held since January 2021. Mr. Dell holds an undergraduate degree in Earth Sciences from St. Peter’s College, Oxford.

We believe that Mr. Dell’s skills and experience, particularly his specialized knowledge and expertise in the oil and gas industry and background in geology, combined with his understanding of capital markets and career long experience covering the E&P industry qualify him to serve as a member of our board of directors.

Scott S. Nyquist—Director Nominee. Mr. Nyquist has been nominated to serve on our board of directors, commencing on the effective date of the registration statement of which this prospectus is a part. Mr. Nyquist has served as Director Emeritus-Senior Advisor at McKinsey and Company (“McKinsey”) since February 2019, having served as a senior partner since June 1997. Mr. Nyquist joined McKinsey in September 1984 as an associate, became a partner in June 1990 and a senior partner in June 1997. During his 35-year tenure with McKinsey, Mr. Nyquist was responsible for advising integrated oil and gas companies, national oil companies, power companies and utilities, and independent downstream, midstream and upstream oil and gas companies on matters of strategy, organization and performance improvements. Mr. Nyquist’s leadership positions included directing McKinsey’s European and America’s Oil and Gas practices, co-leading their Global Energy and Materials sector and Sustainability and Resource productivity practices, and serving as an elected member of McKinsey’s board of directors from June 2011 until June 2017. Prior to joining McKinsey, Mr. Nyquist was a Design Engineer for Exxon Corporation (ExxonMobil). Mr. Nyquist has been a member of the Shareholder Committee of Wintershall DEA since May 2019 and is also an active leader with multiple community based educational and economic organizations. Mr. Nyquist holds a Bachelor of Science degree in Chemical Engineering from the University of Michigan and a Masters of Business Administration from Harvard Business School.

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We believe that Mr. Nyquist’s significant and extensive experience advising multiple companies across the breadth of the oil and gas industry, combined with his understanding and background in engineering will bring proven leadership and business and industry acumen to the board of directors and us and make him strongly qualified to serve as a member of our board of directors.

Alice E. Gould—Director Nominee. Ms. Gould has been nominated to serve on our board of directors, commencing on the effective date of the registration statement of which this prospectus is a part. She joined the Board of Directors of CorePoint Lodging Inc., a publicly-traded select service lodging REIT (NYSE: CPLG) spun off from La Quinta Hotels, in 2018 and serves on its Compensation and Nominating and Corporate Governance Committees. Ms. Gould is a former Investment Manager at DUMAC Inc., a professionally staffed investment office controlled by Duke University that manages over $18 billion of endowment and other Duke-related assets, where Ms. Gould worked from 2004 to 2018 and had responsibility for the evaluation, selection and monitoring of energy and natural resources investments. Prior to her role at DUMAC, Ms. Gould was a management consultant assisting senior executives in the technology, pharmaceutical, media and financial industries with strategic initiatives. Ms. Gould also worked for ten years at International Business Machines Corporation (NYSE: IBM) where she managed product development, marketing and business planning. Ms. Gould has served on the advisory board of over 20 private equity and real assets partnerships in the U.S. and abroad. Ms. Gould received a B.S. in Engineering from Duke University (magna cum laude) and an MBA from The Fuqua School of Business at Duke University, where she was a Fuqua Scholar.

We believe that Ms. Gould’s leadership skills and experience, including serving on another corporate board of directors and its key committees, as well as her asset allocation expertise and significant experience evaluating and monitoring energy and natural resource investments qualify her to serve as a member of our board of directors.

Erik C. Belz—Director Nominee. Mr. Belz has been nominated to serve on our board of directors, commencing on the effective date of the registration statement of which this prospectus is a part. Mr. Belz is a Managing Director in the Private Equity Group at Blackstone. Since joining Blackstone in 2014, Mr. Belz has focused on investments in the upstream and midstream energy sectors and has been involved in each of Blackstone private equity’s investments in the Permian Basin, including EagleClaw Midstream Ventures, Guidon Energy, Swallowtail Royalties, Waterfield Midstream, Permian Highway Pipeline, Grand Prix NGL Pipeline, Jetta Permian, Primexx Energy Partners and Rock Ridge Royalties, in addition to his involvement in Falcon Minerals and Cheniere Energy among others. Before joining Blackstone, from 2011 to 2014, Mr. Belz was a Vice President at Blue Water Energy, an energy-focused private equity fund based in London. Prior to that, Mr. Belz was an Associate at the First Reserve Corporation, an energy-focused private equity firm. Mr. Belz began his career as an Investment Banking Analyst at Lehman Brothers in the Natural Resources, Mergers and Acquisitions Group. Mr. Belz currently serves on the board of directors of Falcon Minerals Corp, a position he has held since April 2021, EagleClaw Midstream, Primexx Energy Partners and Swallowtail Royalties. Mr. Belz received an AB in Economics cum laude with a concentration in Government from Harvard College, where he graduated with high honors.

We believe that Mr. Belz’s skills and experience, particularly his broad knowledge of the industry and experience with oil and gas investments, will bring valuable insights to the board of directors and qualify him to serve on our board of directors.

Allen W. Li—Director Nominee. Mr. Li has been nominated to serve on our board of directors, commencing on the effective date of the registration statement of which this prospectus is a part. Mr. Li is a Senior Vice President in the Opportunities Funds at Oaktree Capital. He currently serves on the Board of Directors of Battalion Oil Corporation (NYSE: BATL), PHI Group, Source Energy, Sierra Energy and Fourpass Energy. Prior to joining Oaktree Capital in 2014, Mr. Li worked in the Investment Banking Division at Goldman Sachs. He holds a Bachelor of Science in Business Administration from the University of Southern California.

We believe that Mr. Li’s skills and experience, particularly his financial expertise and investment banking experience, his experience serving on public company boards and his industry knowledge, make him well qualified to serve as a member of our board of directors.

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Board of Directors

In connection with this offering, we will enter into a director designation agreement with Kimmeridge, Blackstone and Source. Pursuant to the director designation agreement, our board of directors will initially consist of eight directors, two of whom will be designated by Kimmeridge, one of whom will be designated by Blackstone and one of whom will be designated by Source. In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board of directors’ ability to manage and direct our affairs and business, including, when applicable to enhance the ability of the committees of the board of directors to fulfill their duties. Our board of directors will be comprised of a single class of directors, all of whom will hold office until the next annual meeting of stockholders or until the earlier of their death, resignation, retirement, the expiration of term of service, disqualification or removal or until their successors have been duly elected and qualified. It is expected that our directors will serve for a maximum of seven years, but that at least two of our directors will retire within five years so as to provide for a more seamless transition.

Director Independence

We expect that our board of directors will determine that Morris R. Clark, Scott S. Nyquist, Alice E. Gould, Erik C. Belz and Allen W. Li are independent within the meaning of the NYSE listing standards currently in effect and Rule 10A-3 of the Exchange Act.

Committees of the Board of Directors

Our board of directors will have an audit committee, a nominating and corporate governance committee and a compensation committee and may establish such other committees as it determines necessary or advisable from time to time.

Audit Committee

Our audit committee will be comprised of Morris R. Clark, Alice E. Gould and Scott S. Nyquist, with Mr. Clark serving as Chair. We expect that our board of directors will determine that each of the members of our audit committee satisfies the independence standards established by NYSE and the Exchange Act. Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit committee.

Compensation Committee

We will establish a compensation committee prior to completion of this offering. We anticipate that the compensation committee will consist of Alice E. Gould, Morris R. Clark and Erik C. Belz, all of whom will be “independent” under the rules of the SEC, the Sarbanes-Oxley Act and the NYSE. Ms. Gould will serve as Chair. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans. We expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC, the PCAOB and applicable stock exchange or market standards.

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Nominating and Corporate Governance Committee

We will establish a nominating and corporate governance committee prior to completion of this offering. We anticipate that the nominating and corporate governance committee will consist of Scott S. Nyquist, Erik C. Belz and Allen W. Li, all of whom will be “independent” under the rules of the SEC, the Sarbanes-Oxley Act and the NYSE. Mr. Nyquist will serve as Chair. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors; develop and oversee our internal corporate governance processes; and maintain a management succession plan. We expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE standards.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board of directors or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of NYSE.

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EXECUTIVE COMPENSATION

Desert Peak Minerals was incorporated as a Delaware corporation by KMF in anticipation of this offering and had not yet commenced independent operations prior to the consummation of this offering. As a result, we have no historical compensation information to present. Desert Peak Minerals will begin to operate independently from Kimmeridge as of the date of this offering. For all periods prior to 2021, KMF was operated by employees and officers of Kimmeridge.

For all periods prior to the formation of Desert Peak Minerals, KMF was operated by employees and officers of Kimmeridge and it is currently expected that Desert Peak Minerals will continue to be operated by employees and officers of Kimmeridge following the date of this offering through the end of fiscal year 2021. These employees and officers are employed and compensated by Kimmeridge and perform services for Desert Peak Minerals pursuant to the terms and conditions of the services agreement between Kimmeridge and Desert Peak Minerals (the “Services Agreement”). Under the Services Agreement, Desert Peak Minerals will pay or reimburse Kimmeridge for certain allocated compensation expenses such as salaries for the employees and officers who perform services for Desert Peak Minerals. Any compensation paid to the employees and officers of Kimmeridge who perform services for Desert Peak Minerals is paid by, and solely in the discretion of, Kimmeridge and Desert Peak Minerals does not make any decisions regarding such compensation.

As an “emerging growth company” within the meaning of the JOBS Act, for future periods, we will be required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table covering the compensation of our principal executive officer and, generally, our next two other most highly compensated executive officers at the end of each completed fiscal year, whom we will refer to as our “named executive officers.”

As a general matter, compensation for our named executive officers will be determined by the Board of Directors on an annual basis and will be structured with a view toward the following goals and themes:

• Absolute Performance Metrics. As detailed below, we expect that a significant portion of our named executive officers’ compensation will initially be based on absolute total stockholder return (“TSR”) measured over a three-year performance period. This approach is designed with the goal of ensuring that the interests of our management team will be aligned with those of our stockholders. We believe that leadership should be rewarded for outperformance that creates value for our stockholders. We do not believe that compensation structures that reward relative outperformance serve to encourage leadership to work to unlock shareholder value and as such we do not presently plan on incorporating relative TSR into our compensation metrics.

• Alignment with Stockholders. In addition to structuring our executive team’s compensation to be comprised of a base salary and long-term equity-based incentive compensation linked to absolute TSR performance, we presently expect that all equity compensation will be subject to multi-year vesting periods. We believe this will further foster alignment with stockholders and encourage retention.

• Corporate Governance. We expect to structure our executive compensation policy in a manner that is designed to convey a straightforward and clear approach that we believe encourages and supports our philosophy on corporate governance.

We expect that our named executive officers will receive an annual base salary, will be eligible to receive equity-based long-term incentive awards and will participate in employee benefits on the same basis as other employees. We expect that approximately 75% of the initial equity-based awards that we intend to grant in connection with the consummation of this offering will be based on absolute TSR performance and approximately 25% will be subject to time-based vesting, as described in further detail below under “—IPO Awards.” In addition, it is expected that our executive officers will receive one-time cash awards prior to the consummation of this offering, as described in further detail below under “IPO Awards.” Below is a description

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of the anticipated compensation programs and practices for our executive officers, who are the individuals who will be eligible to qualify as our named executive officers in the future. As we grow as an independent company, our compensation programs and practices may evolve and change and may, in the future, include different elements and items of compensation from those described herein.

Base Salary

Effective upon the consummation of this offering, the annualized base salary of our executive officers is currently expected to be set as follows:

Name	Base Salary
Christopher L. Conoscenti—Chief Executive Officer and Director Nominee	$	500,000
Carrie L. Osicka—Chief Financial Officer	$	375,000
Britton L. James—Vice President of Land	$	325,000
Jarret J. Marcoux—Vice President of Engineering and Acquisitions	$	325,000
Brett S. Riesenfeld—General Counsel and Secretary	$	325,000

Cash Bonuses

We do not currently expect to pay cash bonuses to our executive officers pursuant to a formal bonus program.

Equity Compensation and Long-Term Incentives

Our executive officers have not previously received any compensation, including equity compensation and long-term incentive awards, in or from Desert Peak Minerals. However, following the consummation of this offering, our executive officers will be eligible to participate in the equity and long-term incentive compensation programs that we intend to establish, which are expected to consist of awards granted under the 2021 Plan (as defined under “—2021 Long Term Incentive Plan” below) that we intend to adopt in connection with this offering and our executive officers are expected to receive grants of equity pursuant to the 2021 Plan in connection with this offering as described below in “IPO Awards.”

Other Benefits

It is expected that participation in broad-based retirement, health and welfare plans will be offered to all of our employees, including our executive officers who are eligible to participate in such plans on the same basis as all other employees. This is expected to include a plan intended to provide benefits under section 401(k) of the Internal Revenue Code of 1986, as amended, where employees are allowed to contribute portions of their base compensation into a retirement account in order to encourage all employees, including any participating executive officers, to save for the future. It is anticipated that a competitive matching contribution based on a portion of an employee’s eligible compensation will also be provided.

IPO Awards

One-time Equity Awards

In connection with this offering, we intend to grant one-time equity-based awards (each, an “IPO Equity Award”) to our executive officers under the 2021 Plan (which is described in more detail below under—2021 Long Term Incentive Plan), which IPO Equity Awards will consist of restricted stock units (“RSUs”) subject to time-based vesting.

The IPO Equity Award granted to each of our executive officers is expected to consist of a number of RSUs equal to $1,500,000 for Mr. Conoscenti and 100% of base salary for each of Ms. Osicka and Messrs. James,

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Marcoux and Riesenfeld, in each case, divided by an assumed initial offering price of $21.50 per share (the midpoint of the price range set forth on the cover page of this prospectus). As such, we expect that approximately 132,556 RSUs will be subject to the IPO Equity Awards, which consists of 69,767 RSUs to be issued to Mr. Conoscenti, 17,441 RSUs to be issued to Ms. Osicka, 15,116 RSUs to be issued to Mr. James, 15,116 RSUs to be issued to Mr. Marcoux, and 15,116 RSUs to be issued to Mr. Riesenfeld.

The IPO Equity Awards are expected to vest in full on the first anniversary of the applicable date of grant, so long as the executive officer remains continuously employed by us through such vesting date. Vesting of the IPO Equity Awards will accelerate in full upon a termination by us of the recipient’s employment without cause or, following a change in control of us, by the recipient for good reason.

2021 Equity Awards

Shortly following the consummation of this offering, we intend to grant annual equity-based awards (each, an “Annual Equity Award”) in respect of calendar year 2021 to our executive officers under the 2021 Plan, which Annual Equity Awards will consist of RSUs subject to time-based vesting, representing 25% of each individual’s Annual Equity Award (other than Mr. Riesenfeld, who will receive RSUs that represent 37.5% of his Annual Equity Award), and performance stock units (“PSUs”), representing 75% of each individual’s Annual Equity Award (other than Mr. Riesenfeld, who will receive PSUs representing 62.5% of his Annual Equity Award).

The total value of the Annual Equity Award granted to each of our executive officers is expected to be equal to $4,000,000 for Mr. Conoscenti, $2,250,000 for Ms. Osicka and $1,950,000 for each of Messrs. Riesenfeld, Marcoux and James. The value of the portion of the Annual Equity Award comprised of RSUs granted to each of our executive officers is expected to be equal to $1,000,000 for Mr. Conoscenti, $562,500 for Ms. Osicka, $487,500 to each of Messrs. James and Marcoux and $731,250 to Mr. Riesenfeld. The value of the portion of the Annual Equity Award comprised of PSUs (based on target performance) granted to each of our executive officers is expected to be equal to $3,000,000 for Mr. Conoscenti, $1,687,500 for Ms. Osicka, $1,462,500 to each of Messrs. James and Marcoux and $1,218,750 to Mr. Riesenfeld. The number of RSUs and PSUs (based on target performance, or “Target PSUs”) granted to each of the executive officers will be equal to the applicable value described above for such executive officer divided by the volume-weighted average price of the Class A common stock for the 10-day period beginning on the date of the consummation of this offering.

The RSUs are expected to vest in equal installments on the first three anniversaries of the applicable date of grant, so long as the executive officer remains continuously employed by us through each vesting date. Vesting of RSUs will accelerate in full upon a termination by us of the recipient’s employment without cause or, following a change in control of us, by the recipient for good reason.

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The PSUs will be eligible to be earned based on achievement of certain pre-established goals for annualized absolute TSR over a three-year period following the consummation of this offering or such shorter period through the date of a change in control of us or the recipient’s termination of employment by us without cause. Upon the termination of a recipient’s employment by us without cause or by the recipient for good reason that occurs during the period beginning on the date that a change in control of us occurs and ending on the date that is six months following the date that a change in control occurs (the “PSU CIC Period”), then a number of PSUs will become earned based on the greater of (i) target performance or (ii) actual performance and achievement of the applicable performance goals through the date of the change in control. Upon the termination of a recipient’s employment by us without cause or by the recipient for good reason that occurs outside of the PSU CIC Period, or that occurs due to death or disability at any time, then a pro-rata number of PSUs (calculated based on the number of days that the recipient was employed by us during the applicable performance period) will remain outstanding and will become earned based on actual performance and achievement of the applicable performance goals through the end of the applicable performance period. The expected performance targets associated with the PSU award structure are outlined below:

	Annualized Absolute TSR Goal			Percentage of Target PSUs Earned
Base of Range		Less than 0	%		0	%
Threshold		0	%		50	%
Target		10	%		100	%
Maximum		20	%		200	%

For purposes of determining our annualized absolute TSR over the performance period, the beginning stock price will be based on our 20-day volume weighted average stock price beginning on the day after the consummation of this offering and the ending price will generally be based on the 20-day volume weighted average stock price ending on the last day of the performance period. PSU payouts for results that fall in between a stated threshold will be interpolated linearly.

One-time Cash Awards

In addition, in connection with this offering, we expect to grant one-time cash awards to our executive officers prior to the consummation of this offering in recognition of efforts and contributions relating to this offering. The aggregate amount of such awards will equal $1,600,000. Mr. Conoscenti will receive an award of $600,000 and Ms. Osicka and each of Messrs. James, Marcoux and Riesenfeld will receive an award of $250,000.

2021 Long Term Incentive Plan

In connection with this offering, we intend to adopt an omnibus equity incentive plan, the Desert Peak Minerals Inc. 2021 Long Term Incentive Plan (the “2021 Plan”). The following description of the 2021 Plan is based on the form we anticipate adopting, but the 2021 Plan has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final form of the 2021 Plan once adopted.

While the initial awards expected to be granted upon consummation of this offering will be in the form of RSUs and PSUs, the 2021 Plan will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“incentive options”); (ii) stock options that do not qualify as incentive stock options (“nonstatutory options” and, together with incentive options, “options”); (iii) stock appreciation rights (“SARs”); (iv) restricted stock awards (“restricted stock awards”); (v) restricted stock units (“restricted stock units” or “RSUs”); (vi) dividend equivalents; (vii) other stock or cash-based awards; and (viii) substitute awards (referred to collectively herein with the other awards as the “awards”). The vesting, exercise or settlement of awards may be subject to the achievement of one or more performance criteria selected by the Administrator (as defined below).

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Eligibility

Our employees, consultants and non-employee directors, and employees, consultants and non-employee directors of our affiliates, will be eligible to receive awards under the 2021 Plan.

Administration

Our board of directors, or a committee thereof (as applicable, for purposes of the 2021 Plan, the “Administrator”), will administer the 2021 Plan pursuant to its terms and all applicable state, federal or other rules or laws. The Administrator will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common stock), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting or exercisability of an award, delegate duties under the 2021 Plan and execute all other responsibilities permitted or required under the 2021 Plan.

Securities to be Offered

Subject to adjustment in the event of any distribution, recapitalization, split, merger, consolidation or similar corporate event, 6,350,000 shares of our Class A common stock will be available for delivery pursuant to awards under the 2021 Plan. If an award under the 2021 Plan is forfeited, settled for cash or expires without the actual delivery of shares, any shares subject to such award will again be available for new awards under the 2021 Plan.

Types of Awards

While we expect the awards to be granted upon consummation of this offering to be comprised solely of RSUs and PSUs, the 2021 Plan will allow for the Administrator to grant certain other types of awards, including the following:

Restricted stock units (RSUs). RSUs are rights to receive common stock, cash, or a combination of both at the end of a specified period. The Administrator may subject RSUs to restrictions (which may include a risk of forfeiture) to be specified in the RSU award agreement, and those restrictions may lapse at such times determined by the Administrator. Restricted stock units may be settled by delivery of common stock, cash equal to the fair market value of the specified number of shares of common stock covered by the RSUs, or any combination thereof determined by the Administrator at the date of grant or thereafter. Dividend equivalents on the specified number of shares of common stock covered by RSUs may be paid on a current, deferred or contingent basis, as determined by the Administrator on or following the date of grant.

Options. We may grant options to eligible persons including: (i) incentive options (only to our employees or those of our subsidiaries) which comply with Section 422 of the Code; and (ii) nonstatutory options. The exercise price of each option granted under the 2021 Plan will be stated in the option agreement and may vary; however, the exercise price for an option must not be less than the fair market value per share of common stock as of the date of grant (or 110% of the fair market value for certain incentive options). Options may be exercised as the Administrator determines, but not later than ten years from the date of grant. The Administrator will determine the methods and form of payment for the exercise price of an option (including, in the discretion of the Administrator, payment in common stock, other awards or other property) and the methods and forms in which common stock will be delivered to a participant.

SARs. A SAR is the right to receive a share of common stock, or an amount equal to the excess of the fair market value of one share of the common stock on the date of exercise over the grant price of the SAR, as determined by the Administrator. The exercise price of a share of common stock subject to the SAR shall be determined by the Administrator, but in no event shall that exercise price be less than the fair market value of the common stock on the date of grant. The Administrator will have the discretion to determine other terms and conditions of an SAR award.

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Restricted stock awards. A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the Administrator in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the Administrator. Except as otherwise provided under the terms of the 2021 Plan or an award agreement, the holder of a restricted stock award will have rights as a stockholder, including the right to vote the common stock subject to the restricted stock award or to receive dividends on the common stock subject to the restricted stock award during the restriction period. The Administrator shall provide, in the restricted stock award agreement, whether the restricted stock will be forfeited upon certain terminations of employment. Unless otherwise determined by the Administrator, common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, will be subject to restrictions and a risk of forfeiture to the same extent as the restricted stock award with respect to which such common stock or other property has been distributed.

Dividend Equivalents. Dividend equivalents entitle a participant to receive cash or common stock equal in value to dividends paid with respect to a specified number of shares of our common stock. Dividend equivalents may be granted in connection with RSUs.

Other Stock or Cash-Based Awards. Other stock or cash-based awards are awards of cash, fully vested shares of our common stock and other awards valued wholly or partially by referring to, or otherwise based on, shares of our common stock. Other stock or cash-based awards may be granted to participants and may also be available as a payment form in the settlement of other awards, as standalone payments and as payment in lieu of base salary, bonus, fees or other cash compensation otherwise payable to any individual who is eligible to receive awards. The Administrator will determine the terms and conditions of other stock or cash-based awards, which may include vesting conditions based on continued service, performance and/or other conditions.

Substitute Awards. Awards may be granted in substitution or exchange for any other award granted under the 2021 Plan or under another equity incentive plan or any other right of an eligible person to receive payment from us. Awards may also be granted under the 2021 Plan in substitution for similar awards held for individuals who become participants as a result of a merger, consolidation or acquisition of another entity by or with the Company or one of our affiliates.

Provisions of the 2021 Plan Relating to Director Compensation

The 2021 Plan provides that the Administrator may establish compensation for non-employee directors from time to time subject to the 2021 Plan’s limitations. Prior to commencing this offering, our stockholders are expected to approve the initial terms of our non-employee director compensation policy, which is described below under the heading “—Director Compensation.” Our board of directors or its authorized committee may modify the non-employee director compensation policy from time to time in the exercise of its business judgment, taking into account such factors, circumstances and considerations as it shall deem relevant from time to time, provided that the sum of any cash compensation or other compensation and the grant date fair value (as determined in accordance with FASB ASC 718, or any successor thereto) of any awards granted under the 2021 Plan as compensation for services as a non-employee director during any fiscal year may not exceed $750,000, increased to $1,000,000, in the first fiscal year of a non-employee director’s initial service as a non-employee director. The Administrator may make exceptions to this limit for individual non-employee directors in extraordinary circumstances, as the Administrator may determine in its discretion, provided that the non-employee director receiving such additional compensation may not participate in the decision to award such compensation or in other contemporaneous compensation decisions involving non-employee directors.

Certain Transactions

If any change is made to our capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the

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number of outstanding shares of common stock, appropriate adjustments will be made by the Administrator in the shares subject to an award under the 2021 Plan. The Administrator will also have the discretion to make certain adjustments to awards in the event of a change in control, such as accelerating the vesting or exercisability of awards, requiring the surrender of an award, with or without consideration, or making any other adjustment or modification to the award that the Administrator determines is appropriate in light of such transaction.

Plan Amendment and Termination

Our board of directors may amend or terminate the 2021 Plan at any time; however, stockholder approval will be required for any amendment to the extent necessary to comply with applicable law or exchange listing standards. The Administrator will have the authority, without the approval of stockholders, to amend any outstanding stock option or stock appreciation right to reduce its exercise price per share. The 2021 Plan will remain in effect for a period of ten years (unless earlier terminated by our board of directors).

Clawback

All awards under the 2021 Plan will be subject to any clawback or recapture policy adopted by the Company, as in effect from time to time.

Severance Plan

We believe that it is important to provide our executive officers with certain severance and change in control payments and benefits in order to establish a stable work environment for the individuals responsible for our day to day management. We historically have not maintained any employment, severance or change in control agreements with any of our executive officers. However, in order to better assist us in our above-stated goal, we expect to adopt the Desert Peak Minerals Inc. Severance Plan (the “Severance Plan”), which will cover our executive officers. The following description of the Severance Plan is based on the form we anticipate adopting, but the Severance Plan has not yet been adopted and the provisions discussed below remain subject to change. As a result, the following description is qualified in its entirety by reference to the final Severance Plan once adopted.

The Severance Plan provides certain severance and change in control payments and benefits to our executive officers and certain other individuals who are selected for participation by our board of directors, or a committee thereof (as applicable, for purposes of the Severance Plan, the “Administrator”).

If a participant’s employment with us is terminated by us without cause or by the participant for good reason during the period beginning on the date that a change in control of us occurs and ending on the date that is six months following the date that a change in control occurs (the “CIC Period”), the participant is entitled to receive: (i) an amount equal to (a) 36 months of base salary for Mr. Conoscenti or (b) 24 months of base salary for all other participants, in each case, paid in a lump sum, and (ii) all unvested equity-based awards granted under the 2021 Plan that are held by the participant immediately prior to the termination date shall immediately become fully vested, provided that any equity-based awards that are subject to performance-based vesting conditions shall be calculated and settled, without proration, based on the greater of (x) target performance and (y) actual performance and achievement of the applicable performance goals through the date of the change in control.

If a participant’s employment with us is terminated by us without cause or by the participant for good reason outside of the CIC Period, or due to death or disability at any time, the participant is entitled to receive: (i) an amount equal to (a) 24 months of base salary for Mr. Conoscenti or (b) 18 months of base salary for all other participants, in each case, payable in monthly installments, and (ii) all unvested equity-based awards granted

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under the 2021 Plan that are held by the participant immediately prior to the termination date shall immediately become fully vested, provided that, with respect to any equity-based awards that are subject to performance-based vesting conditions, a pro-rata amount of such award (calculated based on the number of days that the participant was employed by us during the applicable performance period) will remain outstanding and will become earned based on actual performance and achievement of the applicable performance goals through the end of the applicable performance period.

The Severance Plan does not provide a tax gross-up provision for federal excise taxes that may be imposed under section 4999 of the Code. Instead, the Severance Plan includes a “best of net” provision, which states that, if amounts payable to a plan participant under the Severance Plan (together with any other amounts that are payable by us as a result of a change in control (the “Payments”) exceed the amount allowed under section 280G of the Code for such participant, thereby subjecting the participant to an excise tax under section 4999 of the Code, then the Payments will either be: (i) reduced to the level at which no excise tax applies, such that the full amount of the Payments would be equal to $1 less than three times the participant’s “base amount,” which is generally the average W-2 earnings for the five calendar years immediately preceding the date of termination, or (ii) paid in full, which would subject the participant to the excise tax.

The Severance Plan contains restrictive covenants that apply to participants, including confidentiality, non-competition (which applies for three months following a participant’s termination of employment) and non-solicitation (which applies for 12 months following a participant’s termination of employment).

Director Compensation

Desert Peak Minerals, the issuer of Class A common stock in this offering, was formed by KMF in anticipation of this offering. No obligations with respect to compensation for directors have been accrued or paid for any periods prior to the consummation of this offering. Individuals serving on the board of managers of our predecessor did not receive any compensation for their services on such board during fiscal year 2020.

Going forward, we believe that attracting and retaining qualified non-employee directors will be critical to our ability to grow in a manner that is consistent with our corporate governance principles and that is designed to create value for our stockholders. We also believe that structuring director compensation with a significant equity component is key to achieving our goals. We believe that this structure will also allow directors to carry out their responsibilities with respect to oversight of the Company while also maintaining alignment with stockholder interests and fiduciary obligations. We anticipate that embedding these core principles and values of alignment and solid governance will enhance our ability to grow and unlock value for stockholders. Accordingly, in connection with this offering, we intend to implement a comprehensive director compensation policy for our non-employee directors, which is expected to consist of:

• no annual cash retainer for non-employee directors;

• an annual cash payment of $25,000 to the chair of the Audit Committee;

• an annual cash payment of $20,000 to the chair of the Compensation Committee;

• an annual cash payment of $15,000 to the chair of the Nominating and Corporate Governance Committee; and

• an annual equity-based award granted to each non-employee director under the 2021 Plan with an aggregate fair market value of approximately $300,000 on the date of grant, which award is expected to consist of deferred share units (“DSUs”) that vest quarterly over a one-year period.

In connection with this offering, we expect to grant 24,418 DSUs under the 2021 Plan to each of our non-employee directors, which has a total value of $525,000 (based on an assumed initial offering price of $21.50 per share (the midpoint of the price range set forth on the cover page of this prospectus)) and reflects a pro-rated

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award of $225,000 for the period from the anticipated consummation of this offering to the date of the 2022 annual meeting of stockholders and a full annual award of $300,000 in respect of the year from the date of the 2022 annual meeting of stockholders to the date of the 2023 annual meeting of stockholders. The DSUs are expected to vest in equal quarterly installments over the one-year period beginning on the applicable date of grant. It is also expected that the DSUs granted to our non-employee directors in connection with this offering will vest in full upon the termination of a recipient’s service relationship by us for any reason within 12 months following a change in control of us, or due to death or disability at any time. Any vested DSUs will be settled in shares of our Class A common stock when a recipient’s service relationship is terminated for any reason.

Each director other than Messrs. Lockshin and Dell will be expected to hold shares of our Class A common stock in an amount equal to five times the annual cash retainer paid to such director for the prior year.

We also expect that our non-employee directors will be reimbursed for certain reasonable expenses incurred in connection with their services to us.

Directors who are also our employees will not receive any additional compensation for their service on our board of directors.

Term Limit. We presently anticipate that our directors will serve for a maximum of seven years but that at least two of our directors will retire within five years so as to provide for a more seamless transition. We do not expect to maintain a mandatory retirement age for our directors.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our Class A common stock and Class B common stock that, upon the consummation of our corporate reorganization and this offering and without giving effect to the Existing Owner Distribution, will be owned by:

• each person known to us who beneficially owns more than 5% of any class of our outstanding shares of common stock;

• each of our directors and our director nominees;

• each of our named executive officers; and

• all of our directors, director nominees and executive officers as a group.

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, directors, director nominees or executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o Desert Peak Minerals Inc., 1144 15th Street, Suite 2650, Denver, Colorado 80202.

To the extent that the underwriters sell more than shares of Class A common stock, the underwriters have the option to purchase up to 1,500,000 additional shares from us. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The table below does not reflect any shares of Class A common stock that directors, director nominees and executive officers may purchase in this offering through the directed share program described under “Underwriting (Conflicts of Interest)—Directed Share Program” or any shares to be issued pursuant to the 2021 Plan.

	Shares Beneficially  Owned After this Offering (No Exercise)														Shares Beneficially  Owned After this Offering (Full Exercise)
Name of Beneficial Owner(1)	Class A Common Stock				Class B Common Stock					Combined Voting Power(3)					Class A Common Stock				Class B Common Stock					Combined Voting Power(3)
	Number		%		Number		%			Number		%			Number		%		Number		%			Number		%
5% Stockholders:
Kimmeridge Funds(2)(4)		—		—		30,810,000		59.3	%		30,810,000		49.7	%		—		—		30,810,000		59.3	%		30,810,000		48.5	%
Rock Ridge Royalty Company LLC(5)		—		—		10,270,000		19.8	%		10,270,000		16.6	%		—		—		10,270,000		19.8	%		10,270,000		16.2	%
Oaktree Capital Management(6)		—		—		10,920,000		21.0	%		10,920,000		17.6	%		—		—		10,920,000		21.0	%		10,920,000		17.2	%
Named Executive Officers, Directors and Director Nominees:
Christopher L. Conoscenti(7)		—		—		—		—			—		—			—		—		—		—			—		—
Carrie L. Osicka		—		—		—		—			—		—			—		—		—		—			—		—
Britton L. James		—		—		—		—			—		—			—		—		—		—			—		—
Jarret J. Marcoux		—		—		—		—			—		—			—		—		—		—			—		—
Brett S. Riesenfeld		—		—		—		—			—		—			—		—		—		—			—		—
Noam Lockshin(4)		—		—		30,810,000		59.3	%		30,810,000		49.7	%		—		—		30,810,000		59.3	%		30,810,000		48.5	%
Morris R. Clark		—		—		—		—			—		—			—		—		—		—			—		—
Benjamin P. Dell(4)		—		—		30,810,000		59.3	%		30,810,000		49.7	%		—		—		30,810,000		59.3	%		30,810,000		48.5	%
Scott S. Nyquist		—		—		—		—			—		—			—		—		—		—			—		—
Alice E. Gould		—		—		—		—			—		—			—		—		—		—			—		—
Allen W. Li		—		—		—		—			—		—			—		—		—		—			—		—
Erik C. Belz		—		—		—		—			—		—			—		—		—		—			—		—
All Executive Officers, Directors and Director Nominees (12 persons)		—		—		30,810,000		59.3	%		30,810,000		49.7	%		—		—		30,810,000		59.3	%		30,810,000		48.5	%

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(1) The amounts and percentages of Class A common stock and Class B common stock beneficially owned are reported on the basis of regulation of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of Class A common stock and Class B common stock, except to the extent this power may be shared with a spouse.

(2) Subject to the terms of the Opco LLC Agreement, our Existing Owners, subject to certain limitations, will have the right to require Opco to redeem all or a portion of their Opco Units for shares of Class A common stock at a redemption ratio of one share of Class A common stock for each Opco Unit redeemed. See “Certain Relationships and Related Person Transactions—Opco LLC Agreement.” Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person, directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise has or shares voting power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership of such security within 60 days. We have the option to deliver cash in lieu of shares of Class A common stock upon exercise by our Existing Owners of the Redemption Right. As a result, beneficial ownership of Class B common stock and Opco Units is not reflected as beneficial ownership of shares of our Class A common stock for which such units and stock may be redeemed.

(3) Represents percentage of voting power of our Class A common stock and Class B common stock voting together as a single class. Each of the Existing Owners will hold one share of Class B common stock for each Opco Unit that it owns. Each share of Class B common stock has no economic rights, but entitles the holder thereof to one vote for each share of Class B common stock held by such holder. The number of shares of Class A common stock, Class B common stock and Opco Units to be issued to the Existing Owners is based on the implied equity value of Opco immediately prior to this offering, based on an initial public offering price of $21.50 per share of Class A common stock, the midpoint of the price range set forth on the cover page of this prospectus. See “Corporation Reorganization,” “Description of Capital Stock—Class A Common Stock” and “Description of Capital Stock—Class B Common Stock.”

(4) Includes 27,266,850 shares directly held by KMF DPM HoldCo, LLC (“KMF HoldCo”) and 3,543,150 shares directly held by Chambers DPM HoldCo, LLC (“Chambers HoldCo”). KMF HoldCo is wholly owned by Kimmeridge Mineral Fund, LP (“KMF”). KMF is controlled by Kimmeridge Energy Management Company, LLC (“Kimmeridge”). Kimmeridge Mineral GP, LLC serves as the general partner of KMF and has delegated day to day investment management responsibilities for KMF to Kimmeridge. The KMF Investment Committee maintains investment discretion for KMF and is comprised of Benjamin P. Dell, Henry Makansi, Neil McMahon and Noam Lockshin, each of whom are managing members of Kimmeridge. Each of the foregoing entities and individuals disclaims beneficial ownership of the securities held by KMF HoldCo (other than KMF HoldCo to the extent of its direct holdings). Chambers HoldCo is owned by Kimmeridge Energy Exploration Fund V, LP, Kimmeridge Energy Net Profits Interest Fund V, LP and Kimmeridge Chambers Co-Invest, L.P. (each, a “Fund V Entity” and together, “Kimmeridge Fund V”). Kimmeridge Fund V is controlled by Kimmeridge. KEMC Fund V GP, LLC serves as the general partner of each of the Fund V Entities and has delegated day to day investment management responsibilities to Kimmeridge. The Kimmeridge Fund V Investment Committee maintains investment discretion for Kimmeridge Fund V and is comprised of Benjamin P. Dell, Neil McMahon, Henry Makansi, Noam Lockshin and Alexander Inkster, each of whom are managing members of Kimmeridge. Each of the foregoing entities and individuals disclaims beneficial ownership of the securities held by Chambers HoldCo (other than Chambers HoldCo to the extent of its direct holdings). Kimmeridge is wholly owned by its managing members and/or related entities. The principal business address of these entities is c/o Kimmeridge Energy Management Company, LLC, 412 West 15th Street, 11th Floor, New York, New York 10011.

(5) Rock Ridge Royalty Company LLC (the “Rock Ridge Royalty Entity”) directly holds the reported shares shown above. Rock Ridge Royalty Company LLC is controlled by RRR Energy LLC. RRR Aggregator LLC is the sole member of RRR Energy LLC. BX Primexx Topco LLC is the sole member of RRR Aggregator LLC. BCP VII/BEP II Holdings Manager L.L.C. is the managing member of BX Primexx Topco LLC. Blackstone Energy Management Associates II L.L.C. and Blackstone Management Associates VII L.L.C. are the managing members of BCP VII/BEP II Holdings Manager L.L.C. Blackstone EMA II L.L.C. is the sole member of Blackstone Energy Management Associates II L.L.C. BMA VII L.L.C. is the sole member of Blackstone Management Associates VII L.L.C. Blackstone Holdings III L.P. is the managing member of each of Blackstone EMA II L.L.C. and BMA VII L.L.C. The general partner of Blackstone Holdings III L.P. is Blackstone Holdings III GP L.P. The general partner of Blackstone Holdings III GP L.P. is Blackstone Holdings III GP Management L.L.C. Blackstone Inc. is the sole member of Blackstone Holdings III GP Management L.L.C. The sole holder of the Series II preferred stock of Blackstone Inc. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman. Each of the foregoing entities and individuals disclaims beneficial ownership of the securities held directly by the Rock Ridge Royalty Entity (other than the Rock Ridge Royalty Entity to the extent of its direct holdings). The principal business address of these entities is c/o Blackstone Inc., 345 Park Avenue, 31st Floor, New York, New York 10154.

(6) Comprised of 6,230,900 shares held by Source Energy Leasehold, LP and 4,689,100 shares held by Permian Mineral Acquisitions, LP, subsidiaries of Source Energy Partners, LLC. Source Energy Partners, LLC in controlled by OCM Source Holdings, L.P. The general partner of OCM Source Holdings, L.P. is Oaktree Fund GP, LLC. The managing member of Oaktree Fund GP, LLC is Oaktree Fund GP I, L.P. The general partner of Oaktree Fund GP I, L.P. is Oaktree Capital I, L.P. The general partner of Oaktree Capital I, L.P. is OCM Holdings I, LLC. The managing member of OCM Holdings I, LLC is Oaktree Holdings, LLC. The managing member of Oaktree Holdings, LLC is Oaktree Capital Group, LLC. Oaktree Capital Group, LLC is managed by its eleven-member board of directors. Each of the general partners, managing members, and directors listed above disclaims beneficial ownership of the Registrable Securities except to the extent of their respective pecuniary interest therein, if any.

(7) Christopher L. Conoscenti may purchase shares of our Class A common stock in this offering.

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CORPORATE REORGANIZATION

Corporate Reorganization

Desert Peak Minerals was incorporated as a Delaware corporation in April 2019 by KMF. Following this offering and our corporate reorganization, we will be a holding company whose sole material asset will consist of a 16% interest in Opco. Opco will continue to wholly own our operating assets. After the consummation of the transactions contemplated by this prospectus, we will be the sole managing member of Opco and will be responsible for all operational, management and administrative decisions relating to Opco’s business.

In connection with this offering:

• on October 8, 2021, we amended and restated our revolving credit facility to, among other things, provide for the transactions contemplated by our corporate reorganization and this offering as well as to provide for an increased borrowing base;

• on October 27, 2021, we made a distribution of approximately $128 million to the Existing Owners using borrowings under the revolving credit facility and cash on hand;

• Opco and the indirect Existing Owners will enter into a merger agreement pursuant to which Opco will acquire our initial assets (which will not include our predecessor’s water business) and the Existing Owners will acquire 52,000,000 Opco Units in the aggregate and will be admitted as members of Opco;

• we will issue 10,000,000 shares of our Class A common stock to purchasers in this offering in exchange for the proceeds of this offering;

• we will contribute all of the net proceeds of this offering and shares of our Class B common stock to Opco in exchange for a number of Opco Units equal to the number of shares of our Class A common stock outstanding following this offering, and Opco will then distribute a number of shares of our Class B common stock to our Existing Owners equal to the number of Opco Units held by them; and

• Opco will use the net proceeds from this offering to (i) repay all of the outstanding borrowings under our revolving credit facility and (ii) fund future acquisitions of mineral and royalty interests.

To the extent the underwriters’ option to purchase additional shares is exercised in full or in part, we will contribute the net proceeds therefrom to Opco in exchange for an additional number of Opco Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Opco will use any such net proceeds to fund future acquisitions of mineral and royalty interests.

Following this offering, our Existing Owners may distribute all or a portion of their respective Opco Units and a corresponding number of shares of Class B common stock to their partners or members, as applicable, in the Existing Owner Distribution, subject to customary lock-up restrictions. Unless otherwise indicated, the information set forth in this prospectus does not give effect to the Existing Owner Distribution.

After giving effect to these transactions and this offering, without giving effect to the Existing Owner Distribution and assuming the underwriters’ option to purchase additional shares is not exercised:

• Our Existing Owners will own 100% of our Class B common stock representing 84% of our capital stock;

• investors in this offering will own, in the aggregate, 10,000,000 shares, or 100%, of our Class A common stock, representing 16% of our capital stock;

• we will own an approximate 16% interest in Opco; and

• our Existing Owners will own an approximate 84% interest in Opco.

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If the underwriters’ option to purchase additional shares is exercised in full, without giving effect to the Existing Owner Distribution:

• our Existing Owners will own, in the aggregate, 100% of our Class B common stock representing 82% of our capital stock;

• investors in this offering will own, in the aggregate, 11,500,000 shares, or 100%, of our Class A common stock, representing 18% of our capital stock;

• we will own an approximate 18% interest in Opco; and

• our Existing Owners will own, in the aggregate, an approximate 82% interest in Opco.

Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list our Class B common stock on any exchange.

Following this offering, under the Opco LLC Agreement, each Opco Unit Holder will, subject to certain limitations, have a Redemption Right to cause Opco to acquire all or a portion of its Opco Units (together with a corresponding number of shares of Class B common stock) for, at Opco’s election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Opco Unit (and corresponding share of Class B common stock) redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions, or (ii) an equivalent amount of cash. We will determine whether to issue shares of Class A common stock or cash based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A common stock (including trading prices for the Class A common stock at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of preferred stock) to acquire the Opco Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, Desert Peak Minerals (instead of Opco) will have a Call Right to, for administrative convenience, acquire each tendered Opco Unit (and corresponding share of Class B common stock) directly from the redeeming Opco Unit Holder for, at its election, (x) one share of Class A common stock or (y) an equivalent amount of cash. In connection with any redemption or acquisition of Opco Units together with a corresponding number of shares of Class B common stock pursuant to the Redemption Right or our Call Right, the corresponding number of shares of Class B common stock will be cancelled. See “Certain Relationships and Related Party Transactions—Opco LLC Agreement.” Kimmeridge, Blackstone and Source and certain of their permitted transferees will have the right, under certain circumstances, to cause us to register the offer and resale of their shares of Class A common stock issuable upon redemption of Opco Units together with a corresponding number of shares of Class B common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

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The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised and without giving effect to the Existing Owner Distribution):

(1) Our Existing Owners will own, in the aggregate, approximately 100% of our Class B common stock and approximately 84% of the Opco Units.

(2) Includes any shares of our Class A common stock that may be purchased by Christopher L. Conoscenti, our Chief Executive Officer and Director Nominee, in this offering.

Offering

Only Class A common stock will be sold to investors in this offering. Immediately following this offering, there will be 10,000,000 shares of Class A common stock issued and outstanding and 52,000,000 shares of Class A common stock reserved for redemptions of Opco Units and shares of Class B common stock pursuant to the Opco Agreement. We estimate that our net proceeds from this offering, after deducting estimated underwriting discounts and commissions and other offering related expenses, will be approximately $199 million. We intend to contribute all of the net proceeds from this offering to Opco in exchange for Opco Units, which will use the net proceeds to (i) repay all of the outstanding borrowings under our revolving credit facility and (ii) fund future acquisitions of mineral and royalty interests.

As a result of the corporate reorganization and this offering described above (and prior to any redemption of Opco Units):

• the investors in this offering will collectively own 10,000,000 shares of Class A common stock (or 11,500,000 shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares);

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• Desert Peak Minerals will hold 10,000,000 Opco Units;

• our Existing Owners will hold, in the aggregate, 52,000,000 shares of Class B common stock and a corresponding number of Opco Units;

• assuming no exercise of the underwriters’ option to purchase additional shares, the investors in this offering will collectively hold 16% of the voting power in us (or 18% if the underwriters exercise in full their option to purchase additional shares); and

• assuming no exercise of the underwriters’ option to purchase additional shares, our Existing Owners will hold, in the aggregate, 84% of the voting power in us (or 82% if the underwriters exercise in full their option to purchase additional shares).

Holding Company Structure

Our post-offering organizational structure will allow our Existing Owners to retain their equity ownership in Opco, a partnership for U.S. federal income tax purposes. Investors in this offering will, by contrast, hold their equity ownership in the form of shares of Class A common stock in us, and we are classified as a domestic corporation for U.S. federal income tax purposes. Our Existing Owners and we will generally incur U.S. federal, state and local income taxes on our respective proportionate shares of any taxable income of Opco.

In addition, pursuant to our amended and restated certificate of incorporation and the Opco Agreement, our capital structure and the capital structure of Opco will generally replicate one another and will provide for customary antidilution mechanisms in order to maintain the one-for-one redemption ratio between the Opco Units and our Class A common stock, among other things.

The holders of Opco Units, including us, will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of Opco and will be allocated their proportionate share of any taxable loss of Opco. The Opco Agreement will provide, to the extent cash is available, for pro rata tax distributions to all Opco unitholders, including to us, in an amount sufficient to allow us to pay our U.S. federal, state, local and non-U.S. tax liabilities.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Opco LLC Agreement

The Opco LLC Agreement is filed as an exhibit to the registration statement of which this prospectus forms a part, and the following description of the Opco LLC Agreement is qualified in its entirety by reference thereto.

The Opco LLC Agreement will provide a redemption right to the holders of Opco Units (“Redemption Right”) which will entitle them to have their Opco Units redeemed from time to time at their election for, at our election, newly-issued shares of Class A common stock on a one-for-one basis or a cash payment equal to a volume weighted average market price of one share of Class A common stock for each Opco Unit redeemed (or, if the shares of Class A common stock are not traded on a securities exchange, then for a cash payment equal to the fair market value of one share of Class A common stock, as determined by a majority of our independent directors (within the meaning of the rules of the NYSE)), in each case in accordance with the terms of the Opco LLC Agreement; provided that, at our election, we may effect a direct exchange of the Class A common stock or such cash, as applicable, for such Opco Units. The holders of Opco Units may exercise such Redemption Right for as long as their Opco Units remain outstanding. In connection with the exercise of the redemption or exchange of Opco Units (i) the holders of Opco Units will be required to surrender a number of shares of Class B common stock registered in the name of such redeeming or exchanging Opco holder, which we will cancel for no consideration on a one-for-one basis with the number of Opco Units so redeemed or exchanged and (ii) all redeeming members will surrender Opco Units to Opco for cancellation.

The Opco LLC Agreement will require that we contribute cash or Class A common stock, as applicable, to Opco in exchange for an amount of newly-issued Opco Units in Opco that will be issued to us equal to the number of Opco Units redeemed from the holders of Opco Units. Opco will then distribute the cash or shares of Class A common stock, as applicable, to such Opco holders to complete the redemption. In the event of such election by an Opco holder, we may, at our option, effect a direct exchange of cash or shares of Class A common stock, as applicable, for such Opco Units in lieu of such a redemption. Whether by redemption or exchange, we are obligated to ensure that at all times the number of Opco Units that we own equals the number of our outstanding Class A common stock (subject to certain exceptions for treasury shares and shares underlying certain convertible or exchangeable securities).

Under the Opco LLC Agreement, we will have the right to determine when distributions will be made to the holders of Opco Units and the amount of any such distributions. Following this offering, if we authorize a distribution, such distribution will be made to the holders of Opco Units on a pro rata basis in accordance with their respective percentage ownership of Opco Units.

The Opco LLC Agreement will provide that, except as otherwise determined by us, at any time we issue a share of our Class A common stock or any other equity security, the net proceeds received by us with respect to such issuance, if any, shall be concurrently invested in Opco, and Opco shall issue to us one Opco Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of Class A common stock are redeemed, repurchased or otherwise acquired, Opco shall redeem, repurchase or otherwise acquire an equal number of Opco Units held by us, upon the same terms and for the same price, as the shares of Class A common stock are redeemed, repurchased or otherwise acquired.

Under the Opco LLC Agreement, the members have agreed that the Opco Unit Holders and/or their respective affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours.

Opco will be dissolved only upon the first to occur of (i) a unanimous decision of the members and us to dissolve Opco or (ii) certain other events contemplated under Sections 18-801(4) and 18-802 of the Delaware Limited Liability Company Act. Upon dissolution, Opco will be liquidated and the proceeds from any liquidation

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will be applied and distributed in the following manner: (a) first, to creditors (including to the extent permitted by law, creditors who are members) in satisfaction of the liabilities of Opco, (b) second, to establish cash reserves for contingent or unforeseen liabilities and (c) third, to the members in proportion to the number of the Opco Units owned by each of them.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with Kimmeridge, Blackstone and Source. Pursuant to the registration rights agreement, we have agreed to register the sale of up to 52,000,000 shares of our Class A common stock under certain circumstances, subject to certain conditions and limitations. Any sales in the public market of our Class A Common Stock registrable pursuant to the registration rights agreement could adversely affect prevailing market prices of our Class A Common Stock. See “Risk Factors—Risks Related to this Offering and our Class A Common Stock—Future sales of shares of our Class A common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.” We will generally be obligated to pay all registration expenses in connection with these registration obligations, regardless of whether a registration statement is filed or becomes effective.

Corporate Reorganization

In connection with our corporate reorganization, we will engage in certain transactions with certain affiliates of the Existing Owners, including Kimmeridge. Please see “Corporation Reorganization.”

Director Designation Agreement

In connection with this offering, we intend to enter into a director designation agreement with Kimmeridge, Blackstone and Source that will provide Kimmeridge, Blackstone and Source certain rights to designate nominees for election to our board of directors. The director designation agreement will provide that, subject to compliance with applicable laws and stock exchange rules, (i) for so long as Kimmeridge’s ownership of our Class A and Class B common stock is at least, in the aggregate, 20% of the total voting power of the issued and outstanding shares of the Company, Kimmeridge shall be entitled to designate two directors to our board of directors, and for so long as Kimmeridge’s ownership is less than 20% but at least 10% of the total voting power of the shares of the Company, Kimmeridge shall be entitled to designate one director to our board of directors, (ii) for so long as Blackstone’s ownership of our Class A and Class B common stock is at least, in the aggregate, 10% of the total voting power of the issued and outstanding shares of the Company, Blackstone shall be entitled to designate one director to our board of directors and (iii) for so long as Source’s ownership of our Class A and Class B common stock is at least, in the aggregate, 10% of the total voting power of the issued and outstanding shares of the Company, Source shall be entitled to designate one director to our board of directors. Kimmeridge, Blackstone and Source shall each be entitled to designate the replacement for each of their respective board designees if such board designee’s board service terminates prior to the end of such director’s term regardless of Kimmeridge’s, Blackstone’s or Source’s, as applicable, beneficial ownership at such time.

The director designation agreement will terminate upon the earliest to occur of (a) the dissolution of the Company, (b) with respect to Kimmeridge, Blackstone and Source separately, the date on which Kimmeridge, Blackstone or Source ceases to own at least 10% of the outstanding shares of our common stock and (c) the written agreement of us and Kimmeridge, Blackstone or Source.

Indications of Interest to Participate in this Offering

Christopher L. Conoscenti, our Chief Executive Officer and Director Nominee, has indicated an interest in purchasing shares of our Class A common stock in this offering at the initial public offering price and, except as

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described below, on the same terms as the other purchasers in this offering. Because indications of interest are not binding agreements or commitments to purchase, Mr. Conoscenti may determine to purchase more, fewer or no shares in this offering. The underwriters will not receive any underwriting discounts or commissions on any shares purchased by Mr. Conoscenti and will allocate any such shares as directed by us as the issuer. Any shares of Class A common stock purchased by Mr. Conoscenti will be subject to the lock-up restrictions described in the section titled “Underwriting (Conflicts of Interest).”

Chambers Acquisition

On June 7, 2021, we completed the acquisition of the Delaware Basin portion of the Chambers ORRI from Chambers Minerals, LLC, an affiliate of Kimmeridge, for equity consideration, which represents approximately 7,200 NRAs consisting of a 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to Callon’s net revenue interest, in substantially all Callon-operated oil and gas leasehold in the Delaware Basin.

Management Fees

Our predecessor incurred and paid annual fees under an investment management agreement with Kimmeridge Energy Management Company, LLC, an affiliate of Kimmeridge, of which Benjamin P. Dell, a Director Nominee, and Noam Lockshin, our Director, are managing members. Fees incurred under the agreement totaled approximately $7.5 million for the years ended December 31, 2020 and 2019. As a result of the corporate reorganization, we will no longer incur fees under this agreement upon completion of this offering.

Services Agreement

For all periods prior to our formation, KMF was operated by employees and officers of Kimmeridge, and it is currently expected that we will continue to be operated by employees and officers of Kimmeridge following the date of this offering through the end of fiscal year 2021. We intend to enter into a Services Agreement with Kimmeridge in connection with the closing of this offering regarding the provision of services by such employees and officers of Kimmeridge to us. Under the Services Agreement, we will pay or reimburse Kimmeridge for certain allocated expenses, including compensation expenses such as salaries for the employees and officers who perform services for us. Any compensation paid to the employees and officers of Kimmeridge who perform services for us is paid by, and solely in the discretion of, Kimmeridge and we do not make any decisions regarding such compensation. We expect to incur total costs of approximately $1.2 million under the Services Agreement during 2021.

Procedures for Approval of Related Party Transactions

Prior to the closing of this offering, our board of directors will adopt a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction in which we or any of our subsidiaries was, is or will be a participant, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

• any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

• any person who is known by us to be the beneficial owner of more than 5% of our outstanding shares of Class A common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our outstanding shares of Class A common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our outstanding shares of Class A common stock; and

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• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest

We anticipate that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.

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DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering, the authorized capital stock of Desert Peak Minerals will consist of 400,000,000 shares of Class A common stock, $0.01 par value per share, of which 10,000,000 shares will be issued and outstanding, of shares 250,000,000 of Class B common stock, $0.001 par value per share, of which 52,000,000 shares will be issued and outstanding, and 50,000,000 shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following summary of the capital stock and amended and restated certificate of incorporation and amended and restated bylaws of Desert Peak Minerals does not purport to be complete and is qualified in its entirety by reference to the provisions of our amended and restated certificate of incorporation and amended and restated bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Class A Common Stock

Voting Rights. Except as provided by law or in a preferred stock designation, holders of our Class A common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders and do not have cumulative voting rights. Except as otherwise required by law, holders of Class A common stock are not entitled to vote on any amendment to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to our amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the Delaware General Corporation Law (“DGCL”).

Dividend Rights. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of Class A common stock are entitled to receive ratably in proportion to the shares of Class A common stock held by them, such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments.

Liquidation Rights. Upon our liquidation, dissolution, distribution of assets or other winding up, the holders of Class A common stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and the liquidation preference of any of our outstanding shares of preferred stock.

Other Matters. The shares of Class A common stock have no preemptive or conversion rights and are not subject to further calls or assessment by us. There are no redemption or sinking fund provisions applicable to our Class A common stock. In connection with this offering, our legal counsel will opine that, subject to the qualifications and limitations stated in such opinion, the shares of our Class A common stock to be issued pursuant to this offering will be fully paid and non-assessable. A copy of such opinion of our legal counsel including a discussion of the qualifications and limitations thereto, is included as Exhibit 5.1 to the registration statement of which this prospectus forms a part.

Class B Common Stock

Generally. In connection with the reorganization and this offering, each Opco Unit Holder will receive one share of Class B common stock for each Opco Unit that it holds. Shares of Class B common stock will not be transferable except in connection with a permitted transfer of a corresponding number of Opco Units. Accordingly, our Existing Owners, and to the extent any Existing Owner Distribution occurs, their respective partners who will hold Opco Units, will have a number of votes in Desert Peak Minerals equal to the aggregate number of Opco Units held by each such Existing Owner or partner, as applicable.

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Voting Rights. Holders of shares of our Class B common stock are entitled to one vote per share held of record on all matters to be voted upon by the stockholders. Holders of shares of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except with respect to the amendment of certain provisions of our certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B common stock so as to affect them adversely, which amendments must be approved by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law.

Dividend Rights. Holders of our Class B common stock do not have any right to receive dividends, unless the dividend consists of shares of our Class B common stock or of rights, options, warrants or other securities convertible or exercisable into or redeemable for shares of Class B common stock paid proportionally with respect to each outstanding share of our Class B common stock and a dividend consisting of shares of Class A common stock or of rights, options, warrants or other securities convertible or exercisable into or redeemable for shares of Class A common stock on the same terms is simultaneously paid to the holders of Class A common stock.

Liquidation Rights. Holders of our Class B common stock do not have any right to receive a distribution upon a liquidation or winding up of Desert Peak Minerals.

Preferred Stock

Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of              shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

We will elect not to be subject to the provisions of Section 203 of the DGCL regulating corporate takeovers. In general, those provisions prohibit a Delaware corporation, including those whose securities are listed for

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trading on NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

• the transaction is approved by the board of directors before the date the interested stockholder attained that status;

• 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; or

• 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.

Our amended and restated certificate of incorporation will contain, however, provisions that are similar to Section 203 of the DGCL (except with respect to the Existing Owners and their affiliates).

Our Amended and Restated Certificate of Incorporation and Our Amended and Restated Bylaws

Certain provisions of our amended and restated certificate of incorporation and our amended and restated bylaws, which will become effective upon the closing of this offering, may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our Class A common stock.

Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

• establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

• provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

• provide that the authorized number of directors constituting our board of directors shall be changed only by resolution of the board of directors;

• provide that all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock and subject to the director designation agreement (to the extent it remains in effect), be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum;

• provide that our bylaws can be amended by the board of directors;

• provide that our certificate of incorporation and our bylaws may be amended by the affirmative vote of the holders of not less than 66 2/3% of our then outstanding shares of common stock;

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• provide that special meetings of our stockholders may only be called by the board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the members of the board of directors serving at the time of such vote; and

• prohibit cumulative voting on all matters.

Corporate Opportunity

Under our amended and restated certificate of incorporation, to the extent permitted by law:

• our Existing Owners and their respective affiliates will have the right to exercise, and have no duty to abstain from, exercising, such right to, conduct business with any business that is competitive or in the same line of business as us, do business with any of our clients or customers, or invest or own any interest publicly or privately in, or develop a business relationship with, any business that is competitive or in the same line of business as us;

• if our Existing Owners and their respective affiliates acquire knowledge of a potential transaction that could be a corporate opportunity, they have no duty to offer such corporate opportunity to us; and

• we have renounced any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities.

Forum Selection

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

• any derivative action or proceeding brought on our behalf;

• any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;

• any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws; or

• any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

Our amended and restated certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of and to have consented to this forum selection provision. Although we believe these provisions will benefit us 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 our directors, officers, employees and agents. This provision would not apply to claims brought to enforce a duty or liability created by the Securities Act, Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. In addition, the enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that, in connection with one or more actions or proceedings described above, a court could rule that this provision in our amended and restated certificate of incorporation is inapplicable or unenforceable.

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Limitation of Liability and Indemnification Matters

Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL.

As permitted by Delaware law, our amended and restated certificate of incorporation will provide that our directors will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

• for any breach of their duty of loyalty to us or our stockholders;

• for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

• for unlawful payment of a dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

• for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws also will permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision that will be in our amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Registration Rights

For a description of registration rights with respect to our Class A common stock, see the information under the heading “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

Director Designation Agreement

In connection with the consummation of this offering, we will enter into a new director designation agreement with Kimmeridge, Blackstone and Source. Please see “Certain Relationships and Related Party Transactions—Director Designation Agreement.”

Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock is American Stock Transfer & Trust Company LLC.

Listing

We have been approved to list our Class A common stock on NYSE under the symbol “DPM.”

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for shares of our Class A common stock. Future sales of shares of our Class A common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our Class A common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our Class A common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our Class A common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon the closing of this offering, we will have outstanding an aggregate of 10,000,000 shares of Class A common stock. Of these shares, all of the 10,000,000 shares of Class A common stock (or 11,500,000 shares of Class A common stock if the underwriters’ option to purchase additional shares is exercised in full) to be sold in this offering, other than any shares sold pursuant to the directed share program, which will be subject to the lock-up restrictions described under “Underwriting (Conflicts of Interest)—Directed Share Program,” will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of Class A common stock held by existing stockholders will be deemed “restricted securities” as such term is defined under Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

In addition, subject to certain limitations and exceptions, pursuant to the terms of the Opco LLC Agreement, our Existing Owners will have the right to redeem all or a portion of their Opco Units for Class A common stock at a redemption ratio of one share of Class A common stock for each Opco Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications, or, at our election, an equivalent amount of cash. Upon consummation of this offering, our Existing Owners will hold Opco Units, all of which will be redeemable for shares of our Class A common stock. See “Certain Relationships and Related Party Transactions—Opco LLC Agreement.” The shares of Class A common stock we issue upon such redemptions would be “restricted securities” as defined in Rule 144 described below. However, upon the closing of this offering, we intend to enter into a registration rights agreement with Kimmeridge, Blackstone and Source that will require us to register under the Securities Act these shares of Class A common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our Class A common stock (excluding the shares to be sold in this offering and including shares of Class A common stock issuable upon exchange of Opco Units and Class B common stock) that will be available for sale in the public market are as follows:

• no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; and

• 52,000,000 shares will be eligible for sale upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus when permitted under Rule 144 or Rule 701.

Lock-up Agreements

We, our Existing Owners and all of our directors, director nominees and executive officers have agreed or will agree that, subject to certain exceptions and under certain conditions, for a period of 180 days after the date

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of this prospectus, we and they will not, without the prior written consent of Barclays Capital Inc., dispose of or hedge any shares or any securities convertible into or exchangeable for shares of our capital stock. See “Underwriting (Conflicts of Interest)” for a description of these lock-up provisions.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person (who has been unaffiliated for at least the past three months) who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our Class A common stock or the average weekly trading volume of shares of our Class A common stock reported through NYSE during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchase or otherwise receive shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering are entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register shares issuable under our long-term incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement may be made available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

Registration Rights

For a description of registration rights with respect to our Class A common stock, see the information under the heading “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

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CERTAIN ERISA CONSIDERATIONS

The following is a summary of certain considerations associated with the acquisition and holding of shares of common stock by employee benefit plans that are subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Code or employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA), non-U.S. plans (as described in Section 4(b)(4) of ERISA) or other plans that are not subject to the foregoing but may be subject to provisions under any other federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of any such plan, account or arrangement (each, a “Plan”).

This summary is based on the provisions of ERISA and the Code (and related regulations and administrative and judicial interpretations) as of the date of this registration statement. This summary does not purport to be complete, and no assurance can be given that future legislation, court decisions, regulations, rulings or pronouncements will not significantly modify the requirements summarized below. Any of these changes may be retroactive and may thereby apply to transactions entered into prior to the date of their enactment or release. This discussion is general in nature and is not intended to be all inclusive, nor should it be construed as investment or legal advice.

General Fiduciary Matters

ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in shares of common stock with a portion of the assets of any Plan, a fiduciary should consider the Plan’s particular circumstances and all of the facts and circumstances of the investment and determine whether the acquisition and holding of shares of common stock is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code, or any Similar Law relating to the fiduciary’s duties to the Plan, including, without limitation:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

• whether, in making the investment, the ERISA Plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

• whether the investment is permitted under the terms of the applicable documents governing the Plan;

• whether the acquisition or holding of the shares of common stock will constitute a “prohibited transaction” under Section 406 of ERISA or Section 4975 of the Code (please see the discussion under “—Prohibited Transaction Issues” below); and

• whether the Plan will be considered to hold, as plan assets, (i) only shares of common stock or (ii) an undivided interest in our underlying assets (please see the discussion under “—Plan Asset Issues” below).

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of

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ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engages in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Code. The acquisition and/or holding of shares of common stock by an ERISA Plan with respect to which the issuer, the initial purchaser, or a guarantor is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption.

Because of the foregoing, shares of common stock should not be acquired or held by any person investing “plan assets” of any Plan, unless such acquisition and holding will not constitute a non-exempt prohibited transaction under ERISA and the Code or a similar violation of any applicable Similar Laws.

Plan Asset Issues

Additionally, a fiduciary of a Plan should consider whether the Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that we would become a fiduciary of the Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor (the “DOL”) regulations provide guidance with respect to whether the assets of an entity in which ERISA Plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets generally would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by ERISA Plans are “publicly-offered securities” (as defined in the DOL regulations)—i.e., the equity interests are part of a class of securities that is widely held by 100 or more investors independent of the issuer and each other, are freely transferable, and are either registered under certain provisions of the federal securities laws or sold to the ERISA Plan as part of a public offering under certain conditions;

(b) the entity is an “operating company” (as defined in the DOL regulations)—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by “benefit plan investors” (as defined in the DOL regulations)—i.e., immediately after the most recent acquisition by an ERISA Plan of any equity interest in the entity, less than 25% of the total value of each class of equity interest (disregarding certain interests held by persons (other than benefit plan investors) with discretionary authority or control over the assets of the entity or who provide investment advice for a fee (direct or indirect) with respect to such assets, and any affiliates thereof) is held by ERISA Plans, IRAs and certain other Plans (but not including governmental plans, foreign plans and certain church plans), and entities whose underlying assets are deemed to include plan assets by reason of a Plan’s investment in the entity.

Due to the complexity of these rules and the excise taxes, penalties and liabilities that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries, or other persons considering acquiring and/or holding shares of our common stock on behalf of, or with the assets of, any Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such investment and whether an exemption would be applicable to the acquisition and holding of shares of common stock. Purchasers of shares of common stock have the exclusive responsibility for ensuring that their acquisition and holding of shares of common stock complies with the fiduciary responsibility rules of ERISA and does not violate the prohibited

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transaction rules of ERISA, the Code or applicable Similar Laws. The sale of shares of common stock to a Plan is in no respect a representation by us or any of our affiliates or representatives that such an investment meets all relevant legal requirements with respect to investments by any such Plan or that such investment is appropriate for any such Plan.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

The following discussion is a summary of the material U.S. federal income tax consequences to Non-U.S. Holders (as defined below) of the purchase, ownership and disposition of our common stock issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local or non-U.S. tax laws are not discussed. This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations promulgated thereunder, judicial decisions, and published rulings and administrative pronouncements of the U.S. Internal Revenue Service (the “IRS”), in each case in effect as of the date hereof. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could adversely affect a Non-U.S. Holder of our common stock. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership and disposition of our common stock.

This discussion is limited to Non-U.S. Holders that hold our common stock as a “capital asset” within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a Non-U.S. Holder’s particular circumstances, including the impact of the Medicare contribution tax on net investment income. In addition, it does not address consequences relevant to Non-U.S. Holders subject to special rules, including, without limitation:

• U.S. expatriates and former citizens or long-term residents of the United States;

• persons subject to the alternative minimum tax;

• persons holding our common stock as part of a hedge, straddle or other risk reduction strategy or as part of a conversion transaction or other integrated investment;

• banks, insurance companies, and other financial institutions;

• brokers, dealers or traders in securities;

• “controlled foreign corporations,” “passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax;

• partnerships or other entities or arrangements treated as partnerships for U.S. federal income tax purposes (and investors therein);

• tax-exempt organizations or governmental organizations;

• persons deemed to sell our common stock under the constructive sale provisions of the Code;

• persons who hold or receive our common stock pursuant to the exercise of any employee stock option or otherwise as compensation;

• tax-qualified retirement plans;

• “qualified foreign pension funds” as defined in Section 897(l)(2) of the Code and entities all of the interests of which are held by qualified foreign pension funds; and

• persons subject to special tax accounting rules as a result of any item of gross income with respect to the stock being taken into account in an applicable financial statement.

If an entity treated as a partnership for U.S. federal income tax purposes holds our common stock, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding our common stock and the partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.

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THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

Definition of a Non-U.S. Holder

For purposes of this discussion, a “Non-U.S. Holder” is any beneficial owner of our common stock that is neither a “U.S. person” nor an entity treated as a partnership for U.S. federal income tax purposes. A U.S. person is any person that, for U.S. federal income tax purposes, is or is treated as any of the following:

• an individual who is a citizen or resident of the United States;

• a corporation created or organized under the laws of the United States, any state thereof, or the District of Columbia;

• an estate, the income of which is subject to U.S. federal income tax regardless of its source; or

• a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more “United States persons” (within the meaning of Section 7701(a)(30) of the Code), or (2) has a valid election in effect to be treated as a United States person for U.S. federal income tax purposes.

Distributions

If we make distributions of cash or property on our common stock, such distributions 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. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and first be applied against and reduce a Non-U.S. Holder’s adjusted tax basis in its common stock, but not below zero. Any excess will be treated as capital gain and will be treated as described below under “—Sale or Other Taxable Disposition.”

Subject to the discussion below on effectively connected income, dividends paid to a Non-U.S. Holder of our common stock will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty, provided the Non-U.S. Holder furnishes a valid IRS Form W-8BEN or W-8BEN-E (or other applicable documentation) certifying qualification for the lower treaty rate). A Non-U.S. Holder that does not timely furnish the required documentation, but that qualifies for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. Holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

If dividends paid to a Non-U.S. Holder are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such dividends are attributable), the Non-U.S. Holder will be exempt from the U.S. federal withholding tax described above. To claim the exemption, the Non-U.S. Holder must furnish to the applicable withholding agent a valid IRS 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.

Any such effectively connected dividends will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at

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a rate of 30% (or such lower rate specified by an applicable income tax treaty) on such effectively connected dividends, as adjusted for certain items. Non-U.S. Holders should consult their tax advisors regarding any applicable tax treaties that may provide for different rules.

Sale or Other Taxable Disposition

A Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of our common stock unless:

• the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such gain is attributable);

• the Non-U.S. Holder is a nonresident alien individual present in the United States for 183 days or more during the taxable year of the disposition and certain other requirements are met; or

• our common stock constitutes a U.S. real property interest by reason of our status as a U.S. real property holding corporation (“USRPHC”) for U.S. federal income tax purposes.

Gain described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on such effectively connected gain, as adjusted for certain items.

Gain described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty), which may be offset by U.S. source capital losses of the Non-U.S. Holder (even though the individual is not considered a resident of the United States), provided the Non-U.S. Holder has timely filed U.S. federal income tax returns with respect to such losses.

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, provided that our common stock is and continues to be “regularly traded on an established securities market” (within the meaning of the U.S. Treasury regulations), only a Non-U.S. Holder that actually or constructively owns, or owned at any time during the shorter of the five year period ending on the date of the disposition or the Non-U.S. Holder’s holding period for the common stock, more than 5% of our common stock will be treated as disposing of a U.S. real property interest and will be taxable on gain realized on the disposition of our common stock at the regular graduated rates as a result of our status as a USRPHC. If our common stock were not considered to be regularly traded on an established securities market, such holder (regardless of the percentage of stock owned) would be treated as disposing of a U.S. real property interest and would be subject to U.S. federal income tax on a taxable disposition of our common stock in the manner generally applicable to United States persons, and a 15% withholding tax would apply to the gross proceeds from such disposition.

Non-U.S. Holders should consult their tax advisors regarding potentially applicable income tax treaties that may provide for different rules.

Information Reporting and Backup Withholding

Payments of dividends on our common stock will not be subject to backup withholding, provided the applicable withholding agent does not have actual knowledge or reason to know the holder is a United States person and the holder either certifies its non-U.S. status, such as by furnishing a valid IRS Form W-8BEN,

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W-8BEN-E or W-8ECI, or otherwise establishes an exemption. However, information returns are required to be filed with the IRS in connection with any distributions on our common stock paid to the Non-U.S. Holder, regardless of whether such distributions constitute dividends or whether any tax was actually withheld. In addition, proceeds of the sale or other taxable disposition of our common stock within the United States or conducted through certain U.S.-related brokers generally will not be subject to backup withholding or information reporting, if the applicable withholding agent receives the certification described above and does not have actual knowledge or reason to know that such holder is a United States person, or the holder otherwise establishes an exemption. Proceeds of a disposition of our common stock conducted through a non-U.S. office of a non-U.S. broker generally will not be subject to backup withholding or information reporting.

Copies of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the country in which the Non-U.S. Holder resides or is established.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. Holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Additional Withholding Tax on Payments Made to Foreign Accounts

Withholding taxes may be imposed under Sections 1471 to 1474 of the Code (such Sections commonly referred to as the Foreign Account Tax Compliance Act, or “FATCA”) on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or (subject to the proposed Treasury Regulations discussed below) gross proceeds from the sale or other disposition of, our common stock paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain “specified United States persons” or “United States-owned foreign entities” (each as defined in the Code), annually report certain information about such accounts, and withhold 30% on certain payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

Under the applicable Treasury Regulations and administrative guidance, withholding under FATCA generally applies to payments of dividends on our common stock. While withholding under FATCA would have applied also to payments of gross proceeds from the sale or other disposition of stock on or after January 1, 2019, proposed Treasury Regulations eliminate FATCA withholding on payments of gross proceeds entirely. Taxpayers generally may rely on these proposed Treasury Regulations until final Treasury Regulations are issued.

Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our common stock.

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UNDERWRITING (CONFLICTS OF INTEREST)

Barclays Capital Inc., Credit Suisse Securities (USA) LLC and UBS Securities LLC are acting as representatives of the underwriters and book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of shares of Class A common stock shown opposite its name below:

Underwriter	Number of Shares
Barclays Capital Inc.
Credit Suisse Securities (USA) LLC
UBS Securities LLC
Capital One Securities, Inc.
Citigroup Global Markets Inc.
Evercore Group L.L.C.
RBC Capital Markets, LLC
Maxim Group LLC
Stephens Inc.
Tudor, Pickering, Holt & Co. Securities, LLC
Tuohy Brothers Investment Research, Inc.
Total		10,000,000

The underwriting agreement provides that the underwriters’ obligation to purchase shares of common stock depends on the satisfaction of the certain conditions contained in the underwriting agreement including:

• the obligation to purchase all of the shares of Class A common stock offered hereby (other than those shares of Class A common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased;

• the representations and warranties made by us to the underwriters are true;

• there is no material change in our business or the financial markets; and

• we deliver customary closing documents to the underwriters.

The underwriters are offering the shares, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the shares, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officers’ certificates and legal opinions. The underwriters reserve the right to withdraw, cancel, or modify offers to the public and to reject orders in whole or in part. The underwriters may offer and sell the shares to the public through one or more of their respective affiliates or other registered broker-dealers or selling agents.

Christopher L. Conoscenti, our Chief Executive Officer and Director Nominee, has indicated an interest in purchasing shares of our Class A common stock in this offering at the initial public offering price and, except as described below, on the same terms as the other purchasers in this offering. Because indications of interest are not binding agreements or commitments to purchase, Mr. Conoscenti may determine to purchase more, fewer or no shares in this offering. The underwriters will not receive any underwriting discounts or commissions on any shares purchased by Mr. Conoscenti and will allocate any such shares as directed by us as the issuer. Any shares of Class A common stock purchased by Mr. Conoscenti will be subject to the lock-up restrictions described below.

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Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the shares.

	Company
	No Exercise	Full Exercise
Per Share	$	$
Total	$	$

The representative has advised us that the underwriters propose to offer the shares of Class A common stock directly to the public at the offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $            per share.

If all the shares are not sold at the initial public offering price following the initial public offering, the representative may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be approximately $4 million (excluding underwriting discounts and commissions). We have agreed to reimburse the underwriters for certain of their expenses in an amount up to $20,000.

Option to Purchase Additional Shares

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of 1,500,000 shares from us at the offering price less underwriting discounts and commissions, solely for the purpose of covering overallotments. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s percentage underwriting commitment in this offering as indicated in the above table.

Lock-Up Agreements

We, our Existing Owners and all of our directors, director nominees and executive officers have agreed, subject to certain exceptions, that, for a period of 180 days after the date of this prospectus, subject to certain limited exceptions, we and they will not directly or indirectly, without the prior written consent of Barclays Capital Inc. (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of Class A common stock (including, without limitation, shares of Class A common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of Class A common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for Class A common stock (other than the stock and shares issued pursuant to employee benefit plans, qualified stock option plans, or other employee compensation plans existing on the date of this prospectus or pursuant to currently outstanding options, warrants or rights not issued under one of those plans), or sell or grant options, rights or warrants with respect to any shares of Class A common stock or securities convertible into or exchangeable for Class A common stock (other than the grant of options pursuant to option plans existing on the date of this prospectus), (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of shares of Class A common stock, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of Class A common stock or other securities, in cash or otherwise, or (3) publicly disclose the intention to do any of the foregoing, in each case, subject to specified exceptions.

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Barclays Capital Inc., in its sole discretion, may release the Class A common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release Class A common stock and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of Class A common stock and other securities for which the release is being requested and market conditions at the time. At least three business days before the effectiveness of any release or waiver of any of the restrictions described above with respect to an officer or director of the Company, Barclays Capital Inc. will notify us of the impending release or waiver and we have agreed to announce the impending release or waiver in accordance with any method permitted by applicable law or regulation (which may include a press release or a publicly filed registration statement), except where the release or waiver is effected solely to permit a transfer of Class A common stock that is not for consideration or to an immediate family member and where the transferee has agreed in writing to be bound by the same terms as the lock-up agreements described above to the extent and for the duration that such terms remain in effect at the time of transfer.

Offering Price Determination

Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price was negotiated between the representative and us. In determining the initial public offering price of our common stock, the representative considered:

• the history and prospects for the industry in which we compete;

• our financial information;

• the ability of our management and our business potential and earning prospects;

• the prevailing securities markets at the time of this offering; and

• the recent market prices of, and the demand for, publicly traded shares of generally comparable companies.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the Class A common stock, in accordance with Regulation M under the Securities Exchange Act of 1934, as amended:

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

• A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional

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shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

• Syndicate covering transactions involve purchases of the Class A common stock in the open market after the distribution has been completed in order to cover syndicate short positions.

• Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the Class A common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our Class A common stock or preventing or retarding a decline in the market price of the Class A common stock. As a result, the price of the Class A common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common stock. In addition, neither we nor any of the underwriters make any representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Listing on the NYSE

We have been approved to list our shares of Class A common stock on the NYSE under the symbol “DPM.”

Stamp Taxes

If you purchase shares of Class A common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

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Other Relationships

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for the issuer and its affiliates, for which they received or may in the future receive customary fees and expenses. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds of this offering. See “Use of Proceeds.”

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the issuer or its affiliates. If the underwriters or their affiliates have a lending relationship with us, certain of those underwriters or their affiliates may hedge their credit exposure to us consistent with their customary risk management policies. Typically, the underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the shares of common stock offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the shares of common stock offered hereby. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Directed Share Program

At our request, the underwriters have reserved up to 5% of the Class A common stock being offered by this prospectus for sale at the initial public offering price to our directors, officers, employees and other individuals associated with us and members of their families. The sales will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, an underwriter of this offering, through a directed share program. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares of Class A common stock. Participants in the directed share program shall be subject to a 25-day lock-up with respect to any shares sold to them pursuant to that program. This lock-up will have similar restrictions and an identical extension provision to the lock-up agreements described above. Any shares sold in the directed share program to our directors, executive officers or selling stockholders shall be subject to the lock-up agreements described above. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the shares reserved for the directed share program.

Conflicts of Interest

Affiliates of Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Capital One Securities Inc. and RBC Capital Markets LLC are lenders under our revolving credit facility and each will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings thereunder. Therefore, each of Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Capital One Securities Inc. and RBC Capital Markets LLC is deemed to have a conflict of interest within the meaning of FINRA Rule 5121. Accordingly, this offering is being conducted in accordance with Rule 5121, which requires, among other things, that a “qualified independent

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underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. UBS Securities LLC has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, including specifically those inherent in Section 11 thereof. UBS Securities LLC will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify UBS Securities LLC against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

Pursuant to Rule 5121, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Capital One Securities Inc. and RBC Capital Markets LLC will not confirm any sales to any account over which it exercises discretionary authority without the specific written approval of the account holder.

Selling Restrictions

Other than in the United States, no action has been taken by us or the underwriters that would permit a public offering of the securities offered by this prospectus in any jurisdiction where action for that purpose is required. The securities offered by this prospectus may not be offered or sold, directly or indirectly, nor may this prospectus or any other offering material or advertisements in connection with the offer and sale of any such securities be distributed or published in any jurisdiction, except under circumstances that will result in compliance with the applicable rules and regulations of that jurisdiction. Persons into whose possession this prospectus comes are advised to inform themselves about and to observe any restrictions relating to the offering and the distribution of this prospectus. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities offered by this prospectus in any jurisdiction in which such an offer or a solicitation is unlawful.

European Economic Area and United Kingdom

In relation to each Member State of the European Economic Area and the United Kingdom (each, a “Relevant Member State”), no Class A common stock has been offered or will be offered pursuant to the offering to a public in that Relevant Member State prior to the publication of a prospectus in relation to the Class A common stock which has been approved by the competent authority in that Relevant State or, where appropriate, approved in another Relevant State and notified to the competent authority in that Relevant State, all in accordance with the Prospectus Regulation, except that offers of shares may be made to the public in that Relevant State at any time under the following exemptions under the Prospectus Regulation:

• to legal entities which are qualified investors as defined under the Prospectus Regulation;

• by the underwriters to fewer than 150 natural or legal persons (other than qualified investors as defined in the Prospectus Regulation), subject to obtaining prior consent of the representative of the underwriters for any such offer; or

• in any other circumstances falling within Article 1(4) of the Prospectus Regulation,

provided that no such offer of Class A common stock shall result in a requirement for us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Regulation or supplement a prospectus pursuant to Article 23 of the Prospectus Regulation.

For the purposes of this provision, the expression “offer to the public” in relation to any shares in any Relevant State means the communication in any form and by any means of sufficient information on the terms of the offer and any shares to be offered so as to enable an investor to decide to purchase or subscribe for any shares, and the expression “Prospectus Regulation” means Regulation (EU) 2017/1129.

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United Kingdom

This prospectus has only been communicated or caused to have been communicated and will only be communicated or caused to be communicated as an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act of 2000 (the “FSMA”)) as received in connection with the issue or sale of the Class A common stock in circumstances in which Section 21(1) of the FSMA does not apply to us. All applicable provisions of the FSMA will be complied with in respect to anything done in relation to the Class A common stock in, from or otherwise involving the United Kingdom.

Canada

The securities may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the securities must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 Underwriting Conflicts (“NI 33-105”), the underwriters are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

Notice to Prospective Investors in Switzerland

This offering memorandum does not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of Obligations and the notes will not be listed on the SIX Swiss Exchange. Therefore, this offering memorandum may not comply with the disclosure standards of the listing rules (including any additional listing rules or prospectus schemes) of the SIX Swiss Exchange. Accordingly, the notes may not be offered to the public in or from Switzerland, but only to a selected and limited circle of investors who do not subscribe to the notes with a view to distribution. Any such investors will be individually approached by the initial purchasers from time to time.

Dubai International Financial Centre

This offering memorandum relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This offering memorandum is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this offering memorandum nor taken steps to verify the information set forth herein and has no responsibility for the offering memorandum. The notes to which this offering memorandum relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the notes offered should conduct their own due diligence on the notes. If you do not understand the contents of this offering memorandum you should consult an authorized financial advisor.

Hong Kong

The shares may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies (Winding Up

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and Miscellaneous Provisions) Ordinance (Cap. 32 of the Laws of Hong Kong) (“Companies (Winding Up and Miscellaneous Provisions) Ordinance”) or which do not constitute an invitation to the public within the meaning of the Securities and Futures Ordinance (Cap. 571 of the Laws of Hong Kong) (“Securities and Futures Ordinance”), or (ii) to “professional investors” as defined in the Securities and Futures Ordinance and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies (Winding Up and Miscellaneous Provisions) Ordinance, and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” in Hong Kong as defined in the Securities and Futures Ordinance and any rules made thereunder.

Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor (as defined under Section 4A of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”)) under Section 274 of the SFA, (ii) to a relevant person (as defined in Section 275(2) of the SFA) pursuant to Section 275(1) of the SFA, or any person pursuant to Section 275(1A) of the SFA, and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor, the securities (as defined in Section 239(1) of the SFA) of that corporation shall not be transferable for 6 months after that corporation has acquired the shares under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer in that corporation’s securities pursuant to Section 275(1A) of the SFA, (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32 of the Securities and Futures (Offers of Investments) (Shares and Debentures) Regulations 2005 of Singapore (“Regulation 32”).

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole purpose is to hold investments and each beneficiary of the trust is an accredited investor, the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable for 6 months after that trust has acquired the shares under Section 275 of the SFA except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA), (2) where such transfer arises from an offer that is made on terms that such rights or interest are acquired at a consideration of not less than $200,000 (or its equivalent in a foreign currency) for each transaction (whether such amount is to be paid for in cash or by exchange of securities or other assets), (3) where no consideration is or will be given for the transfer, (4) where the transfer is by operation of law, (5) as specified in Section 276(7) of the SFA, or (6) as specified in Regulation 32.

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Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Act of Japan (Act No. 25 of 1948, as amended), or the FIEA. The securities may not be offered or sold, directly or indirectly, in Japan or to or for the benefit of any resident of Japan (including any person resident in Japan or any corporation or other entity organized under the laws of Japan) or to others for reoffering or resale, directly or indirectly, in Japan or to or for the benefit of any resident of Japan, except pursuant to an exemption from the registration requirements of the FIEA and otherwise in compliance with any relevant laws and regulations of Japan.

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LEGAL MATTERS

The validity of the shares of our Class A common stock offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The balance sheets of Desert Peak Minerals Inc. as of December 31, 2020 and 2019, have been included in the prospectus herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of Kimmeridge Mineral Fund, LP as of December 31, 2020 and 2019 and for the years then ended, have been included in the prospectus herein in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Estimates of our reserves and related future net cash flows related to our properties as of December 31, 2020 and 2019 included herein and elsewhere in the registration statement were based upon reserve reports prepared by independent petroleum engineers, Cawley, Gillespie & Associates, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

The financial statements of Rock Ridge Royalty Company LLC as of and for the years ended December 31, 2020 and 2019 included in this prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

Estimates of Rock Ridge’s reserves and related future net cash flows related to our properties as of December 31, 2020 and 2019 included herein and elsewhere in the registration statement were based upon reserve reports prepared by independent petroleum engineers, Netherland, Sewell & Associates, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

The Source Acquisition statement of revenues and direct expenses for the year ended December 31, 2020 have been included in the prospectus herein in reliance upon the report of KPMG LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

CHANGE IN INDEPENDENT ACCOUNTANT

On September 25, 2020, with the approval of our predecessor’s manager, the predecessor dismissed Deloitte & Touche LLP (“Deloitte”) as our independent registered public accounting firm. Effective December 3, 2020, we retained KPMG LLP (“KPMG”) as our independent registered public accounting firm. Subsequent to KPMG’s appointment, our predecessor engaged KPMG to reaudit the registrant’s and our predecessor’s consolidated financial statements and the balance sheet of the registrant as of and for the year ended December 31, 2019 because such period is required to be included in the registration statement of which this prospectus forms a part, which was previously audited by Deloitte.

The reports of Deloitte on our predecessor’s consolidated financial statements for each of the two fiscal years prior to its dismissal and the balance sheet of the registrant as of April 17, 2019, did not contain any adverse opinion or disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope or accounting principles. We had no disagreements with Deloitte on any matter of accounting principles or

179

practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to its satisfaction, would have caused Deloitte to make reference in connection with its opinion to the subject matter of the disagreement during its audits for each of the two fiscal years of our predecessor’s financial statements and the balance sheet of the registrant as of April 17, 2019 prior to its dismissal. During the two most recent fiscal years preceding Deloitte’s dismissal, and the subsequent interim period through the date of dismissal, there were no “reportable events” as such term is defined in Item 304(a)(1)(v) of Regulation S-K.

We have provided Deloitte with a copy of the foregoing disclosure and have requested that Deloitte furnish us with a letter addressed to the SEC stating whether or not Deloitte agrees with the above statements and, if not, stating the respects in which it does not agree. A copy of the letter from Deloitte is filed as an exhibit to the registration statement of which this prospectus is a part.

While Deloitte was engaged as the independent accountant for our predecessor and the registrant and through the date of their dismissal, neither we, nor anyone acting on our behalf, consulted with KPMG on matters that involved the application of accounting principles to a specified transaction, either completed or proposed, the type of audit opinion that might be rendered on our consolidated financial statements, and neither a written report nor oral advice was provided to us by KPMG that KPMG concluded was an important factor considered by us in reaching a decision as to the accounting, auditing or financial reporting issue or any other matter that was the subject of a disagreement as that term is used in Item 304 (a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K or a reportable event as that term is used in Item 304(a)(1)(v) and the related instructions to Item 304 of Regulation S-K.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our Class A common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to us and the Class A common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC.

As a result of this offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

180

INDEX TO FINANCIAL STATEMENTS

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
Introduction	F-2
Unaudited pro forma consolidated balance sheet as of June 30, 2021	F-4
Unaudited pro forma consolidated statements of operations for the year ended December 31, 2020 and the six months ended June 30, 2021	F-6
Notes to unaudited pro forma consolidated financial statements	F-8
DESERT PEAK MINERALS INC.
Balance Sheets and Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm	F-20
Balance sheets as of December 31, 2020 and December 31, 2019	F-21
Notes to balance sheets	F-22
KIMMERIDGE MINERAL FUND, LP
Audited Consolidated Financial Statements and Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm	F-23
Consolidated balance sheets as of December 31, 2020 and 2019	F-24
Consolidated statements of operations for the years ended December 31, 2020 and 2019	F-25
Consolidated statements of changes in Partners’ capital for the years ended December  31, 2020 and 2019	F-26
Consolidated statements of cash flows for the years ended December 31, 2020 and 2019	F-27
Notes to consolidated financial statements	F-28
Unaudited Condensed Consolidated Financial Statements
Condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020	F-52
Condensed consolidated statements of operations for the six months ended June 30, 2021 and 2020	F-53
Condensed consolidated statements of changes in partners’ capital for the six months ended June 30, 2021 and 2020	F-54
Condensed consolidated statements of cash flows for the six months ended June 30, 2021 and 2020	F-55
Notes to condensed consolidated financial statements	F-56
ROCK RIDGE ROYALTY COMPANY LLC
Audited Financial Statements and Report of Independent Auditor
Report of Independent Registered Public Accounting Firm	F-75
Balance sheets as of December 31, 2020 and 2019	F-76
Statements of operations for the years ended December 31, 2020 and 2019	F-77
Statement of changes in members’ interest for the years ended December 31, 2020 and 2019	F-78
Statement of cash flows for the years ended December 31, 2020 and 2019	F-79
Notes to financial statements	F-80
Supplemental oil and gas information (unaudited)	F-87
Unaudited Condensed Financial Statements
Condensed balance sheets as of March 31, 2021 and December 31, 2020	F-91
Condensed statements of operations for the periods ended March 31, 2021 and 2020	F-92
Condensed statement of changes in members’ interest for the period ended March 31, 2021	F-93
Condensed statements of cash flows for the periods ended March 31, 2021 and 2020	F-94
Notes to condensed financial statements	F-95
SOURCE ACQUISITION
Audited Statement of Revenues and Direct Expenses and Report of Independent Auditor
Report of Independent Auditor	F-102
Statement of revenues and direct expenses for the year ended December 31, 2020	F-103
Notes to statement of revenues and direct expenses	F-104
Unaudited Statement of Revenues and Direct Expenses
Statement of revenues and direct expenses for the six months ended June 30, 2021	F-109
Notes to statement of revenues and direct expenses	F-110

F-1

DESERT PEAK MINERALS INC.

PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Introduction

Desert Peak Minerals Inc., the issuer in this offering (together with its wholly owned subsidiaries, “Desert Peak Minerals” or the “Company”), is a holding company formed to own an interest in, and act as the sole managing member of, Desert Peak LLC (“Desert Peak LLC”). Desert Peak LLC will wholly own KMF Land, LLC (“KMF Land”). Our historical financial statements are those of Kimmeridge Mineral Fund, LP (“KMF”), the historical parent of KMF Land and our predecessor for financial reporting purposes (the “Predecessor”).

Unless otherwise stated below, the unaudited pro forma consolidated financial statements of the Company reflect the historical results of the Company on a pro forma basis to give effect to the following transactions (collectively, the “Transactions”), which are described in further detail below:

• the acquisition on June 7, 2021 of approximately 7,200 NRAs from Chambers Minerals, LLC, an affiliate of Kimmeridge, consisting of a 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to Callon Petroleum Company’s (“Callon”) net revenue interest, in substantially all Callon-operated oil and gas leaseholds in the Delaware Basin (the “Chambers Acquisition”);

• the acquisition on June 30, 2021 of approximately 18,500 NRAs from Rock Ridge Royalty, LLC (the “Rock Ridge Acquisition”);

• the acquisition on August 31, 2021 of approximately 25,000 NRAs from Source Energy Leasehold, LP and Permian Mineral Acquisition, LP (the “Source Acquisition”);

• the Corporate Reorganization as described under “Corporate Reorganization” elsewhere in this prospectus;

• the initial public offering of 10,000,000 shares of Class A common stock and the use of the net proceeds therefrom as described in “Use of Proceeds” (the “Offering”). The net proceeds from the sale of the shares of Class A common stock (based on an assumed initial public offering price of $21.50 per share) are expected to be $199.2 million, net of underwriting discounts of $11.8 million and other offering costs of $4.0 million; and

• in the case of the unaudited pro forma statement of operations, a provision for corporate income taxes at a blended statutory rate of 22%, inclusive of federal, state and local income taxes.

The unaudited pro forma consolidated balance sheet of the Company is based on the historical consolidated balance sheet of our Predecessor as of June 30, 2021 and includes pro forma adjustments to give effect to the Source Acquisition, the Corporate Reorganization and the Offering as if they had occurred on June 30, 2021. The Rock Ridge Acquisition and the Chambers Acquisition are reflected in the historical consolidated balance sheet of our Predecessor as of June 30, 2021, and, as such, no pro forma adjustments are made for such transactions in the pro forma consolidated balance sheet. The unaudited pro forma consolidated statements of operations of the Company for the year ended December 31, 2020 and six months ended June 30, 2021 are based on the historical consolidated statements of operations of KMF, giving effect to the Transactions as if they had occurred January 1, 2020 (other than the Chambers Acquisition, for which pro forma effect is given as if it occurred on October 1, 2020, the date on which the acquired overriding royalty interest was created).

The unaudited pro forma consolidated 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,” using assumptions set forth in the notes to the unaudited pro forma financial statements. The pro forma financial statements have been adjusted to include transaction accounting adjustments in accordance with GAAP, linking the effects of the Transactions to the historical consolidated financial statements of KMF.

F-2

The unaudited pro forma consolidated financial statements have also been prepared on the basis that the Company will be taxed as a corporation under the Internal Revenue Code of 1986, as amended, and, as a result, will be a tax-paying entity subject to U.S. federal and state taxes, and should be read in conjunction with “Corporate Reorganization” and with the audited historical consolidated financial statements and related notes of KMF included elsewhere in this prospectus.

The pro forma data are not necessarily indicative of financial results that would have been attained had the Transactions occurred on the date indicated or which could be achieved in the future because they necessarily exclude various operating expenses, such as incremental general and administrative expenses associated with being a public company. 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 Company’s results of operations. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the Transactions as contemplated and the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma consolidated financial statements.

The unaudited pro forma consolidated financial statements and related notes are presented for illustrative purposes only. If the Transactions contemplated herein had occurred in the past, the Company’s operating results might have been materially different from those presented in the unaudited pro forma consolidated financial statements. The unaudited pro forma consolidated financial statements should not be relied upon as an indication of operating results that the Company would have achieved if the Transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the unaudited pro forma consolidated financial statement of operations and should not be relied upon as an indication of the future results the Company will have after the completion of the Transactions contemplated by these unaudited pro forma consolidated financial statements.

F-3

DESERT PEAK MINERALS INC.

PRO FORMA BALANCE SHEET

AS OF JUNE 30, 2021

(Unaudited)

	Historical			Transaction Accounting Adjustments
	Kimmeridge Mineral Fund, L.P. (Predecessor)			Source Acquisition		Corporate Reorganization				Offering				Pro Forma Desert Peak Minerals Inc.
	(In thousands)
ASSETS					A
Current assets:
Cash and cash equivalents	$	6,188		$		$	(8,188	)	B, C	$	66,175		F	$	64,175
Accrued revenue and accounts receivable, net		11,201													11,201
Other current assets		688									(398	)	G		290
Total current assets		18,077			—		(8,188	)			65,777				75,666
Property and equipment:
Oil and natural gas properties, successful efforts method:
Unproved properties		632,010			185,869										817,879
Proved properties		344,451			68,720										413,171
Other property and equipment		7,990					(6,023	)	B						1,967
Accumulated depreciation, depletion, and amortization		(96,431	)				2,565		B						(93,866	)
Net oil and gas properties and other property and equipment		888,020			254,589		(3,458	)			—				1,139,151
Other long-term assets:
Deposits for property acquisitions		2,325													2,325
Deferred financing costs		1,126													1,126
Deferred tax assets							2,063		E						2,063
Total long-term assets		3,451			—		2,063				—				5,514
TOTAL ASSETS	$	909,548		$	254,589	$	(9,583	)		$	65,777			$	1,220,331
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued expenses and other liabilities	$	3,652		$		$	(16	)	B	$				$	3,636
Contributions of partners’ capital received in advance		1,463					(1,463	)	B						—
Due to affiliates		1,334													1,334
Total current liabilities		6,449			—		(1,479	)			—				4,970
Long-term liabilities:
Long-term debt		9,900					123,100		C		(133,000	)	F		—
Deferred rent		617													617
Total liabilities		16,966			—		121,621				(133,000	)			5,587

F-4

	Historical		Transaction Accounting Adjustments
	Kimmeridge Mineral Fund, L.P. (Predecessor)		Source Acquisition		Corporate Reorganization				Offering				Pro Forma Desert Peak Minerals Inc.
	(In thousands)
COMMITMENTS AND CONTINGENCIES
Temporary equity		—				1,013,852		D						1,013,852
Permanent equity:														—
Shareholders'/Partners' contributed capital		593,642				(3,666	)	B						—
						(128,000	)	C
						(461,976	)	D
Class A common stock		—								100		F		100
Class B common stock		—				52		D						52
Additional paid-in capital		—				2,063		E		199,075		F		200,740
										(398	)	G
Non-controlling interest		298,940		254,589		(553,529	)	D						—
Permanent equity		892,582		254,589		(1,145,056	)			198,777				200,892
Total liabilities, temporary equity and permanent equity	$	909,548	$	254,589	$	(9,583	)		$	65,777			$	1,220,331

F-5

Desert Peak Minerals Inc.

Pro Forma Consolidated Statement of Operations

For the Six Months Ended June 30, 2021

(Unaudited)

	Historical				Transaction Accounting Adjustments
	Kimmeridge Mineral Fund, L.P. (Predecessor)				Chambers Acquisition		Rock Ridge Acquisition			Source Acquisition		Acquisition Adjustments				Corporate Reorganization				Offering			Pro Forma Desert Peak Minerals Inc.
	(In thousands, except per share data)
					A		B			C
Revenue:
Oil, natural gas and natural gas liquids revenues	$	36,069			$	4,105	$	10,328		$	14,708	$				$				$			$	65,210
Lease bonus and other income		650						925			71						(205	)	F					1,441
Commodity derivatives losses		—						(1,125	)				1,125		D									—
Total revenue		36,719				4,105		10,128			14,779		1,125				(205	)			—			66,651
Operating Expenses:
Management fees to affiliates		3,740		G																				3,740
Depreciation, depletion and amortization		15,801						3,366					10,609		E		(143	)	F					29,633
General and administrative		1,278						1,314									(125	)	F					2,467
General and administrative—affiliates		3,217																						3,217
Severance ad valorem taxes		2,557				247		276			996													4,076
Total operating expenses		26,593				247		4,956			996		10,609				(268	)			—			43,133
Net income (loss) from operations		10,126				3,858		5,172			13,783		(9,484	)			63				—			23,518
Other income (expense):
Interest income (expense), net		(524	)					(88	)												304	J		(308	)
Net income before income tax expense		9,602				3,858		5,084			13,783		(9,484	)			63				304			23,210
Income tax (expense) benefit		(107	)					27									(4,961	)	H					(5,041	)
Net income	$	9,495			$	3,858	$	5,111		$	13,783	$	(9,484	)		$	(4,898	)		$	304		$	18,169
Less net income attributable to temporary equity																	15,239		I					15,239
Less net income attributable to non-controlling interests		28															(28	)	I					—
Net income (loss) attributable to Desert Peak Minerals Inc.	$	9,467			$	3,858	$	5,111		$	13,783	$	(9,484	)		$	(20,109	)		$	304		$	2,930
Net Income per Common Share
Basic																							$	0.29		K
Diluted																								0.29		K
Weighted Average Common Shares Outstanding
Basic																								10,000		K
Diluted																								10,000		K

F-6

Desert Peak Minerals Inc.

Pro Forma Consolidated Statement of Operations

For the Year Ended December 31, 2020

(Unaudited)

	Historical			Transaction Accounting Adjustments
	Kimmeridge Mineral Fund, L.P. (Predecessor)			Chambers Acquisition		Rock  Ridge Acquisition			Source Acquisition		Acquisition Adjustments			Corporate Reorganization			Offering			Pro Forma Desert Peak Minerals Inc.
	(In thousands, except per share data)
				A		B			C
Revenue:
Oil, natural gas and natural gas liquids revenues	$	44,194		$	1,608	$	18,023		$	13,578	$			$			$			$	77,403
Lease bonus and other income		1,505					47			165					(13	) F					1,704
Commodity derivatives losses		(2,573	)				(156	)				156	D								(2,573	)
Total revenue		43,126			1,608		17,914			13,743		156			(13	)		—			76,534
Operating Expenses:
Management fees to affiliates		7,480	G																		7,480
Depreciation, depletion and amortization		32,049					15,555					9,862	E		(303	) F					57,163
General and administrative		4,981					3,182								(534	) F					7,629
General and administrative - affiliates		4,407																			4,407
Production costs, ad valorem taxes, and operating expense		3,151			104		364			893					(4	) F					4,508
Deferred offering costs write-off		2,747																			2,747
Impairment of oil and natural gas properties		812					63,528														64,340
Gain on sale of other property		(42	)												42	F					—
Bad debt expense (recovered)		(251	)												251	F					—
Total operating expenses		55,334			104		82,629			893		9,862			(548	)		—			148,274
Net income (loss) from operations		(12,208	)		1,504		(64,715	)		12,850		(9,706	)		535			—			(71,740	)
Other income (expense):
Other income		—					156														156
Interest income (expense), net		(1,968	)				(208	)							(35	) F		1,625	J		(586	)
Net income (loss) before income tax expense		(14,176	)		1,504		(64,767	)		12,850		(9,706	)		500			1,625			(72,170	)
Income tax (expense) benefit		(38	)				(43	)							15,756	H					15,675
Net income (loss)	$	(14,214	)	$	1,504	$	(64,810	)	$	12,850	$	(9,706	)	$	16,256		$	1,625		$	(56,495	)
Less net loss attributable to temporary equity															(47,383	) I					(47,383	)
Net income (loss) attributable to Desert Peak Minerals Inc.	$	(14,214	)	$	1,504	$	(64,810	)	$	12,850	$	(9,706	)	$	63,639		$	1,625		$	(9,112	)
Net Loss per Common Share
Basic																				$	(0.91	) K
Diluted																					(0.91	) K
Weighted Average Common Shares Outstanding
Basic																					10,000	K
Diluted																					10,000	K

F-7

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation, the Offering and Reorganization

The historical financial information is derived from the unaudited condensed consolidated financial statements as of and for the six months ended June 30, 2021 and the audited consolidated financial statements for the year ended December 31, 2020 of Kimmeridge Mineral Fund, LP (“KMF,” or the “Predecessor”) included elsewhere in this prospectus. For purposes of the unaudited pro forma consolidated balance sheet, it is assumed that the Source Acquisition, the Corporate Reorganization and the Offering had taken place on June 30, 2021. For purposes of the unaudited pro forma consolidated statements of operations, it is assumed the Transactions had taken place on January 1, 2020 (other than the Chambers Acquisition, for which pro forma effect is given as if it occurred on October 1, 2020, the date on which the acquired overriding royalty interest was created).

Upon the closing of the Offering, the Company expects to incur direct, incremental general and administrative expenses as a result of being publicly traded, including but not limited to costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. These direct, incremental general and administrative expenditures are not reflected in the historical financial statements or in the unaudited pro forma consolidated financial statements.

Desert Peak Minerals Inc. was incorporated as a Delaware corporation on April 17, 2019. Following this offering, Desert Peak Minerals will be a holding company whose sole material assets consists of direct and indirect membership interests in Desert Peak LLC (“Opco”), which will wholly own KMF Land. KMF Land will continue to wholly own the mineral subsidiaries. Following this offering, Desert Peak Minerals will be the sole managing member of Desert Peak LLC and will be responsible for all operational, management and administrative decisions relating to Desert Peak LLC’s business and will consolidate the financial results of Desert Peak LLC and its subsidiaries.

In connection with this Offering, we have engaged, or will engage, in the following series of transactions, which, together with the Offering, are collectively referred to in this prospectus as our “corporate reorganization”:

• on October 8, 2021, we amended and restated our revolving credit facility to, among other things, provide for the transactions contemplated by our corporate reorganization and this offering as well as to provide for an increased borrowing base;

• on October 27, 2021, we made a distribution of approximately $128 million to the Existing Owners using borrowings under the revolving credit facility and cash on hand;

• Opco and the indirect owners of our initial assets (our “Existing Owners”) will enter into a merger agreement pursuant to which Opco will acquire our initial assets (which will not include our Predecessor’s water business) and the Existing Owners will acquire 52,000,000 common units in Opco (the “Opco Units”) in the aggregate and will be admitted as members of Opco;

• we will issue 10,000,000 shares of our Class A common stock to purchasers in the Offering in exchange for the proceeds of the Offering;

• we will contribute all of the net proceeds of this offering and shares of our Class B common stock to Opco in exchange for a number of Opco Units equal to the number of shares of our Class A common stock outstanding following this offering, and Opco will then distribute a number of shares of our Class B common stock to our Existing Owners equal to the number of Opco Units held by them; and

F-8

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

• Opco will use a portion of the proceeds from this offering to (i) repay all of the outstanding borrowings under our revolving credit facility and (ii) fund future acquisitions of mineral and royalty interests.

To the extent the underwriters’ option to purchase additional shares is exercised in full or in part, we will contribute the net proceeds therefrom to Opco in exchange for an additional number of Opco Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Opco will use any such net proceeds to fund future acquisitions of mineral and royalty interests.

Following this Offering, our Existing Owners may distribute all or a portion of their respective Opco Units and a corresponding number of shares of Class B common stock to their partners or members, as applicable (the “Existing Owner Distribution”), subject to customary lock-up restrictions. Unless otherwise indicated, the information set forth in these pro forma consolidated financial statements does not give effect to the Existing Owner Distribution.

After giving effect to these transactions and the Offering, without giving effect to the Existing Owner Distribution and assuming the underwriters’ option to purchase additional shares is not exercised:

• our Existing Owners will own, in the aggregate, 100% of our Class B common stock, representing 84% of our capital stock;

• investors in the Offering will own, in the aggregate, 10,000,000 shares, or 100%, of our Class A common stock, representing 16% of our capital stock;

• we will own an approximate 16% interest in Opco; and

• our Existing Owners, will own, in the aggregate, an approximate 84% interest in Opco.

If the underwriters’ option to purchase additional shares is exercised in full, without giving effect to the Existing Owner Distribution:

• our Existing Owners will own, in the aggregate,100% of our Class B common stock, representing 82% of our capital stock;

• investors in the Offering will own, in the aggregate, 11,500,000 shares, or 100%, of our Class A common stock, representing 18% of our capital stock;

• we will own an approximate 18% interest in Opco; and

• our Existing Owners will own, in the aggregate, an approximate 82% interest in Opco.

2. Unaudited Pro Forma Consolidated Balance Sheet

Adjustments to the Pro Forma Consolidated Balance Sheet as of June 30, 2021

Source Acquisition Adjustments

A. Reflects the preliminary purchase price allocation of the properties for $254.6 million on August 31, 2021. The properties were acquired with equity consideration in a consolidated subsidiary of our predecessor.

Corporate Reorganization Adjustments

B. Reflects the elimination of assets and liabilities included in the balance sheet of the Predecessor related to the water business of Kimmeridge Mineral Fund, LP and KMF Water, LLC that will not be acquired by Opco. Other than the water business, Opco will acquire all of the assets and liabilities of the Predecessor.

F-9

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

C. Reflects the distribution of approximately $128 million to the Existing Owners using borrowings under the revolving credit facility and cash on hand on October 27, 2021.

D. Reflects the issuance of 52,000,000 shares of Class B common stock ($0.001 par value) to our Existing Owners in exchange for all outstanding Partners’ contributed capital, retained earnings and the noncontrolling interest. Following the offering, the Opco Unit holders will, subject to certain limitations, have the right to cause Opco to acquire all or a portion of its Opco Units (together with an equivalent number of shares of our Class B common stock) for, at Opco’s election, shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Opco Unit redeemed or an equivalent amount of cash. As a result of this cash redemption right, we have presented the associated Class B common stock as temporary equity on our pro forma consolidated balance sheet.

E. Reflects the pro forma adjustment of $2.1 million to reflect the estimated change in deferred tax assets for temporary differences between the historical cost basis and tax basis of the assets and liabilities being contributed to the Company following the corporate reorganization. The Company will be subject to subchapter C of the Internal Revenue Code of 1986, as amended, and as a result, will become taxable as a corporation and subject to U.S. federal and state income taxes at the entity level. The deferred tax assets associated with the corporate reorganization will be recorded in equity as it represents a transaction among shareholders.

The amounts to be recorded for the net deferred tax assets have been estimated. All of the effects of changes in any of our estimates after the date of purchase will be included in net income. Similarly, the effect of subsequent changes in the enacted tax rates will be included in net income.

Offering Adjustments

F. Reflects the issuance and sale of 10,000,000 shares of Class A common stock ($0.01 par value) at an assumed initial public offering price of $21.50 per share, net of underwriting discounts and commissions of $11.8 million in the aggregate, and additional estimated expenses related to the Offering of approximately $4.0 million and the use of the net proceeds therefrom as follows:

• the Company will contribute all of the net proceeds from the Offering to Desert Peak LLC in exchange for Opco Units; and

• Desert Peak LLC will use the net proceeds from the Offering:

• to repay $133 million of outstanding borrowings under the revolving credit facility; and

• to fund future acquisitions of mineral and royalty interests.

As of October 22, 2021, our outstanding borrowings totaled $11.9 million under our revolving credit facility, and we had cash and cash equivalents of $12.7 million.

The following table provides a reconciliation of the pro forma cash expected to be received and used in connection with consummation of the Offering and the net proceeds from the Offering as disclosed throughout this prospectus (in thousands):

Gross proceeds from the Offering	$	215,000
Estimated underwriting discounts and commissions		(11,825	)
Additional estimated Offering expenses		(4,000	)
Pro forma cash received from the Offering	$	199,175
Repayment of revolving credit facility		(133,000	)
Net pro forma cash provided by the Offering	$	66,175

F-10

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

G. Reflects the reclassification of $0.4 million of deferred offering costs from other current assets to a reduction in additional paid-in capital.

3. Unaudited Pro Forma Consolidated Statements of Operations

Adjustments to the Pro Forma Consolidated Statement of Operations for the six months ended June 30, 2021

Chambers Acquisition Adjustments

A. Reflects oil and gas operations of properties acquired from Chambers Minerals, LLC, an affiliate of Kimmeridge, on June 7, 2021 (the “Chambers Acquisition”).

Rock Ridge Acquisition Adjustments

B. Reflects the historical statements of operations of certain oil and gas properties acquired from Rock Ridge Royalty, LLC on June 30, 2021 (the “Rock Ridge Acquisition”).

Source Acquisition Adjustments

C. Reflects the historical statements of revenues and direct operating expenses, as included elsewhere in this prospectus, of certain oil and gas properties acquired from Source Energy Leasehold, LP and Permian Mineral Acquisitions, LP on August 31, 2021 (the “Source Acquisition”).

Acquisition Adjustments

D. Reflects the elimination of the commodity derivative losses associated with the Rock Ridge Acquisition. In accordance with the terms of the purchase and sale agreement, the seller was obligated to terminate the derivative contracts prior to the closing of the Rock Ridge Acquisition.

E. Reflects the pro forma impact to depletion expense associated with the change in fair value adjustment to oil and gas properties, as a result of the Chambers Acquisition, Rock Ridge Acquisition and Source Acquisition. The Company calculated depletion expense associated with all oil and gas properties of the Predecessor and those acquired in the Chambers Acquisition, the Rock Ridge Acquisition and the Source Acquisition on a consolidated basis as though all such properties were owned for the entire period. This number was then offset by the historical depletion expense related to the Predecessor and the Rock Ridge Acquisition presented in the Kimmeridge Mineral Fund, LP and Rock Ridge Acquisition columns, respectively, in the pro forma statement of operations, and the remaining amount was included as an Acquisition Adjustment on the face of the pro forma statement of operations. There is no historical depletion expense related to the Chambers Acquisition or the Source Acquisition. The adjustment reflected under Acquisition Adjustments was calculated using the units-of-production method under the successful efforts method of accounting (in thousands).

Depletion expense related to the fair value of the oil and gas properties of the Predecessor and those acquired in the Chambers Acquisition, Rock Ridge Acquisition and Source Acquisition	$	29,469
Less Predecessor historical depletion expense		(15,507	)
Less Rock Ridge Acquisition historical depletion expense		(3,353	)
Acquisition Adjustments to depletion expense	$	10,609

F-11

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Corporate Reorganization Adjustments

F. Reflects the elimination of revenues and operating expenses included in the results of operations of the Predecessor related to the water business of Kimmeridge Mineral Fund, LP and KMF Water, LLC that will not be acquired by Opco. Other than the water business, Opco will acquire all of the operations of the Predecessor.

G. Reflects the management fee expenses of Kimmeridge Mineral Fund, LP that were paid as compensation for services rendered in the management of the partnership. The management fee expenses represent the charge for managing the investment fund and did not include general and administrative expenses related to operating the business. The administrative expenses incurred by and reimbursed to management are presented in the general and administrative line item on the consolidated statement of operations. While a pro forma adjustment has not been made to eliminate the management fee expenses, the Company will no longer incur any management fees after completion of the Offering.

H. Reflects estimated income tax provision associated with the Company’s historical results of operations assuming the Company’s earnings had been subject to federal and state income tax as a subchapter C corporation using a blended statutory rate of 22% for the six months ended June 30, 2021. This rate is inclusive of U.S. federal and state taxes. The calculation of future net income tax expense is performed on a year-by-year basis by taking into account each year’s projected revenues, operating expenses, depreciation, depletion, and other factors in arriving at each year’s tax outflow. As such, the effective rate utilized in this calculation can differ from the blended statutory rate.

I. Reflects the elimination of net income attributable to non-controlling interest of the Predecessor historical consolidated financial statements, as the non-controlling interest will not exist subsequent to the Corporate Reorganization. In addition, the Company estimated the net income attributable to the Class B Common Stock that will be classified as temporary equity on the Company’s consolidated balance sheet subsequent to the Corporate Reorganization.

Offering Adjustments

J. Reflects the reversal of interest expense of $0.3 million as a result of the repayment of the revolving credit facility in connection with the Offering. On a pro forma basis, there would have been no outstanding borrowings under the Company’s revolving credit facility.

F-12

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

K. Reflects basic and diluted earnings per common shares of Class A Common Stock in the Corporate Reorganization and the Offering as shown below for the applicable period (in thousands, except per share data):

BASIC
Net income	$	18,169
Net income attributable to stockholders		2,930
Shares issued in the Corporate Reorganization and the Offering		10,000
Basic earnings per share	$	0.29
DILUTED
Numerator:
Net income	$	18,169
Effect of dilutive securities		—
Diluted net income attributable to stockholders		2,930
Denominator:
Basic weighted average shares outstanding		10,000
Effect of dilutive securities		—
Diluted weighted average shares outstanding		10,000
Diluted earnings per share	$	0.29

Adjustments to the Pro Forma Consolidated Statement of Operations for the year ended December 31, 2020

Chambers Acquisition Adjustments

A. Reflects oil and gas operations of properties acquired through the Chambers Acquisition from October 1, 2020 (the date on which the acquired overriding royalty interest was created) to December 31, 2020.

Rock Ridge Acquisition Adjustments

B. Reflects the historical statements of operations, as included elsewhere in this prospectus, of certain oil and gas properties acquired through the Rock Ridge Acquisition for the periods presented.

Source Acquisition Adjustments

C. Reflects the historical statements of revenues and direct operating expenses, as included elsewhere in this prospectus, of certain oil and gas operations of properties acquired through the Source Acquisition for the periods presented.

Acquisition Adjustments

D. Reflects the elimination of the commodity derivative losses associated with the Rock Ridge Acquisition. In accordance with the terms of the purchase and sale agreement, the seller was obligated to terminate the derivative contracts prior to the closing of the Rock Ridge Acquisition.

E. Reflects the pro forma impact to depletion expense associated with the change in fair value adjustment to oil and gas properties, as a result of the Chambers Acquisition, Rock Ridge Acquisition and Source Acquisition. The Company calculated depletion expense associated with all oil and gas properties of

F-13

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

the Predecessor and those acquired in the Chambers Acquisition, the Rock Ridge Acquisition and the Source Acquisition on a consolidated basis as though all such properties were owned for the entire period. This number was then offset by the historical depletion expense related to the Predecessor and the Rock Ridge Acquisition presented in the Kimmeridge Mineral Fund, LP and Rock Ridge Acquisition columns, respectively, in the pro forma statement of operations, and the remaining amount was included as an Acquisition Adjustment on the face of the pro forma statement of operations. There is no historical depletion expense related to the Chambers Acquisition or the Source Acquisition. The adjustment reflected under Acquisition Adjustments was calculated using the units-of-production method under the successful efforts method of accounting (in thousands).

Depletion expense related to the fair value of the oil and gas properties of the Predecessor and those acquired in the Chambers Acquisition, Rock Ridge Acquisition and Source Acquisition	$	56,782
Less Predecessor historical depletion expense		(31,428	)
Less Rock Ridge Acquisition historical depletion expense		(15,492	)
Acquisition Adjustments to depletion expense	$	9,862

Corporate Reorganization Adjustments

F. Reflects the elimination of revenues and operating expenses included in the results of operations of the Predecessor related to Kimmeridge Mineral Fund, LP and KMF Water, LLC that will not acquired by Opco.

G. Reflects the management fee expenses of Kimmeridge Mineral Fund, LP that were paid as compensation for services rendered in the management of the partnership. The management fee expenses represent the charge for managing the investment fund and did not include general and administrative expenses related to operating the business. The administrative expenses incurred by and reimbursed to management are presented in the general and administrative line item on the consolidated statement of operations. While a pro forma adjustment has not been made to eliminate the management fee expenses, the Company will no longer incur any management fees after completion of the Offering.

H. Reflects estimated income tax provision associated with the Company’s historical results of operations assuming the Company’s earnings had been subject to federal and state income tax as a subchapter C corporation using a blended statutory rate of 22% for the year ended December 31, 2020. This rate is inclusive of U.S. federal and state taxes. The calculation of future net income tax expense is performed on a year-by-year basis by taking into account each year’s projected revenues, operating expenses, depreciation, depletion, and other factors in arriving at each year’s tax outflow. As such, the effective rate utilized in this calculation can differ from the blended statutory rate.

I. Reflects the estimated net loss attributable to Class B Common Stock that will be classified as temporary equity on the Company’s consolidated balance sheet subsequent to the Corporate Reorganization.

F-14

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Offering Adjustments

J. Reflects the reversal of interest expense of $1.6 million as a result of the repayment of the revolving credit facility in connection with the Offering. On a pro forma basis, there would have been no outstanding borrowings under the Company’s revolving credit facility.

K. Reflects basic and diluted loss per common shares of Class A Common Stock in the Corporate Reorganization and the Offering as shown below for the applicable period:

BASIC
Net loss	$	(56,495)
Net loss attributable to stockholders		(9,112	)
Shares issued in the Corporate Reorganization and the Offering		10,000
Basic loss per share	$	(0.91)
DILUTED
Numerator:
Net loss	$	(56,495)
Effect of dilutive securities		—
Diluted net loss attributable to stockholders		(9,112	)
Denominator:
Basic weighted average shares outstanding		10,000
Effect of dilutive securities		—
Diluted weighted average shares outstanding		10,000
Diluted loss per share	$	(0.91)

F-15

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

4. Management’s Adjustments

Management expects that, following completion of the Rock Ridge Acquisition, the post-acquisition company will realize certain cost savings as compared to the historical combined costs of the Company and Rock Ridge operating independently. Such cost savings, which result from the elimination of duplicative costs and the manner in which the post-acquisition company will be integrated and managed prospectively, are not reflected in the unaudited pro forma statements of operations. The Company does not expect to incur any additional costs in order to achieve these cost savings. Management estimates that, had the Rock Ridge Acquisition been completed as of January 1, 2020, the corporate level expenses of the Predecessor would have been sufficient to operate the properties of the Predecessor and those acquired in the Rock Ridge Acquisition for the year ended December 31, 2020 and for the six months ended June 30, 2021. The following tables present the estimated effects on the pro forma consolidated statements of operations from elimination of the identified corporate level expenses:

	Six Months Ended June 30, 2021
	Amounts presented on consolidated statement of operations		Management assumptions			As Adjusted
General and administrative	$	2,467	$	(1,314	)	$	1,153
Net income before income taxes		23,210		1,314			24,524
Net income		18,169		1,028			19,197
Net income attributable to Desert Peak Minerals Inc.	$	2,930	$	166		$	3,096
Basic	$	0.29	$	0.02		$	0.31
Diluted	$	0.29	$	0.02		$	0.31

	Year Ended December 31, 2020
	Amounts presented on consolidated statement of operations			Management assumptions			As Adjusted
General and administrative	$	7,629		$	(3,182	)	$	4,447
Net loss before income taxes		(72,170	)		3,182			(68,988	)
Net loss		(56,495	)		2,491			(54,004	)
Net loss attributable to Desert Peak Minerals Inc.	$	(9,112	)	$	402		$	(8,710	)
Basic	$	(0.91	)	$	0.04		$	(0.87	)
Diluted	$	(0.91	)	$	0.04		$	(0.87	)

5. Supplementary Disclosure of Oil and Natural Gas Operations

The following tables present the estimated pro forma proved reserve information as of December 31, 2020, along with a summary of changes in quantities of remaining proved reserves during the year ended December 31, 2020.

F-16

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The following estimated pro forma reserve information is not necessarily indicative of the results that might have occurred had the Transactions been completed on December 31, 2020 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those described under “Risk Factors.”

	Balance, December 31, 2019		Revisions			Extensions		Acquisition of reserves		Divestiture of reserves			Production			Balance, December 31, 2020
Kimmeridge Mineral Fund, LP
Oil (MBbls)		5,839		(1,098	)		995		445		(173	)		(933	)		5,075
Natural Gas (MMcf)		24,493		(867	)		3,486		633		(209	)		(4,134	)		23,402
Natural Gas Liquids (MBbls)		2,774		65			423		77		(26	)		(488	)		2,825
Total (MBOE)		12,695		(1,178	)		1,999		628		(234	)		(2,110	)		11,800
Chambers Acquisition
Oil (MBbls)		—		—			—		808		—			(33	)		775
Natural Gas (MMcf)		—		—			—		2,791		—			(97	)		2,694
Natural Gas Liquids (MBbls)		—		—			—		340		—			(14	)		326
Total (MBOE)		—		—			—		1,613					(63	)		1,550
Rock Ridge Acquisition
Oil (MBbls)		5,139		(3,096	)		1,951		14		—			(444	)		3,564
Natural Gas (MMcf)		9,367		(4,475	)		4,041		29		—			(830	)		8,132
Natural Gas Liquids (MBbls)		1,444		(666	)		672		4		—			(129	)		1,325
Total (MBOE)		8,144		(4,510	)		3,297		23		—			(710	)		6,244
Source Acquisition
Oil (MBbls)		1,142		16			684		1		—			(328	)		1,515
Natural Gas (MMcf)		3,490		(75	)		1,196		4		—			(582	)		4,033
Natural Gas Liquids (MBbls)		311		(8	)		107		—		—			(51	)		359
Total (MBOE)		2,035		(5	)		990		2		—			(476	)		2,546
Pro Forma
Oil (MBbls)		12,120		(4,178	)		3,630		1,268		(173	)		(1,738	)		10,929
Natural Gas (MMcf)		37,350		(5,417	)		8,723		3,457		(209	)		(5,643	)		38,261
Natural Gas Liquids (MBbls)		4,529		(609	)		1,202		421		(26	)		(682	)		4,835
Total (MBOE)		22,874		(5,693	)		6,286		2,266		(234	)		(3,359	)		22,140

F-17

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

	Proved Developed and Undeveloped Reserves
	Developed as of December 31, 2019		Undeveloped as of December 31, 2019		Balance, December 31, 2019		Developed as of December 31, 2020		Undeveloped as of December 31, 2020		Balance, December 31, 2020
Kimmeridge Mineral Fund, LP
Oil (MBbls)		4,223		1,616		5,839		3,731		1,344		5,075
Natural Gas (MMcf)		20,293		4,200		24,493		19,505		3,897		23,402
Natural Gas Liquids (MBbls)		2,298		476		2,774		2,352		473		2,825
Total (MBOE)		9,903		2,792		12,695		9,334		2,467		11,800
Chambers Acquisition
Oil (MBbls)		—		—		—		596		179		775
Natural Gas (MMcf)		—		—		—		2,088		606		2,694
Natural Gas Liquids (MBbls)		—		—		—		253		73		326
Total (MBOE)		—		—		—		1,196		354		1,550
Rock Ridge Acquisition
Oil (MBbls)		1,605		3,534		5,139		1,469		2,095		3,564
Natural Gas (MMcf)		3,320		6,048		9,367		3,723		4,409		8,132
Natural Gas Liquids (MBbls)		452		992		1,444		599		726		1,325
Total (MBOE)		2,610		5,534		8,144		2,688		3,556		6,244
Source Acquisition
Oil (MBbls)		967		175		1,142		1,060		455		1,515
Natural Gas (MMcf)		2,953		537		3,490		3,244		789		4,033
Natural Gas Liquids (MBbls)		263		48		311		289		70		359
Total (MBOE)		1,723		312		2,035		1,890		656		2,546
Pro Forma
Oil (MBbls)		6,795		5,325		12,120		6,856		4,073		10,929
Natural Gas (MMcf)		26,566		10,785		37,350		28,560		9,701		38,261
Natural Gas Liquids (MBbls)		3,013		1,516		4,529		3,493		1,342		4,835
Total (MBOE)		14,236		8,638		22,874		15,108		7,033		22,140

Standardized Measure of Discounted Future Cash Flows

The following pro forma standardized measure of the discounted net future cash flows and changes applicable to KMF’s proved reserves reflect the effect of income taxes assuming KMF’s standardized measure had been subject to federal and state income tax as a subchapter C corporation. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies audited by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Therefore, the standardized measure of discounted future net cash flows is not necessarily indicative of the fair value of KMF’s proved oil and natural gas properties.

F-18

DESERT PEAK MINERALS INC.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The data presented should not be viewed as representing the expected cash flows from or current value of existing proved reserves since the computations are based on a large number of estimates and assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2020 (in thousands):

	KIMMERIDGE MINERAL FUND, LP			CHAMBERS ACQUISITION			ROCK RIDGE ACQUISITION			SOURCE ACQUISITION			CORPORATE REORGANIZATION			PRO FORMA
Future oil and natural gas sales	$	238,977			33,344			145,440			69,161			—		$	486,922
Future production costs		(19,379	)		(2,638	)		(9,801	)		(5,611	)		—			(37,429	)
Future income tax expense		(1,236	)		(175	)		—			(361	)		(55,000	)		(56,772	)
Future net cash flows		218,362			30,531			135,639			63,189			(55,000	)		392,721
10% annual discount		(94,803	)		(12,693	)		(63,000	)		(23,224	)		23,275			(170,445	)
Standardized measure of discounted future net cash flows	$	123,559			17,838			72,639			39,965			(31,725	)	$	222,276

Pro forma income tax expense is calculated using the estimated statutory rate of 22%. The pro forma future income tax expense, as calculated, is lower than the statutory rate due to the tax basis related to the acquired properties.

The change in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2020 (in thousands):

	KIMMERIDGE MINERAL FUND, LP			CHAMBERS ACQUISITION			ROCK RIDGE ACQUISITION			SOURCE ACQUISITION			CORPORATE REORGANIZATION			PRO FORMA
Balance at the beginning of the period	$	183,225			—			135,313			41,535			—		$	360,073
Net change in prices and production costs		(59,911	)		—			(59,140	)		(10,929	)		—			(129,980	)
Sales, net of production costs		(41,043	)		(1,504	)		(17,659	)		(12,685	)		—			(72,891	)
Extensions and discoveries		25,196			—			38,978			17,972			—			82,146
Acquisitions of reserves		9,137			19,342			278			35			—			28,792
Divestiture of reserves		(3,563	)		—			—			—			—			(3,563	)
Revisions of previous quantity estimates		(18,140	)		—			(38,134	)		(537	)		—			(56,811	)
Net change in income taxes		343			—			—			9			(31,725	)		(31,373	)
Accretion of discount		18,427			—			13,531			4,177			—			36,135
Changes in timing and other		9,888			—			(529	)		388			—			9,747
Balance at the end of the period	$	123,559			17,838			72,639			39,965			(31,725	)	$	222,276

F-19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Desert Peak Minerals Inc.:

Opinion on the Balance Sheets

We have audited the accompanying balance sheets of Desert Peak Minerals Inc. (the Company) as of December 31, 2020 and 2019 and the related notes (collectively, the balance sheets). In our opinion, the balance sheets present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

The balance sheets are the responsibility of the Company’s management. Our responsibility is to express an opinion on the balance sheets 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 and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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 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 balance sheets. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2020.

Denver, Colorado

June 16, 2021

F-20

DESERT PEAK MINERALS INC.

BALANCE SHEETS

	December 31, 2020			December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	—		$	—
Total assets	$	—		$	—
Liabilities and stockholders’ equity
Total liabilities
Total liabilities	$	—		$	—
Stockholders’ equity:
Common stock, $.01 par value; authorized 1,000 shares, 1,000 issued and outstanding at December 31, 2020 and 2019, respectively	$	10		$	10
Less receivable from Kimmeridge Mineral Fund, LP		(10	)		(10	)
Total stockholders’ equity	$	—		$	—

F-21

DESERT PEAK MINERALS INC.

NOTES TO BALANCE SHEETS

1. Organization and basis of presentation

Desert Peak Minerals Inc. (“DPM”) is a Delaware corporation formed in April 2019 to become a holding company.

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America. Receivable from Kimmeridge Mineral Fund, LP (“KMF”) represents an amount of $10.00 due for the issuance of 1,000 shares of $.01 par value common stock to KMF. Prior to payment by KMF, this receivable will be recorded as a reduction of shareholder’s equity. Separate Statements of Operations, Changes in Shareholders’ Equity and of Cash Flows have not been presented because DPM has had no business transactions or activities to date.

2. Subsequent events

DPM has evaluated subsequent events through June 16, 2021, the date on which the balance sheet as of December 31, 2020 was available to be issued. We are not aware of any events that have occurred subsequent to December 31, 2020 that would require recognition or disclosure in this balance sheet.

F-22

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Kimmeridge Mineral Fund, LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Kimmeridge Mineral Fund, LP and subsidiaries (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, changes in partners’ capital, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated 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 consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2020.

Denver, Colorado

April 2, 2021

F-23

KIMMERIDGE MINERAL FUND, LP

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,
	2020			2019
ASSETS
Current assets
Cash and cash equivalents	$	7,531		$	16,507
Restricted cash		—			1,626
Accounts receivable, net		8,505			12,805
Other current assets		138			2,086
Total current assets		16,174			33,024
Property and equipment
Oil and natural gas properties, successful efforts method:
Unproved properties		399,229			398,710
Proved properties		254,854			236,742
Other property and equipment		7,990			7,989
Accumulated depreciation, depletion, and amortization		(80,630	)		(48,706	)
Net oil and gas properties and other property and equipment		581,443			594,735
Other long-term assets
Escrow deposits		—			3,067
Deferred financing costs		1,011			979
Total other long-term assets		1,011			4,046
TOTAL ASSETS	$	598,628		$	631,805
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accrued expenses and other liabilities	$	2,035		$	8,036
Due to affiliates (Note 10)		55			106
Total current liabilities		2,090			8,142
Long-term liabilities
Long-term debt		33,500			60,000
Deferred rent		641			52
Total long-term liabilities		34,141			60,052
Total liabilities		36,231			68,194
COMMITMENTS AND CONTINGENCIES (NOTE 11)
Partners’ capital		562,397			563,611
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	598,628		$	631,805

The accompanying notes are an integral part of the consolidated financial statements

F-24

KIMMERIDGE MINERAL FUND, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31,
	2020			2019
Revenue:
Oil, natural gas and natural gas liquids revenues	$	44,194		$	50,886
Lease bonus and other income		1,505			5,319
Water sales		—			3,475
Commodity derivatives losses		(2,573	)		—
Total revenues		43,126			59,680
Operating Expenses:
Management fees to affiliates (Note 10)		7,480			7,480
Depreciation, depletion and amortization		32,049			26,201
General and administrative		4,981			2,349
General and administrative - affiliates (Note 10)		4,407			8,167
Production costs, ad valorem taxes and operating expense		3,151			5,249
Deferred offering costs write off		2,747			—
Impairment of oil and natural gas properties		812			—
Gain on sale of other property		(42	)		—
Bad debt expense (recovered)		(251	)		405
Total operating expenses		55,334			49,851
Net income (loss) from operations		(12,208	)		9,829
Other expense:
Interest expense		(1,968	)		(868	)
Net income (loss) before income tax expense		(14,176	)		8,961
Income tax expense		(38	)		(171	)
Net income (loss)	$	(14,214	)	$	8,790

The accompanying notes are an integral part of the consolidated financial statements

F-25

KIMMERIDGE MINERAL FUND, LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

(In thousands)

							Total
	General Partner			Limited Partners			Partners’ Capital
Partners’ capital at January 1, 2019	$	4,623		$	385,458		$	390,081
Capital contributions		2,388			162,352			164,740
Net income		235			8,555			8,790
Partners’ capital at December 31, 2019	$	7,246		$	556,365		$	563,611
Capital contributions		166			12,834			13,000
Net loss		(86	)		(14,128	)		(14,214	)
Partners’ capital at December 31, 2020	$	7,326		$	555,071		$	562,397

The accompanying notes are an integral part of the consolidated financial statements

F-26

KIMMERIDGE MINERAL FUND, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year ended December 31,
	2020			2019
Cash flows from operating activities:
Net income (loss)	$	(14,214	)	$	8,790
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		32,049			26,201
Impairment of oil and natural gas properties		812			—
Deferred offering costs write off		2,747			—
Loss on extinguishment of debt		—			308
Bad debt expense (recovered)		(251	)		405
Gain on sale of other property		(42	)		—
Change in operating assets and liabilities:
Accounts receivable, net		4,436			(1,340	)
Due from affiliates (Note 10)		—			610
Other current assets		14			(60	)
Deferred financing costs		256			53
Accrued expenses and other liabilities		(328	)		(121	)
Due to affiliates (Note 10)		(51	)		(107	)
Deferred rent		588			52
Net cash provided by operating activities		26,016			34,791
Cash flows from investing activities:
Purchases of oil and gas properties		(35,543	)		(266,538	)
Proceeds from sale of oil and gas properties		14,069			22,019
Purchases of other property and equipment		(293	)		(1,041	)
Proceeds from sale of other property and equipment		210			—
Escrow deposits		—			(3,067	)
Net cash used in investing activities		(21,557	)		(248,627	)
Cash flows from financing activities:
Capital contributions		13,000			164,740
Borrowings on credit facility		10,000			60,000
Repayments on credit facility		(36,500	)		—
Payments of deferred financing costs		(316	)		(1,284	)
Deferred initial public offering costs		(1,245	)		(1,502	)
Net cash provided by (used in) financing activities		(15,061	)		221,954
Net change in cash, cash equivalents and restricted cash		(10,602	)		8,118
Cash, cash equivalents and restricted cash, beginning of year		18,133			10,015
Cash, cash equivalents and restricted cash, end of year	$	7,531		$	18,133
Supplemental disclosure of non-cash transactions:
Escrow deposits reclassified to oil and gas properties:	$	3,067		$	—
Increase in current liabilities for additions to property and equipment:		2,145			2,184
Supplemental disclosure of cash flow information:
Cash paid for income taxes:	$	230		$	175
Cash paid for interest expense:		1,687			676

The accompanying notes are an integral part of the consolidated financial statements

F-27

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

1. Organization

Kimmeridge Mineral Fund, LP (the “Partnership”) is a Delaware limited partnership operating under the Third Amendment to the Second Amended and Restated Limited Partnership Agreement (the “Partnership Agreement”) dated as of July 19, 2019. The Partnership formed on November 1, 2016 and commenced operation on November 11, 2016. The primary purpose of the Partnership is to acquire, own and manage mineral and royalty interests in the Delaware Basin, located in West Texas and southeastern New Mexico of the United States. Mineral interests are real property interests that are typically perpetual and grant ownership of the oil and natural gas underlying a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those rights are leased to third party operators, usually for a one to three-year term, the Partnership typically receives an upfront cash payment, known as a lease bonus, and the Partnership retains a mineral royalty, which entitles the Partnership to a cost-free percentage (up to 25%) of production or revenue from production free of lease operating expenses. The Partnership also owns surface rights which generate revenues from the sale of water produced from the Partnership’s water supply assets and from rights-of-way, easements and other rights.

The Partnership Agreement provides that the Partnership will continue (unless earlier dissolved) for ten years from the final closing date provided, however, that Kimmeridge Mineral GP, LLC (the “General Partner” or “Management”), may, in its discretion, extend the term of the Partnership for two additional one-year periods. In addition, the General Partner may extend the term of the Partnership for a third additional three-year period (the “Final Extension”); provided however, that the General Partner shall provide notice of such a proposed extension to the Limited Partners at least 60 calendar days before the expiration of the then current term. The Final Extension shall automatically take effect unless a majority of the Limited Partnership Advisory Committee (“LPAC”) members notify the General Partner in writing within 30 calendar days of receipt of the extension notice of their decision not to allow the Final Extension. Except as may be required by law or expressly provided for in the Partnership Agreement, the liability of each Limited Partner is limited to its Capital Commitment.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Partnership’s financial position as of December 31, 2020 and 2019, and the results of its operations and its cash flows for the years ended December 31, 2020 and 2019.

Use of Estimates

The preparation of 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 financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

The Partnership’s estimates and classification 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. Reserve engineering is a subjective process of

F-28

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

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. These factors and assumptions include 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. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas and estimates of the future net cash flows may vary substantially.

Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of the Partnership’s oil and natural gas properties and/or the rate of depletion related to oil and natural gas properties.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Partnership’s wholly-owned limited liability company subsidiaries KMF Land, LLC (“KMF Land”) and KMF Water, LLC (“KMF Water”). All intercompany accounts and transactions have been eliminated in consolidation.

Risks and Uncertainties

The ongoing global spread of the novel coronavirus (“COVID-19”), has caused a continuing disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil beginning in the first quarter of 2020 and continuing through the fourth quarter of 2020. The markets for oil, natural gas and natural gas liquids (“NGL”) have experienced significant price fluctuations. Such price volatility is expected to continue into the future. Lower commodity prices may reduce the amount of oil, natural gas and NGL that can be produced economically by operators. Increases or decreases in commodities could impact the Partnership’s financial performance and expected operating results, which may include future reserves estimates and potential recognition of impairment charges related to the Partnership’s mineral and royalty interests.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, Leases, which requires all leasing arrangements to be presented on the balance sheet as liabilities along with a corresponding asset. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. The ASU will replace most existing lease guidance in GAAP when it becomes effective. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11 Leases: Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The new standards become effective for the Partnership during the fiscal year ending December 31, 2022 and interim periods within the fiscal year ending December 31, 2023. Early adoption is permitted. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.

F-29

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses, which amends current impairment guidance by adding an impairment model (known as the current expected credit loss model (“CECL”) that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of lifetime expected credit losses, which the FASB believes will result in more timely recognition of such losses. ASU 2016-13 is effective for annual periods beginning after December 15, 2022 and interim periods within those annual periods. The Partnership is currently evaluating the impact of the adoption of this standard but does not believe it will have a material impact on the Partnership’s financial statements.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement, which removes, modifies, and adds certain required disclosures on fair value measurements. As amended, Topic 820 no longer requires the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. In addition, certain modifications to prior disclosure requirements were made, including clarifying that the measurement uncertainty disclosure is to communicate information about the uncertainty in measurement as of the reporting date. Certain disclosure requirements were also added, including the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements. The new standard was adopted by the Partnership effective January 1, 2020. Adoption of the standard did not have an impact on the Partnership’s financial statements.

In March 2020, the FASB issued ASU 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In response to the cessation of the London Interbank Offered Rate (“LIBOR”) by December 31, 2021, the FASB issued this update to provide optional expedients and exceptions for applying GAAP to contract modifications, hedging relations, and other affected transactions. The Partnership currently only has one contract subject to LIBOR, its revolving credit facility, that may be impacted by this ASU. Modifications of debt contracts should be accounted for by prospectively adjusting the effective interest rate. This update is effective immediately, but may be adopted through December 31, 2022, and allows for elections to be made by the Partnership in terms of how the ASU is adopted. Once elected for a Topic or Industry Subtopic, the update must be applied prospectively for all eligible contract modifications. The Partnership is currently evaluating the impact of the adoption of this standard but does not believe it will have a material impact on the Partnership’s financial statements.

Cash and Cash Equivalents

The Partnership considers all highly-liquid instruments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash

The Partnership segregates certain cash balances as restricted cash if they represent funds required to be set aside by a contractual agreement. The Partnership classifies restricted cash amounts as either current or non-current assets based on the length of restriction on use. As of December 31, 2019, approximately $1.6 million related to certain oil and gas property acquisitions was held in restricted cash accounts. This balance was released and relieved a corresponding liability in accrued expenses and other liabilities once the holdback conditions were met in 2020. There were no such balances as of December 31, 2020.

F-30

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Accounts Receivable

Accounts receivable represent amounts due to the Partnership and are uncollateralized, consisting primarily of royalty revenue receivable and water sales receivable. Royalty revenue receivable consists of royalties due from operators for oil, natural gas and NGL volumes sold to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to the Partnership. Receivables from third parties for which we did not receive actual production information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. We do not recognize revenues for wells with no historical actual production data or available state database information because we cannot conclude that it is probable that a significant revenue reversal will not occur in future periods. The Partnership accrues for oil, natural gas and NGL sales based on actual production dates.

Water sales receivable represents water sales to various basin operators produced from the water supply assets of the Partnership.

The Partnership routinely assesses the recoverability of all material accounts receivable to determine their collectability. The Partnership accrues a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. The Partnership had an allowance for doubtful accounts related to its KMF Water receivables of $0.2 million and $0.4 million as of December 31, 2020 and 2019, respectively. There were no such allowances for KMF Land’s royalty revenue receivables as of December 31, 2020 and 2019. For the year ended December 31, 2020, the Partnership collected $0.3 million related to receivables of KMF Water for which an allowance had previously been established.

The Partnership’s accounts receivable consisted of the following as of the dates indicated (in thousands):

	December 31, 2020		December 31, 2019
Royalty revenue	$	8,504	$	11,317
Water sales		—		1,373
Other		1		115
Total accounts receivable, net	$	8,505	$	12,805

Oil and Gas Properties

The Partnership uses the successful efforts method of accounting for oil and natural gas producing properties, as further defined under ASC 932, Extractive Activities - Oil and Natural Gas. Under this method, costs to acquire mineral interests in oil and natural gas properties are capitalized. The costs of non-producing mineral interests and associated acquisition costs are capitalized as unproved properties pending the results of leasing efforts and drilling activities of Exploration and Production (“E&P”) operators on our interests. As unproved properties are determined to have proved reserves, the related costs are transferred to proved oil and gas properties. Capitalized costs for proved oil and natural gas mineral interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved oil and gas properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions. Depletion expense totaled approximately $31.4 million and $25.7 million for the years ended December 31, 2020 and 2019, respectively.

F-31

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Other Property and Equipment

Other property and equipment is recorded at cost, which includes water supply assets (water wells and water storage pits), field vehicles, and other assets. Depreciation and amortization are calculated using the straight-line method over the estimated useful lives of the assets. Leasehold improvements are depreciated over the shorter of the lease term or the useful lives of the assets. Water wells are depreciated over estimated useful lives of two to twenty-five years. For the years ended December 31, 2020 and 2019, the Partnership recorded approximately $0.6 million and $0.5 million, respectively, in depreciation for water wells and other property and equipment.

The costs to drill water wells are capitalized while drilling is in progress. If a water well is determined to be unsuccessful or unproductive prior to being placed in service, the associated costs will be charged to expense in the period the determination is made. No expense was recognized in connection with unsuccessful water wells for the years ended December 31, 2020 and 2019. Additionally, we evaluate our other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset that has been placed in service may not be recoverable. No impairment charge was recorded for the years ended December 31, 2020 and 2019.

Impairment of Oil and Gas Properties

The Partnership evaluates its producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, the Partnership compares the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. There was no impairment of proved properties for the years ended December 31, 2020 and 2019. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Unproved oil and gas properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed based on when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include but are not limited to commodity price outlooks, current and future operator activity in the Delaware Basin, and analysis of recent mineral transactions in the surrounding area. The Partnership recognized approximately $0.8 million of unproved property impairment for the year ended December 31, 2020. This impairment was related to capitalized acquisition costs for a prospective mineral interest acquisition that the Partnership did not complete. The Partnership recognized no impairment of unproved properties for the year ended December 31, 2019.

Escrow Deposits

Escrow deposits are utilized for certain purchases of oil and gas properties. Such deposits are reclassified to oil and gas properties upon closure of the acquisitions. As of December 31, 2020, there were no such balances. As of December 31, 2019, approximately $3.1 million related to acquisitions was held in escrow deposits.

F-32

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Derivative Financial Instruments

In order to manage its exposure to oil, natural gas, and NGLs price volatility, the Partnership may periodically enter into derivative transactions, which may include commodity swap agreements, basis swap agreements, and other similar agreements which help manage the price risk associated with the Partnership’s production. These derivatives are not entered into for trading or speculative purposes. To the extent legal right of offset exists with a counterparty, the Partnership reports derivative assets and liabilities on a net basis. The Partnership has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Partnership actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions.

The Partnership records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Partnership’s consolidated statements of operations. The Partnership’s derivatives have not been designated as hedges for accounting purposes.

Accrued Expenses and Other Liabilities

The Partnership’s accrued expenses and other liabilities consisted of the following as of the dates indicated (in thousands):

	December 31, 2020		December 31, 2019
Payables for conveyed interests	$	99	$	2,954
Restricted cash for oil and gas property acquisitions		—		1,626
Taxes payable		1,268		1,810
General and administrative		445		452
Capital expenditures		—		711
Deferred offering costs		—		431
Deferred rent expense		63		—
Interest expense		88		62
Other		72		(10	)
Total accrued expenses and other liabilities	$	2,035	$	8,036

Income Taxes

The Partnership is organized as a pass-through entity for income tax purposes. As a result, the partners are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. However, the Partnership is required to pay Texas State franchise taxes and certain New Mexico income taxes. The Partnership recognized approximately $38 thousand and $171 thousand of Texas state franchise taxes and New Mexico income taxes for the years ended December 31, 2020 and 2019, respectively.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGL, less production taxes and post-production expenses. The prices of oil, natural gas, and NGL from the properties in which we own a mineral or royalty interest are primarily determined by supply and demand in

F-33

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no working interest or operational control over the volumes and methods of sale of the oil, natural gas, and NGL produced and sold from our properties. We do not explore, develop, or operate the properties and, accordingly, do not incur any of the associated costs.

Oil, natural gas, and NGL revenues from our mineral and royalty interests are recognized when control transfers at the wellhead. Water sales are recognized when control of the water is transferred to an E&P operator and collectability is reasonably assured.

The Partnership also earns revenue related to lease bonuses. The Partnership earns lease bonus revenue by leasing its mineral interests to E&P companies. The Partnership recognizes lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.

See Note 3 for additional disclosures regarding revenue recognition.

Concentration of Revenue

Collectability of the Partnership’s royalty revenue is dependent upon the financial condition of the Partnership’s operators as well as general economic conditions in the industry.

For the year ended December 31, 2020, in the Oil and Gas Producing Activities segment, revenue from Diamondback Energy, Inc, Cimarex Energy, and Oxy USA Inc represented approximately 15%, 12% and 10% of total revenue, respectively. These figures are the same as total revenues due to the fact that revenues attributable to the Water Services Operations segment for the year ended December 31, 2020 were de minimis.

For the year ended December 31, 2019, in the Oil and Gas Producing Activities segment, revenue from Cimarex Energy, Oxy USA Inc and PDC Energy represented approximately 16%, 10% and 10% of total revenue, respectively. In the Water Services Operations segment PDC Energy, WPX Energy, OXY USA Inc. and BTA Oil Producers represented 37%, 24%, 20% and 16% of total revenue, respectively. Combining both the Water Services Operations and Oil and Gas Producing Activities segments, Cimarex Energy, PDC Energy, and Oxy USA Inc represented approximately 15%, 12% and 11% of total revenue, respectively.

Although the Partnership is exposed to a concentration of credit risk, the Partnership does not believe the loss of any single purchaser would materially impact the Partnership’s operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. If multiple purchasers were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving the Partnership’s operators have stipulated that royalty owners must still be paid for oil, natural gas and NGLs extracted from their mineral acreage during the bankruptcy process. In light of this, the Partnership does not expect the entry of one of our operators into bankruptcy proceeding to materially affect our operating results.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, restricted cash, accounts receivable, accrued expenses, and other liabilities approximate fair value, as of December 31, 2020 and 2019.

The fair values of the Partnership’s derivative asset and liabilities are based on a third-party industry-standard pricing model using contract terms, prices, assumptions, and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price

F-34

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

curves, discount rates, and credit risk adjustments. See Note 9 for information regarding the fair values of derivative instruments.

The Revolving Credit Facility (defined in Note 7) has a recorded value that approximates its fair value as the interest rates are based on prevailing market rates.

Deferred Financing Costs

Debt issuance costs incurred in connection with KMF Land’s entry into its credit facility, and subsequent amendments, are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. As of December 31, 2020 and 2019, KMF Land had unamortized debt issuance costs of $1.0 million and $1.3 million, respectively, in connection with its entry into the facility and subsequent amendments.

Deferred Offering Costs

The Partnership recognized a write off of approximately $2.7 million of deferred offering costs for the year ended December 31, 2020 related to the temporary postponement of an initial public offering in accordance with SAB Topic 5.A of the Securities and Exchange Commission. No such charge was recorded for the year ended December 31, 2019.

Deferred Rent

The Partnership recognizes rent expense on a straight-line basis over the term of the lease. Due to the variable rental payments, a liability has been recognized.

3. Revenue from Contracts with Customers

Oil and natural gas sales

Oil, natural gas and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Partnership’s oil, natural gas and NGL sales are made under contracts with customers (operators). The performance obligations for the Partnership’s contracts with customers are satisfied at a point in time when control transfers at the wellhead, at which point payment is unconditional. Accordingly, the Partnership’s contracts do not give rise to contract assets or liabilities. The Partnership typically receives payment for oil, natural gas and NGL sales within 30 to 90 days of the month of delivery after initial production from the well. Such periods can extend longer due to factors outside of our control. The Partnership’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions.

Lease bonus and other income

The Partnership also earns revenue from lease bonuses, delay rentals, and right-of-way payments. The Partnership generates lease bonus revenue by leasing its mineral interests to E&P companies. A lease agreement represents our contract with a customer and generally transfers the rights, for a specified period of time, to explore for and develop any oil, natural gas and hydrocarbons discovered, grants us a specified

F-35

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

royalty interest in the hydrocarbons produced from the leased property, and requires that drilling and completion operations commence within a specified time period. The Partnership recognizes lease bonus revenues when the lease agreement has been executed and payment is determined to be collectible. At the time the Partnership executes the lease agreement, the lease bonus payment is delivered to the Partnership. Upon receipt of the lease bonus payment, the Partnership will release the recordable original lease documents to the customer. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period and payment has been received. Right-of-way payments are recorded by the Partnership when the agreement has been executed and payment is determined to be collectable. Payments for lease bonus and other income become unconditional upon the execution of an associated agreement. Accordingly, the Partnership’s lease bonus and other income transactions do not give rise to contract assets or liabilities.

Water sales

In 2019, the Partnership earned revenue from water sales to various E&P operators located near its water supply assets. Water sales revenues are recognized when control of the water is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. The performance obligations for the Partnership’s water sales are satisfied when control of the water is transferred to the customer, which may occur at the location of the Partnership’s water operations or at the customer’s well site. The Partnership’s water sales agreements are inherently short-term in nature and are executed on an as-needed basis with customers. The Partnership’s contracts for water sales are satisfied at the point in time when control of the water is transferred to the customer, at which point payment is unconditional. Accordingly, the Partnership’s contracts do not give rise to contract assets or liabilities.

In 2020, KMF Water entered into an agreement (the “Water Services Agreement”) with a third-party water services company under which the third party agreed to manage the Partnership’s water assets and operations. See Note 12 for additional information.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of our royalty income contracts.

Lease bonus and other income

Given that the Partnership does not recognize lease bonus or other income until an agreement has been executed, at which point its performance obligation has been satisfied, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Water sales

Given that the Partnership does not recognize water revenue until water is delivered, at which point its performance obligation has been satisfied, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. As a royalty interest owner, the Partnership has limited visibility into the timing of when new wells start producing as production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. The difference between the Partnership’s estimates of royalty income and the actual amounts received for oil and natural gas sales are recorded in the month that the royalty payment is received from the customer. For the years ended December 31, 2020 and 2019, revenue recognized related to performance obligations satisfied in prior reporting periods was primarily attributable to production revisions by operators or amounts for which the information was not available at the time when revenue was estimated.

4. Oil and Gas Properties

The Partnership has been and is engaged in the purchase of mineral rights in the Delaware Basin portion of the Permian Basin in West Texas and southeastern New Mexico. The following is a summary of oil and natural gas properties as of December 31, 2020 and 2019 (in thousands):

	December 31, 2020			December 31, 2019
Oil and natural gas properties:
Unproved properties	$	399,229		$	398,710
Proved properties		254,854			236,742
Oil and natural gas properties, gross		654,083			635,452
Accumulated depletion and impairment		(77,857	)		(46,417	)
Oil and natural gas properties, net	$	576,226		$	589,035

The Partnership incurred mineral acquisition costs of approximately $35.5 million and $266.5 million for the years ended December 31, 2020 and 2019, respectively. The Partnership received proceeds from the sale of mineral interests of approximately $14.1 million and $22.0 million for the years ended December 31, 2020 and 2019, respectively.

5. Acquisitions

DRC Acquisition

In July 2019, KMF Land entered into a Purchase and Sale Agreement and a Cooperation Agreement with Desert Royalty Company (“DRC”) pursuant to which KMF Land agreed to acquire all of DRC’s Delaware Basin oil and gas mineral and royalty interests. Pursuant to the Purchase and Sale Agreement which closed on September 26, 2019, with an effective date of September 1, 2019, DRC conveyed an undivided 25% interest in their Delaware Basin mineral and royalty interests to KMF Land (the “Initial Acquisition”).

The Initial Acquisition was accounted for as an asset acquisition and therefore, the interests were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. KMF Land acquired these initial mineral and royalty interests for $185.0 million, which it financed substantially with Partnership capital calls, cash

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

flows from operations and a draw on the KMF Land Revolving Credit Facility of $60.0 million. The Partnership recorded $160.4 million of the total consideration as unproved oil and gas property and $24.6 million as proved oil and gas property. Additionally, $1.4 million of transaction costs were capitalized related to the transaction.

The Cooperation Agreement set forth terms under which each entity is allowed to participate in the other entity’s purchases of royalty and mineral interests in certain areas of the Delaware Basin (the “AMI”) as defined in the Cooperation Agreement. The Cooperation Agreement also calls for a conveyance of these purchased mineral interests between the entities. In October 2019, the entities executed a Letter Agreement and certain Special Warranty Deeds, whereby the conveyances described above were executed. As such, certain royalty and mineral interests were conveyed by KMF Land to DRC, and certain royalty and mineral interests were conveyed by DRC to KMF Land. In October 2019, payment for the conveyed interests outlined in the Letter Agreement occurred. KMF Land paid $8.0 million to and received $22.0 million from DRC as a result of the conveyances.

In January 2020, the entities executed an Amendment to the Letter Agreement and certain Special Warranty Deeds, whereby additional conveyances were executed. As such, certain royalty and mineral interests were conveyed by KMF Land to DRC, and certain royalty and mineral interests were conveyed by DRC to KMF Land. In January 2020, payment for the conveyed interests outlined in the Amendment to the Letter Agreement occurred. KMF Land paid $6.2 million to and received $3.8 million from DRC as a result of the conveyances. In March 2020, KMF and DRC executed a Second Amendment to the Letter Agreement and certain Special Warranty Deeds, whereby a conveyance of certain royalty and mineral interests were executed. As such, a portion of these royalty and mineral interests were conveyed by KMF Land to DRC. In March 2020, payment for the conveyed interests outlined in the Second Amendment to the Letter Agreement occurred. KMF Land received $11.3 million from DRC as a result of the conveyances.

In December 2020, the entities executed a Letter Agreement in light of the expiration of the Cooperation Agreement. In March 2021, subsequent to December 31, 2020, a notice of KMF’s intent to pursue an initial public offering (an “IPO Notice”) was provided to DRC in accordance with the last agreement executed. DRC notified the Company that they declined to participate in the IPO.

Other Acquisitions

In February 2020, the Partnership acquired certain mineral and royalty interests in the Delaware Basin for $30.3 million. The Partnership funded the acquisition with capital contributions, cash flows from operations and borrowings under the KMF Revolving Credit Facility.

6. Partners’ Capital – Contributions and Distributions

Committed Capital

As of December 31, 2020, the Partnership had aggregate capital commitments (the “Committed Capital”) of $618.4 million from Limited Partners and $8.0 million from the General Partner. At December 31, 2020, approximately $37.5 million of this Committed Capital remained available to call for purposes of satisfying investment commitments, management fees, and expenses over the remaining life of the Partnership. Through December 31, 2020, the Partnership’s contributed capital as a percentage of total Committed Capital was approximately 94%.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

As of December 31, 2019, the Partnership had aggregate capital commitments (the “Committed Capital”) of $618.4 million from Limited Partners and $8.0 million from the General Partner. At December 31, 2019, approximately $50.5 million of this Committed Capital remained available to call for purposes of satisfying investment commitments, management fees, and expenses over the remaining life of the Partnership. Through December 31, 2019, the Partnership’s contributed capital as a percentage of total Committed Capital was approximately 92%.

The General Partner may admit additional Subscription Limited Partners, or permit any existing Subscription Limited Partner to increase its Committed Capital, at one or more subsequent closings on or before the nine month anniversary of the Initial Closing except with respect to the Extended Closing Date and the Second Extended Closing Date. The General Partner and each Subscription Limited Partner that is admitted or that increases its Committed Capital at a Subsequent Closing shall make, at such Subsequent Closing, Capital Contributions for Investments, Management Fees, and Expenses such that such partners’ Capital Contributions included or made as of the date of the Subsequent Closing are equal to their Pro Rata Share of such amounts made by the Partnership as of the date of such Subsequent Closing. In September 2019, the Partnership had a Subsequent Closing and increased its Committed Capital to a total of $626.4 million, with $618.4 million from Limited Partners and $8.0 million from the General Partner. In September 2019, pursuant of Article III of the Partnership Agreement, a subsequent close rebalance was executed to reflect the change in partner ownership.

Allocation of Partners’ Net Profits and Losses

In accordance with the Partnership Agreement, net profit or net loss is generally allocated among the Capital Accounts of the Partners in accordance with the following distribution methodology.

Partners’ Distributions

Subject to the provisions of the Partnership Agreement, investment proceeds shall be distributed to the Partners, in proportion to each of their respective percentage interests, as follows:

First - 100% to such Limited Partner until such Limited Partner has received cumulative distributions pursuant to this clause (i) in an amount equal to all Capital Contributions of such Limited Partner (whether such Capital Contributions were made to fund Investments, utilized for the payment of Partnership Expenses, Management Fees or applied for any other purpose);

Second - 100% to such Limited Partner until the cumulative distributions to such Limited Partner represents an 8% per annum (compounded annually) internal rate of return on the Capital Contributions of such Limited Partner referred to in clause (i) above calculated from the due date specified in the applicable Payment Notice until the date of the distribution (the “Preferred Return Amount”);

Third - 50% to the General Partner and 50% to such Limited Partner until the General Partner has received distributions pursuant to this clause (iii) equal to the sum of (A) the ratio of such Limited Partner’s Capital Contribution to the total Capital Contributions of all Limited Partners multiplied by the General Partner’s aggregate Capital Contribution plus (B) 20% of the sum of (Y) the amount distributed to such Limited Partner pursuant to clause (ii) above and (Z) the amount distributed to such Limited Partner and to the General Partner with respect to such Limited Partner pursuant to this clause (iii); and;

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

Upon the final distribution of proceeds attributable to the Partnership’s investments, the General Partner, if required, must return to the Limited Partners, in proportion to their capital contributions used to fund the

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Partnership’s investments an aggregate amount, not to exceed the General Partner’s reallocation, to assure that the total distributions of proceeds attributable to the Partnership’s investments are made in accordance with the above formula.

7. Long-Term Debt

Revolving Credit Facility

In September 2019, KMF Land entered into a credit agreement with a syndicate of banks led by BMO Harris Bank N.A. as Administrative Agent and Issuing Bank, Bank of America, N.A, as Syndication Agent and Capital One National Association and Royal Bank of Canada as Co-Documentation Agents (the “Revolving Credit Facility”).

Availability under our Revolving Credit Facility is governed by a borrowing base, which is subject to redetermination semi-annually each year. In addition, lenders holding two-thirds of the aggregate commitments may request one additional redetermination each year. The Partnership can also request one additional redetermination each year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. Increases to the borrowing base requires unanimous approval of the lenders, while decreases only require approval of lenders holding two-thirds of the aggregate commitments at such time.

The determination of the borrowing base takes into consideration the estimated value of KMF Land’s oil and gas mineral interests in accordance with the lenders’ customary practices for oil and gas loans. The Revolving Credit Facility is guaranteed by KMF Land and is collateralized by substantially all of the assets of KMF Land.

In November 2019, KMF Land and the Partnership entered into the First Amendment to Credit Agreement and Resignation and Appointment Agreement (the “First Amendment”). The First Amendment, among other things, removed BMO Harris Bank N.A. (“BMO”), in its capacity as Administrative Agent and Issuing Bank from the Credit Agreement. Additionally, BMO is no longer a Lender under the Credit Agreement and its Maximum Credit Amount as defined by the Credit Agreement was allocated to other Lenders. Bank of America N.A. assumed the role of Administrative Agent and Issuing Bank under the First Amendment. In connection with BMO’s removal from the Revolving Credit Facility, $0.3 million of previously capitalized deferred financing costs were written off to interest expense for the year ended December 31, 2019.

In January 2020, KMF Land and the Partnership entered into the Second Amendment to Credit Agreement (the “Second Amendment”). The Second Amendment, among other things, specified steps to ensure all funds received by KMF Land or the Partnership were directed into appropriate banking accounts. Additionally, the Second Amendment added certain deliverables and certifications to be provided to the Administrative Agent, Bank of America N.A.

In June 2020, KMF Land and the Partnership entered into the Third Amendment to Credit Agreement (the “Third Amendment”). The Third Amendment, among other things, amended the covenant governing the ratio of total net debt to EBITDA so that for the quarter ended December 31, 2020 and 2019, that ratio shall not be greater than 3.50 to 1.00. The Third Amendment also provided for certain amendments to the margin on outstanding borrowings and limitations on the accumulation of excess cash. Furthermore, the Third Amendment reaffirmed the borrowing base at $75.0 million.

In August 2020, KMF Land and the Partnership entered into the Fourth Amendment to Credit Agreement (the “Fourth Amendment”). The Fourth Amendment, among other things, specified steps to ensure all funds

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

received by KMF Land or the Partnership were directed into appropriate banking accounts and amended certain definitions.

As of December 31, 2020, the borrowing base was $75.0 million as determined by the lenders and the outstanding balance under our Revolving Credit Facility was $33.5 million. As of December 31, 2019, the borrowing base was $75.0 million as determined by the lenders and the outstanding balance under our Revolving Credit Facility was $60.0 million.

The Revolving Credit Facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our Revolving Credit Facility and ranges from (a) in the case of adjusted base rate loans, 1.250% to 2.250% and (b) in the case of adjusted LIBOR rate loans, 2.250% to 3.250%. The Partnership may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our Revolving Credit Facility in an amount ranging from 0.375% to 0.500% based on utilization of our Revolving Credit Facility. The Revolving Credit Facility is subject to other customary fee, interest and expense reimbursement provisions.

As of December 31, 2020 and 2019, the weighted average interest rate related to our outstanding borrowings was 2.66% and 6.25%, respectively. As of December 31, 2020 and 2019, KMF Land had unamortized debt issuance costs of $1.0 million and $1.3 million, respectively, in connection with its entry into the facility and subsequent amendments. Such costs are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. For the years ended December 31, 2020 and 2019, we recognized $0.3 million and $0.1 million, respectively, in interest expense related to the amortization of deferred financing costs.

Our Revolving Credit Facility matures on September 26, 2024. Loans drawn under our Revolving Credit Facility may be prepaid at any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, the Partnership may permanently reduce or terminate in full the commitments under our Revolving Credit Facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our Revolving Credit Facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our Revolving Credit Facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

Our Revolving Credit Facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making distributions (subject only to no default or borrowing base deficiency) and investments. In addition, our Revolving Credit Facility requires us to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than 3.50 to 1.00. The Partnership was in compliance with the terms and covenants of the Revolving Credit Facility at December 31, 2020 and 2019.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

8. Derivative Instruments

Commodity Derivatives

KMF Land may enter into commodity derivative contracts to manage its exposure to oil and gas price volatility associated with its production. These derivatives are not entered into for trading or speculative purposes. While the use of these instruments limits the downside risk of adverse commodity price changes, their use may also limit future cash flows from favorable commodity price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, the Partnership may increase or decrease its derivative positions. The Partnership’s commodity derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses on commodity derivatives are recognized in the Partnership’s statement of operations.

In 2020, the Partnership utilized fixed price swaps and basis swaps to manage commodity price risks. The Partnership has entered into these swap contracts when management believes that favorable future sales prices for the Partnership’s production can be secured. Under fixed price swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Partnership pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Partnership receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price that is representative of the price received by many of the operators in the Delaware Basin.

In October 2020, KMF Land terminated all of its outstanding oil and basis swap derivative contracts. KMF was not party to any derivative contracts as of December 31, 2020.

The following table is a summary of derivative gains and losses, and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2020 and 2019 (in thousands):

	Statement of operations location		Year ended December 31, 2020			Year ended December 31, 2019
Commodity derivative losses		Revenue	$	(2,573	)	$	—

The fair value of commodity derivative instruments was determined using Level 2 inputs.

9. Fair Value Measurement

The Partnership is subject to ASC 820, Fair Value Measurements and Disclosures. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure 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). Inputs are used in applying the various valuation techniques and broadly refer to the assumptions that market participants use to make valuation decisions, including assumptions about risk. Inputs may include price information, volatility statistics, specific and broad credit data, liquidity statistics, and other factors. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. However, the determination of what constitutes “observable” requires significant judgment by Management. Management considers observable data to be market data which is readily available, regularly distributed or updated, reliable and verifiable, not proprietary, and provided by independent sources that are actively involved in the relevant market. The categorization of a financial instrument within the hierarchy is based upon the pricing transparency of the instrument and does not necessarily correspond to Management’s perceived risk of that instrument.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Level 1 - Fair values are based on unadjusted quoted prices in active markets that are accessible at the measurement date of identical, unrestricted assets.

Level 2 - Fair values are based on quoted prices for markets that are not active or financial instruments for which all significant inputs are observable, either directly or indirectly.

Level 3 - Inputs that are unobservable and significant to the overall fair value measurement and include situations where there is little, if any, market activity for the asset or liability.

The Partnership’s proved oil and gas properties are assessed for impairment on a periodic basis. If the Partnership’s proved properties are determined to be impaired, the carrying basis of the properties is adjusted down to fair value. This represents a fair value measurement that would qualify as a non-recurring Level 3 fair value measurement. The fair value represents Management’s best estimate using the inputs available as of December 31, 2020 and 2019. No impairment of proved properties was recorded for the years ended December 31, 2020 and 2019.

The fair value of the Partnership’s derivative instruments (Level 2) was estimated using discounted cash flows and credit risk adjustments. See Note 8 for further information on the fair value of our derivative instruments.

10. Related Party Transactions

Management Fees

The Partnership has entered into a management services arrangement with Kimmeridge Energy Management Company, LLC (the “Manager”).

As compensation for services rendered in the management of the Partnership, the Partnership will pay the Manager with respect to each Limited Partner an annual management fee (“Management Fee”) computed on a daily basis from the date of the Initial Closing. Limited Partners who increased their Commitment to the Partnership at the Extended Closing Date will only be required to pay Management Fees with respect to their increased Commitment from and after the Extended Closing Date. Limited Partners who increased their Commitments on the Second Extended Closing Date will not be obligated to pay Management Fees with respect to such increased Commitments until after the Commitment Period Expiration Date. The Management Fee will be paid in quarterly installments on the first business day of each Fiscal Quarter with each installment to be equal to one-quarter of the amount that would be payable on the last day of its preceding Fiscal Quarter. Until the earlier of (A) the Commitment Period Expiration Date and (B) the date that the General Partner, any Principal or any Affiliate thereof first accrues or is paid a Management Fee, advisory fee or similar fee with respect to a Successor Fund (the earlier of the dates referred to in (A) or (B) being the “Initial Step-Down Date”), 2% per annum of such Limited Partner’s Commitment.

Beginning on the day after the Initial Step-Down Date and until the earlier of (A) termination of the Partnership pursuant to Article IX of the Partnership Agreement and (B) the sixth anniversary of the Final Closing (the earlier of the dates referred to in (A) or (B) being the “Second Step-Down Date”), 2% per annum of such Limited Partner’s pro rata share of the cost basis of all Investments held by the Partnership as of the end of the immediately preceding Fiscal Quarter less the value of Investments which have been written-off as a result of a permanent impairment.

Beginning on the day after the Second Step-Down Date and until the termination of the Partnership, 1% per annum of such Limited Partner’s pro rata share of the cost basis of all Investments held by the Partnership as of the end of the immediately preceding Fiscal Quarter less the value of Investments which have been written-off as a result of a permanent impairment.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Each quarterly installment of the Management Fee calculated with respect to each Limited Partner, shall be reduced by the Limited Partner’s pro rata percentage (based on Capital Contributions) of any application fees, closing fees, breakup fees or similar fees associated with an Investment or proposed investment and other routine fees, received by the General Partner during the quarter. If the credited amounts exceed the quarterly Management Fee payment next due and payable, such excess shall be carried forward from quarter to quarter to reduce the Management Fee payable in future periods. For the years ended December 31, 2020 and 2019 there were no adjustments or credited amounts and the Manager earned and was paid approximately $7.5 million and $7.5 million in Management Fees relating to management services, respectively.

Cost Reimbursements and Allocations from Affiliates

General and administrative expenses and certain capitalizable costs are not directly associated with the generation of the Partnership’s revenues and include costs such as employee compensation, office expenses and fees for professional services. These costs are allocated on a “time spent” basis, a pro rata basis, or by another manner which is designed to be fair and equitable. Some of those costs are incurred on the Partnership’s behalf and allocated to the Partnership by the Manager and its affiliates and reimbursed by the Partnership. These costs may not be indicative of costs incurred by the Partnership had such services been provided by an unaffiliated company during the period presented. We have not estimated what these costs and expenses would be if they were incurred by the Partnership on a standalone basis as such estimate would be impractical and lack precision. We believe the methodology utilized by Kimmeridge Operations and the Manager for the allocation of these costs to be reasonable.

Kimmeridge Operations Reimbursements

From time to time, the Partnership reimburses Kimmeridge Operations, LLC (“Kimmeridge Operations”), a wholly owned subsidiary of the Manager and affiliate of the Partnership, for general and administrative expenses. As a subsidiary of the Manager, Kimmeridge Operations staff perform land and administrative services on behalf of the Partnership. For the years ended December 31, 2020 and 2019, the Partnership reimbursed Kimmeridge Operations for approximately $3.8 million and $7.3 million related to these services, respectively. As of December 31, 2020 and 2019, there were no amounts due to Kimmeridge Operations.

Kimmeridge Energy Management Company Reimbursements

From time to time, the Partnership reimburses the Manager for investments and expenses prefunded on behalf of the Partnership. For the years ended December 31, 2020 and 2019, the Partnership reimbursed the Manager for approximately $0.4 million and $1.5 million, respectively. As of December 31, 2020, approximately $55 thousand was classified as due to affiliates on the balance sheet. As of December 31, 2019 approximately $0.1 million was classified as due to affiliates on the balance sheet.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

11. Commitment and Contingencies

The Partnership leases office space under an operating lease. Future minimum lease commitments under the lease at December 31, 2020 are presented below (in thousands):

Year	Total
2021	$	299
2022		306
2023		313
2024		320
2025		327
Thereafter		1,444
Total	$	3,009

Legal Proceedings

From time to time, the Partnership may be involved in various legal proceedings, lawsuits, and other claims in the ordinary course of business including proceedings related to environmental and other matters. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance. Management does not believe that the resolution of these matters will have a material adverse impact on our financial condition, cash flows or results of operations.

12. Lease Income

In April 2020, KMF Water entered into the Water Services Agreement with a third-party water services company under which the third party agreed to manage the Partnership’s water assets and operations for an initial term of three months. Under the terms of the agreement, the third party is responsible for the production, marketing, and sales of water from the Partnership’s water properties, but each entity will each be entitled to fifty percent of the revenues generated from water sales. The agreement also prescribes which entity (KMF or the third party) will be responsible for various costs under the arrangement. The initial term has been renewed for successive three-month periods and will continue to automatically renew for successive three-month terms unless terminated.

The Water Services Agreement constitutes a leasing arrangement under which the Partnership is a lessor. Under the terms of the agreement, the Partnership is not entitled to any income until the lessee has completed a water sale and received payment from its customer. The Partnership does not accrue this contingent rental income until the lessee has received payment. Leasing income related to the Water Sales Agreement was $13 thousand during the year ended December 31, 2020.

13. Business Segment Information

The Partnership has two reportable segments: Oil and Gas Producing Activities and Water Service Operations. The segments provide the chief operating decision maker (“CODM”) with a comprehensive financial view of the Partnership’s core business. The Partnership’s Management has been determined to be the CODM. The CODM assesses performance and allocates resources based on the two reportable segments.

The Oil and Gas Producing Activities segment is comprised of managing the mineral and royalty interests and related revenue streams of KMF Land. The revenue streams of this segment principally consist of

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

royalties from oil, natural gas and NGL producing activities and revenues from lease bonus payments and easements. We are not a producer and the Partnership’s oil, natural gas, and NGL revenues are derived from a fixed percentage of the oil, natural gas and NGL produced from the acreage underlying our interests, net of post-production expenses and production taxes. The Water Service Operations segment comprises the water supply assets and revenues of KMF Water. The revenue of this segment consists of water sales to various basin operators produced from the water supply assets of the Partnership, as well as lease income under the Water Services Agreement.

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profit. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the CODM in deciding how to allocate resources and assess performance. Segment profit is defined as segment revenues less operating expenses, depreciation, depletion and amortization, income taxes, and interest expense. Partnership expenses include general expenses associated with managing the Partnership and are not allocated directly to the two reportable segments.

The following table sets forth certain financial information with respect to the Partnership’s reportable segments (in thousands):

	For the year ended December 31, 2020
	Oil and Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	43,113		$	13		$	—		$	43,126
Depreciation, depletion and amortization		31,746			303			—			32,049
Income tax expense		(38	)		—			—			(38	)
Interest expense		(2,021	)		—			—			(2,021	)
Segment loss		(6,253	)		(165	)		(7,849	)		(14,267	)
Total assets as of December 31, 2020		591,140			3,602			3,886			598,628
Capital expenditures including mineral acquisitions		35,836			—			—			35,836
A reconciliation of segment profit (loss) to net income is as follows:
Segment loss	$	(14,267	)
Interest income		53
Net loss		(14,214	)

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

	For the year ended December 31, 2019
	Oil and Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	56,205		$	3,475			—		$	59,680
Depreciation, depletion and amortization		25,730			471			—			26,201
Income tax (expense) benefit		(166	)		3			(8	)		(171	)
Interest expense		(1,099	)		(10	)		—			(1,109	)
Segment profit (loss)		19,559			537			(11,547	)		8,549
Total assets as of December 31, 2019		608,170			5,445			18,190			631,805
Capital expenditures including mineral acquisitions		266,942			637			—			267,579
A reconciliation of segment profit (loss) to net income is as follows:
Segment profit	$	8,549
Interest income		241
Net income		8,790

14. Subsequent Events

Management has evaluated all subsequent events from the balance sheet date through April 2, 2021 for disclosure within these financial statements.

In March 2021, an IPO notice was provided to DRC in accordance with the last agreement executed. DRC notified the Company that they declined to participate in the IPO. Following DRC’s notification, the Partnership terminated the Letter Agreement with DRC in accordance with its terms.

15. Supplemental Oil and Gas Information (Unaudited)

The Partnership’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows (in thousands):

	December 31,			December 31,
	2020			2019
Oil and natural gas interests:
Unproved	$	399,229		$	398,710
Proved		254,854			236,742
Total oil and natural gas interests		654,083			635,452
Accumulated depletion and impairment		(77,857	)		(46,417	)
Net oil and natural gas interests capitalized	$	576,226		$	589,035

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows (in thousands):

	December 31, 2020		December 31, 2019
Acquisition costs
Unproved properties	$	21,840	$	220,992
Proved properties		13,703		45,546
Total	$	35,543	$	266,538

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas (in thousands). It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the net operating results of the Partnership’s oil, natural gas and NGL operations.

	December  31, 2020			December  31, 2019
Oil, natural gas and natural gas liquids revenues	$	44,194		$	50,886
Production and ad valorem taxes		(3,147	)		(3,774	)
Depletion		(31,440	)		(25,684	)
Impairment of oil and natural gas properties		(812	)		—
Income tax expense		(38	)		(171	)
Results of operations from oil, natural gas and natural gas liquids	$	8,757		$	21,257

The reserves at December 31, 2020 and 2019 presented below were prepared by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Texas and New Mexico.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries—Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGL to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future ad valorem taxes are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and

F-48

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Analysis of Changes in Proved Reserves

The following table sets forth information regarding the Partnership’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for each of the periods presented:

	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBOE)
Balance, December 31, 2018		3,676			16,191			1,988			8,363
Revisions		(438	)		934			(22	)		(305	)
Extensions		1,929			6,214			704			3,668
Acquisition of Reserves		1,655			4,904			555			3,028
Divestiture of Reserves		(167	)		(513	)		(58	)		(310	)
Production		(816	)		(3,237	)		(393	)		(1,749	)
Balance as of December 31, 2019		5,839			24,493			2,774			12,695
Revisions		(1,098	)		(867	)		65			(1,178	)
Extensions		995			3,486			423			1,999
Acquisition of Reserves		445			633			77			628
Divestiture of Reserves		(173	)		(209	)		(26	)		(234	)
Production		(933	)		(4,134	)		(488	)		(2,110	)
Balance as of December 31, 2020		5,075			23,402			2,825			11,800
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBOE)
Proved developed and undeveloped reserves:
Developed as of December 31, 2018		2,541			12,840			1,576			6,259
Undeveloped as of December 31, 2018		1,135			3,351			412			2,104
Balance at December 31, 2018		3,676			16,191			1,988			8,363
Developed as of December 31, 2019		4,223			20,293			2,298			9,903
Undeveloped as of December 31, 2019		1,616			4,200			476			2,792
Balance at December 31, 2019		5,839			24,493			2,774			12,695
Developed as of December 31, 2020		3,731			19,505			2,352			9,334
Undeveloped as of December 31, 2020		1,344			3,897			473			2,467
Balance at December 31, 2020		5,075			23,402			2,825			11,800

For the year ended December 31, 2020, the Partnership had downward revisions of 1,098 MBbls of oil and 867 MMcf of gas and upward revisions of 65 MBbls of NGL. Total downward revisions of 1,178 MBOE were primarily due to downward revisions of 887 MBOE related to changes in estimated ultimate recovery and downward revisions of 239 MBOE due to decreases in pricing. For the year ended December 31, 2020, the Partnership had extensions of 995 MBbls of oil, 3,486 MMcf of gas, and 423 MBbls of NGLs. These extensions

F-49

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

were primarily the result of various operators’ drilling activities within the Permian Basin. In 2020, the Partnership acquired royalty and mineral interests of 445 MBbls of oil, 633 MMcf of gas, and 77 MBbls of NGLs through multiple acquisitions. For the year ended December 31, 2020, the Partnership divested royalty and mineral interests of 173 MBbls, 209 MMcf, and 26 MBbls of proved oil, natural gas, and NGL, respectively, in conjunction with the conveyances to DRC described in Note 5.

For the year ended December 31, 2019, the Partnership had downward revisions of 13 MBbls of oil, 34 MMcf of gas and 4 MBbls of NGL due to the removal of 11 wells that were no longer economically feasible. Additional downward revisions of 425 MBbls of oil and 18 MBbls of NGLs were largely due to decreases in pricing. Decreases in gas pricing were offset by positive performance revisions, resulting in an upward revision of 968 MMcf of gas. For the year ended December 31, 2019, the Partnership had extensions of 1,929 MBbls of oil, 6,214 MMcf of gas, and 704 MBbls of NGLs. These extensions were primarily the result of various operators’ drilling activities within the Permian Basin. In 2019, the Partnership acquired royalty and mineral interests of 1,655 MBbls of oil, 4,904 MMcf of gas and 555 MBbls of NGLs through multiple acquisitions including the acquisition of DRC described in Note 5. For the year ended December 31, 2019, the Partnership divested royalty and mineral interests of 167 MBbls, 513 MMcf, and 58 MBbls of proved oil, gas and NGL, respectively, in conjunction with the conveyances to DRC described in Note 5.

Standardized Measure of Oil and Gas

The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. 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 the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Our calculations of the standardized measure of discounted future net cash flows and the related changes therein include Texas margin tax and do not include the effect of estimated federal income tax expenses because the Partnership is not subject to federal income taxes.

As of December 31, 2020, the reserves are comprised of 43% crude oil, 33% natural gas and 24% NGL on an energy equivalent basis.

For the years ended December 31, 2020 and 2019, future cash inflows are calculated by applying the 12-month arithmetic average of the first-of-month price from January to December, of oil and gas relating to the Partnership’s proved reserves, to the year-end quantities of those reserves. The values for the December 31, 2020 and 2019 proved reserves were derived based on prices presented in the table below. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the NGL pricing was 28% of WTI for 2020 and 27% of WTI for 2019; the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.

	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2020 (Average)	$	36.28	$	1.02	$	11.01
December 31, 2019 (Average)	$	50.92	$	0.69	$	14.90

The standardized measure of discounted future net cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized

F-50

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020 AND 2019

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 the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following summary sets forth the future net cash flows related to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

	Year Ended December 31,
	2020			2019
Future oil and natural gas sales	$	238,977		$	355,551
Future production costs		(19,379	)		(28,178	)
Future income tax expense (1)		(1,236	)		(1,852	)
Future net cash flows		218,362			325,521
10% annual discount		(94,803	)		(142,296	)
Standardized measure of discounted future net cash flows	$	123,559		$	183,225

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Year Ended December 31,
	2020			2019
Balance at the beginning of the period	$	183,225		$	155,432
Net change in prices and production costs		(59,911	)		(38,177	)
Sales, net of production costs		(41,043	)		(47,112	)
Extensions and discoveries		25,196			53,246
Acquisitions of reserves		9,137			43,946
Divestiture of reserves		(3,563	)		(5,795	)
Revisions of previous quantity estimates		(18,140	)		(6,414	)
Net change in income taxes(1)		343			(150	)
Accretion of discount		18,427			15,632
Changes in timing and other		9,888			12,617
Balance at the end of the period	$	123,559		$	183,225

(1) The Company was not subject to U.S. federal income taxes for the years ended December 31, 2020 and 2019. Accordingly, no provision for income taxes has been provided in the Consolidated Statement of Operations. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2020 and 2019 would have been $6.9 million and $24.7 million, respectively. The unaudited pro forma standardized measure of discounted future net cash flows at December 31, 2020 and 2019 would have been $120.0 million and $169.8 million.

F-51

KIMMERIDGE MINERAL FUND, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)	June 30,			December 31,
	2021			2020
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	6,188		$	7,531
Accrued revenue and accounts receivable, net		11,201			8,505
Other current assets		688			138
Total current assets		18,077			16,174
Property and equipment
Oil and natural gas properties, successful efforts method:
Unproved properties		632,010			399,229
Proved properties		344,451			254,854
Other property and equipment		7,990			7,990
Accumulated depreciation, depletion and amortization		(96,431	)		(80,630	)
Net oil and gas properties and other property and equipment		888,020			581,443
Other long-term assets
Deposits for property acquisitions		2,325			—
Deferred financing costs		1,126			1,011
Total other long-term assets		3,451			1,011
TOTAL ASSETS	$	909,548		$	598,628
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accrued expenses and other liabilities	$	3,652		$	2,035
Contributions of partners’ capital received in advance		1,463			—
Due to affiliates (Note 9)		1,334			55
Distribution payable		—			—
Total current liabilities		6,449			2,090
Long-term liabilities
Long-term debt		9,900			33,500
Deferred rent		617			641
Total long-term liabilities		10,517			34,141
Total liabilities		16,966			36,231
COMMITMENTS AND CONTINGENCIES (NOTE 10)
Equity:
Partners’ capital		593,642			562,397
Noncontrolling interests		298,940			—
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	909,548		$	598,628

The accompanying notes are an integral part of the consolidated financial statements.

F-52

KIMMERIDGE MINERAL FUND, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)	Six months ended June 30,
(Unaudited)	2021			2020
Revenue:
Oil, natural gas and natural gas liquids revenues	$	36,069		$	21,322
Lease bonus and other income		650			1,031
Commodity derivatives losses		—			(2,642	)
Total revenues		36,719			19,711
Operating expenses:
Management fees to affiliates (Note 9)		3,740			3,740
Depreciation, depletion and amortization		15,801			15,695
General and administrative		1,278			5,241
General and administrative—affiliates (Note 9)		3,217			540
Severance and ad valorem taxes		2,557			2,007
Deferred offering costs write off		—			2,742
Impairment of oil and natural gas properties		—			812
Gain on sale of other property		—			(41	)
Bad debt recovered		—			(181	)
Total operating expenses		26,593			30,555
Net income (loss) from operations		10,126			(10,844	)
Other expense:
Interest expense, net		(524	)		(1,185	)
Income (loss) before income tax expense		9,602			(12,029	)
Income tax expense		(107	)		(124	)
Net income (loss) including noncontrolling interests		9,495			(12,153	)
Net income attributable to noncontrolling interests		28			—
Net income (loss)	$	9,467		$	(12,153	)

The accompanying notes are an integral part of the consolidated financial statements.

F-53

KIMMERIDGE MINERAL FUND, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(In thousands)

(Unaudited)

	General Partner			Limited Partners			Noncontrolling interests		Total Partners’ Capital
Partners’ capital at January 1, 2020	$	7,246		$	556,365		$	—	$	563,611
Capital Contributions		166			12,834			—		13,000
Net loss		(105	)		(12,048	)		—		(12,153	)
Partners’ capital at June 30, 2020	$	7,307		$	557,151		$	—	$	564,458
Partners’ capital at January 1, 2021	$	7,326		$	555,071		$		$	562,397
Issuance of equity by consolidated subsidiary		757			58,480			261,453		320,690
Deemed distribution in connection with common control acquisition (Note 5)		(478	)		(36,981	)		37,459		—
Net income		169			9,298			28		9,495
Partners’ capital at June 30, 2021	$	7,774		$	585,868		$	298,940	$	892,582

The accompanying notes are an integral part of the consolidated financial statements.

F-54

KIMMERIDGE MINERAL FUND, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)	Six Months Ended June 30,
(Unaudited)	2021			2020
Cash flows from operating activities:
Net income (loss) including noncontrolling interests	$	9,495		$	(12,153	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		15,801			15,695
Impairment of oil and natural gas properties		—			812
Deferred offering costs write off		—			2,742
Bad debt recovered		—			(181	)
Gain on sale of other property		—			(41	)
Commodity derivative losses		—			2,642
Losses on settled commodity derivatives		—			(170	)
Change in operating assets and liabilities:
Accrued revenue and accounts receivable, net		(2,696	)		5,652
Other current assets		(25	)		(89	)
Deferred financing costs		141			124
Accrued expenses and other liabilities		(310	)		490
Due to affiliates (Note 9)		1,279			(106	)
Deferred rent		(23	)		609
Net cash provided by operating activities		23,662			16,026
Cash flows from investing activities:
Purchases of oil and gas properties		(1,918	)		(34,514	)
Proceeds from sales of oil and gas properties		(63	)		14,239
Purchases of other property and equipment		—			(143	)
Proceeds from sale of other property and equipment		—			59
Deposits for property acquisitions		(2,325	)		—
Net cash used in investing activities		(4,306	)		(20,359	)
Cash flows from financing activities:
Capital contributions		—			13,000
Issuance of equity in consolidated subsidiary		1,467			—
Contributions of partners’ capital received in advance		1,463			—
Borrowings on credit facility		—			10,000
Repayments on credit facility		(23,600	)		(24,500	)
Payments of deferred financing costs		(29	)		(245	)
Deferred initial public offering costs		—			(277	)
Net cash used in financing activities		(20,699	)		(2,022	)
Net change in cash, cash equivalents and restricted cash		(1,343	)		(6,355	)
Cash, cash equivalents and restricted cash, beginning of year		7,531			18,133
Cash, cash equivalents and restricted cash, end of period	$	6,188		$	11,778
Supplemental disclosure of non-cash transactions:
Escrow deposits reclassified to oil and gas properties:	$	—		$	3,067
Increase (decrease) in current liabilities for additions to property and equipment:		1,174			(3,580	)
Oil and gas properties acquired through issuance of equity in consolidated subsidiary		319,224			—
Supplemental disclosure of cash flow information:
Cash paid for income taxes:	$	42		$	3
Cash paid for interest expense:		461			1,063

The accompanying notes are an integral part of the consolidated financial statements.

F-55

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

1. Organization

Kimmeridge Mineral Fund, LP (the “Partnership”) is a Delaware limited partnership operating under the Third Amendment to the Second Amended and Restated Limited Partnership Agreement (the “Partnership Agreement”) dated as of July 19, 2019. The Partnership formed on November 1, 2016 and commenced operation on November 11, 2016. The primary purpose of the Partnership is to acquire, own and manage mineral and royalty interests in the Delaware Basin, located in West Texas and southeastern New Mexico of the United States. Mineral interests are real property interests that are typically perpetual and grant ownership of the oil and natural gas underlying a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those rights are leased to third party operators, usually for a one to three-year term, the Partnership typically receives an upfront cash payment, known as a lease bonus, and the Partnership retains a mineral royalty, which entitles the Partnership to a cost-free percentage (up to 25%) of production or revenue from production free of lease operating expenses. The Partnership also owns surface rights which generate revenues from the sale of water produced from the Partnership’s water supply assets and from rights-of-way, easements and other rights.

The Partnership Agreement provides that the Partnership will continue (unless earlier dissolved) for ten years from the final closing date provided, however, that Kimmeridge Mineral GP, LLC (the “General Partner” or “Management”), may, in its discretion, extend the term of the Partnership for two additional one-year periods. In addition, the General Partner may extend the term of the Partnership for a third additional three-year period (the “Final Extension”); provided however, that the General Partner shall provide notice of such a proposed extension to the Limited Partners at least 60 calendar days before the expiration of the then current term. The Final Extension shall automatically take effect unless a majority of the Limited Partnership Advisory Committee (“LPAC”) members notify the General Partner in writing within 30 calendar days of receipt of the extension notice of their decision not to allow the Final Extension. Except as may be required by law or expressly provided for in the Partnership Agreement, the liability of each Limited Partner is limited to its Capital Commitment.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

These condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, the accompanying condensed consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Partnership’s financial position as of June 30, 2021 and December 31, 2020, and the results of its operations and its cash flows for the six months ended June 30, 2021 and 2020. Certain prior period amounts have been reclassified to conform to the current period presentation.

Use of Estimates

The preparation of 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 financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

The Partnership’s estimates and classification 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

F-56

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

data as well as the projection of future rates of production. 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. These factors and assumptions include 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. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas and estimates of the future net cash flows may vary substantially.

Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of the Partnership’s oil and natural gas properties and/or the rate of depletion related to oil and natural gas properties.

Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of the Partnership’s wholly-owned subsidiaries and any entities in which the Partnership owns a controlling interest. All intercompany accounts and transactions have been eliminated in consolidation. Noncontrolling interests in the Partnership’s condensed consolidated financial statements represents the interests in a newly-formed subsidiary of the Partnership, DPM HoldCo, LLC (“DPM HoldCo”), which are owned by outside parties. Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Partnership’s condensed consolidated balance sheets.

Risks and Uncertainties

The ongoing global spread of the novel coronavirus (“COVID-19”) has caused a continuing disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil beginning in the first quarter of 2020 and continuing throughout 2020. Although prices have recovered substantially in 2021, the markets for oil, natural gas and natural gas liquids (“NGL”) have experienced significant price fluctuations. Such price volatility is expected to continue into the future. Lower commodity prices may reduce the amount of oil, natural gas and NGL that can be produced economically by operators. Increases or decreases in commodity prices could impact the Partnership’s financial performance and expected operating results, which may include future reserves estimates and potential recognition of impairment charges related to the Partnership’s mineral and royalty interests.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, Leases, which requires all leasing arrangements to be presented on the balance sheet as liabilities along with a corresponding asset. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. The ASU will replace most existing lease guidance in GAAP when it becomes effective. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11 Leases: Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The new standards become effective for the Partnership during the fiscal year ending December 31, 2022 and interim periods within the fiscal year ending December 31, 2023. Early adoption is permitted. We are currently evaluating the impact that the adoption of this standard will have on our financial statements.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses, which amends current impairment guidance by adding an impairment model (known as the current expected credit loss model (“CECL”)) that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of lifetime expected credit losses, which the FASB believes will result in more timely recognition of such losses. ASU 2016-13 is effective for annual periods beginning after December 15, 2022 and interim periods within those annual periods. The Partnership is currently evaluating the impact of the adoption of this standard but does not believe it will have a material impact on the Partnership’s financial statements.

In March 2020, the FASB issued ASU 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In response to the cessation of the London Interbank Offered Rate (“LIBOR”) by December 31, 2021, the FASB issued this update to provide optional expedients and exceptions for applying GAAP to contract modifications, hedging relations, and other affected transactions. The Partnership currently only has one contract subject to LIBOR, its revolving credit facility, that may be impacted by this ASU. Modifications of debt contracts should be accounted for by prospectively adjusting the effective interest rate. This update is effective immediately, but may be adopted through December 31, 2022, and allows for elections to be made by the Partnership in terms of how the ASU is adopted. Once elected for a Topic or Industry Subtopic, the update must be applied prospectively for all eligible contract modifications. The Partnership is currently evaluating the impact of the adoption of this standard but does not believe it will have a material impact on the Partnership’s financial statements.

Cash and Cash Equivalents

The Partnership considers all highly-liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Partnership maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Partnership has not experienced any significant losses from such investments.

Accrued Revenue and Accounts Receivable

Accrued revenue and accounts receivable represent amounts due to the Partnership and are uncollateralized, consisting primarily of royalty revenue receivable. Royalty revenue receivable consists of royalties due from operators for oil, natural gas and NGL volumes sold to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to the Partnership. Receivables from third parties for which we did not receive actual production information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated. We do not recognize revenues for wells with no historical actual production data or available state database information because we cannot conclude that it is probable that a significant revenue reversal will not occur in future periods. The Partnership accrues for oil, natural gas and NGL sales based on actual production dates.

The Partnership routinely assesses the recoverability of all material accounts receivable to determine their collectability. The Partnership accrues a reserve to the allowance for doubtful accounts when it is probable

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

that a receivable will not be collected and the amount of the reserve may be reasonably estimated. The Partnership had an allowance for doubtful accounts related to its KMF Water, LLC (“KMF Water”) receivables of $0.2 million and $0.2 million as of June 30, 2021 and December 31, 2020, respectively. There were no such allowances for KMF Land, LLC’s (“KMF Land”) royalty revenue receivables as of June 30, 2021 and December 31, 2020.

Oil and Gas Properties

The Partnership uses the successful efforts method of accounting for oil and natural gas producing properties, as further defined under ASC 932, Extractive Activities—Oil and Natural Gas. Under this method, costs to acquire mineral interests in oil and natural gas properties are capitalized. The costs of non-producing mineral interests and associated acquisition costs are capitalized as unproved properties pending the results of leasing efforts and drilling activities of Exploration and Production (“E&P”) operators on our interests. As unproved properties are determined to have proved reserves, the related costs are transferred to proved oil and gas properties. Capitalized costs for proved oil and natural gas mineral interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved oil and gas properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions. Depletion expense totaled approximately $15.5 million and $15.4 million for the six months ended June 30, 2021 and 2020, respectively.

Other Property and Equipment

Other property and equipment is recorded at cost, which includes water supply assets (water wells and water storage pits), field vehicles, and other assets. Depreciation and amortization are calculated using the straight-line method over the estimated useful lives of the assets. Leasehold improvements are depreciated over the shorter of the lease term or the useful lives of the assets. Water wells are depreciated over estimated useful lives of two to twenty-five years. For the six months ended June 30, 2021 and 2020, the Partnership recorded $294 thousand and $315 thousand, respectively, in depreciation for water assets and other property and equipment.

The costs to drill water wells are capitalized while drilling is in progress. If a water well is determined to be unsuccessful or unproductive prior to being placed in service, the associated costs will be charged to expense in the period the determination is made. No expense was recognized in connection with unsuccessful water wells for the six months ended June 30, 2021 and 2020. Additionally, we evaluate our other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset that has been placed in service may not be recoverable. No impairment charge was recorded for the six months ended June 30, 2021 and 2020.

Impairment of Oil and Gas Properties

The Partnership evaluates its producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, the Partnership compares the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. There was no impairment of proved properties for the six months ended June 30, 2021 and 2020. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Unproved oil and gas properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include, but are not limited to, commodity price outlooks, current and future operator activity in the Delaware Basin, and analysis of recent mineral transactions in the surrounding area. There was no impairment of unproved properties for the six months ended June 30, 2021. The Partnership recognized approximately $0.8 million of unproved property impairment for the six months ended June 30, 2020. This impairment was related to capitalized acquisition costs for a prospective mineral interest acquisition that the Partnership did not complete.

Deferred Financing Costs

Debt issuance costs incurred in connection with KMF Land’s entry into its credit facility, and subsequent amendments, are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. As of June 30, 2021 and December 31, 2020, KMF Land had unamortized debt issuance costs of $1.1 million and $1.0 million, respectively, in connection with its entry into the facility and subsequent amendments.

Deferred Offering Costs

The Partnership recognized a write-off of approximate $2.7 million of deferred offering costs for the six months ended June 30, 2020 related to the temporary postponement of an initial public offering in accordance with SAB Topic 5.A of the Securities and Exchange Commission. No such charge was recorded for the six months ended June 30, 2021.

Derivative Financial Instruments

In order to manage its exposure to oil, natural gas, and NGLs price volatility, the Partnership may periodically enter into derivative transactions, which may include commodity swap agreements, basis swap agreements, and other similar agreements which help manage the price risk associated with the Partnership’s production. These derivatives are not entered into for trading or speculative purposes. To the extent legal right of offset exists with a counterparty, the Partnership reports derivative assets and liabilities on a net basis. The Partnership has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Partnership actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions.

The Partnership records derivative instruments on its condensed consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Partnership’s condensed consolidated statements of operations.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

The Partnership’s derivatives have not been designated as hedges for accounting purposes. In October 2020, KMF Land terminated all of its outstanding oil and basis swap derivative contracts. KMF was not party to any derivative contracts as of June 30, 2021 and December 31, 2020.

Accrued Expenses and Other Liabilities

The Partnership’s accrued expenses and other liabilities consisted of the following as of the dates indicated (in thousands):

	June 30, 2021		December 31, 2020
Ad valorem taxes payable	$	1,275	$	1,200
Acquisition costs		1,167		—
Initial public offering costs		398		—
Financing costs		253		—
General and administrative		152		445
Texas state franchise taxes payable		133		68
Software costs		128		—
Deferred rent expense		63		63
Payable for conveyed interests		43		99
Interest expense		10		88
Other		30		72
Total accrued expenses and other liabilities	$	3,652	$	2,035

Income Taxes

The Partnership is organized as a pass-through entity for income tax purposes. As a result, the partners are responsible for federal and state income taxes attributable to their share of the Partnership’s taxable income. However, the Partnership is required to pay Texas State franchise taxes and certain New Mexico income taxes. The Partnership recognized approximately $107 thousand and $124 thousand of Texas state franchise taxes and New Mexico income taxes for the six months ended June 30, 2021 and 2020, respectively.

Revenue Recognition

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGL, less production taxes and post-production expenses. The prices of oil, natural gas, and NGL from the properties in which we own a mineral or royalty interest are primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no working interest or operational control over the volumes and methods of sale of the oil, natural gas, and NGL produced and sold from our properties. We do not explore, develop, or operate the properties and, accordingly, do not incur any of the associated costs.

Oil, natural gas, and NGL revenues from our mineral and royalty interests are recognized when control transfers at the wellhead.

The Water Services Agreement (defined in Note 3) constitutes a leasing arrangement under which the Partnership is a lessor. Under the terms of the agreement, the Partnership is not entitled to any income until the lessee has completed a water sale and received payment from its customer. The Partnership does not accrue this contingent rental income until the lessee has received payment.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

The Partnership also earns revenue related to lease bonuses. The Partnership earns lease bonus revenue by leasing its mineral interests to E&P companies. The Partnership recognizes lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.

See Note 3 for additional disclosures regarding revenue recognition.

Concentration of Revenue

Collectability of the Partnership’s royalty revenue is dependent upon the financial condition of the Partnership’s operators as well as general economic conditions in the industry.

Although the Partnership is exposed to a concentration of credit risk, the Partnership does not believe the loss of any single purchaser would materially impact the Partnership’s operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. If multiple purchasers were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving the Partnership’s operators have stipulated that royalty owners must still be paid for oil, natural gas and NGLs extracted from their mineral acreage during the bankruptcy process. In light of this, the Partnership does not expect the entry of one of our operators into bankruptcy proceedings to materially affect our operating results.

Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accrued revenue and accounts receivable, accrued expenses, and other liabilities approximate fair value, as of June 30, 2021 and December 31, 2020 due to their short-term nature.

The fair values of the Partnership’s derivative asset and liabilities are based on a third-party industry-standard pricing model using contract terms, prices, assumptions, and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, and credit risk adjustments. See Note 13 for information regarding the fair values of derivative instruments.

The Revolving Credit Facility (defined in Note 7) has a recorded value that approximates its fair value as the interest rates are based on prevailing market rates.

Deferred Rent

The Partnership recognizes rental expense for an operating lease on a straight-line basis over the term of the lease agreement. The deferred rent liability on the Partnership’s condensed consolidated balance sheets is attributable to the difference between rental expense (recognized on a straight-line basis) and the variable lease payments over the term of the agreement.

3. Revenue from Contracts with Customers

Oil and natural gas sales

Oil, natural gas and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

collectability is reasonably assured. All of the Partnership’s oil, natural gas and NGL sales are made under contracts with customers (operators). The performance obligations for the Partnership’s contracts with customers are satisfied at a point in time when control transfers at the wellhead, at which point payment is unconditional. Accordingly, the Partnership’s contracts do not give rise to contract assets or liabilities. The Partnership typically receives payment for oil, natural gas and NGL sales within 30 to 90 days of the month of delivery after initial production from the well. Such periods can extend longer due to factors outside of our control. The Partnership’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions.

Lease bonus and other income

The Partnership also earns revenue from lease bonuses, delay rentals, and right-of-way payments. The Partnership generates lease bonus revenue by leasing its mineral interests to E&P companies. A mineral lease agreement represents our contract with a customer and generally transfers the rights, for a specified period of time, to explore for and develop any oil, natural gas and NGL discovered, grants us a specified royalty interest in the hydrocarbons produced from the leased property, and requires that drilling and completion operations commence within a specified time period. The Partnership recognizes lease bonus revenues when the lease agreement has been executed and payment is determined to be collectible. At the time the Partnership executes the lease agreement, the lease bonus payment is delivered to the Partnership. Upon receipt of the lease bonus payment, the Partnership will release the recordable original lease documents to the customer. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period and payment has been received. Right-of-way payments are recorded by the Partnership when the agreement has been executed and payment is determined to be collectable. Payments for lease bonus and other income become unconditional upon the execution of an associated agreement. Accordingly, the Partnership’s lease bonus and other income transactions do not give rise to contract assets or liabilities.

In 2020, KMF Water entered into an agreement (the “Water Services Agreement”) with a third-party water services company under which the third party agreed to manage the Partnership’s water assets and operations. The Water Services Agreement constitutes a leasing arrangement under which the Partnership is a lessor. Under the terms of the agreement, the Partnership is not entitled to any income until the lessee has completed a water sale and received payment from its customer. The Partnership does not accrue this contingent rental income until the lessee has received payment. Such amounts are included in Lease bonus and other income in the condensed consolidated statement of operations. See Note 11 for additional information.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of our royalty income contracts.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

Lease bonus and other income

Given that the Partnership does not recognize lease bonus or other income until an agreement has been executed, at which point its performance obligation has been satisfied, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Water leasing income

Given that the Partnership does not recognize water leasing income until the lessee receives payment from its customer, at which point Partnership’s performance obligation has been satisfied, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Prior-period performance obligations

The Partnership records revenue in the month production is delivered to the purchaser. As a royalty interest owner, the Partnership has limited visibility into the timing of when new wells start producing as production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within accrued revenue and accounts receivable in the accompanying condensed consolidated balance sheets. The difference between the Partnership’s estimates of royalty income and the actual amounts received for oil and natural gas sales are recorded in the month that the royalty payment is received from the customer. For the six months ended June 30, 2021 and 2020, revenue recognized related to performance obligations satisfied in prior reporting periods was primarily attributable to production revisions by operators or amounts for which the information was not available at the time when revenue was estimated.

4. Oil and Gas Properties

The Partnership has been and is engaged in the purchase of mineral rights in the Delaware Basin portion of the Permian Basin in West Texas and southeastern New Mexico. The following is a summary of oil and natural gas properties as of June 30, 2021 and December 31, 2020 (in thousands):

	June 30, 2021			December 31, 2020
Oil and natural gas properties:
Unproved properties	$	632,010		$	399,229
Proved properties		344,451			254,854
Oil and natural gas properties, gross		976,461			654,083
Accumulated depletion and impairment		(93,364	)		(77,857	)
Oil and natural gas properties, net	$	883,097		$	576,226

For the six months ended June 30, 2021, the Partnership paid $1.9 million for mineral acquisition costs and paid $63 thousand related to purchase price adjustments from prior property sales. Additionally, the Partnership acquired mineral and royalty interests of $319.2 million in two separate transactions in exchange for equity interests in a subsidiary of the Partnership. Please see Note 5 for additional information regarding these transactions.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

For the six months ended June 30, 2020, the Partnership paid $34.5 million for mineral acquisition costs. The Partnership received proceeds from the sale of mineral interests of approximately $14.2 million for the six months ended June 30, 2020.

5. Acquisitions

DRC Acquisition

In July 2019, KMF Land entered into a Purchase and Sale Agreement and a Cooperation Agreement with Desert Royalty Company (“DRC”) pursuant to which KMF Land agreed to acquire an undivided 25% interest in DRC’s Delaware Basin oil and gas mineral and royalty interests. In January 2020, the entities executed an Amendment to the Letter Agreement and certain Special Warranty Deeds. In March 2021, a notice of KMF’s intent to pursue an initial public offering (an “IPO Notice”) was provided to DRC in accordance with the last agreement executed. Subsequent to this notice, the Partnership terminated the Letter Agreement with DRC in accordance with its terms.

Other Acquisitions

In February 2020, the Partnership acquired certain mineral and royalty interests in the Delaware Basin for $30.3 million. The Partnership funded the acquisition with capital contributions, cash flows from operations and borrowings under the KMF Revolving Credit Facility.

Rock Ridge Acquisition

In June 2021, KMF Land completed the acquisition of approximately 18,700 NRAs from Rock Ridge Royalty, LLC (“RRR”). At close, subject to the terms and conditions of the transaction agreement, RRR contributed its mineral and royalty interests to KMF Land and in consideration for the contribution, Kimmeridge affiliates caused DPM Holdco (a subsidiary of the Partnership and the sole member of KMF Land, LLC) to issue equity interests in DPM HoldCo to RRR.

The RRR acquisition was accounted for as an asset acquisition and, therefore, the acquired interests were recorded based on the fair value of the total assets acquired on the acquisition date. Based on the estimated fair values of the assets received, the Partnership recorded $190.3 million of the total consideration as unproved oil and gas property and $68.3 million as proved oil and gas property. Additionally, $865 thousand of transaction costs were capitalized related to the transaction.

Delaware ORRIs Acquisition

In October 2020, another partnership owned and managed by Kimmeridge, (“Fund V”), acquired a 2.0% (on an 8/8ths basis) overriding royalty interest in all of Callon Petroleum Company’s (“Callon”) operated assets in the Delaware, Midland and Eagle Ford Basins, proportionately reduced to Callon’s net revenue interest (the “Chambers ORRI”).

In June 2021, KMF Land entered into a definitive agreement to acquire 84% of the Delaware Basin portion of the Chambers ORRI from Chambers Minerals, LLC, a subsidiary of Fund V (the “Chambers Acquisition”). Immediately following the consummation of the contributions of assets to KMF Land, Chambers HoldCo, LLC (the managing member of Chambers Minerals, LLC) was issued equity in DPM

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

HoldCo. As the general partner of Fund V and the General Partner of the Partnership are affiliated, the transaction was approved by the Partnership’s Limited Partner Advisory Committee on June 3, 2021.

The Chambers Acquisition was accounted for as an asset acquisition. The Chambers Acquisition was also accounted for as a transaction between entities under common control; the controlling ownership and management of the general partner of Fund V and the general partner of the Partnership have significant overlap, including responsibility for the management, control, and direction of the business affairs of the respective partnerships. As KMF Land and Fund V are entities under common control, the Partnership recorded the acquisition utilizing the properties’ net book value. The properties acquired by KMF Land had a historical net book value to Fund V at the time of sale of approximately $60.6 million ($45.3 million was allocated to unproved property and $15.3 million was allocated to proved property). Accordingly, the $37.5 million excess of the fair value of the properties above their net book value was recorded as a decrease to partners’ capital at the date of the transaction.

6. Partners’ Capital – Contributions and Distributions

Committed Capital

As of June 30, 2021 and December 31, 2020, the Partnership had aggregate capital commitments (the “Committed Capital”) of $618.4 million from Limited Partners and $8.0 million from the General Partner. At June 30, 2021 and December 31, 2020, approximately $37.5 million of this Committed Capital remained available to call for purposes of satisfying investment commitments, management fees, and expenses over the remaining life of the Partnership. Through June 30, 2021 and December 31, 2020, the Partnership’s contributed capital as a percentage of total Committed Capital was approximately 94%.

On June 18, 2021, the Partnership called additional capital of approximately $8.0 million due July 1, 2021, of which $1.5 million was pre-funded and recorded as a liability as of June 30, 2021 as the capital was yet not due.

The General Partner may admit additional Subscription Limited Partners, or permit any existing Subscription Limited Partner to increase its Committed Capital, at one or more subsequent closings on or before the nine month anniversary of the Initial Closing except with respect to the Extended Closing Date and the Second Extended Closing Date. The General Partner and each Subscription Limited Partner that is admitted or that increases its Committed Capital at a Subsequent Closing shall make, at such Subsequent Closing, Capital Contributions for Investments, Management Fees, and Expenses such that such partners’ Capital Contributions included or made as of the date of the Subsequent Closing are equal to their Pro Rata Share of such amounts made by the Partnership as of the date of such Subsequent Closing.

Allocation of Partners’ Net Profits and Losses

In accordance with the Partnership Agreement, net profit or net loss is generally allocated among the Capital Accounts of the Partners in accordance with the following distribution methodology.

Partners’ Distributions

Subject to the provisions of the Partnership Agreement, investment proceeds shall be distributed to the Partners, in proportion to each of their respective percentage interests, as follows:

First - 100% to such Limited Partner until such Limited Partner has received cumulative distributions pursuant to this clause (i) in an amount equal to all Capital Contributions of such Limited Partner (whether

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

such Capital Contributions were made to fund Investments, utilized for the payment of Partnership Expenses, Management Fees or applied for any other purpose);

Second - 100% to such Limited Partner until the cumulative distributions to such Limited Partner represents an 8% per annum (compounded annually) internal rate of return on the Capital Contributions of such Limited Partner referred to in clause (i) above calculated from the due date specified in the applicable Payment Notice until the date of the distribution (the “Preferred Return Amount”);

Third - 50% to the General Partner and 50% to such Limited Partner until the General Partner has received distributions pursuant to this clause (iii) equal to the sum of (A) the ratio of such Limited Partner’s Capital Contribution to the total Capital Contributions of all Limited Partners multiplied by the General Partner’s aggregate Capital Contribution plus (B) 20% of the sum of (Y) the amount distributed to such Limited Partner pursuant to clause (ii) above and (Z) the amount distributed to such Limited Partner and to the General Partner with respect to such Limited Partner pursuant to this clause (iii); and;

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

Upon the final distribution of proceeds attributable to the Partnership’s investments, the General Partner, if required, must return to the Limited Partners, in proportion to their capital contributions used to fund the Partnership’s investments an aggregate amount, not to exceed the General Partner’s reallocation, to assure that the total distributions of proceeds attributable to the Partnership’s investments are made in accordance with the above formula.

7. Long-Term Debt

Revolving Credit Facility

KMF Land is party to a credit agreement with a syndicate of banks led by Bank of America N.A. as Administrative Agent, Issuing Bank and Syndication Agent, and Capital One National Association and Royal Bank of Canada as Co-Documentation Agents (the “Revolving Credit Facility”).

In August 2020, KMF Land and the Partnership entered into a limited waiver and amendment (the “Letter Agreement”). The Letter Agreement, among other things, specified steps to ensure all funds received by KMF Land or the Partnership were directed into appropriate banking accounts and amended certain definitions.

In June 2021, KMF Land and the Partnership entered into the Fourth Amendment to Credit Agreement (the “Fourth Amendment”). The Fourth Amendment, among other things, allowed for the consummation of the acquisitions described in Note 5.

Availability under our Revolving Credit Facility is governed by a borrowing base, which is subject to redetermination semi-annually each year. In addition, lenders holding two-thirds of the aggregate commitments may request one additional redetermination each year. The Partnership can also request one additional redetermination each year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. Increases to the borrowing base requires unanimous approval of the lenders, while decreases only require approval of lenders holding two-thirds of the aggregate commitments at such time. The determination of the borrowing base takes into consideration the estimated value of KMF Land’s oil and gas mineral interests in accordance with the lenders’ customary practices for oil and gas loans. The Revolving Credit Facility is guaranteed by KMF Land and is collateralized by substantially all of the assets of KMF Land.

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KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

As of June 30, 2021, the borrowing base was $75.0 million as determined by the lenders and the outstanding balance under our Revolving Credit Facility was $9.9 million. As of December 31, 2020, the borrowing base was $75.0 million as determined by the lenders and the outstanding balance under our Revolving Credit Facility was $33.5 million.

The Revolving Credit Facility bears interest at a rate per annum equal to, at our option, the adjusted base rate or the adjusted LIBOR rate plus an applicable margin. The applicable margin is based on utilization of our Revolving Credit Facility and ranges from (a) in the case of adjusted base rate loans, 1.250% to 2.250% and (b) in the case of adjusted LIBOR rate loans, 2.250% to 3.250%. The Partnership may elect an interest period of one, two, three, six, or if available to all lenders, twelve months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under our Revolving Credit Facility in an amount ranging from 0.375% to 0.500% based on utilization of our Revolving Credit Facility.

As of June 30, 2021 and December 31, 2020, the weighted average interest rate related to our outstanding borrowings was 2.34% and 2.66%, respectively. As of June 30, 2021 and December 31, 2020, KMF Land had unamortized debt issuance costs of $1.1 million and $1.0 million, respectively, in connection with its entry into the facility and subsequent amendments. Such costs are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. For the six months ended June 30, 2021 and 2020, we recognized $141 thousand and $124 thousand, respectively, of interest expense related to the amortization of deferred financing costs.

Our Revolving Credit Facility matures on September 26, 2024. Loans drawn under our Revolving Credit Facility may be prepaid at any time without premium or penalty (other than customary LIBOR breakage) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected availability at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed. In addition, the Partnership may permanently reduce or terminate in full the commitments under our Revolving Credit Facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid. Upon the occurrence of an event of default under our Revolving Credit Facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under our Revolving Credit Facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default. Our Revolving Credit Facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making distributions (subject only to no default or borrowing base deficiency) and investments. In addition, our Revolving Credit Facility requires us to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than 3.50 to 1.00. The Partnership was in compliance with the terms and covenants of the Revolving Credit Facility at June 30, 2021 and December 31, 2020.

8. Fair Value Measurement

The Partnership is subject to ASC 820, Fair Value Measurements and Disclosures. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure 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).

F-68

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

Inputs are used in applying the various valuation techniques and broadly refer to the assumptions that market participants use to make valuation decisions, including assumptions about risk. Inputs may include price information, volatility statistics, specific and broad credit data, liquidity statistics, and other factors. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. However, the determination of what constitutes “observable” requires significant judgment by Management. Management considers observable data to be market data which is readily available, regularly distributed or updated, reliable and verifiable, not proprietary, and provided by independent sources that are actively involved in the relevant market. The categorization of a financial instrument within the hierarchy is based upon the pricing transparency of the instrument and does not necessarily correspond to Management’s perceived risk of that instrument.

Level 1 - Fair values are based on unadjusted quoted prices in active markets that are accessible at the measurement date of identical, unrestricted assets.

Level 2 - Fair values are based on quoted prices for markets that are not active or financial instruments for which all significant inputs are observable, either directly or indirectly.

Level 3 - Inputs that are unobservable and significant to the overall fair value measurement and include situations where there is little, if any, market activity for the asset or liability.

The Partnership’s proved oil and gas properties are assessed for impairment on a periodic basis. If the Partnership’s proved properties are determined to be impaired, the carrying basis of the properties is adjusted down to fair value. This represents a fair value measurement that would qualify as a non-recurring Level 3 fair value measurement. The fair value represents Management’s best estimate using the inputs available as of June 30, 2021 and December 31, 2020. No impairment of proved properties was recorded for the six months ended June 30, 2021 and 2020.

The fair value of the Partnership’s derivative instruments (Level 2) was estimated using discounted cash flows and credit risk adjustments. As of June 30, 2021, the Partnership did not have any derivative instruments. See Note 13 for further information on our derivative instruments.

9. Related Party Transactions

Management Fees

The Partnership has entered into a management services arrangement with Kimmeridge Energy Management Company, LLC (the “Manager”).

As compensation for services rendered in the management of the Partnership, the Partnership will pay the Manager with respect to each Limited Partner an annual management fee (“Management Fee”) computed on a daily basis from the date of the Initial Closing. Limited Partners who increased their Commitment to the Partnership at the Extended Closing Date will only be required to pay Management Fees with respect to their increased Commitment from and after the Extended Closing Date. Limited Partners who increased their Commitments on the Second Extended Closing Date will not be obligated to pay Management Fees with respect to such increased Commitments until after the Commitment Period Expiration Date. The Management Fee will be paid in quarterly installments on the first business day of each Fiscal Quarter with each installment to be equal to one-quarter of the amount that would be payable on the last day of its preceding Fiscal Quarter. Until the earlier of (A) the Commitment Period Expiration Date and (B) the date that the General Partner, any Principal or any Affiliate thereof first accrues or is paid a Management Fee, advisory fee or similar fee with respect to a Successor Fund (the earlier of the dates referred to in (A) or (B) being the “Initial Step-Down Date”), 2% per annum of such Limited Partner’s Commitment.

F-69

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

Beginning on the day after the Initial Step-Down Date and until the earlier of (A) termination of the Partnership pursuant to Article IX of the Partnership Agreement and (B) the sixth anniversary of the Final Closing (the earlier of the dates referred to in (A) or (B) being the “Second Step-Down Date”), 2% per annum of such Limited Partner’s pro rata share of the cost basis of all Investments held by the Partnership as of the end of the immediately preceding Fiscal Quarter less the value of Investments which have been written-off as a result of a permanent impairment.

Beginning on the day after the Second Step-Down Date and until the termination of the Partnership, 1% per annum of such Limited Partner’s pro rata share of the cost basis of all Investments held by the Partnership as of the end of the immediately preceding Fiscal Quarter less the value of Investments which have been written-off as a result of a permanent impairment.

Each quarterly installment of the Management Fee calculated with respect to each Limited Partner, shall be reduced by the Limited Partner’s pro rata percentage (based on Capital Contributions) of any application fees, closing fees, breakup fees or similar fees associated with an Investment or proposed investment and other routine fees, received by the General Partner during the quarter. If the credited amounts exceed the quarterly Management Fee payment next due and payable, such excess shall be carried forward from quarter to quarter to reduce the Management Fee payable in future periods. For the six months ended June 30, 2021 and 2020, there were no adjustments or credited amounts and the Manager earned and was paid approximately $3.7 million and $3.7 million, respectively, in Management Fees relating to management services.

Common Control Transaction

The Partnership has acquired oil and gas properties from separate limited partnerships whereby the General Partner of the Partnership and the general partner of the separate limited partnerships are affiliated. These transactions were accounted for as a reduction to partners’ capital as the affiliated entities were under common control. The following transaction was completed during the six months ended June 30, 2021:

Delaware ORRIs Acquisition

In October 2020, another partnership owned and managed by Kimmeridge acquired a 2.0% (on an 8/8ths basis) overriding royalty interest in all of Callon’s operated assets in the Delaware, Midland and Eagle Ford Basins, proportionately reduced to Callon’s net revenue interest.

In June 2021, KMF Land entered into a definitive agreement to acquire 84% of the Delaware Basin portion of the Chambers ORRI from Chambers Minerals, LLC, a subsidiary of Fund V. Immediately following the consummation of the contributions of assets to KMF Land, Chambers HoldCo, LLC (the managing member of Chambers Minerals, LLC) was issued equity in DPM HoldCo. As the general partner of Fund V and the General Partner of the Partnership are affiliated, the transaction was approved by the Partnership’s Limited Partner Advisory Committee on June 3, 2021.

The Chambers Acquisition was accounted for as an asset acquisition. The Chambers Acquisition was also accounted for as a transaction between entities under common control; the controlling ownership and management of the general partner of Fund V and the general partner of the Partnership have significant overlap, including responsibility for the management, control, and direction of the business affairs of the respective partnerships. As KMF Land and Fund V are entities under common control, the Partnership recorded the acquisition utilizing the properties’ net book value. The properties acquired by KMF Land had a historical net book value to Fund V at the time of sale of approximately $60.6 million ($45.3 million was

F-70

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

allocated to unproved property and $15.3 million was allocated to proved property). Accordingly, the $37.5 million excess of the fair value of the properties above their net book value was recorded as a decrease to partners’ capital at the date of the transaction.

Cost Reimbursements and Allocations from Affiliates

General and administrative expenses and certain capitalizable costs are not directly associated with the generation of the Partnership’s revenues and include costs such as employee compensation, office expenses and fees for professional services. These costs are allocated on a “time spent” basis, a pro rata basis, or by another manner which is designed to be fair and equitable. Some of those costs are incurred on the Partnership’s behalf and allocated to the Partnership by the Manager and its affiliates and reimbursed by the Partnership. These costs may not be indicative of costs incurred by the Partnership had such services been provided by an unaffiliated company during the period presented. We have not estimated what these costs and expenses would be if they were incurred by the Partnership on a standalone basis as such estimate would be impractical and lack precision. We believe the methodology utilized by Kimmeridge Operations and the Manager for the allocation of these costs to be reasonable.

Kimmeridge Operations Reimbursements

From time to time, the Partnership reimburses Kimmeridge Operations, LLC (“Kimmeridge Operations”), a wholly owned subsidiary of the Manager and affiliate of the Partnership, for general and administrative expenses. As a subsidiary of the Manager, Kimmeridge Operations staff perform land and administrative services on behalf of the Partnership. For the six months ended June 30, 2021 and 2020, the Partnership reimbursed Kimmeridge Operations for approximately $2.1 million and $0.2 million, respectively, related to these services. As of June 30, 2021 and December 31, 2020, there were no amounts due to Kimmeridge Operations.

Kimmeridge Energy Management Company Reimbursements

From time to time, the Partnership reimburses the Manager for expenses prefunded on behalf of the Partnership. For the six months ended June 30, 2021 and 2020, the Partnership reimbursed the Manager for approximately $7 thousand and $0.3 million, respectively. As of June 30, 2021, there were no amounts due to the Manager. As of December 31, 2020, approximately $55 thousand was classified as due to affiliates on the balance sheet.

10. Commitments and Contingencies

The Partnership leases office space under an operating lease. Future minimum lease commitments under the lease at June 30, 2021, are presented below (in thousands):

Year	Total
2021	$	150
2022		306
2023		313
2024		320
2025		327
Thereafter		1,444
Total	$	2,860

F-71

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

Legal Proceedings

From time to time, the Partnership may be involved in various legal proceedings, lawsuits, and other claims in the ordinary course of business including proceedings related to environmental and other matters. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance. Management does not believe that the resolution of these matters will have a material adverse impact on our financial condition, cash flows or results of operations.

11. Lease Income

In April 2020, KMF Water entered into the Water Services Agreement with a third-party water services company under which the third party agreed to manage the Partnership’s water assets and operations for an initial term of three months. Under the terms of the agreement, the third party is responsible for the production, marketing, and sales of water from the Partnership’s water properties, but each entity will each be entitled to fifty percent of the proceeds generated from water sales. The agreement also prescribes which entity (KMF or the third party) will be responsible for various costs under the arrangement. The initial term has been renewed for successive three-month periods and will continue to automatically renew for successive three-month terms unless terminated.

The Water Services Agreement constitutes a leasing arrangement under which the Partnership is a lessor. Under the terms of the agreement, the Partnership is not entitled to any income until the lessee has completed a water sale and received payment from its customer. The Partnership does not accrue this contingent rental income until the lessee has received payment. Leasing income related to the Water Sales Agreement was $0.2 million during the six months ended June 30, 2021.There was no leasing income associated with the Water Services Agreement for the six months ended June 30, 2020.

12. Business Segment Information

The Partnership has two reportable segments: Oil and Gas Producing Activities and Water Service Operations. The segments provide the chief operating decision maker (“CODM”) with a comprehensive financial view of the Partnership’s core business. The Partnership’s Management has been determined to be the CODM. The CODM assesses performance and allocates resources based on the two reportable segments.

The Oil and Gas Producing Activities segment is comprised of managing the mineral and royalty interests and related revenue streams of KMF Land. The revenue streams of this segment principally consist of royalties from oil, natural gas and NGL producing activities and revenues from lease bonus payments and easements. We are not a producer and the Partnership’s oil, natural gas, and NGL revenues are derived from a fixed percentage of the oil, natural gas and NGL produced from the acreage underlying our interests, net of post-production expenses and production taxes. The Water Service Operations segment comprises the water supply assets and operations of KMF Water. The revenue of this segment consists of water sales to various basin operators produced from the water supply assets of the Partnership, as well as lease income under the Water Services Agreement.

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profit. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the CODM in deciding how to allocate resources and assess performance. Segment profit is defined as segment revenues less operating expenses, depreciation, depletion and amortization, income taxes, and interest expense. Partnership expenses include general expenses associated with managing the Partnership and are not allocated directly to the two reportable segments.

F-72

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

The following table sets forth certain financial information with respect to the Partnership’s reportable segments (in thousands):

	For the six months ended June 30, 2021
	Oil and  Gas Producing Activities			Water Service Operations		Partnership			Consolidated Total
Revenues	$	36,514		$	205	$	—		$	36,719
Depreciation, depletion and amortization		15,658			143		—			15,801
Income tax expense		(107	)		—		—			(107	)
Interest expense		(543	)		—		—			(543	)
Segment profit (loss)		13,279			61		(3,864	)		9,476
Total assets as of June 30, 2021		904,404			3,457		1,687			909,548
Capital expenditures including mineral acquisitions		1,918			—		—			1,918
A reconciliation of segment profit (loss) to net income is as follows:
Segment profit	$	9,476
Interest income		19
Net income attributable to noncontrolling interests		(28	)
Net income		9,467

	For the six months ended June 30, 2020
	Oil and  Gas Producing Activities			Water Service Operations			Partnership			Consolidated Total
Revenues	$	19,711		$	—		$	—		$	19,711
Depreciation, depletion and amortization		15,536			159			—			15,695
Income tax expense		(124	)		—			—			(124	)
Interest expense		(1,234	)		—			—			(1,234	)
Segment loss		(8,181	)		(80	)		(3,941	)		(12,202	)
Total assets as of June 30, 2020		605,339			4,435			8,803			618,577
Capital expenditures including mineral acquisitions		34,657			—			—			34,657
A reconciliation of segment profit (loss) to net income is as follows:
Segment loss	$	(12,202	)
Interest income		49
Net loss		(12,153	)

13. Derivative Instruments

Commodity Derivatives

KMF Land may enter into commodity derivative contracts to manage its exposure to oil and gas price volatility associated with its production. These derivatives are not entered into for trading or speculative purposes. While the use of these instruments limits the downside risk of adverse commodity price changes, their use may also limit future cash flows from favorable commodity price changes. Depending on changes

F-73

KIMMERIDGE MINERAL FUND, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 2021 and 2020

(Unaudited)

in oil and gas futures markets and management’s view of underlying supply and demand trends, the Partnership may increase or decrease its derivative positions. The Partnership’s commodity derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses on commodity derivatives are recognized in the Partnership’s statement of operations.

In 2020, the Partnership utilized fixed price swaps and basis swaps to manage commodity price risks. The Partnership has entered into these swap contracts when management believes that favorable future sales prices for the Partnership’s production can be secured. Under fixed price swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Partnership pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Partnership receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price that is representative of the price received by many of the operators in the Delaware Basin.

In October 2020, KMF Land terminated all of its outstanding oil and basis swap derivative contracts. KMF was not party to any derivative contracts as of June 30, 2021 or December 31, 2020.

The following table is a summary of derivative gains and losses, and where such values are recorded in the condensed consolidated statements of operations for the six months ended June 30, 2021 and 2020 (in thousands):

	Statement of operations location		Six months ended June 30, 2021		Six months ended June 30, 2020
Commodity derivative losses		Revenue	$	—	$	(2,642	)

The fair value of commodity derivative instruments was determined using Level 2 inputs.

14. Subsequent Events

Management has evaluated all subsequent events from the balance sheet date through August 13, 2021 for disclosure within these financial statements and no items requiring disclosure were identified except for the acquisition identified below.

Acquisition

On July 26, 2021, the Partnership acquired certain mineral and royalty interests in the Delaware Basin for $21.6 million, of which $2.3 million was classified as a deposit as of June 30, 2021. The Partnership predominantly funded the acquisition with $20.0 million of borrowings under the KMF Revolving Credit Facility.

F-74

INDEPENDENT AUDITORS’ REPORT

To the Board of Managers of Rock Ridge Royalty Company LLC

We have audited the accompanying financial statements of Rock Ridge Royalty Company LLC (the “Company”), which comprise the balance sheets as of December 31, 2020 and 2019, and the related statements of operations, changes in members’ interest, and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes 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.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements 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 the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rock Ridge Royalty Company LLC as of December 31, 2020 and 2019, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Dallas, Texas

March 15, 2021

F-75

ROCK RIDGE ROYALTY COMPANY LLC

BALANCE SHEETS

AS OF DECEMBER 31

(in thousands)

	2020		2019
Assets
Current assets
Cash and cash equivalents	$	6,267	$	2,390
Accounts receivable		5,290		3,912
Accounts receivable—affiliates		—		92
Prepaids and other current assets		79		80
Total current assets		11,636		6,474
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting		72,634		135,873
Unproved property excluded from amortization		50,276		63,659
Total oil and gas properties, net		122,910		199,532
Other property and equipment, net		64		122
Loan origination cost, net		310		325
Total assets	$	134,920	$	206,453
Liabilities and Members’ Interest
Accounts payable	$	115	$	601
Accounts payable—affiliates		158		345
Commodity derivatives		156		—
Other liabilities		18		21
Total current liabilities		447		967
Credit facility		—		1,200
Other liabilities		19		22
Total liabilities		466		2,189
Commitments and contingencies (Note 9)
Members’ interest		134,454		204,264
Total liabilities and members’ interest	$	134,920	$	206,453

The accompanying notes are an integral part of the financial statements.

F-76

ROCK RIDGE ROYALTY COMPANY LLC

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31

(in thousands)

	2020			2019
Revenues
Royalty revenue	$	18,023		$	15,150
Lease bonus and right of way revenue		47			6,814
Unrealized loss on derivatives		(156	)		—
Total revenues		17,914			21,964
Operating Expenses
Ad valorem taxes		364			297
Depreciation, depletion and amortization		15,555			6,808
Impairment of oil and gas properties		63,528			—
General and administrative		3,182			4,748
Total operating expenses		82,629			11,853
Operating (expense) income		(64,715	)		10,111
Other income		156			—
Interest expense		(208	)		(21	)
(Loss) income before taxes		(64,767	)		10,090
Texas margin tax expense		43			—
Net (loss) income	$	(64,810	)	$	10,090

The accompanying notes are an integral part of the financial statements.

F-77

ROCK RIDGE ROYALTY COMPANY LLC

STATEMENT OF CHANGES IN MEMBERS’ INTEREST

(in thousands)

	Total Members’ Interest
January 1, 2019		162,281
Contributions		81,861
Return of contributions		(49,968	)
Net income		10,090
December 31, 2019	$	204,264
Distributions		(5,000	)
Net (loss)		(64,810	)
December 31, 2020	$	134,454

The accompanying notes are an integral part of the financial statements.

F-78

ROCK RIDGE ROYALTY COMPANY LLC

STATEMENT OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31

(in thousands)

	2020			2019
Cash flows from operating activities
Net (loss) income	$	(64,810	)	$	10,090
Depreciation, depletion and amortization		15,555			6,808
Impairment of oil and gas properties		63,528			—
Deferred loan cost amortization		80			—
Unrealized loss on derivatives		156			—
Changes in operating assets and liabilities
Accounts receivable		(1,286	)		(3,307	)
Accounts payable		(486	)		97
Accounts payable—affiliates		(187	)		(191	)
Prepaids and other		(4	)		15
Net cash provided by operating activities		12,546			13,513
Cash flows from investing activities
Purchase of oil and gas mineral interest		(2,383	)		(61,949	)
Purchase of other property and equipment		(6	)		(46	)
Net cash used in investing activities		(2,389	)		(61,995	)
Cash flows from financing activities
Proceeds from member contributions		—			81,861
Return of contributions		—			(49,969	)
Member distributions		(5,000	)		—
Proceeds from line of credit		—			5,000
Repayment of line of credit		(1,200	)		(3,800	)
Loan origination cost		(80	)		(325	)
Net cash (used in) provided by financing activities		(6,280	)		32,767
Net change in cash		3,877			(15,715	)
Cash at beginning of period		2,390			18,105
Cash at end of period	$	6,267		$	2,390
Supplemental cash disclosure:
Cash paid for interest	$	125		$	—

The accompanying notes are an integral part of the financial statements.

F-79

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION

Rock Ridge Royalty Company LLC (the “Company”), a Delaware limited liability company, was formed on November 23, 2016, and is engaged in the acquisition and management of mineral and royalty assets throughout the Delaware basin in west Texas.

The Company is managed by the board of managers. The board of managers is comprised of nine members, five of which are appointed by the Series B interest holders. Series B interests are held through funds controlled by The Blackstone Group L.P. (“Blackstone”) and have a commitment to fund $500 million. Additionally, Series A interest holders have committed $33.6 million through the purchase of Series C common interests as described in Note 6. As of December 31, 2020, there was approximately $326.1 million remaining in uncalled committed capital.

Basis of Presentation

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All dollar amounts in the financial statements and tables in the notes are stated in thousands of U.S. dollars unless otherwise indicated.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates include the carrying value of oil and gas properties.

Cash and Cash Equivalents

The Company considers all liquid investments with original maturities of three months or less to be cash equivalents. At December 31, 2020 and 2019, the Company did not have any cash equivalents.

Royalty Mineral Interests in Oil and Gas Properties

Royalty interests include acquired mineral, oil and natural gas, and other royalty interests in the production, development and exploration stage properties.

The Company’s royalty interests have no rights or obligations to explore, develop or operate the properties in which it maintains such interests, and the Company does not incur any of the cost of exploration, development and operation of the properties.

The Company applies the full cost method of accounting for oil and gas properties. Accordingly, all costs incurred in the acquisition of oil and gas properties are capitalized.

Costs associated with proved oil and gas properties are subject to the full cost ceiling limitation which generally limits unamortized capitalized costs to the discounted future net revenues from proved reserves, based

F-80

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE FINANCIAL STATEMENTS

on the average of the last day prices of the previous twelve months and operating conditions. As a result of the Company’s proved property impairment assessment as of December 31, 2020, the Company recorded a $63.5 million noncash impairment charge to reduce the carrying value of its proved oil and gas properties, which is included in impairments of oil and gas properties in the statements of operations. There were no impairments of proved oil and gas properties for the year ended December 31, 2019.

Costs associated with unproved properties that have not been impaired are excluded from the depletion base. As proved reserves are established, costs associated with unproved properties become part of our depletion base. We determine the amount of costs to transfer from unproved properties based on our estimate of the potential drilling locations and potential reserves associated with those properties.

Unproved properties are assessed annually to ascertain whether impairment has occurred. The impairment assessment includes consideration of our understanding of the operators’ intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and market considerations, among others. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties, become part of our depletion base, and become subject to the full cost ceiling limitation. There were no unproved properties transferred to the depletion base due to impairment during 2020 and 2019.

Depreciation, depletion and amortization of proved oil and gas properties are computed on the units–of–production method, using estimates of the underlying proved reserves.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.

Revenue Recognition

Royalty revenue from sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.

The price we receive for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration.

The Company also earns revenue from lease bonuses, right-of-way and delay rentals. The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company’s contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Company a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company recognizes revenue from right-of-way

F-81

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE FINANCIAL STATEMENTS

payments, which grants others access to land owned by the Company to perform necessary services to produce oil and gas. The Company also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Company has no further obligation to refund the payment.

Income Taxes

The Company is a pass-through entity for federal income tax purposes, as such, federal income tax is assessed against the individual owner rather than against the Company. The Company evaluates the tax positions taken or expected to be taken in the course of preparing the Company’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Company’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold.

The Company’s policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable. Tax positions taken related to the Company’s pass-through status and those taken in determining their state income tax liability, including deductibility of expenses, have been reviewed and management is of the opinion that material positions taken by the Company has not recorded an income tax liability for uncertain tax positions. The Company’s tax returns are subject to examinations under Internal Revenue Service’s general statutes.

Loan Origination Costs

Loan origination costs are amortized over the term of the related obligation using the effective interest method. Origination cost associated with our reserves-based line of credit are presented net of amortization within long-term assets.

NOTE 3. MINERAL INTERESTS

Property consisted of the following at December 31 (in thousands):

	2020			2019
Oil and gas properties:
Proved oil and gas properties	$	169,949		$	154,183
Unproved oil and gas properties excluded from amortization		50,276			63,659
Accumulated depreciation, depletion and amortization and impairment		(97,315	)		(18,310	)
Total oil and gas properties, net	$	122,910		$	199,532
Other property and equipment:
Furniture and equipment	$	160		$	155
Accumulated depreciation		(96	)		(33	)
Total other property and equipment, net	$	64		$	122

F-82

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE FINANCIAL STATEMENTS

Acquisitions and Divestitures

During the year ended December 31, 2020, the Company acquired 77.8 net mineral acres¹ resulting in 147.5 net royalty acres² in 18 transactions for an aggregate amount of $2.4 million, including acquisition cost. The acquisitions were funded through equity contributions by members and debt.

During the year ended December 31, 2019, the Company acquired 2,678 net mineral acres¹ resulting in 3,917 net royalty acres² in 57 transactions for an aggregate amount of $61.3 million, including acquisition cost. The acquisitions were funded through equity contributions by members and debt.

NOTE 4. DERIVATIVE INSTRUMENTS

The Company engages in price risk management activities. These activities are intended to manage the Partnership’s exposure to fluctuations in crude oil prices. The Partnership primarily utilizes price swaps.

Commodity derivatives are classified as Level 2 within the fair value hierarchy. The fair value of these instruments is estimated using forward-looking price curves and discounted cash flows that are observable or that can be corroborated by observable market data.

Crude oil derivatives settle against the average of the prompt month NYMEX future prices for West Texas Intermediate crude oil.

The fair values of commodity derivatives at December 31 were as follows (in thousands):

	2020			2019
Commodity derivative liabilities
Current portion	$	156		$	—
Long-term portion		—			—
		156			—
Net commodity derivatives	$	(156	)	$	—

The Company had the following outstanding open crude oil positions as of December 31, 2020:

	Expirations 2021
Oil Swaps:
Notional volume (bbl)		69,602
Weighted average swap price	$	46.05

¹   Net Mineral Acres: As to a given tract of land, the Company’s Net Mineral Acre (NMA) ownership is determined by (A) the number of gross surface acres in such tract of land, multiplied by (B) the Company’s undivided interest in and to the oil, gas, and other minerals associated with such tract. Royalty Acres are defined as the royalty associated to the Net Mineral Acres owned.

²  Net Royalty Acres: As to a given tract of land, the Company’s Net Royalty Acre ownership is determined by taking the sum product of (A) the Net Mineral Acres in such tract, multiplied by (B) if the tract is subject to oil and gas lease(s), the average lessor’s royalty interest under such lease(s) (provided, if any portion of the minerals are unleased, the lease royalty is assumed to be twenty five percent (25%)), less any non-participating royalty interests or similar burdens on the lease royalty; and (C) dividing the sum product of (A) and (B) by twelve and one half percent (12.5%).

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ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE FINANCIAL STATEMENTS

The Company had no outstanding open crude oil positions as of December 31, 2019.

NOTE 5. CREDIT FACILITY

Reserves-based line of credit

On September 30, 2019, the Company entered into a senior, first lien credit agreement with Royal Bank of Canada (“RBC”), as administrative agent, collateral agent, swingline lender, and an issuing bank. The credit agreement provides for a $25.0 million senior secured revolving credit facility expiring September 30, 2024 (the “Credit Facility”). The borrowing base at December 31, 2020 is $25 million.

The Credit Facility contains certain financial covenants that must be met by the Company. A current ratio of 1.0 times or greater must be maintained at each quarter end starting with the quarter ending December 31, 2019. The calculation of the current ratio under the Credit Agreement dictates that the available, undrawn balance on the Credit Facility be added to current assets for debt compliance calculation purposes, among other adjustments. Further, the debt to EBITDA ratio for the trailing four-fiscal quarters must be no greater than 4.0 times starting with the quarter ending December 31, 2019. The covenants also include certain customary restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.

The applicable base rate is equal to the London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 2% to 3% based on the percentage of the borrowing base utilized. As of December 31, 2020, the margin was 2%. The Credit Facility carries a commitment fee of 37.5 to 50 basis points on the unused portion of the borrowing base.

Deferred loan costs of $0.4 million and $0.3 million (net of $0.1 million and $0 in amortization) is recorded in long-term assets for the year ended December 31, 2020 and 2019, respectively.

NOTE 6. MEMBERS INTEREST

The Company has two classes of Member Interests consisting of Common Interest and Profits Interest. These interests include one series of Profits Interest, the Series A Profits Interest, and two series of Common Interest, the Series B Common Interest and the Series C Common Interest. The Series B members have a total aggregate commitment of up to $500 million and the Series A Profits Interest holders have the right to contribute and purchase Series C Common interest for an aggregate commitment amount of up to $33.6 million.

Series A Profits Interests were issued to legacy unit holders of Primexx Energy Partners, Ltd. (“PEP”). Additionally, a total 650 units of Series A Profits Interests have been authorized for issuance to management of the Company as incentive compensation. Granted shares vest equally over a five year period and become immediately vested upon a change in control. The following chart details the issuance of these units:

Units outstanding as of January 1, 2019	387
Units granted during 2019	50
Units outstanding as of December 31, 2019	437
Units granted during 2020	65
Units outstanding as of December 31, 2020	502

Series A Profits Interest represent equity awards whose holders participate in profits of the Company once certain payout thresholds are met for the Series B and C Common Interest holders. Accordingly, the value of the Series A Profits Interest at issuance was de minimis.

F-84

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE FINANCIAL STATEMENTS

The Company’s distribution of profit and loss will be applied as follows:

• First, to the Common Interest Holders based on their pro-rata invested capital until a 13.5% rate of return is achieved.

• Second, the vested Series A Profits Interest will receive 12.5% of the distributions with the remainder going to the Common Interest Holders until the Common Interest Holder achieve a 20% rate of return and a multiple of 2.05 times their invested capital.

• Third, the vested Series A Profits Interest will receive 22.5% of the distributions with the remainder going to Common Interest Holders until the Common Interest Holders achieve a 30% rate of return and a multiple of 3.05 times their invested capital.

• Fourth, the vested Series A Profits Interest will receive 32.5% of the distributions with the remainder going to the Common Interest Holders.

NOTE 7. MID-TERM INCENTIVE PLAN

In 2020, the Board of Directors established the Mid Term Incentive Plan (“MTIP”) as an incentive program for the Company’s directors, executives, and key employees. The program designates a pool of up to $15.0 million to be granted to employees and provide a cash award when the affiliated Primexx entities (Primexx Energy Partners, Ltd., BPP Energy Partners LLC, and Rock Ridge Royalty Company LLC) have a Liquidity Event. The award is to be split proportionately amongst the affiliated entities based on the cash amount received for each entity. The award vests in two tranches with 65% of the award vesting over a three-year period and 35% of the award is based on personal performance of the grantee as determined by the Board of Directors. The portion that is time vested will fully accelerate and vest upon the change of control of the entity subject to the grantee’s continuous service and remaining in good standing with the Company through the date of the change in control.

Because the MTIP award is not considered a substantive class of equity, and only pays grantees upon a liquidity event of the entity, there is no expense recorded in the financial statements related to these awards. As of December 31, 2020, the total pool granted to employees under the MTIP was completely distributed.

NOTE 8. RELATED PARTY TRANSACTIONS

Primexx Energy Partners Ltd.

The Company and Primexx Energy Partners, Ltd. (“PEP”) have management and unitholders in common and various resources of PEP are utilized in the management and operations of the Company. These resources include technology, office space and personnel. The costs of these resources are charged to the Company based on the time allocated by employees engaged in the work of the Company as well as actual cost incurred. The following chart details the transactions between these entities for the period (in thousands):

	2020		2019
Rock Ridge payable to PEP	$	158	$	345
Cash lease bonuses received from PEP	$	47	$	—
Revenue received from PEP	$	5,930	$	3,738
General and administrative expenses reimbursed to PEP	$	2,487	$	3,010

BPP Energy Partners LLC

The Company has unitholders and management in common with BPP Energy Partners LLC (“BPP”) a Delaware limited liability company formed in 2017 to acquire and hold mineral and royalty interests in the

F-85

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE FINANCIAL STATEMENTS

Delaware Basin. During 2019, the Company leased approximately 361 acres to BPP receiving a total lease bonuses of $3.8 million.

Saragosa Field Services LLC

The Company has unitholders and management in common with Saragosa Field Services LLC (“SFS”) a Delaware limited liability company and subsidiary of PEP that was formed in 2017. During 2019, the Company received surface damage revenue in the amount of $20 thousand.

NOTE 9. COMMITMENTS AND CONTINGENCIES

The Company leases office and computer equipment and software under non-cancellable operating leases. Expenses associated with these operating leases for the years ended December 31, 2020 and 2019 were approximately $0.2 million and $0.1 million, respectively. Future minimum lease commitments under non-cancellable operating leases are as follows (in thousands):

2021	$	24
2022	$	8
2023	$	2
Thereafter	$	—

The Company may become involved from time to time in litigation on various matters which are routine to the conduct of its business. Management is not currently a party to any material litigation and is not aware of any litigation threatened against the Company that could have a material adverse effect on the Company.

Current economic conditions may adversely affect the results of operations in future periods. The novel coronavirus (“COVID-19”) pandemic significantly affected the global economy and created significant volatility in the financial markets. These events, in addition to disruptions in the demand for oil combined with pressures on the global supply-demand balance for oil, resulted in significant volatility in oil prices during 2020. The effects of the COVID-19 pandemic negatively impacted the Company’s results of operations and led to a reduction in capital activities on the Company’s leasehold acreage. The impact of these events on the financial performance of the Company’s long-term operations is uncertain, including the duration of the COVID-19 pandemic and long-term effects on global oil demand. The financial statements have been prepared using values and information currently available to the Company.

NOTE 10. SUBSEQUENT EVENTS

Subsequent events have been evaluated through March 15, 2021, the date on which the financial statements were available to be issued.

F-86

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Geographic Area of Operation

The Company’s oil and natural gas reserves are located within the continental United States and concentrated in the Delaware Basin of Texas and New Mexico.

Capitalized Oil and Natural Gas Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows (in thousands):

	December 31, 2020			December 31, 2019
Oil and gas properties
Proved oil and gas properties	$	169,949		$	154,183
Unproved oil and gas properties		50,276			63,659
Total oil and gas properties		220,225			217,842
Accumulated depletion and impairment		(97,315	)		(18,310	)
Net oil and gas properties capitalized	$	122,910		$	199,532

Costs Incurred in Oil and Natural Gas Activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows (in thousands):

	December 31, 2020		December 31, 2019
Acquisition costs
Proved oil and gas properties	$	586	$	60,718
Unproved oil and gas properties		1,797		1,231
Total acquisition costs		2,383		61,949

Results of Operations from Oil and Natural Gas Producing Activities

The following sets forth the revenues and expenses related to the production and sale of oil and natural gas (in thousands). It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the net operating results of the Company’s oil and natural gas operations.

	December 31, 2020			December 31, 2019
Oil, natural gas and NGL royalty revenues	$	18,988		$	15,905
Production and ad valorem taxes		(1,329	)		(1,051	)
Depletion		(15,492	)		(6,765	)
Impairment of oil and gas properties		(63,528	)		—
Income tax expense		(43	)		—
Results of operations from oil and natural gas producing activities	$	(61,404	)	$	8,089

The reserves as of December 31, 2020 and 2019 presented below were prepared by independent petroleum engineers. The calculation and analysis of interim changes in proved reserves were prepared by the Company. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in the Delaware Basin of Texas and New Mexico.

F-87

The following tables set forth estimated net quantities of the Company’s estimated proved reserves and projected future cash inflows and future production costs and are prepared in accordance with GAAP. For estimates of proved reserves, the average spot prices are determined based on the first day of the month average prices adjusted by applying price and cost basis differentials, including transportation and quality, to the period-end estimated quantities of oil, natural gas and NGL to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future ad valorem taxes are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period-end costs and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by GAAP. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Analysis of Changes in Proved Reserves

The following table sets forth information regarding the Company’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for each of the periods presented:

	Oil (MBbls)			Natural Gas (MMcf)			NGLs (MBb(s)			Total (MBOE)
Balance, January 1, 2019		1,678			2,649			349			2,468
Revisions		(601	)		(618	)		(11	)		(715	)
Extensions		3,176			5,904			859			5,019
Acquisitions of reserves		1,168			1,889			324			1,806
Production		(282	)		(457	)		(77	)		(434	)
Balance, December 31, 2019		5,139			9,367			1,444			8,144
Revisions		(3,096	)		(4,475	)		(666	)		(4,510	)
Extensions		1,951			4,041			672			3,297
Acquisitions of reserves		14			29			4			23
Production		(444	)		(830	)		(129	)		(710	)
Balance, December 31, 2020		3,564			8,132			1,325			6,244

F-88

	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBb(s)		Total (MBOE)
Proved developed and undeveloped reserves:
Developed as of January 1, 2019		638		1,423		129		1,003
Undeveloped as of January 1, 2019		1,040		1,226		220		1,465
Balance at January 1, 2019		1,678		2,649		349		2,468
Developed as of December 31, 2019		1,605		3,320		452		2,610
Undeveloped as of December 31, 2019		3,534		6,048		992		5,534
Balance at December 31, 2019		5,139		9,367		1,444		8,144
Developed as of December 31, 2020		1,469		3,723		599		2,688
Undeveloped as of December 31, 2020		2,095		4,409		726		3,556
Balance at December 31, 2020		3,564		8,132		1,325		6,244

Revisions to previous estimates of proved reserves, either upward or downward, are a result of updated information obtained in the reporting period, including operator drilling activity and production history or changes in economic factors such as commodity prices, operating and development costs.

During the year ended December 31, 2020, the Company’s extensions and discoveries of 3,297 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to operator drilling activity. In addition, the Company purchased certain mineral interests in Loving County, Texas and Eddy County, New Mexico which resulted in 23 MBOE of acquisitions. The Company negatively revised previous estimates by 4,510 MBOE due to the following:

• Downgrade of 2,128 MBOE of proved reserves to non-proved due to the decrease in operator activity in 2020 resulting in development falling outside of five years

• Negative revision of 259 MBOE due to downward movement of SEC pricing

• Increase of 331 MBOE due to updated gas and natural gas liquids processing and basis differentials

• Negative revision of 2,454 MBOE attributed to downward revisions of estimated ultimate recovery, proved unit configuration and operator development planning.

During the year ended December 31, 2019, the Company’s extensions and discoveries of 5,019 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to operator drilling activity. In addition, the Company purchased certain mineral interests in Loving County, Texas, Reeves County, Texas, and Lea County, New Mexico which resulted in 1,806 MBOE of acquisitions. The Company negatively revised previous estimates by 715 MBOE due to the following:

• Downgrade of 318 MBOE of proved reserves to non-proved due to the decrease in operator activity in 2019 resulting in development falling outside of five years

• Negative revision of 13 MBOE due to downward movement of SEC pricing

• Increase of 107 MBOE due to updated gas and natural gas liquids processing and basis differentials

• Negative revision of 491 MBOE attributed to downward revisions of estimated ultimate recovery, proved unit configuration and operator development planning.

Standardized Measure of Oil and Gas

The standardized measure and projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves

F-89

may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Our calculations of the standardized measure of discounted future net cash flows and the related changes therein do not include the effect of estimated federal income tax expenses because the Company is not subject to federal income taxes. The Company is subject to certain state-based taxes; however, these amounts are not material.

As of December 31, 2020, the reserves are comprised of 57% crude oil, 22% natural gas and 21% NGL on an energy equivalent basis.

The values for the December 31, 2020 and 2019 proved reserves were derived based on prices presented in the table below. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the NGL pricing was 30% of WTI for 2020 and 39% of WTI for 2019; the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.

	Oil (Bbl)		Natural Gas (Mcf)		NGLs (Bbl)
December 31, 2020 (Average)	$	35.32	$	0.68	$	10.63
December 31, 2019 (Average)	$	46.17	$	0.18	$	18.21

The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

	December 31, 2020			December 31, 2019
Future oil and natural gas sales	$	145,440		$	265,239
Future production taxes		(7,564	)		(13,145	)
Future ad valorem taxes		(2,237	)		(5,030	)
Future net cash flows		135,639			247,064
10% annual discount		(63,000	)		(111,751	)
Standardized measure of discounted future net cash flows	$	72,639		$	135,313

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Year Ended December 31,
	2020			2019
Standardized measure, beginning of year	$	135,313		$	53,090
Net change in prices and production costs		(59,140	)		(31,842	)
Oil and gas sales, net of production costs		(17,659	)		(14,854	)
Extensions and discoveries		38,978			82,819
Acquisitions of reserves		278			31,569
Revisions of previous quantity estimates		(38,134	)		(6,018	)
Accretion of discount		13,531			5,309
Changes in timing and other		(529	)		15,241
Standardized measure, end of year	$	72,639		$	135,313

F-90

ROCK RIDGE ROYALTY COMPANY LLC

CONDENSED BALANCE SHEETS

UNAUDITED

(in thousands)

	March 31, 2021		December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	8,517	$	6,267
Accounts receivable		6,752		5,290
Prepaids and other current assets		40		79
Total current assets		15,309		11,636
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting		121,435		122,910
Other property and equipment, net		58		64
Loan origination cost, net		289		310
Total assets	$	137,091	$	134,920
Liabilities and Members’ Interest
Accounts payable	$	237	$	115
Accounts payable—affiliates		62		158
Commodity derivatives		585		156
Other liabilities		15		18
Total current liabilities		899		447
Credit facility		—		—
Other liabilities		13		19
Total liabilities		912		466
Commitments and contingencies (Note 9)
Members’ interest		136,179		134,454
Total liabilities and members’ interest	$	137,091	$	134,920

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ROCK RIDGE ROYALTY COMPANY LLC

CONDENSED STATEMENTS OF OPERATIONS

UNAUDITED

FOR THE PERIODS ENDED MARCH 31

(in thousands)

	2021			2020
Revenues
Royalty revenue	$	4,560		$	8,837
Lease bonus and right of way revenue		—			12
Loss on derivative instruments, net		(671	)		—
Total revenues		3,889			8,849
Operating Expenses
Lease operating expenses		2			—
Ad valorem taxes		226			10
Depreciation, depletion and amortization		1,482			4,104
General and administrative		410			1,594
Total operating expenses		2,120			5,708
Operating income		1,769			3,141
Interest expense		(44	)		(52	)
Net income	$	1,725		$	3,089

The accompanying notes are an integral part of the condensed financial statements.

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ROCK RIDGE ROYALTY COMPANY LLC

CONDENSED STATEMENT OF CHANGES IN MEMBERS’ INTEREST

UNAUDITED

(in thousands)

	Total Members’ Interest
December 31, 2020	$	134,454
Net income		1,725
March 31, 2021	$	136,179

	Total Members’ Interest
December 31, 2019	$	204,264
Net income		3,685
March 31, 2020	$	207,949

The accompanying notes are an integral part of the condensed financial statements.

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ROCK RIDGE ROYALTY COMPANY LLC

CONDENSED STATEMENTS OF CASH FLOWS

FOR THE PERIODS ENDED MARCH 31

UNAUDITED

(in thousands)

	2021			2020
Cash flows from operating activities
Net income	$	1,725		$	3,089
Depreciation, depletion and amortization		1,482			4,104
Deferred loan cost amortization		21			19
Unrealized loss on derivatives		429			—
Changes in operating assets and liabilities
Accounts receivable		(1,463	)		(1,522	)
Accounts payable		121			(177	)
Accounts payable—affiliates		(95	)		246
Prepaids and other		30			(70	)
Net cash provided by operating activities		2,250			5,689
Cash flows from investing activities
Purchase of oil and gas mineral interest		—			(2,358	)
Purchase of other property and equipment		—			(10	)
Net cash used in investing activities		—			(2,368	)
Cash flows from financing activities
Repayment of line of credit		—			(1,200	)
Loan origination cost		—			(58	)
Net cash used in financing activities		—			(1,258	)
Net change in cash and cash equivalents		2,250			2,063
Cash and cash equivalents, beginning of period		6,267			2,390
Cash and cash equivalents, end of period	$	8,517		$	4,453
Supplemental cash disclosure:
Cash paid for interest	$	47		$	54

The accompanying notes are an integral part of the condensed financial statements.

F-94

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE CONDENSED UNAUDITED FINANCIAL STATEMENTS

NOTE 1.     ORGANIZATION

Rock Ridge Royalty Company LLC (the “Company”), a Delaware limited liability company, was formed on November 23, 2016, and is engaged in the acquisition and management of mineral and royalty assets throughout the Delaware basin in west Texas.

NOTE 2.     SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All dollar amounts in the financial statements and tables in the notes are stated in thousands of U.S. dollars unless otherwise indicated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies which are, in the opinion of management, necessary to a fair statement of the results in the interim periods presented and are of a normal recurring nature. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these condensed notes to the financial statements should be read in conjunction with the audited financial statements.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates include the carrying value of oil and gas properties.

Royalty Mineral Interests in Oil and Gas Properties

Royalty interests include acquired mineral, oil and natural gas, and other royalty interests in the production, development and exploration stage properties. The Company’s royalty interests have no rights or obligations to explore, develop or operate the properties in which it maintains such interests, and the Company does not incur any of the cost of exploration, development and operation of the properties.

The Company applies the full cost method of accounting for oil and gas properties. Accordingly, all costs incurred in the acquisition of oil and gas properties are capitalized.

The Company assesses its oil and gas properties whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Costs associated with proved oil and gas properties are subject to the full cost ceiling limitation which generally limits unamortized capitalized costs to the discounted future net revenues from proved reserves, based on the average of the first day prices of the previous twelve months and operating conditions. There were no impairments of proved oil and gas properties for the three-month periods ended March 31, 2021 and 2020.

Costs associated with unproved properties that have not been impaired are excluded from the depletion base. As proved reserves are established, costs associated with unproved properties become part of our depletion base. We determine the amount of costs to transfer from unproved properties based on our estimate of the potential drilling locations and potential reserves associated with those properties.

F-95

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE CONDENSED UNAUDITED FINANCIAL STATEMENTS

Unproved properties are assessed annually to ascertain whether impairment has occurred. The impairment assessment includes consideration of our understanding of the operators’ intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and market considerations, among others. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties, become part of our depletion base, and become subject to the full cost ceiling limitation.

Depreciation, depletion and amortization of proved oil and gas properties are computed on the units–of–production method, using estimates of the underlying proved reserves.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.

Derivative Activity

The Company uses derivative financial instruments to reduce exposure to fluctuations in commodity prices. These transactions are in the form of crude oil swaps.

The Company reports the fair value of derivatives on the condensed balance sheets in commodity derivative assets or liabilities as either current or noncurrent. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of the individual trades. The Company reports these on a gross basis by counterparty.

The Company’s derivative instruments were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized along with realized gains and losses in Loss on derivative instruments, net, in the condensed statements of operations in the period of change.

Fair Value of Financial Instruments

Certain of our assets and liabilities are measured at fair value as of the reporting period. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. Fair value measurements are classified according to the following hierarchy that consists of three broad levels:

Level 1 inputs: Unadjusted quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 inputs: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 inputs: Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value

F-96

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE CONDENSED UNAUDITED FINANCIAL STATEMENTS

measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between level 1, level 2, and level 3 of the fair value hierarchy, if applicable, are made at the end of each reporting period.

Revenue Recognition

Royalty revenue from sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.

The price we receive for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration.

The Company also earns revenue from lease bonuses, right-of-way and delay rentals. The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company’s contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Company a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company recognizes revenue from right-of-way payments, which grants others access to land owned by the Company to perform necessary services to produce oil and gas. The Company also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Company has no further obligation to refund the payment.

NOTE 3.    MINERAL INTERESTS

Property consisted of the following as of (in thousands):

	March 31, 2021			December 31, 2020
Oil and gas properties:
Proved oil and gas properties	$	169,949		$	169,949
Unproved oil and gas properties excluded from amortization		50,276			50,276
Accumulated depreciation, depletion and amortization and impairment		(98,790	)		(97,315	)
Total oil and gas properties, net	$	121,435		$	122,910
Other property and equipment:
Furniture and equipment	$	160		$	160
Accumulated depreciation		(102	)		(96	)
Total other property and equipment, net	$	58		$	64

F-97

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE CONDENSED UNAUDITED FINANCIAL STATEMENTS

NOTE 4.    DERIVATIVE INSTRUMENTS

The Company engages in price risk management activities. These activities are intended to manage the Partnership’s exposure to fluctuations in crude oil prices. The Partnership primarily utilizes price swaps.

Commodity derivatives are classified as Level 2 within the fair value hierarchy. The fair value of these instruments is estimated using forward-looking price curves and discounted cash flows that are observable or that can be corroborated by observable market data.

Crude oil derivatives settle against the average of the prompt month NYMEX future prices for West Texas Intermediate crude oil.

The fair values of commodity derivatives were as follows (in thousands):

	March 31, 2021			December 31, 2020
Commodity derivative liabilities
Current portion	$	585		$	156
Long-term portion		—			—
		585			156
Net commodity derivatives	$	(585	)	$	(156	)

The following presents the results of the Company’s oil and gas derivative activity included in revenue in the statements of operations during the three-month periods ended March 31, 2021 and 2020:

	March 31, 2021			March 31, 2020
Realized loss
Oil derivatives	$	(242	)	$	—
Unrealized loss
Oil derivatives	$	(429	)	$	—
Loss on derivative instruments, net	$	(671	)	$	—

The Company had the following outstanding open crude oil positions as of March 31, 2021:

	Expirations 2021
Oil Swaps:
Notional volume (bbl)		55,349
Weighted average swap price	$	46.05

The Company had the following outstanding open crude oil positions as of December 31, 2020:

	Expirations 2021
Oil Swaps:
Notional volume (bbl)		69,602
Weighted average swap price	$	46.05

F-98

ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE CONDENSED UNAUDITED FINANCIAL STATEMENTS

NOTE 5.    CREDIT FACILITY

Reserves-based line of credit

On September 30, 2019, the Company entered into a senior, first lien credit agreement with Royal Bank of Canada (“RBC”), as administrative agent, collateral agent, swingline lender, and an issuing bank. The credit agreement provides for a $25.0 million senior secured revolving credit facility expiring September 30, 2024 (the “Credit Facility”). The borrowing base at December 31, 2020 is $25 million.

On April 16, 2021, the borrowing base was reaffirmed at $25.0 million.

The Credit Facility contains certain financial covenants that must be met by the Company. A current ratio of 1.0 times or greater must be maintained at each quarter end starting with the quarter ending December 31, 2019. The calculation of the current ratio under the Credit Agreement dictates that the available, undrawn balance on the Credit Facility be added to current assets for debt compliance calculation purposes, among other adjustments. Further, the debt to EBITDA ratio for the trailing four-fiscal quarters must be no greater than 4.0 times starting with the quarter ending December 31, 2019. The covenants also include certain customary restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.

The applicable base rate is equal to the London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 2% to 3% based on the percentage of the borrowing base utilized. As of December 31, 2020, the margin was 2%. The Credit Facility carries a commitment fee of 37.5 to 50 basis points on the unused portion of the borrowing base. Interest expense related to the commitment fee on the unused portion of the borrowing base of $23 thousand and $33 thousand was recorded during the three-month periods ended March 31, 2021 and 2020, respectively.

NOTE 6.    MEMBERS’ INTEREST

The Company has two classes of Member Interests consisting of Common Interest and Profits Interest. These interests include one series of Profits Interest, the Series A Profits Interest, and two series of Common Interest, the Series B Common Interest and the Series C Common Interest. The Series B members have a total aggregate commitment of up to $500 million and the Series A Profits Interest holders have the right to contribute and purchase Series C Common interest for an aggregate commitment amount of up to $33.6 million.

Series A Profits Interests were issued to legacy unit holders of Primexx Energy Partners, Ltd. (“PEP”). Additionally, a total 650 units of Series A Profits Interests have been authorized for issuance to management of the Company as incentive compensation. Granted shares vest equally over a five year period and become immediately vested upon a change in control.

Series A Profits Interest represent equity awards whose holders participate in profits of the Company once certain payout thresholds are met for the Series B and C Common Interest holders. Accordingly, the value of the Series A Profits Interest at issuance was de minimis.

The Company’s distribution of profit and loss will be applied as follows:

• First, to the Common Interest Holders based on their pro-rata invested capital until a 13.5% rate of return is achieved.

• Second, the vested Series A Profits Interest will receive 12.5% of the distributions with the remainder going to the Common Interest Holders until the Common Interest Holder achieve a 20% rate of return and a multiple of 2.05 times their invested capital.

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ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE CONDENSED UNAUDITED FINANCIAL STATEMENTS

• Third, the vested Series A Profits Interest will receive 22.5% of the distributions with the remainder going to Common Interest Holders until the Common Interest Holders achieve a 30% rate of return and a multiple of 3.05 times their invested capital.

• Fourth, the vested Series A Profits Interest will receive 32.5% of the distributions with the remainder going to the Common Interest Holders.

NOTE 7.    MID-TERM INCENTIVE PLAN

In 2020, the Board of Directors established the Mid Term Incentive Plan (“MTIP”) as an incentive program for the Company’s directors, executives, and key employees. The program designates a pool of up to $15.0 million to be granted to employees and provide a cash award when the affiliated Primexx entities (Primexx Energy Partners, Ltd., BPP Energy Partners LLC, and Rock Ridge Royalty Company LLC) have a Liquidity Event. The award is to be split proportionately amongst the affiliated entities based on the cash amount received for each entity. The award vests in two tranches with 65% of the award vesting over a three-year period and 35% of the award is based on personal performance of the grantee as determined by the Board of Directors. The portion that is time vested will fully accelerate and vest upon the change of control of the entity subject to the grantee’s continuous service and remaining in good standing with the Company through the date of the change in control.

Because the MTIP award is not considered a substantive class of equity, and only pays grantees upon a liquidity event of the entity, there is no expense recorded in the financial statements related to these awards. As of December 31, 2020, the total pool granted to employees under the MTIP was completely distributed.

NOTE 8.    RELATED PARTY TRANSACTIONS

Primexx Energy Partners Ltd.

The Company and Primexx Energy Partners, Ltd. (“PEP”) have management and unitholders in common and various resources of PEP are utilized in the management and operations of the Company. These resources include technology, office space and personnel. The costs of these resources are charged to the Company based on the time allocated by employees engaged in the work of the Company as well as actual cost incurred. The following chart details the transactions between these entities for the period (in thousands):

	March 31, 2021		March 31, 2020
Rock Ridge payable to PEP	$	62	$	591
Revenue received from PEP	$	1,141	$	2,727
General and administrative expenses reimbursed to PEP	$	268	$	775

BPP Energy Partners LLC

The Company has unitholders and management in common with BPP Energy Partners LLC (“BPP”) a Delaware limited liability company formed in 2017 to acquire and hold mineral and royalty interests in the Delaware Basin. The Company did not lease acres to BPP during the three-month periods ending March 31, 2021 and 2020.

Saragosa Field Services LLC

The Company has unitholders and management in common with Saragosa Field Services LLC (“SFS”) a Delaware limited liability company and subsidiary of PEP that was formed in 2017. The Company did not receive surface damage revenue from SFS during the three-month periods ending March 31, 2021 and 2020.

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ROCK RIDGE ROYALTY COMPANY LLC

NOTES TO THE CONDENSED UNAUDITED FINANCIAL STATEMENTS

NOTE 9.    COMMITMENTS AND CONTINGENCIES

The Company may become involved from time to time in litigation on various matters which are routine to the conduct of its business. Management is not currently a party to any material litigation and is not aware of any litigation threatened against the Company that could have a material adverse effect on the Company.

Current economic conditions may adversely affect the results of operations in future periods. The novel coronavirus (“COVID-19”) pandemic significantly affected the global economy and created significant volatility in the financial markets. These events, in addition to disruptions in the demand for oil combined with pressures on the global supply-demand balance for oil, resulted in significant volatility in oil prices during 2020. The effects of the COVID-19 pandemic negatively impacted the Company’s results of operations and led to a reduction in capital activities on the Company’s leasehold acreage. The impact of these events on the financial performance of the Company’s long-term operations is uncertain, including the duration of the COVID-19 pandemic and long-term effects on global oil demand. The financial statements have been prepared using values and information currently available to the Company.

NOTE 10.    SUBSEQUENT EVENTS

Subsequent events were evaluated through the date the financial statements were available to be issued on July 29, 2021.

On June 8, 2021, the Company entered into an agreement with KMF Chambers HoldCo, LLC (“KMF”) to contribute all its mineral and royalty interests in exchange for certain membership interests in a wholly owned subsidiary of KMF. The closing of the transaction is expected to occur on June 30, 2021.

In connection with the transaction, the Company paid $0.8 million to unwind its remaining outstanding crude oil swap positions on June 11, 2021.

F-101

Independent Auditors’ Report

Those Charged With Governance

Source Energy Partners, LLC:

Report on the Statement of Revenues and Direct Expenses

We have audited the accompanying Source Acquisition Statement of Revenues and Direct Expenses (the Financial Statement) as described in note 1, for the year ended December 31, 2020, and the related notes to the Financial Statement.

Management’s Responsibility for the Financial Statement

Management is responsible for the preparation and fair presentation of the Financial Statement in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the Financial Statement that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the Financial Statement based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Financial Statement is free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the Financial Statement. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the Financial Statement, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the Financial Statement 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 the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the Financial Statement.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the Financial Statement referred to above presents fairly, in all material respects, the Source Acquisition revenues and direct expenses for the year ended December 31, 2020, in accordance with U.S. generally accepted accounting principles.

Emphasis of Matter

We draw attention to the basis of presentation, which describes that the Financial Statement was prepared for the purpose of complying with the rules and regulations under Rule 3-05 of the Securities and Exchange Commission Regulation S-X as described in note 1 to the Financial Statement, and is not intended to be a complete presentation of the Source Acquisition’s results of operations. Our opinion is not modified with respect to this matter.

/s/ KPMG LLP

Denver, Colorado

October 6, 2021

F-102

SOURCE ACQUISITION

STATEMENT OF REVENUES AND DIRECT EXPENSES

(in thousands)

	Year ended December 31, 2020
Revenues:
Oil, natural gas and natural gas liquids	$	13,578
Lease bonus and other revenues		165
Total Revenues		13,743
Direct expenses		(893	)
Revenues in excess of direct expenses	$	12,850

See accompanying Notes to the Statement of Revenues and Direct Expenses

F-103

SOURCE ACQUISITION

NOTES TO THE STATEMENT OF REVENUES AND DIRECT EXPENSES

Note 1—Summary of Significant Accounting Policies

Basis of Presentation

On August 31, 2021, DPM Holdco, LLC, a subsidiary of Kimmeridge Mineral Fund, LP. (“DPM” or the “Company”) completed the acquisition of certain oil, natural gas and natural gas liquids mineral and royalty properties within the Permian Basin, from Source Energy Leasehold, LP and Permian Mineral Acquisition, LP (collectively, “Source” or the “Seller”) for equity consideration (the “Source Acquisition”). The acquired properties include approximately 25,000 net royalty acres in the Permian Basin.

Separate historical financial statements prepared in accordance with accounting principles generally accepted in the United States of America have never been prepared for the Source properties. During the periods presented, the Source properties were not accounted for or operated as a consolidated entity or as a separate division by Source. The accompanying Statement of Revenues and Direct Expenses for the Source properties was derived from the historical accounting records and other applicable source documents of Source. Accordingly, the accompanying statements are presented in lieu of the financial statements required under Rule 3–05 of Securities and Exchange Commission’s Regulation S–X.

The accompanying Statement of Revenues and Direct Expenses does not represent a complete set of financial statements reflecting the financial position, results of operations, members’ equity and cash flows of the Source properties and are not necessarily indicative of the results of operations for the Source properties going forward. Certain indirect expenses, as further described in Note 4, were not allocated to the Source properties and have been excluded from the accompanying statement. Any attempt to allocate these expenses would require significant judgement, which would be arbitrary and would likely not be indicative of the performance of the properties on a stand-alone basis.

In the opinion of management, the accompanying Statement of Revenues and Direct Expenses for the year ended December 31, 2020 includes all adjustments (consisting of normal recurring accruals) that are necessary for a fair presentation of the revenues and direct expenses of the Source properties for the period presented.

Note 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Statement of Revenues and Direct Expenses in conformity with accounting principles generally accepted in the United States of America requires DPM management to make various assumptions, judgements and estimates to determine the reported amounts of revenues and expenses, and in the disclosures of contingencies. These estimates and assumptions are based upon management’s best estimates and judgements. Actual results could differ from those estimates.

Revenue Recognition

Crude oil, natural gas and natural gas liquids revenues from our mineral and royalty interests are recognized when control transfers at the wellhead. These revenues are reported net of post-production expenses, such as gathering, transportation, and processing costs.

Concentration

The Source properties are subject to risk resulting from the concentration of its mineral and royalty interests. For the year ended December 31, 2020, two operators each accounted for more than 10% of royalty interest revenue.

F-104

SOURCE ACQUISITION

NOTES TO THE STATEMENT OF REVENUES AND DIRECT EXPENSES

Although the Source properties are exposed to a concentration of credit risk, management does not believe the loss of any single operator would materially impact the Source properties’ operating results as crude oil, natural gas and natural gas liquids are fungible products with well-established markets and numerous purchasers. If multiple operators were to cease operations at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving certain operators have stipulated that royalty owners must still be paid for oil, natural gas and natural gas liquids extracted from their mineral acreage during the bankruptcy process. In light of this, Source and DPM do not expect the entry of one of the Source properties’ operators into bankruptcy to materially affect the Statement of Revenues and Direct Expenses.

Direct Expenses

Direct expenses for oil, natural gas and natural gas liquids mineral and royalty interests include severance taxes, ad valorem taxes, and any other taxes or expenses not associated with or attributable to post-production expenses. As royalty and mineral interests, the Source properties are not subject to any lease operating or production expenses.

Note 3—COMMITMENTS AND CONTINGENCIES

From time to time, the Source properties may become subject to potential claims and litigation in the normal course of business. While the ultimate impact on any proceedings cannot be predicted with certainty, Source’s management is currently not aware of any legal or other contingencies that would have a material effect on the Statement of Revenues and Direct Expenses for the year ended December 31, 2020.

Note 4—EXCLUDED EXPENSES

Indirect expenses such as general and administrative, income tax, interest expense and other indirect expenses have not been allocated to the Source Acquisition and as such, have been excluded from the accompanying financial statement. Any allocation of such indirect expenses may not be indicative of costs which would have been incurred by DPM on a stand-alone basis. Depletion and impairment expenses have also been excluded from the accompanying Statement of Revenues and Direct Expenses as such amounts would not be indicative of the depletion and impairment calculated for DPM on the Source Acquisition on a stand-alone basis.

Note 5—SUBSEQUENT EVENTS

The Company has evaluated subsequent events through October 6, 2021, the date the accompanying Statement of Revenues and Direct Expenses was available to be issued. There were no material subsequent events that required recognition or additional disclosure in the accompanying Statement of Revenues and Direct Operating Expenses.

Note 6—SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited)

The reserves at December 31, 2020 presented below were prepared by the Company’s internal petroleum engineers. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Texas and New Mexico.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to

F-105

SOURCE ACQUISITION

NOTES TO THE STATEMENT OF REVENUES AND DIRECT EXPENSES

estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGL to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future ad valorem taxes are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Analysis of Changes in Proved Reserves

The following table sets forth information regarding Source’s net ownership interest in estimated quantities of proved developed and undeveloped oil, natural gas, and natural gas liquids quantities and the changes therein for each of the periods presented:

	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas  Liquids (MBbls)			Total (MBOE)
Balance as of January 1, 2020		1,142			3,490			311			2,035
Revisions		16			(75	)		(8	)		(5	)
Extensions		684			1,196			107			990
Acquisition of Reserves		1			4			—			2
Production		(328	)		(582	)		(51	)		(476	)
Balance as of December 31, 2020		1,515			4,033			359			2,546
	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas  Liquids (MBbls)			Total (MBOE)
Proved developed and undeveloped reserves:
Developed as of January 1, 2020		967			2,953			263			1,723
Undeveloped as of January 1, 2020		175			537			48			312
Balance at January 1, 2020		1,142			3,490			311			2,035
Developed as of December 31, 2020		1,060			3,244			289			1,890
Undeveloped as of December 31, 2020		455			789			70			656
Balance at December 31, 2020		1,515			4,033			359			2,546

For the year ended December 31, 2020, Source had upward revisions of 16 MBbls of oil and downward revisions of 75 MMcf of gas and 8 MBbls of natural gas liquids (“NGL”). Total downward revisions of 5 MBOE were primarily due to decreases in pricing. For the year ended December 31, 2020, Source had extensions of 684 MBbls of oil, 1,196 MMcf of gas, and 107 MBbls of NGLs. These extensions were primarily the result of various operators’ drilling activities within the Permian Basin. In 2020, Source acquired royalty and mineral interests of 1 MBbls of oil and 4 MMcf of gas. Acquisitions of NGL in 2020 were de minimis.

F-106

SOURCE ACQUISITION

NOTES TO THE STATEMENT OF REVENUES AND DIRECT EXPENSES

Standardized Measure of Oil and Gas

The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. 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 Source or the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

As of December 31, 2020, the reserves are comprised of 60% crude oil, 26% natural gas and 14% NGL on an energy equivalent basis.

For the year ended December 31, 2020, future cash inflows are calculated by applying the 12-month arithmetic average of the first-of-month price from January to December, of oil and gas relating to Source’s proved reserves, to the year-end quantities of those reserves. The values for the December 31, 2020 proved reserves were derived based on prices presented in the table below. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the NGL pricing was 44% of WTI for 2020; the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.

	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2020 (Average)	$	37.61	$	1.54	$	16.64

The standardized measure of discounted future net cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first-day-of-the-month price. 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 Source or the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following summary sets forth the future net cash flows related to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):

	Year Ended December 31, 2020
Future oil and natural gas sales	$	69,161
Future production costs		(5,611	)
Future income tax expense		(361	)
Future net cash flows		63,189
10% annual discount		(23,224	)
Standardized measure of discounted future net cash flows	$	39,965

F-107

SOURCE ACQUISITION

NOTES TO THE STATEMENT OF REVENUES AND DIRECT EXPENSES

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Year Ended December 31, 2020
Balance at the beginning of the period	$	41,535
Net change in prices and production costs		(10,929	)
Sales, net of production costs		(12,685	)
Extensions and discoveries		17,972
Acquisitions of reserves		35
Revisions of previous quantity estimates		(537	)
Net change in income taxes		9
Accretion of discount		4,177
Changes in timing and other		388
Balance at the end of the period	$	39,965

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SOURCE ACQUISITION

STATEMENT OF REVENUES AND DIRECT EXPENSES (UNAUDITED)

(in thousands)

	For the six  months June 30, 2021
Revenues:
Oil, natural gas and natural gas liquids	$	14,708
Lease bonus and other revenues		71
Total Revenues		14,779
Direct expenses		(996	)
Revenues in excess of direct expenses	$	13,783

See accompanying Notes to the Statement of Revenues and Direct Expenses (Unaudited)

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SOURCE ACQUISITION

NOTES TO THE STATEMENT OF REVENUES AND DIRECT EXPENSES (UNAUDITED)

Note 1—Summary of Significant Accounting Policies

Basis of Presentation

On August 31, 2021, DPM Holdco, LLC, a subsidiary of Kimmeridge Mineral Fund, LP. (“DPM” or the “Company”) completed the acquisition of certain oil, natural gas and natural gas liquids mineral and royalty properties within the Permian Basin, from Source Energy Leasehold, LP and Permian Mineral Acquisition, LP (collectively, “Source” or the “Seller”) for equity consideration (the “Source Acquisition”). The acquired properties include approximately 25,000 net royalty acres in the Permian Basin.

Separate historical financial statements prepared in accordance with accounting principles generally accepted in the United States of America have never been prepared for the Source properties. During the period presented, the Source properties were not accounted for or operated as a consolidated entity or as a separate division by Source. The accompanying Statement of Revenues and Direct Expenses for the Source properties was derived from the historical accounting records and other applicable source documents of Source. Accordingly, the accompanying statement is presented in lieu of the financial statements required under Rule 3–05 of Securities and Exchange Commission’s Regulation S–X.

The accompanying Statement of Revenues and Direct Expenses does not represent a complete set of financial statements reflecting the financial position, results of operations, members’ equity and cash flows of the Source properties and are not necessarily indicative of the results of operations for the Source properties going forward. Certain indirect expenses, as further described in Note 4, were not allocated to the Source properties and have been excluded from the accompanying statements. Any attempt to allocate these expenses would require significant judgement, which would be arbitrary and would likely not be indicative of the performance of the properties on a stand-alone basis.

In the opinion of management, the unaudited Statement of Revenues and Direct Expenses for the six months ended June 30, 2021 reflect all adjustments (consisting of normal and recurring accruals), necessary to present fairly the Source Acquisitions’ revenues and direct expenses.

Note 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Statement of Revenues and Direct Expenses in conformity with accounting principles generally accepted in the United States of America requires DPM management to make various assumptions, judgements and estimates to determine the reported amounts of revenues and expenses, and in the disclosures of contingencies. These estimates and assumptions are based upon management’s best estimates and judgements. Actual results could differ from those estimates.

Revenue Recognition

Crude oil, natural gas and natural gas liquids revenues from our mineral and royalty interests are recognized when control transfers at the wellhead. These revenues are reported net of post-production expenses, such as gathering, transportation, and processing costs.

Concentration

The Source properties are subject to risk resulting from the concentration of its mineral and royalty interests. For the six months ended June 30, 2021, two operators each accounted for more than 10% of royalty interest revenue.

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SOURCE ACQUISITION

NOTES TO THE STATEMENT OF REVENUES AND DIRECT EXPENSES (UNAUDITED)

Although the Source properties are exposed to a concentration of credit risk, management does not believe the loss of any single operator would materially impact the Source properties’ operating results as crude oil, natural gas and natural gas liquids are fungible products with well-established markets and numerous purchasers. If multiple operators were to cease operations at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving certain operators have stipulated that royalty owners must still be paid for oil, natural gas and natural gas liquids extracted from their mineral acreage during the bankruptcy process. In light of this, Source and DPM do not expect the entry of one of the Source properties’ operators into bankruptcy to materially affect the Statement of Revenues and Direct Expenses.

Direct Expenses

Direct expenses for oil, natural gas and natural gas liquids mineral and royalty interests include severance taxes, ad valorem taxes, and any other taxes or expenses not associated with or attributable to post-production expenses. As mineral and royalty interests, the Source properties are not subject to any lease operating or production expenses.

Note 3—COMMITMENTS AND CONTINGENCIES

From time to time, the Source properties may become subject to potential claims and litigation in the normal course of business. While the ultimate impact on any proceedings cannot be predicted with certainty, Source’s management is currently not aware of any legal or other contingencies that would have a material effect on the Statement of Revenues and Direct Expenses for the six months ended June 30, 2021.

Note 4—EXCLUDED EXPENSES

Indirect expenses such as general and administrative, income tax, interest expenses and other indirect expenses have not been allocated to the Source Acquisition, and as such, have been excluded from the accompanying financial statement. Any allocation of such indirect expenses may not be indicative of costs which would have been incurred by DPM on a stand-alone basis. Depletion and impairment expenses have also been excluded from the accompanying Statement of Revenues and Direct Expenses as such amounts would not be indicative of the depletion and impairment calculated for DPM on the Source Acquisition on a stand-alone basis.

Note 5—SUBSEQUENT EVENTS

The Company has evaluated subsequent events through October 6, 2021, the date the accompanying Unaudited Statement of Revenues and Direct Expenses was available to be issued. There were no material subsequent events that required recognition or additional disclosure in the accompanying Unaudited Statement of Revenues and Direct Operating Expenses.

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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 document, which are commonly used in the crude oil and natural gas industry:

100% NRAs. One NRA multiplied by 12.5% as a result of adjustment to a 100% royalty.

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. For a complete definition of analogous reservoir, refer to the SEC’s Regulation S-X, Rule 4-10(a)(2).

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.

Bbl/d. Bbl per day.

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 crude oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

BOE/d. BOE per day.

British thermal unit or Btu. The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. Installation of permanent equipment for production of crude oil, natural gas or NGLs, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

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.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing crude oil, natural gas and NGLs. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

Development project. 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 a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of crude oil or natural gas from an established spot market price to reflect differences in the quality and/or location of crude oil or natural gas.

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Dry hole or dry well. 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 that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

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. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

Formation. A layer of rock that has distinct characteristics that differs from nearby rock.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a mineral or royalty 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 crude oil, natural gas or NGLs.

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.

MBbl. One thousand barrels of crude oil, condensate or NGLs.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

Net mineral acres. The number of gross acres in which we have a mineral interest.

Net production. Production on our properties calculated net to our royalty interests.

Net revenue interest. The net royalty, overriding royalty, production payment and net profits interests in a particular tract or well.

Net royalty acres or NRAs. Mineral ownership standardized to a 12.5%, or 1/8th, royalty interest.

Net wells. The number of wells net to our mineral and royalty interests. A net well is deemed to exist when the sum of fractional mineral and royalty interest in gross wells equals one. The number of net wells is the sum of the fractional mineral and royalty interests in gross wells.

NGLs. Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

Nonparticipating Royalty Interests or NPRIs. A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.

Operator. The individual or company responsible for the development and/or production of a crude oil or natural gas well or lease.

Overriding Royalty Interests or ORRIs. Royalty interests that burden working interests and represent the right to receive a fixed percentage of production or revenue from production (free of operating costs) from a lease. Overriding royalty interests remain in effect until the associated leases expire.

Play. A geographic area with hydrocarbon potential.

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Pooling. An E&P operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating expenses 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.

Prospect. A specific geographic area that, 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 area. The part of a property to which proved reserves have been specifically attributed.

Proved developed reserves. Reserves that can be expected to be recovered through (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (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.

Proved reserves. Those quantities of crude oil, natural gas and NGLs that, 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 E&P operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

Proved undeveloped reserves or PUDs. 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 proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Realized price. The cash market price less all expected quality, transportation and demand adjustments.

Reasonable certainty. A high degree of confidence that quantities will be recovered. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

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.

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Reserves. Estimated remaining quantities of crude oil and natural 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 crude oil and natural gas or related substances to market and all permits and financing required to implement the project. 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).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resources. Quantities of crude oil, natural gas and NGLs 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.

Royalty. An interest in a crude 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 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.

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 crude oil, natural gas and NGL properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

Success rate. The percentage of wells drilled that produce hydrocarbons in commercial quantities.

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 crude oil, natural gas or NGLs 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.

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Working interest. The right granted to the lessee of a property to develop, produce and own crude oil, natural gas, NGLs or other minerals. The working interest owners bear the exploration, development and operating expenses on either a cash, penalty or carried basis.

Workover. Operations on a producing well to restore or increase production.

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10,000,000 Shares

Desert Peak Minerals Inc.

Class A Common Stock

Prospectus

                , 2021

Barclays

Credit Suisse

UBS Investment Bank

Capital One Securities

Citigroup

Evercore ISI

RBC Capital Markets

Maxim Group LLC

Stephens Inc.

Tudor, Pickering, Holt & Co.

Tuohy Brothers

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts and commissions) payable by us in connection with the registration of the shares of Class A common stock offered hereby. With the exception of the SEC registration fee, FINRA filing fee and NYSE listing fee, the amounts set forth below are estimates.

SEC registration fee	$	24,519
FINRA filing fee		40,175
NYSE listing fee		90,000
Accounting fees and expenses		1,250,000
Legal fees and expenses		1,500,000
Printing and engraving expenses		300,000
Transfer agent and registrar fees		25,000
Miscellaneous		770,306
Total	$	4,000,000

Item 14. Indemnification of Directors and Officers

Section 145 of the DGCL provides that a corporation may indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation by reason of the fact that he or she is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise), against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him or her in connection with such action, suit or proceeding if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful. A similar standard is applicable in the case of derivative actions (i.e., actions by or in the right of the corporation), except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation.

Our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that limit the liability of our directors and officers for monetary damages to the fullest extent permitted by the DGCL. Consequently, our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except liability:

• for any breach of the director’s duty of loyalty to our company or our stockholders;

• for any act or omission not in good faith or that involve intentional misconduct or knowing violation of law;

• under Section 174 of the DGCL regarding unlawful dividends and stock purchases; or

• for any transaction form which the director derived an improper personal benefit.

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Any amendment to, or repeal of, these provisions will not eliminate or reduce the effect of these provisions in respect of any act, omission or claim that occurred or arose prior to that amendment or repeal. If the DGCL is amended to provide for further limitations on the personal liability of directors or officers of corporations, then the personal liability of our directors and officers will be further limited to the fullest extent permitted by the DGCL.

In addition, we intend to enter into indemnification agreements with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements will require us, among other things, to indemnify our directors against certain liabilities that may arise by reason of their status or service as directors and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities under arising under the Securities Act and the Exchange Act, that may be incurred by them in their capacity as such.

The proposed form of Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities

In connection with our incorporation in April 2019, under the laws of the State of Delaware, we issued 1,000 shares of our Class A common stock to Opco for an aggregate purchase price of $10.00. These securities were offered and sold by us in reliance upon the exemption from the registration requirements provided by Section 4(a)(2) of the Securities Act. These shares will be redeemed for nominal value in connection with our reorganization.

Item 16. Exhibits and Financial Statement Schedules

(a) Exhibits.

Exhibit Number	Description
1.1*	Form of Underwriting Agreement
3.1*	Certificate of Incorporation of Desert Peak Minerals Inc.
3.2*	Certificate of Amendment of Certificate of Incorporation of Desert Peak Minerals Inc.
3.3*	Form of Amended and Restated Certificate of Incorporation of Desert Peak Minerals Inc.
3.4*	Bylaws of Desert Peak Minerals Inc.
3.5*	Form of Amended and Restated Bylaws of Desert Peak Minerals Inc.
4.1*	Form of Class A Common Stock Certificate
4.2*	Form of Registration Rights Agreement
5.1	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered

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Exhibit Number	Description
10.1*	Amended and Restated Credit Agreement, dated as of October 8, 2021, among KMF Land, LLC, as Borrower, DPM HoldCo, LLC, as Parent, Bank of America, N.A., as Administrative Agent, Issuing Bank and Syndication Agent, Barclays Bank PLC and Capital One, National Association, as Co-Documentation Agents, and the lenders party thereto
10.2*	Form of Master Reorganization Agreement
10.3†*	Form of Desert Peak Minerals Inc. 2021 Long Term Incentive Plan
10.4*	Form of Desert Peak LLC Amended and Restated Limited Liability Company Agreement
10.5*	Form of Director Designation Agreement
10.6*	Form of Indemnification Agreement between Desert Peak Minerals Inc. and each of the directors and officers thereof
10.7*	Form of Services Agreement
16.1*	Letter from Deloitte & Touche LLP to the Securities and Exchange Commission
21.1*	Subsidiaries of Desert Peak Minerals Inc.
23.1	Consent of KPMG LLP related to Desert Peak Minerals Inc.
23.2	Consent of KPMG LLP related to Kimmeridge Mineral Fund, LP
23.3	Consent of Deloitte & Touche LLP related to Rock Ridge Royalty Company LLC
23.4	Consent of KPMG LLP related to Source Acquisition
23.5	Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
23.6	Consent of Cawley, Gillespie & Associates, Inc. (Kimmeridge Mineral Fund, LP)
23.7	Consent of Netherland, Sewell & Associates, Inc. (Rock Ridge)
23.8*	Consent of Director Nominee (Clark)
23.9*	Consent of Director Nominee (Dell)
23.10*	Consent of Director Nominee (Gould)
23.11*	Consent of Director Nominee (Nyquist)
23.12*	Consent of Director Nominee (Belz)
23.13*	Consent of Director Nominee (Li)
23.14*	Consent of Director Nominee (Conoscenti)
24.1*	Power of Attorney (included on the signature page of this Registration Statement)
99.1*	Report of Cawley, Gillespie  & Associates, Inc. as of December 31, 2019 (Kimmeridge Mineral Fund, LP)
99.2*	Report of Cawley, Gillespie & Associates, Inc. as of December  31, 2020 (Kimmeridge Mineral Fund, LP)
99.3*	Report of Netherland, Sewell & Associates, Inc. as of December 31, 2019 (Rock Ridge)
99.4*	Report of Netherland, Sewell & Associates, Inc. as of December 31, 2020 (Rock Ridge)

* Previously filed.

† Compensatory plan, contract or arrangement.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, Colorado, on October 28, 2021.

Desert Peak Minerals Inc.
By:	/s/ Christopher L. Conoscenti
	Name: Christopher L. Conoscenti
	Title: Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities on October 28, 2021.

Signature	Title
/s/ Christopher L. Conoscenti Christopher L. Conoscenti	Chief Executive Officer (Principal Executive Officer)
* Carrie L. Osicka	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
*	Director
Noam Lockshin

*By:	/s/ Christopher L. Conoscenti
	Christopher L. Conoscenti Attorney-in-fact

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