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

LOGO

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.

LOGO

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

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.

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.

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.

LOGO

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

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

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.

LOGO

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

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.

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
Productive Horizon	Developed		Undeveloped		Total		Number of DSUs		Total Gross Wells/DSU (one mile wide DSU basis(1)		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)		Net Developed Wells		Net Undeveloped Wells		Total Net Wells
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		9,692		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.

LOGO

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

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:

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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.

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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.

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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:

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sufficient visibility to production growth;

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attractive economics;

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de-risked geology supported by offsetting production;

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top-tier E&P operators; and

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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.

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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:

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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:

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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;

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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;

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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;

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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;

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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

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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:

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

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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;

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

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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:

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

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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;

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

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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.”

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):

LOGO

(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”);

•

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.

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.

•

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.

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

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

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.”

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

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.

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.

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			Six Month Ended June 30, 2021			Year Ended December 31, 2020
							(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		As of June 30, 2021
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.

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		Six Months Ended June 30, 2021		Year Ended December 31, 2020
						(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

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,

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.

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.

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.

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

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:

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

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

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prevailing commodity prices;

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

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the availability of storage for hydrocarbons,

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

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approval of other participants in drilling wells;

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

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the selection of technology;

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

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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

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:

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recoverable reserves;

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

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development plans;

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

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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

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.

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:

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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;

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

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

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

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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;

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

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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.

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.

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.

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.

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

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.

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

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 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

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

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

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:

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

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

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

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

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

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the level of U.S. domestic production;

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

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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;

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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;

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

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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;

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

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domestic and foreign governmental regulations and taxes;

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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;

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

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the price and availability of alternative fuels; and

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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.

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,

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 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 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

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.

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:

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unusual or unexpected geological formations;

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loss of drilling fluid circulation;

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title problems;

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facility or equipment malfunctions;

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unexpected operational events;

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shortages or delivery delays of equipment and services;

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compliance with environmental and other governmental requirements; and

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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.

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.

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

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

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:

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

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the establishment of maximum rates of production from wells;

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the spacing of wells;

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the plugging and abandonment of wells; and

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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.

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

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.

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

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

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

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

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:

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incur or guarantee additional debt;

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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;

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enter into certain swap arrangements;

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make certain investments and acquisitions;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company;

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transfer, sell or otherwise dispose of assets;

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enter into certain other lines of business; and

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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.

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:

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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;

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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;

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our access to the capital markets may be limited;

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our borrowing costs may increase;

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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

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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.

Risks Related to this Offering and 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.

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

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.

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.”

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:

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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

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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

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;

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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;

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

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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;

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

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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;

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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.

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.

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.

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. 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

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

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

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.

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:

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our ability to execute on our business strategies;

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the effect of change in commodity prices;

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the level of production on our properties;

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

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

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

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the availability of pipeline capacity and transportation facilities;

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the effect of existing and future laws and regulatory actions;

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

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

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

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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;

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competition from others in the energy industry;

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

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

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

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

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

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our ability to identify and complete acquisitions;

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title defects in the properties in which we invest;

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the cost of inflation;

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technological advances;

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

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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.

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.

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:

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general economic and business conditions;

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our financial condition and operating results;

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

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our capital requirements;

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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.

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.

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.

(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.

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			Average Price Per Share
						(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.

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.

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			Six Month Ended June 30, 2021			Year Ended December 31, 2020
							(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		As of June 30, 2021
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.

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.

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

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

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

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.

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.

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

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.

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	)


	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%

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.

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


	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.

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.

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

(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.

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.

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

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.

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	%

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

$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

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,

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

$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

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.

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.

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.

100

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.

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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.


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 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

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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LOGO

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.

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		Total Gross Wells/DSU (one mile wide DSU basis)(1)		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)

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	Gross Wells (5,000 foot lateral length basis)						Net Developed Wells		Net Undeveloped Wells		Total Net Wells
Productive Horizon	Developed		Undeveloped		Total(1)		Net Developed Wells		Net Undeveloped Wells		Total Net Wells
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.


	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 E&P Operators

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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.

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Financial Philosophy

ESG Philosophy

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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.

Business Strategies

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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.

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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.

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sufficient visibility to production growth;

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attractive economics;

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de-risked geology supported by offsetting production;

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top-tier E&P operators; and

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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.

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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:

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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.

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Desert Peak Minerals Inc. S-1/A