Exhibit 99.8

INFORMATION ABOUT DESERT PEAK

Unless otherwise indicated, the historical financial and operating information presented in this “Information About Desert Peak” is that of Kimmeridge Mineral Fund, LP, Desert Peak’s predecessor for financial reporting purposes, and its consolidated subsidiaries (the “predecessor,” “KMF” or the “Partnership”), which includes the assets acquired in the Chambers Acquisition (as defined herein), the Rock Ridge Acquisition (as defined herein), the Source Acquisition (as defined herein), and the Recent Acquisitions (as defined herein) as of December 31, 2021. Unless otherwise indicated, references in this “Information About Desert Peak” to 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 and (iii) the Source Acquisition, in each case as if the transaction occurred on January 1, 2021. Unless otherwise indicated, references in this “Information About Desert Peak” to 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, 2021.

Overview

Desert Peak acquires, owns and manages 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 its base of cash flow generating assets. Desert Peak’s assets are exclusively focused in the Permian Basin. Desert Peak benefits from cash flow growth through continued development of its mineral and royalty interests, free of capital costs and lease operating expenses. As of December 31, 2021, Desert Peak owned mineral and royalty interests representing over 105,000 NRAs when adjusted to a 1/8 royalty. For the year ended December 31, 2021, on a pro forma basis the average net daily production associated with Desert Peak’s mineral and royalty interests was 9,149 Boe/d barrels of oil equivalent per day (“BOE/d”) consisting of 4,816 barrels per day (“Bbls/d”) of oil, 15,966 million cubic feet per day (“Mcf/d”) of natural gas and 1,673 Bbls/d of NGLs. Since Desert Peak’s formation in November 2016, Desert Peak has accumulated its acreage position by making 180 acquisitions. Desert Peak expects to continue to grow its acreage position by making acquisitions that meet its investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

As of December 31, 2021, approximately 95% of Desert Peak’s NRAs were located in West Texas where there are no federal lands, which means that operators on Desert Peak’s acreage are not subject to leasing, permitting, or easement authority from the federal government. The remaining 5% of Desert Peak’s NRAs are located in southeastern New Mexico. Desert Peak believes 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.

Desert Peak’s mineral and royalty interests entitle it to receive a fixed percentage of the revenue from crude oil, natural gas and NGLs produced from the acreage underlying its interests. Unlike owners of working interests in oil and gas properties, Desert Peak is 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, Desert Peak incurs only its proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs. Accordingly, Desert Peak’s business generates strong margins, requires very low overhead and is highly scalable. For the year ended December 31, 2021, on a pro forma basis Desert Peak’s production and ad valorem taxes were approximately $2.61 per barrel of oil equivalent (“BOE”), relative to an average realized price of $45.74 per BOE. As a result, Desert Peak’s 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 year ended December 31, 2021, Desert Peak generated net income of $62.7 million and Adjusted

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EBITDA of $133.4 million. Desert Peak does not anticipate engaging in any activities, other than acquisitions, that will incur capital costs.

Desert Peak has built its acreage position through the consummation of 180 acquisitions since November 2016. In addition to completing numerous small transactions, Desert Peak have completed a total of 14 transactions larger than 1,500 NRAs that account for approximately 85% of its 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 25,000 NRAs. During the six years ended December 31, 2021, Desert Peak evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 167 acquisitions from landowners and other mineral interest owners, representing 47,837 NRAs, to its asset base. During 2020, Desert Peak’s 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, Desert Peak experienced a meaningful difference in sellers’ pricing expectations and the prices Desert Peak was willing to offer for assets. Desert Peak 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, Desert Peak utilized its significant free cash flow during 2020 to reduce its 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, Desert Peak saw a meaningful increase in its acquisition activity as evidenced by the approximately 26,000 NRAs it acquired in the second quarter and the approximately 28,000 NRAs it acquired in the third quarter. The following table summarizes Desert Peak’s completed acquisitions from November 2016 through December 31, 2021.

Year	Number of Acquisitions		Total NRAs Acquired
2016		2		4,060
2017		50		18,037
2018		48		14,698
2019		67		11,042
2020		4		1,614
2021		9		55,908
Total		180		105,359

Desert Peak is 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. Desert Peak intends to capitalize on its management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in the Permian Basin designed to increase its cash flows per share.

Desert Peak was 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 Desert Peak’s management team founded and managed two Delaware Basin-focused E&P companies, Arris Petroleum (as defined below) and 299 Resources (as defined below), and successfully monetized those companies in 2016 by selling Kimmeridge’s ownership interests in those companies to PDC Energy (as defined below). Additionally, in October 2020, another private equity fund managed by Kimmeridge acquired a 2.0% (on an 8/8ths basis) ORRI in all of Callon Petroleum Company’s (“Callon”) operated assets in the Delaware, Midland and Eagle Ford Basins, which proportionately reduced Callon’s net revenue interest (“Chambers ORRI”). Subsequent to the transaction, Desert Peak’s management team managed the acquired ORRI. Desert Peak has leveraged Kimmeridge’s extensive Permian Basin experience and relationships with mineral and royalty owners in the region as Desert Peak has grown its acreage position, and Desert Peak expects

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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 ESG matters, and Desert Peak’s 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 “—ESG Philosophy.”

Desert Peak’s Key Producing Region

As of December 31, 2021, all of Desert Peak’s properties were located exclusively within the Permian Basin. As of December 31, 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 95% of Desert Peak’s NRAs were located as of December 31, 2021, and therefore the acreage underlying Desert Peak’s Texas NRAs is not subject to federal government involvement in or regulation of leasing, permitting or easements. According to the USGS, the Delaware Basin contains the largest recoverable reserves among all unconventional basins in the United States.

Desert Peak believes 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, Desert Peak believes 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. Desert Peak believes these factors will continue to support development activity in the region and in the areas where it holds mineral and royalty interests, leading to increasing cash flows free of lease operating expenses.

Desert Peak believes 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. Desert Peak believes these factors will continue to support development activity in the region and in the areas where it holds mineral and royalty interests, leading to increasing cash flows free of lease operating expenses. Desert Peak expects Midland Basin drilling efficiency to continue to improve as drilling days further compress and lateral lengths keep expanding.

Desert Peak’s Mineral and Royalty Interests

Desert Peak’s interests consist of mineral and royalty interests. Mineral interests, which represent approximately 82% of Desert Peak’s NRAs as of December 31, 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 Desert Peak leases those rights, usually for a one- to three-year term, Desert Peak typically receives an upfront cash payment, known as a lease bonus, and it retains a mineral royalty, which entitles it 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 Desert Peak to lease the exploration and development rights to another party

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and receive another lease bonus. As of December 31, 2021, other types of royalty interests, non-participating royalty interests (“NPRIs”) and ORRIs, comprised approximately 5% and 13%, respectively, of Desert Peak’s NRAs. Also, as of December 31, 2021, approximately 86% of Desert Peak’s total NRAs, derived from mineral interests only, were leased to E&P operators and other working interest owners. As of December 31, 2021, approximately 95% of Desert Peak’s 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. Desert Peak refers its mineral interests, NPRIs and ORRIs collectively as Desert Peak’s “mineral and royalty interests.” Desert Peak generates a substantial majority of its revenues and cash flows from its mineral and royalty interests when crude oil, natural gas and NGLs are produced from its acreage and sold by the applicable E&P operators and other working interest owners. Desert Peak’s predecessor’s pro forma revenue generated from these mineral and royalty interests was approximately $117.5 million for the year ended December 31, 2020 and $223.6 million for the year ended on December 31, 2021. Approximately 88% of 2020 and 83% of 2021 revenue was derived from the sale of oil and NGLs on a pro forma basis.

Currently, Desert Peak’s mineral and royalty interests reside entirely in the Permian Basin, which Desert Peak believes is one of the premier unconventional crude oil, natural gas and NGL producing regions in the United States. As of December 31, 2021, Desert Peak’s interests covered 56,595 net mineral acres, approximately 85% of which have been leased to E&P operators and other working interest owners with Desert Peak retaining an average 19.3% royalty. If Desert Peak were to lease its remaining unleased net mineral acres this would change to a 19.1% average royalty. Typically, within the mineral and royalty industry, owners standardize ownership of NRAs to a 12.5%, or a 1/8th, royalty interest, representing the number of equivalent acres earning a 12.5% royalty, which is referred to as an NRA. When adjusted to a 1/8th royalty, Desert Peak’s mineral interests represent 86,260 NRAs, and its NPRIs and ORRIs represent an additional 19,099 NRAs, totaling 105,359 NRAs in the aggregate. Desert Peak’s drilling spacing units (“DSUs”), in the aggregate, consist of a total of 1.38 million gross acres, which Desert Peak refers to as Desert Peak’s “gross DSU acreage.” Desert Peak expects to have an ownership interest in all wells that will be drilled within its gross DSU acreage in the future. The following table summarizes Desert Peak’s mineral and royalty interest position and the conversion of its interests from net mineral acres to NRAs and 100% royalty acres as of December 31, 2021.

Net Mineral Acres	Average Royalty	NRAs (Mineral Interests)(1)(2)	NRAs (NPRIs)	NRAs (ORRIs)	Total NRAs	100% NRAs(3)	Gross DSU Acres	Implied Average Net Revenue Interest per Well(4)
56,595	19.05%	86,260	5,325	13,774	105,359	13,170	1,379,873	1.0%

(1) Desert Peak’s mineral interests are based on its average royalty interests across its 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 56,595 net mineral acres multiplied by an average royalty of 19.05% and then divided by 12.5%).

(2) All unleased mineral interests are assumed at a 25% royalty interest or 12.5% royalty interest on Relinquishment Act land.

(3) Calculated as 105,359 NRAs multiplied by 12.5%.

(4) Calculated as 13,170, 100% royalty acres divided by 1.38 MM gross DSU acres.

As of December 31, 2021, Desert Peak has interests in 659 (4.644 net) horizontal wells on which drilling has commenced but are not yet producing in paying quantities, which Desert Peak refers to as spud wells, and 533 (3.394 net) wells for which permits have been issued to the operators, but on which drilling has not yet commenced, which Desert Peak refers to as permitted wells. For the year ended December 31, 2021, Desert Peak’s permitted wells converted into spud wells within an average of 5.9 months and its spud wells converted into producing wells within an average of 7.6 months. The total time from permit to first production on Desert Peak’s producing wells was 13.5 months on average as compared to a total time of 14.6 months for the Permian Basin on average. Desert Peak’s Reserves and Production

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As of December 31, 2021, the estimated proved crude oil, natural gas and NGLs reserves attributable to Desert Peak’s interests in its underlying acreage were 24,592 thousands of BOE (“MBOE”) (68% liquids, consisting of 48% crude oil and 20% NGLs), based on a reserve report prepared by CG&A. Of these reserves, approximately 83% were classified as proved developed producing (“PDP”) reserves, 1% were classified as proved developed non-producing (“PDNP”) reserves and 17% 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, 2021. 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.

Desert Peak believes its production and discretionary cash flows will grow significantly as E&P operators drill the substantial undeveloped inventory of horizontal drilling locations located on its gross DSU acreage. As of December 31, 2021, Desert Peak had production from 4,459 (36.887 net) horizontal wells, and it has identified 16,298 (129.667) undeveloped horizontal drilling locations based on its assessment of current geological, engineering and land data, which is equivalent to 12.489 gross undeveloped horizontal drilling locations per one mile-wide DSU. Furthermore, Desert Peak believes there is potential for additional drilling activity through drilling efforts by its current E&P operators and through development of additional horizontal formations, including the Woodford/Barnett formations.

Desert Peak’s 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 December 31, 2021, Desert Peak’s position has an average of 3.47 gross producing horizontal wells per mile wide DSU, compared to its spacing assumption of 15.9 gross wells per DSU. Furthermore, Desert Peak expects to see increases in its production, revenue and discretionary cash flows from the development of

659 spud wells and 533 permitted wells across its interests as of December 31, 2021, compared to 546 gross wells completed on its acreage in the year ended December 31, 2021. If all of Desert Peak’s spud wells were completed and all of its permitted wells were drilled and completed, Desert Peak expects that its gross producing horizontal wells per mile wide DSU would increase from 3.47 to 4.38. Desert Peak believes its current interests provide the potential for significant long-term organic revenue growth as E&P operators develop its acreage and utilize advancements in drilling and completion techniques to increase crude oil, natural gas and NGL production.

Desert Peak’s E&P Operators

In addition to utilizing technical analysis to identify attractive mineral and royalty interests in the prolific Permian Basin, Desert Peak’s management team strives to acquire mineral and royalty interests in properties with top-tier E&P operators. Desert Peak seeks E&P operators that are well-capitalized, have a strong operational track record, and that Desert Peak believes will continue to increase production through the application of the latest drilling and completion techniques across its mineral and royalty interests. Approximately 58 horizontal E&P operators are currently producing oil and gas from Desert Peak’s acreage. The chart below summarizes the E&P operators of Desert Peak’s acreage based on revenue received in the year ended December 31, 2021.

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ESG Philosophy

Since Desert Peak’s inception, Kimmeridge and Desert Peak have been committed to all three elements of ESG and are in the process of developing appropriate ESG policies, including strong governance policies. Desert Peak’s fully staffed, experienced team will be dedicated solely to its business of pursuing and consummating acquisitions. The Desert Peak board of directors and employee base are reflective of a culture that values diversity, with approximately one-half of Desert Peak’s employees being women or minorities. Desert Peak targets minerals under operators with strong environmental track records. Desert Peak prioritizes responsible environmental practices and it endeavors to prohibit flaring by the operator in each lease. As Desert Peak continues to gain additional scale, it intends to further pressure operators to eliminate flaring and venting of methane.

Recent Acquisitions

Chambers Acquisition

On June 7, 2021, Desert Peak 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) ORRI, 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, Desert Peak completed the acquisition of approximately 18,500 NRAs in the Delaware Basin from Rock Ridge (the “Rock Ridge Acquisition”), a limited liability company formed by investment funds affiliated with Blackstone Inc. (“Blackstone”).

Source Acquisition

On August 31, 2021, Desert Peak completed the acquisition of approximately 25,000 NRAs (the “Source Assets”) in the Midland and Delaware Basins from the Source Stockholders ( the “Source Acquisition”), limited partnerships backed by investment funds affiliated with Oaktree Capital Management, L.P. (“Oaktree”).

The Source Assets consist of approximately 21,500 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.

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Other Acquisitions

Subsequent to December 31, 2020, in addition to the Chambers Acquisition, the Rock Ridge Acquisition and the Source Acquisition, Desert Peak has (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 and (ii) on July 26, 2021, acquired approximately 3,500 additional NRAs from a private third-party seller (the “Recent Acquisitions”).

Business Strategies

Desert Peak’s primary business objective is to generate discretionary cash flow 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. Desert Peak intends to accomplish this objective by executing the following strategies:

• Generate strong discretionary cash flow supported by disciplined acquisition strategy. As mineral and royalty interest owners, Desert Peak benefits from the continued organic development of its acreage in the Permian Basin and is able to convert a high percentage of its revenue to discretionary cash flow, which it defines as its Adjusted EBITDA less cash interest expense and cash taxes. Desert Peak does not incur operating costs for the production of crude oil and natural gas or capital costs for the drilling and completion of wells on its acreage. Desert Peak’s only cash operating costs related to its mineral and royalty business consist of certain taxes, gathering, processing and transportation costs, and general and administrative expenses. For the year ended December 31, 2021, on a pro forma basis Desert Peak’s production and ad valorem taxes were approximately $2.61 per BOE, relative to an average realized price of $45.74 per BOE. Desert Peak believes that its 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. Desert Peak expects to continue to grow its acreage position by making acquisitions that meet its investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

• Focus primarily on the Permian Basin. All of Desert Peak’s mineral and royalty interests are currently located in the Permian Basin, one of the most prolific oil and gas basins in the United States. Desert Peak believes 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.

• Leverage expertise and relationships to continue acquiring Permian Basin mineral and royalty interests associated with top-tier E&P operators. Desert Peak has 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, Desert Peak has completed more than 180 acquisitions, demonstrating its ability to add scale quickly and effectively. Desert Peak’s management team intends to continue to apply this experience in a disciplined manner when identifying and acquiring mineral and royalty interests. Desert Peak believes 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 its target investment criteria. With sellers seeking to monetize their investments but lacking the scale to do so in the public markets, Desert Peak intends to continue to acquire mineral and royalty interests that have substantial resource potential in the Permian Basin, an area that it expects 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. Desert Peak expects to focus on acquisitions that complement its 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

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conversion rates of permits issued to wells completed on large contiguous acreage positions. Furthermore, Desert Peak seeks to maximize its return on capital by targeting acquisitions that meet the following criteria:

• sufficient visibility to production growth;

• attractive economics;

• de-risked geology supported by offsetting production;

• top-tier E&P operators; and

• a geographic footprint that Desert Peak believes is complementary to its diverse portfolio of Permian Basin assets and maximizes its potential for upside reserve and production growth.

• Maintain conservative and flexible capital structure to support Desert Peak’s business and facilitate long-term operations. Desert Peak is committed to maintaining a conservative capital structure that will afford it the financial flexibility to execute its business strategies on an ongoing basis. Desert Peak believes that internally generated cash flows from operations, available borrowing capacity under its revolving credit facility, and access to capital markets will provide it with sufficient liquidity and financial flexibility to continue to acquire attractive mineral and royalty interests that will position it to grow its cash flows and return capital to stockholders. Desert Peak intends 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

Desert Peak believes that the following competitive strengths will allow it to successfully execute its business strategies and achieve its primary business objective:

• Differentiated energy investment opportunity. As opposed to traditional E&P operators who require significant capital, Desert Peak’s 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, Desert Peak is not responsible for environmental or other operational liabilities in connection with oil and gas production associated with its interests, and its only operating cash costs related to its mineral and royalty business consist of certain production taxes, gathering, processing and transportation costs and general and administrative expenses. For example, for the year ended December 31, 2021, on a pro forma basis Desert Peak’s production and ad valorem taxes were approximately $2.61 per BOE, relative to an average realized price of $45.74 per BOE. Furthermore, Desert Peak has significantly reduced its indebtedness during the COVID-19 pandemic, while many other energy companies struggled with indebtedness and leverage issues during 2020. Desert Peak believe its low capital requirements and financial discipline will result in an ability to distribute a meaningful amount of cash flow to stockholders.

• Permian Basin focused public minerals company positioned as a preferred buyer in the basin. Desert Peak believes that its focus on the Permian Basin will position it as a preferred buyer of Permian Basin mineral and royalty interests. After giving effect to the Merger Transactions, over 75% of the Post-Combination Company’s NRAs will be located in the Permian Basin, one of the most prolific oil plays in the United States, and the majority of its current properties are well positioned in areas with proven results from multiple stacked productive zones. Desert Peak’s properties in the Permian Basin are high-quality, high-margin, and oil- and liquids-weighted, and it believes they will be viewed favorably by sellers interested in receiving equity consideration in exchange for their assets as compared to equity consideration diluted by lower quality assets located in less prolific basins.

• Favorable and stable operating environment in the Permian Basin. With over 400,000 wells drilled in the Permian Basin since 1900, the region features a reliable and predictable geological and regulatory environment, according to Enverus. Desert Peak believes that the impact of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of

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development and exploration activities as compared to other, emerging hydrocarbon basins. As of December 31, 2021, approximately 95% of Desert Peak’s acreage was located in Texas and does not require federal approval to permit and drill oil and gas wells or to grant easements to allow E&P operators to deliver their production to market.

• Experienced management team with an extensive track record of minerals acquisitions. The members of Desert Peak’s management team have grown its acreage position through the consummation of 180 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 25,000 NRAs. Notably, Desert Peak has acquired nearly 85% of Desert Peak’s NRAs through 14 large acquisitions, using both cash and equity consideration to suit the needs of sellers. Desert Peak’s 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. Desert Peak plans to continue to evaluate and pursue acquisitions of all sizes. Desert Peak expects to benefit from the industry relationships fostered by its management team’s decades of experience in the oil and natural gas industry with a focus on the Permian Basin, in addition to leveraging its relationship with Kimmeridge.

• Development potential of the properties underlying Desert Peak’s Permian Basin mineral and royalty interests. Desert Peak’s assets consist of mineral and royalty interests located in the Permian Basin, and Desert Peak expects production from its mineral and royalty interests to increase as E&P operators continue to actively drill and develop its acreage. Relative to other unconventional basins in the continental United States, Desert Peak believes 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 Desert Peak to achieve higher realized cash flows per net mineral acre. Desert Peak targets acquisitions of properties that are relatively undeveloped in the core of the Delaware Basin, and it believes the organic development of its acreage will result in substantial production growth regardless of acquisition activity. From January 1, 2016 to September 30, 2021, production attributable to Desert Peak’s properties increased at a CAGR of 37% assuming its NRAs as of December 31, 2020 were owned on January 1, 2016, as compared to a CAGR of 23% for Permian Basin production growth generally and a CAGR of 8% for total U.S. onshore production growth for the same period.

• Diverse group of blue-chip E&P operators on Desert Peak’s mineral and royalty interests driving production growth. Desert Peak’s mineral and royalty interests consist of properties operated by established E&P companies, such as Occidental Petroleum Corporation, BP plc, Coterra Energy Inc., Conoco Phillips and Chevron Corporation. Desert Peak’s blue-chip E&P operators provide a diversified source of revenues, as no single E&P operator provided greater than 12% of Desert Peak’s total revenues for the year ended December 31, 2021.

Crude Oil, Natural Gas and NGLs Data

The information included in “—Crude Oil, Natural Gas and NGLs Data” and “—Crude Oil, Natural Gas and NGL Production Prices and Costs” presents Desert Peak’s reserves and operating data as of and for the years ended December 31, 2021 and 2020 on an actual basis, without giving pro forma effect to transactions completed after such dates. As such, the reserves and operating data as of and for the year ended December 31, 2020 presented in these sections does not give effect to the Chambers Acquisition, the Rock Ridge Acquisition, the Source Acquisition or the Recent Acquisitions. The assets acquired in the Chambers Acquisition, the Rock Ridge Acquisition, the Source Acquisition and the Recent Acquisitions are included in Desert Peak’s reserves and operating data as of December 31, 2021, and operating data attributable to the assets acquired in such acquisitions is included since the date of each respective acquisition for the year ended December 31, 2021 on an actual basis.

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Preparation of Reserve Estimates

Desert Peak’s reserve estimates as of December 31, 2021 and 2020 are based on evaluations prepared by the independent petroleum engineering firm of CG&A in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Desert Peak selected CG&A as its independent reserve engineer for its historical experience and geographic expertise in engineering similar resources.

In accordance with rules and regulations of the SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of Desert Peak’s proved reserves were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable crude oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods, (ii) material balance-based methods; (iii) volumetric-based methods and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with

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very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting PDNP and PUDs for Desert Peak’s properties due to the abundance of analog data.

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

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

Internal Controls

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

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

CG&A is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. The lead evaluator that prepared Desert Peak’s reserve report was Zane Meekins at CG&A. Mr. Meekins has been a practicing consulting petroleum engineer at CG&A since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 34 years of practical experience in petroleum engineering, with over 32 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of

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Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Summary of Reserves

The following table presents Desert Peak’s estimated proved reserves as of December 31, 2021 and 2020. The reserve estimates presented in the table below are based on reports prepared by CG&A, Desert Peak’s independent petroleum engineers, which reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting:

	December 31, 2021(1)		December 31, 2020(2)
Estimated proved developed reserves:
Crude oil (MBbls)		9,285		3,731
Natural gas (MMcf)		40,747		19,505
NGLs (MBbls)		4,417		2,352
Total (MBOE)		20,493		9,334
Estimated proved undeveloped reserves:
Crude oil (MBbls)		2,559		1,344
Natural gas (MMcf)		5,596		3,897
NGLs (MBbls)		607		473
Total (MBOE)		4,098		2,467
Estimated proved reserves:
Crude oil (MBbls)		11,844		5,075
Natural gas (MMcf)		46,343		23,402
NGLs (MBbls)		5,023		2,825
Total (MBOE)		24,592		11,800

(1) Desert Peak’s estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For crude oil and NGL volumes, the average WTI posted price of $66.56 per Bbl as of December 31, 2021 was adjusted for quality, transportation fees and a regional price differential. NGL price was modeled at 45.3% of the WTI posted price. For natural gas volumes, the average Henry Hub spot price of $3.598 per MMBtu as of December 31, 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 $66.34 per Bbl of crude oil, $30.14 per Bbl of NGL and $3.35 per Mcf of natural gas as of December 31, 2021.

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

Reserve engineering is a process of estimating volumes of economically recoverable crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of

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different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of economically recoverable crude oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Other Risk Factors of Desert Peak.”

PUDs

As of December 31, 2021, Desert Peak estimated its PUD reserves to be 2,559 MBbls of crude oil, 5,596 MMcf of natural gas and 606 MMbls of NGLs, for a total of 4,098 MBOE. As of December 31, 2020, Desert Peak estimated its PUD reserves to be 1,344 MBbls of crude oil, 3,897 MMcf of natural gas and 473 MBbls of NGLs, for a total of 2,467 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production. PUD reserves included in these estimates relate solely to wells that have been spud but are not yet producing as of the date of the report.

The following tables summarize Desert Peak’s changes in PUD reserves during the year ended December 31, 2021 (in MBOE):

	Proved Undeveloped Reserves (MBOE)
Balance, December 31, 2020		2,467
Acquisitions of Reserves		3,265
Extensions and Discoveries		626
Revisions of Previous Estimates		(451	)
Transfers to Estimated Proved Developed		(1,808	)
Balance, December 31, 2021		4,099

Changes in Desert Peak’s PUD reserves that occurred during the year ended December 31, 2021 were primarily due to the following:

• the acquisition of additional mineral and royalty interests located in the Delaware Basin in multiple transactions, which included 3,265 MBOE of additional PUDs;

• well additions, extensions and discoveries of approximately 626 MBOE, as 112 horizontal well locations were converted to proved undeveloped;

• negative volume revisions of 451 MBOE due to adjustments in expected well ownership;

• and the conversion of approximately 1,808 MBOE in PUD reserves into proved developed reserves as 118 horizontal locations were drilled and completed.

As a mineral and royalty interests owner, Desert Peak does not incur any capital expenditures or lease operating expenses in connection with the development of its PUDs, which costs are borne entirely by the E&P operator. As a result, during the twelve months ended December 31, 2021, Desert Peak had no expenditures to convert PUDs to proved developed reserves.

Desert Peak identifies drilling locations based on its assessment of current geologic, engineering and land data. This includes DSU formation and current well spacing information derived from state agencies and the

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operations of the E&P companies drilling Desert Peak’s mineral and royalty interests. Desert Peak limits its PUDs solely to wells that have been spud but are not yet producing. As of December 31, 2021, approximately 17% of Desert Peak’s total proved reserves were classified as PUDs.

Crude Oil, Natural Gas and NGL Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of crude oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

	Year Ended December 31,
	2021		2020
Production data:
Crude oil (MBbls)		1,261		933
Natural gas (MMcf)		4,746		4,134
NGLs (MBbls)		499		488
Total (MBOE)		2,551		2,110
Average realized prices:
Crude oil (per Bbl)	$	67.29	$	37.40
Natural gas (per Mcf)	$	3.61	$	1.03
NGLs (per Bbl)	$	33.22	$	10.32
Total (per BOE)(1)	$	46.47	$	20.95
Average cost (per BOE):
Production and ad valorem taxes	$	2.69	$	1.49

(1) “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per Bbl of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between crude oil and natural gas.

Drilling Results

Productive wells consist of producing horizontal wells, wells capable of production and exploratory, development or extension wells that are not dry wells. As of December 31, 2021 and 2020, Desert Peak owned mineral and royalty interests in 4,459 and 1,650 productive horizontal wells. Desert Peak does not own any working interests in any wells other than in one plugged and abandoned well. Accordingly, Desert Peak does not own any net wells as such term is defined by Item 1208(c)(2) of Regulation S-K. However, based on its net revenue interest per well, as of December 31, 2021 and 2020, Desert Peak had the equivalent of 36.887 and 17.767 net producing horizontal wells on its acreage.

Desert Peak is not aware of any dry holes drilled on the acreage underlying its mineral and royalty interests during the relevant periods.

Acreage

The following table sets forth information relating to Desert Peak’s acreage for its mineral and royalty interests as of December 31, 2021:

Basin	Gross DSU Acreage	Total NRAs	100% NRAs	Gross DSU Developed Acreage	Gross DSU Undeveloped Acreage	NRAs (Developed)	NRAs (Undeveloped)
Delaware	1,379,873	105,359	13,170	354,444	1,025,428	24,704	80,655

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Mineral interests comprised approximately 82% of our NRAs, ORRIs comprised approximately 13% of our NRAs and NPRIs comprised approximately 5% of our NRAs as of December 31, 2021. For information regarding the impact of lease expirations on our interests, please see “Risk Factors — Risk Factors Related to Desert Peak—Risks Related to Desert Peak’s Business — Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Desert Peak’s E&P operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities. In addition, Desert Peak’s ORRIs may be lost if the underlying acreage is not drilled before the expiration of the applicable lease or if the lease otherwise terminates.”

Regulation

The following disclosure describes regulation directly associated with E&P operators of crude oil and natural gas properties, including Desert Peak’s current E&P operators, and other owners of working interests in crude oil and natural gas properties.

Crude oil and natural gas operations are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the crude oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business.

Environmental Matters

Crude oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the properties in which Desert Peak owns mineral interests, which could materially adversely affect its business and its prospects. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the E&P operators of Desert Peak’s properties regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect Desert Peak’s business and prospects.

Non-Hazardous and Hazardous Waste

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative,

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civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with E&P of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. On May 4, 2016, a coalition of environmental groups filed a lawsuit against EPA in the U.S. District Court for the District of Columbia for failing to update its RCRA Subtitle D criteria regulations governing the disposal of certain crude oil and natural gas drilling wastes. In December 2016, EPA and the environmental groups entered into a consent decree to address EPA’s alleged failure. In response to the consent decree, in April 2019, the EPA signed a determination that revision of the regulations is not necessary at this time. However, any changes in the laws and regulations could have a material adverse effect on the E&P operators of Desert Peak’s properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying Desert Peak’s mineral and royalty interests and adversely affect Desert Peak’s business and prospects.

Remediation

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and analogous state laws generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying Desert Peak’s mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying Desert Peak’s mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

Water Discharges

The Clean Water Act (“CWA”), the SDWA, the Oil Pollution Act of 1990 (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into regulated waters. The definition of regulated waters has been the subject of significant controversy in recent years, with different definitions proposed under the Obama and Trump Administrations. Both of these definitions have been subject to litigation, and the EPA and the U.S. Army Corps of Engineers have published a proposed rulemaking to revoke the 2020 rule in favor of a pre-2015 definition until a new definition is proposed, which the Biden Administration has announced is underway. To the extent any future rule expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on Desert Peak’s operators. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued

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permit. In addition, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The EPA has also adopted regulations requiring certain crude oil and natural gas E&P facilities to obtain individual permits or coverage under general permits for storm water discharges, and in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.

The OPA is the primary federal law for crude oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of crude oil into surface waters.

Noncompliance with the CWA, the SDWA, or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the E&P operators of the acreage underlying Desert Peak’s mineral interests.

Air Emissions

The CAA, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in June 2016, the EPA established criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for crude oil and natural gas producers and impact production of the acreage underlying Desert Peak’s mineral and royalty interests. In addition federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of crude oil and natural gas projects.

Climate Change

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

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised regulations

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initially promulgated in June 2016 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOO(b) new source and OOOO(c) first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirement, and reduction of emissions by 95% through capture and control systems. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

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. Additionally, at COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The full impact of these actions 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 called for restrictions on leasing on federal land, including the Department of the Interior’s publication of a report recommending various changes to the federal leasing program, though many such changes would require Congressional action. Substantially all of Desert Peak’s interests are located on private lands, but it 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. For example, at COP26, GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of

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GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. 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. In late 2021, the Federal Reserve announced that it had joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network for Greening the Financial System to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. 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. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

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 Desert Peak’s interests. Additionally, political, litigation and financial risks may result in Desert Peak’s 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 Desert Peak’s interests. One or more of these developments could have a material adverse effect on Desert Peak’s business, financial condition and results of operation.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully insured. However, at this time, Desert Peak is unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting its business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their crude oil and natural gas regulatory programs. However, several agencies have asserted regulatory authority over certain aspects of the process. For example, in August 2012, the EPA finalized regulations under the federal CAA that establish new air emission controls for crude oil and natural gas production and natural gas processing operations. Federal regulation of methane emissions from the oil and gas sector has been subject to substantial controversy in recent years. For more information, see Desert Peak’s risk factor titled “Desert Peak’s operations, and those of its E&P operators, are subject to a series of risks arising from climate change.”

In addition, governments have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water under certain limited circumstances.

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Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Railroad Commission has previously issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. For example, in October 2014, the Texas Railroad Commission published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in. In late 2021, the Texas Railroad Commission issued a notice to operators of disposal wells in the Midland area, to reduce saltwater disposal well actions and provide certain data to the commission. Separately, in November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. As a result of these developments, Desert Peak’s operators may be required to curtail operations or adjust development plans, which may adversely impact Desert Peak’s business.

The USGS has identified six states with the most significant hazards from induced seismicity, including New Mexico, Oklahoma and Texas. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the E&P operators of Desert Peak’s properties and on their waste disposal activities.

If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause E&P operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by E&P operators could have a material adverse effect on Desert Peak’s financial condition and results of operations. At this time, it is not possible to estimate the impact on Desert Peak’s business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

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Endangered Species Act

The ESA restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, and to reconsider listing the species under the ESA. For example, in October 2019 environmental groups filed a lawsuit against the FWS seeking to compel the agency to list the species under the ESA, and in July 2020, FWS agreed to initiate a 12-month review to determine whether listing the species was warranted, which determination remains outstanding. Additionally, in June 2021, the FWS proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where Desert Peak’s properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

Employee Health and Safety

Operations on Desert Peak’s properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Other Regulation of the Crude Oil and Natural Gas Industry

The crude oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the crude oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the crude oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the crude oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and conditions and cost of transportation significantly affect sales of crude oil and natural gas. The interstate transportation of crude oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to crude oil and natural gas pipeline transportation. FERC’s regulations for interstate crude oil and natural gas transmission in some circumstances may also affect the intrastate transportation of crude oil and natural gas.

Desert Peak cannot predict whether new legislation to regulate crude oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on its operations. Sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices.

Drilling and Production

The operations of the E&P operators of Desert Peak’s properties are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells,

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drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which Desert Peak operates also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the timing of construction or drilling activities, including seasonal wildlife closures;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells;

• and notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce Desert Peak’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of crude oil and natural gas that the E&P operators of Desert Peak’s properties can produce from Desert Peak’s wells or limit the number of wells or the locations at which E&P operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of crude oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but Desert Peak cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of crude oil and natural gas that may be produced from Desert Peak’s wells, negatively affect the economics of production from these wells or to limit the number of locations E&P operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the E&P operators of Desert Peak’s properties operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the E&P operators of Desert Peak’s properties may use interstate natural gas pipeline capacity, as well as the revenues such E&P operators receive for release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas

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purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the E&P operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the E&P operators of Desert Peak’s properties produce.

Historically, the natural gas industry was more heavily regulated; therefore, Desert Peak cannot guarantee that the regulatory approach currently pursued by FERC and the U.S. Congress will continue indefinitely into the future nor can Desert Peak determine what effect, if any, future regulatory changes might have on its natural gas related activities.

Crude Oil Sales and Transportation

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of crude oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act and intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, Desert Peak believes that the regulation of crude oil transportation rates will not affect its operations in any materially different way than such regulation will affect the operations of its competitors.

Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, Desert Peak believes that access to crude oil pipeline transportation services by E&P operators of Desert Peak’s properties will not materially differ from Desert Peak’s competitors’ access to crude oil pipeline transportation services.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, crude oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of crude oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of crude oil and natural gas resources.

States may regulate rates of production and may establish maximum daily production allowables from crude oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but Desert Peak cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of crude oil and natural gas that may be produced from wells on Desert Peak’s properties and the number of wells or locations the E&P operators of Desert Peak’s properties can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. Desert Peak does not believe that compliance with these laws will have a material adverse effect on its business.

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Title to Properties

Prior to completing an acquisition of mineral and royalty interests, Desert Peak performs a title review on each tract to be acquired. Desert Peak’s title review is meant to confirm the quantum of mineral and royalty interest owned by a prospective seller, the property’s lease status and royalty amount as well as encumbrances or other related burdens. As a result, title examinations have been obtained on a significant portion of Desert Peak’s properties.

In addition to Desert Peak’s initial title work, E&P operators often will conduct a thorough title examination prior to leasing and/or drilling a well. Should an E&P operator’s title work uncover any further title defects, either Desert Peak or the E&P operator will perform curative work with respect to such defects. An E&P operator generally will not commence drilling operations on a property until any material title defects on such property have been cured.

Desert Peak believes that the title to its assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in connection with the acquisition of crude oil and gas interests, non-participating royalty interests and other burdens, easements, restrictions or minor encumbrances customary in the crude oil and natural gas industry, Desert Peak believes that none of these encumbrances will materially detract from the value of these properties or from its interest in these properties.

Competition

The crude oil and natural gas business is highly competitive; Desert Peak primarily competes with companies for the acquisition of mineral and royalty interests and acquisition of minerals and crude oil and natural gas leases. Many of Desert Peak’s competitors not only own and acquire mineral and royalty interests but also explore for and produce crude oil and natural gas and, in some cases, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. By engaging in such other activities, Desert Peak’s competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, certain of Desert Peak’s competitors may possess financial or other resources substantially larger than Desert Peak possesses. Desert Peak’s ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

In addition, crude oil and natural gas products compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of crude oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand for crude oil and natural gas.

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting Desert Peak’s overall business plans. Additionally, some of the areas in which Desert Peak’s properties are located are adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow, ice or rain, Desert Peak’s E&P operators may be unable to move their equipment between locations, thereby reducing their ability to operate Desert Peak’s wells, reducing the amount of crude oil and natural gas produced from the wells on Desert Peak’s properties during such times. Additionally, extended drought conditions in the areas in which Desert Peak’s properties are located could impact its E&P operators’ ability to source sufficient water or increase the cost for such water. Furthermore, demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for Desert Peak’s natural gas production during its first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase

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some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other crude oil and natural gas operations in a portion of Desert Peak’s operating areas. Due to these seasonal fluctuations, Desert Peak’s results of operations for individual quarterly periods may not be indicative of the results that it may realize on an annual basis.

Employees

Desert Peak and its predecessor do not have any employees. As of December 31, 2021, an affiliate of Desert Peak’s predecessor employed approximately 26 full-time equivalent individuals who provided direct support to Desert Peak’s operations pursuant to a management services arrangement. None of these employees are covered by collective bargaining agreements. Immediately after the Closing, Desert Peak expects to employ approximately 30 individuals, none of which are expected to be covered by collective bargaining agreements.

Legal Proceedings

Desert Peak is party to lawsuits arising in the ordinary course of its business. Desert Peak cannot predict the outcome of any such lawsuits with certainty, but Desert Peak’s management believes it is remote that pending or threatened legal matters will have a material adverse impact on its financial condition.

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