10-K

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No 

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

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

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive oﬃcers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, 2022 (the last business day of the registrant’s most recent completed second fiscal quarter) based on the closing price of the Class A Common Stock on the New York Stock Exchange was $293.6 million. There were 80,178,279 and 74,340,735 shares of the registrant’s Class A and Class C Common Stock, respectively, issued and outstanding as of March 3, 2023.

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Barrel or Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil or other liquid hydrocarbons.

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

BOE. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of crude oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

British Thermal Unit or Btu. The quantity of heat required to raise the temperature of one pound of water by one-degree Fahrenheit.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing crude oil, natural gas and NGLs. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

Development project. The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Differential. An adjustment to the price of crude oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of crude oil or natural gas.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. The term economically producible, as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

Formation. A layer of rock that has distinct characteristics that differs from nearby rock.

Gross acres. The total acres, as the case may be, in which a mineral or royalty interest is owned.

Gross wells. The number of wells, normalized to a 5000 foot lateral length basis, where we have ownership in a mineral or royalty interest.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Horizontal wells. The number of horizontal wells, normalized to a 5000 foot lateral length basis, where we have ownership in a mineral or royalty interest.

Natural Gas Liquids or NGLs. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

Net revenue interest. The net royalty, overriding royalty, production payment and net profits interests in a particular tract or well.

Net royalty acres or NRAs. Mineral ownership standardized to a 12.5%, or 1/8th, royalty interest.

Net wells. The number of wells net to our mineral and royalty interests. A net well is deemed to exist when the sum of fractional mineral and royalty interest in gross wells equals one. The number of net wells is the sum of the fractional mineral and royalty interests in gross wells.

Non-participating Royalty Interests or NPRIs. A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease.

Operator. The individual or company responsible for the development and/or production of a crude oil or natural gas well or lease.

Overriding Royalty Interests or ORRIs. Royalty interests that burden working interests and represent the right to receive a fixed percentage of production or revenue from production (free of operating costs) from a lease. Overriding royalty interests remain in effect until the associated leases expire.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating expenses of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

Prospect. A specific geographic area that, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved reserves. Those quantities of crude oil, natural gas and NGLs that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that

renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the E&P operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

Proved undeveloped reserves or PUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Relinquishment Act Lands. Enacted in 1919, the Relinquishment Act, as interpreted by the courts, reserves all minerals to the state of Texas in those lands sold with a mineral classification between September 1, 1895 and June 29, 1931. Under the Relinquishment Act the surface owner acts as the agent for the State of Texas in negotiating and executing oil and gas leases on Relinquishment Act Lands. The State surrenders to the surface owner one-half (1/2) of any bonus, rental and royalty as compensation for acting as its agent, and in lieu of surface damages.

Realized price. The cash market price less all expected quality, transportation and demand adjustments.

Reasonable certainty. A high degree of confidence that quantities will be recovered. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

Reserves. Estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resources. Quantities of crude oil, natural gas and NGLs estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Royalty. An interest in a crude oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

SOFR or Term SOFR rate. A borrowing rate equal to the secured overnight financing rate as administered by the Federal Reserve Bank of New York.

Spot market price. The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized measure. Discounted future net cash flows estimated by applying year end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and

development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the crude oil, natural gas and NGL properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

Undeveloped locations. The number of potential well locations, normalized to a 5000 foot lateral length basis, where we have ownership in a mineral or royalty interest.

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Working interest. The right granted to the lessee of a property to develop, produce and own crude oil, natural gas, NGLs or other minerals. The working interest owners bear the exploration, development and operating expenses on either a cash, penalty or carried basis.

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements” for purposes of the federal securities laws. All statements, other than statements of present or historical fact, included in this Annual Report concerning, among other things, our strategy, future operations, financial condition, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. Words such as “could,” “should,” “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” the negative of such terms and other similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report include statements regarding our financial position, business strategy and other plans and objectives for future operations or transactions. These forward-looking statements are based on current expectations and assumptions of our management about future events and are based on currently available information as to the outcome and timing of future events. Such forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under Item 1A. “Risk Factors” included in this Annual Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause actual results to differ materially from the results contemplated by such forward-looking statements include, but are not limited to, the following risks and uncertainties:

Should one or more of the risks or uncertainties described in this Annual Report, any subsequent quarterly report or any of our other SEC filings, occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We caution that the foregoing list of factors is not exclusive. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time, and we may be subject to currently unforeseen risks that may have a materially adverse effect on our company. All subsequent written and oral forward-looking statements concerning our company, or any person acting on our behalf, are expressly qualified in their entirety by the cautionary statements above. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact our strategy. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that we expect our operators to ultimately recover.

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. The forward-looking statements speak only as of the date made and, other than as required by law, we do not undertake any obligation to update publicly or revise any of these forward-looking statements.

Unless the context clearly indicates otherwise, references in this Annual Report on Form 10-K to “Sitio,” the “Company,” “we,” “our,” “us” or similar terms refer to Sitio Royalties Corp. and its subsidiaries.

Sitio acquires, owns and manages high-quality mineral and royalty interests across premium basins in the United States with the objective of generating cash flow from operations that can be distributed to shareholders as dividends, utilized to pay down debt obligations, and reinvested to expand its base of cash flow generating assets. Sitio leases its mineral interests to oil and gas exploration and production (“E&P”) companies. Our leases permit E&P companies to explore for and produce oil, natural gas and natural gas liquids from our properties and entitle Sitio to receive a percentage of the proceeds from the sales of these commodities. Unlike owners of working interests in oil and gas properties, Sitio 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, Sitio incurs only its proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs.

As of December 31, 2022, Sitio owned mineral and royalty interests representing over 260,600 net royalty acres (“NRAs”) when adjusted to a 1/8 royalty. Unless otherwise indicated, references to the financial and operating information on a "pro forma basis" refer to the historical financial and operating information of Sitio, as adjusted to give pro forma effect to (i) the Falcon Merger (defined below) and (ii) the Brigham Merger (defined below), in each case as if the transaction had occurred at the beginning of the period presented. For the year ended December 31, 2022, on a pro forma basis the average net daily production associated with Sitio’s mineral and royalty interests was 30,782 barrels of oil equivalent per day (“BOE/d”) consisting of 15,662 barrels per day (“Bbls/d”) of oil, 53,452 thousand cubic feet per day (“Mcf/d”) of natural gas and 6,211 Bbls/d of natural gas liquids (“NGLs”). Since Sitio’s original Predecessor’s (defined below) formation in November 2016, it has accumulated its acreage position through 187 acquisitions. Sitio expects to continue to add to its mineral and royalty asset base by making acquisitions that meet its investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation, regulatory environment, and, most importantly, rate of return.

Sitio’s assets are focused primarily in the Permian Basin in West Texas and Southeast New Mexico, with additional assets across productive and high-quality areas of the United States, including the Denver-Julesburg (“DJ”) Basin in Colorado and Wyoming, Eagle Ford in South Texas, Appalachia Basin in Pennsylvania, West Virginia and Ohio, Anadarko Basin in Oklahoma and Williston Basin in North Dakota. As of December 31, 2022, approximately 70% of Sitio’s NRAs were located in the Permian Basin, 10% in the DJ Basin, 8% in the Eagle Ford, 5% in the Appalachia region, 4% in the Anadarko Basin and 3% in the Williston Basin. Sitio believes the basins in which its assets are located offer some of the most compelling rates of return for domestic E&P companies and significant potential for mineral and royalty income growth. For example, 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 Permian Basin production to grow faster than production in the rest of the United States.

Since January 1, 2016, Sitio has evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 187 acquisitions from landowners and other mineral interest owners, representing over 260,600 NRAs as of December 31, 2022. In addition to completing numerous small transactions, Sitio has completed a total of 19 transactions larger than 1,500 NRAs that account for approximately 93% of its NRAs. During 2020, Sitio’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, Sitio experienced a meaningful difference in sellers’ pricing expectations and the prices Sitio was willing to offer for assets. Sitio evaluated approximately 197,400 NRAs and submitted formal offers on approximately 56,700 NRAs but did not consummate any acquisitions subsequent to the first quarter of 2020 through the end of the first quarter of 2021. However, Sitio utilized its free cash flow to reduce its indebtedness from $66.0 million as of March 31, 2020 to $25.0 million as of March 31, 2021. Beginning in the second quarter of 2021, Sitio saw a meaningful increase in its acquisition activity as evidenced by the approximate 26,000 NRAs it acquired in the second quarter of 2021 and the approximate 28,000 NRAs it acquired in the third

quarter of 2021. In June 2022, Sitio added approximately 34,000 NRAs in connection with the reverse merger with Falcon Minerals Corp. (“Falcon” and such merger, the “Falcon Merger”). Since completing the Falcon Merger, Sitio’s acquisition activity has continued, with the completion of the acquisition of approximately 19,700 NRAs from Foundation Minerals in June 2022 (the “Foundation Acquisition”), the acquisition of approximately 12,200 NRAs from Momentum Minerals in July 2022 (the “Momentum Acquisition”) and the merger with Brigham Minerals Inc. in December 2022 which included the addition of approximately 86,500 NRAs. The following table summarizes Sitio’s acquisitions from November 2016 through December 31, 2022.

Sitio is led by a management team with extensive oil and gas engineering, geology 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 acquiring and managing mineral and royalty interests. Sitio intends to capitalize on its management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in premium basins in the United States designed to increase its cash flow per share.

As of December 31, 2022, 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 or actively under construction. According to the United States Geological Study (“USGS”), the Delaware Basin contains the largest recoverable reserves among all unconventional basins in the United States. The average net daily production attributable to Sitio’s net royalty interests in the Permian Basin on a pro forma basis was 25,308 BOE/d (55% oil) for the three months ended December 31, 2022.

Sitio 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, Sitio 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. Sitio 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.

Sitio 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. Sitio 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. Sitio expects Midland Basin drilling efficiency to continue to improve as drilling days further compress and lateral lengths keep expanding.

The DJ Basin is located in Northeast Colorado and Southeast Wyoming, with the majority of operator horizontal drilling activity located in Weld and Broomfield Counties, Colorado, and Laramie County, Wyoming. Based on Sitio’s geologic and engineering interpretations as well as current delineation efforts by operators, Sitio believes its mineral and royalty interests in the DJ Basin are prospective for four or more producing zones of economic horizontal development including the Niobrara A, B and C and Codell formations.

The Eagle Ford is one of the largest oil fields in North America with an aerial extent that covers approximately 13 million surface acres across multiple counties in South Texas. The Eagle Ford has top-tier single-well economics, is operated by premier E&P companies, and has access to abundant offtake infrastructure in close proximity to the U.S. Gulf Coast.

Sitio’s Eagle Ford assets are concentrated in what Sitio believes is the core of the liquids-rich condensate region of the Eagle Ford in Karnes, DeWitt, and Gonzales Counties, Texas and are characterized by high oil and liquids content and low finding and development costs. In all three of these counties, Sitio also has substantial exposure to the Austin Chalk and Upper Eagle Ford formations, which have experienced increased horizontal development activity, in addition to the more established and historically developed Lower Eagle Ford formation.

The Appalachian Basin extends from northern Pennsylvania through southeast Ohio and most of West Virginia. The basin consists of two main plays, the Marcellus shale, and the Utica Shale. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the Appalachian Basin are prospective for both the Marcellus and Utica zones of economic horizontal development. There are two main areas of Marcellus Shale development, northeastern Pennsylvania and southwestern Pennsylvania and northern West Virginia. The main area for Utica development is located in southeastern Ohio.

The Anadarko Basin is in Central and Western Oklahoma and stretches from the Panhandle of Oklahoma southward to Stephens and Garvin Counties. The Anadarko Basin is composed of multiple oil and gas plays varying by formation of interest, lithologic composition, and fluid type. Based on our geologic and engineering interpretations, Sitio has focused its activities around the two primary oil and gas plays in the Anadarko Basin: STACK and SCOOP. The SCOOP play is located in central Oklahoma in Grady, Garvin, Stephens and McClain Counties. Based on our geologic and engineering interpretations as well as current delineation efforts by operators, we believe our mineral and royalty interests in the SCOOP play are prospective for two or more producing zones of economic horizontal development including multiple Woodford benches and the Springer Shale. The STACK play is located in central Oklahoma in Kingfisher, Canadian, Caddo and Blaine Counties. Based on our geologic and engineering data as well as current delineation efforts by operators, Sitio believes its mineral and royalty interests in the STACK play are prospective for two or more producing zones of economic horizontal development including multiple benches within both the Meramec and Woodford formations.

The Williston Basin stretches from western North Dakota into eastern Montana with the majority of operator horizontal drilling activity located in Mountrail, Williams, and McKenzie Counties, North Dakota. Based on Sitio’s geologic and engineering interpretations as well as current operator delineation efforts, Sitio believes its mineral and royalty interests are prospective for two or more producing zones of economic horizontal development including the Bakken and multiple Three Forks benches. The majority of our interests are located in Mountrail, Williams and

McKenzie Counties with additional interests owned in Divide, Burke, Dunn, Billings and Stark Counties, North Dakota and Richland County, Montana.

Sitio’s interests consist of mineral and royalty interests. Mineral interests, which represent approximately 80% of Sitio’s NRAs as of December 31, 2022, 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 E&P companies lease those rights from Sitio, usually for a one- to three-year term, Sitio 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 Sitio to lease the exploration and development rights to another party and receive another lease bonus. As of December 31, 2022, other types of royalty interests, non-participating royalty interests (“NPRIs”) and overriding royalty interests (“ORRIs”), comprised approximately 8% and 12%, respectively, of Sitio’s NRAs. Also, as of December 31, 2022, approximately 90% of Sitio’s total NRAs derived from mineral interests only, were leased to E&P operators and other working interest owners. Sitio refers its mineral interests, NPRIs and ORRIs collectively as Sitio’s “mineral and royalty interests.”

Sitio 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. Sitio and its predecessor’s pro forma revenue generated from these mineral and royalty interests was approximately $756.6 million and $389.6 million for the years ended December 31, 2022 and 2021, respectively. Approximately 80% of 2022 and 81% of 2021 revenue was derived from the sale of oil and NGLs on a pro forma basis.

As of December 31, 2022, Sitio’s interests covered 143,189 net mineral acres, approximately 90% of which have been leased to E&P operators and other working interest owners with Sitio retaining an average 18.3% 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, Sitio’s mineral interests represent 209,411 NRAs, and its NPRIs and ORRIs represent an additional 51,196 NRAs, totaling 260,607 NRAs in the aggregate. Sitio’s drilling spacing units (“DSUs”), in the aggregate, consist of a total of 3.79 million gross acres, which Sitio refers to as Sitio’s “gross DSU acreage.” Sitio 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 Sitio’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, 2022.

(4) Represents number of horizontal producing wells across all DSUs in which we participate; normalized to a 5,000 foot basis.

(5) Represents actual production plus allocated accrued volumes attributable to the period presented

As of December 31, 2022, Sitio has interests in 4,254 (31.1 net) horizontal wells on which drilling has commenced but are not yet producing in paying quantities, which Sitio refers to as spud wells, and 3,223 (16.8 net) horizontal wells for which permits have been issued to the operators, but on which drilling has not yet commenced, which Sitio refers to as permitted wells.

As of December 31, 2022, the estimated proved crude oil, natural gas and NGLs reserves attributable to Sitio’s interests in its underlying acreage were 79,989 MBOE (67% liquids, consisting of 44% crude oil and 23% NGLs), based on a reserve report prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”). Of these reserves, approximately 81% were classified as proved developed reserves and approximately 19% were classified as proved undeveloped (“PUD”) reserves. PUD reserves for Sitio included in these estimates relate solely to wells that were spud but not yet producing as of December 31, 2022. As of December 31, 2022, Sitio had production from 32,451 (239.9 net) horizontal wells.

Sitio anticipates E&P operators to continue shifting drilling activity from a focus on drilling single wells to hold acreage towards more drilling in each DSU, particularly on multi-well pads. Furthermore, Sitio expects to see increases in its production, revenue and discretionary cash flows from the development of 4,254 spud wells and 3,223 permitted wells across its interests as of December 31, 2022. Sitio 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.

In addition to utilizing technical analysis to identify attractive mineral and royalty interests Sitio’s management team strives to acquire mineral and royalty interests in properties with top-tier E&P operators. Sitio seeks E&P operators that are well-capitalized, have a strong operational track record, and that Sitio believes will continue to increase production through the application of the latest drilling and completion techniques across its mineral and royalty interests. Approximately 174 E&P operators are currently producing oil and gas from horizontally drilled wells on Sitio’s acreage. The chart below summarizes the E&P operators of Sitio’s acreage based on pro forma production for the three months ended December 31, 2022.

Since Sitio’s inception, it has been committed to all three elements of ESG. Sitio’s fully staffed, experienced team is dedicated solely to its business of efficiently managing its assets and pursuing and consummating acquisitions. The board of directors of Sitio (the “Board”) and employee base are reflective of a culture that values diversity, with approximately one-half of Sitio’s employees and approximately 56% of Sitio’s directors who are women or minorities. Sitio’s compensation for its Board and executive management is structured to be well aligned with shareholders, with incentive compensation for executive management that is 100% equity based, with an emphasis on absolute total shareholder return over a three-year period. Sitio targets minerals under operators with strong environmental track records and prioritizes responsible environmental practices, striving to incentivize E&P companies to avoid flaring natural gas in each lease. As Sitio continues to gain additional scale, it intends to further work with operators to reduce flaring and venting of methane. Presently, Sitio has no environmental liabilities and, due to the nature of our business, no Scope 1 “greenhouse gas” (“GHG”) emissions. Our minimal Scope 2 emissions are from power consumption at Sitio office locations.

The information included in “—Crude Oil, Natural Gas and NGLs Data” and “—Crude Oil, Natural Gas and NGL Production Prices and Costs” presents Sitio’s (i) proved reserves as of the years ended December 31, 2022, 2021 and 2020 and operating data as of and for the years ended December 31, 2022, 2021 and 2020, in each case, on an actual basis, without giving pro forma effect to transactions completed after such dates. As such, the proved reserves and operating data as of and for the year ended December 31, 2021 presented in these sections does not give effect to the Falcon Merger, Brigham Merger or the Other Acquisitions (defined below). The assets acquired in the Falcon Merger, Brigham Merger and the Other Acquisitions are included in Sitio’s proved reserves and operating data as of December 31, 2022, 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, 2022 on an actual basis.

Sitio’s proved reserve estimates as of December 31, 2022, 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. Sitio 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 Sitio’s proved reserves as of December 31, 2022, 2021 and 2020 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable crude oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods, (ii) material balance-based methods; (iii) volumetric-based methods and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting PDNP and PUDs for Sitio’s properties due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, Sitio 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 Sitio’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.

Sitio’s internal staff of petroleum engineers and geoscience professionals work closely with Sitio’s management team and its independent reserve engineer to ensure the integrity, accuracy and timeliness of data furnished to such independent reserve engineer in its preparation of proved reserve estimates. Sitio’s internal staff, along with members of its management team, meet with its independent reserve engineer periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. Sitio provides historical information to its independent reserve engineer for its properties, such as ownership interest crude oil and natural gas production, well test data, commodity prices and estimates of its operators’ operating and development costs. 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 can 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, natural gas and NGLs that are ultimately recovered. Sitio’s engineering group is responsible for the internal review of reserve estimates and includes the Executive Vice President of Engineering and Acquisitions, Jarret Marcoux. Mr. Marcoux is primarily responsible for overseeing the preparation of its reserve estimates and has more than 17 years of experience as an engineer. Prior to joining Sitio, Mr. Marcoux worked at Kimmeridge Energy.

The preparation of Sitio’s proved reserve estimates was completed in accordance with its internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

No portion of Sitio’s internal engineering and geoscience group’s compensation is directly dependent on the quantity of reserves booked. The engineering and geoscience group reviews the estimates with the independent reserve engineering firm. CG&A does not own an interest in any of Sitio’s properties, nor is it employed on a contingent basis. A summary of CG&A’s report with respect to our proved reserve estimates as of December 31, 2022 is included as an exhibit to this Annual Report on Form 10-K.

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 Sitio’s reserve reports 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 35 years of practical experience in petroleum engineering, with over 33 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, as well as the independence, objectivity and confidentiality requirements, set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The following table presents Sitio’s estimated proved reserves as of December 31, 2022, 2021 and 2020. The reserve estimates presented in the table below are based on reports prepared by CG&A, Sitio’s independent petroleum engineers, which reports were prepared in accordance with current SEC rules and regulations. All of Sitio’s proved reserves are located in the United States.

(1) Sitio’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 $93.67 per Bbl as of December 31, 2022 was adjusted for quality, transportation fees and a regional price differential. NGL price was modeled at 37.3% of the WTI posted price. For natural gas volumes, the average Henry Hub spot price of $6.358 per MMBtu as of December 31, 2022 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 $93.05 per Bbl of crude oil, $34.97 per Bbl of NGL and $5.70 per Mcf of natural gas as of December 31, 2022.

(2) Sitio’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 $64.34 per Bbl of crude oil, $30.14 per Bbl of NGL and $3.35 per Mcf of natural gas as of December 31, 2021.

(3) Sitio’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 subjective process of estimating volumes of economically recoverable crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of economically recoverable crude oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read “Item 1A. “Risk Factors.”

Sitio’s reserve estimates do not include any value for probable or possible reserves that may exist. The reserve estimates represent Sitio’s net revenue interest and royalty interest in its properties. Although Sitio believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas may vary substantially from these 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 Item 1A. “Risk Factors.”

As of December 31, 2022, Sitio estimated its PUD reserves to be 7,650 MBbls of crude oil, 25,953 MMcf of natural gas and 3,190 MBbls of NGLs, for a total of 15,165 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following tables summarize Sitio’s changes in PUD reserves during the year ended December 31, 2022 (in MBOE):

Changes in Sitio’s PUD reserves that occurred during the year ended December 31, 2022 were primarily due to the following:

As a mineral and royalty interest owner, Sitio does not incur any capital expenditures or lease operating expenses in connection with the development of its PUDs, which are costs borne entirely by the E&P operator. As a result, during the year ended December 31, 2022, Sitio had no expenditures to convert PUDs to proved developed reserves.

Sitio 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 operations of the E&P companies drilling Sitio’s mineral and royalty interests. Sitio limits its PUDs solely to wells that have been spud but are not yet producing. As of December 31, 2022, 2021 and 2020, approximately 19%, 17% and 21%, respectively, of Sitio’s total proved reserves were classified as PUDs.

As of December 31, 2022, Sitio identified 50,358 undeveloped locations across its gross DSU acreage. Furthermore, Sitio believes additional opportunity is possible through the delineation of additional formations as well as incremental wells in existing formations. Approximately 89% of Sitio’s estimated total net horizontal undeveloped

locations are located in the Permian Basin, with another 6% located in the DJ Basin in Colorado and Wyoming as shown in the following table.

For the years ended December 31, 2022, 2021 and 2020, 96%, 98% and 96% of our total revenue were related to crude oil, natural gas and NGL sales, respectively.

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:

(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.

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, 2022, 2021, and 2020, there were 32,451, 7,722, and 2,537 productive horizontal wells, respectively, on Sitio's mineral and royalty interests. Accordingly, Sitio 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, 2022, 2021, and 2020, Sitio had the equivalent of 239.9, 59.4, and 25.7 net producing horizontal wells, respectively, on its acreage.

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

The following table sets forth information relating to Sitio’s acreage for its mineral and royalty interests as of December 31, 2022:

Mineral interests comprised approximately 80% of our NRAs, ORRIs comprised approximately 8% of our NRAs and NPRIs comprised approximately 12% of our NRAs as of December 31, 2022. For information regarding the impact of lease expirations on our interests, please see Item 1A. “Risk Factors.”

The following disclosure describes regulation directly associated with E&P operators of crude oil and natural gas properties, including Sitio’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.

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 Sitio owns mineral interests, which could materially adversely affect its business and its prospects. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (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 Sitio’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 Sitio’s business and prospects.

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with 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. Any changes in the laws and regulations could have a material adverse effect on the E&P operators of Sitio’s properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying Sitio’s mineral and royalty interests and adversely affect Sitio’s business and prospects.

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 Sitio’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 Sitio’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.

The Clean Water Act (the “CWA”), U.S. Safe Drinking Water Act (the “SDWA”), the Oil Pollution Act of 1990 (the “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, in December 2022, the EPA and the U.S. Army Corps of Engineers released a final revised definition of “waters of the united states” founded upon a pre-2015 definition and including updates to incorporate existing Supreme Court decisions. The revised definition is already subject to legal challenge by a number of states, with suits filed in Texas and Kentucky. To the extent any future rule expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on Sitio’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 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 Sitio’s mineral interests.

The Clean Air Act (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 Sitio’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 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, besides the IRA 2022, 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 to this effect. Moreover, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised regulations initially promulgated in June 2016 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, 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 (a) new source and (b) 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. In November 2022, the EPA published a supplemental methane proposal which, among other items, sets forth specific revisions strengthening the first nationwide emission guidelines for states to limit methane emissions from existing crude oil and natural gas

facilities. The proposal also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys and establishes a “super-emitter” response program to timely mitigate emissions events. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that it will be subject to legal challenges. 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 the 26th Conference of the Parties to the United Nations Framework Convention on Climate Change (the “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. At the 27th Conference of the Parties to the United Nations Framework Convention on Climate Change (the “COP27”) in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase-out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. The full impact of these actions cannot be predicted at this time.

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 and, in November 2021, the Department of the Interior released a comprehensive report on the federal leasing program which stated an intent to modernize the federal oil and gas leasing program, although many of the recommendations made would require Congressional action. The majority of Sitio’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. 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, and, in September 2022, announced that six of the U.S.’ largest banks would participate in a pilot climate scenario analysis exercise to enhance the ability of firms and supervisors to measure and manage climate-related financial risks. The Federal Reserve released its pilot exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. The 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, on March 21, 2022, the

SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. A final rule is anticipated to be released in the second quarter of 2023. 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, alongside increased costs of and restrictions on access to capital.

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 Sitio’s interests. Additionally, political, litigation and financial risks may result in Sitio’s oil and natural gas operators restricting or canceling 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 Sitio’s interests. One or more of these developments could have a material adverse effect on Sitio’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, Sitio is unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting its business.

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 Sitio’s risk factor titled “Sitio’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.

Several states where we operate, including Colorado, North Dakota, Oklahoma, Texas, and New Mexico, 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.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. For example, in November 2020, the Colorado Oil and Gas Conservation Committee (“COGCC”), as part of Senate Bill 181’s mandate for the COGCC to

prioritize public health and environmental concerns in its decisions, adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. The Colorado Department of Public Health and the Environment also recently finalized rules related to the control of emissions from certain pre-production activities; namely, curbing methane emissions by setting limits of per 1,000 barrels of oil equivalent produced, more frequent inspections, and limits on emissions during maintenance. These and other developments related to the implementation of SB 181 could adversely impact our revenues and future production from our properties.

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, New Mexico, 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. And, in December 2021, the Texas Railroad Commission suspended all disposal well permits to inject oil and gas waste within the boundaries of the Gardendale Seismic Response Area. Relatedly, in March 2022, the Texas Railroad Commission began implementation of its Northern Culberson-Reeves Seismic Response Area Plan to address injection-induced seismicity with the goal to eliminate 3.5 magnitude or greater earthquakes no later than December 31, 2023. 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, Sitio’s operators may be required to curtail operations or adjust development plans, which may adversely impact Sitio’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 Sitio’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 Sitio’s financial condition and results of operations. At this time, it is not possible to estimate the impact on Sitio’s business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

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. In August 2022, the FWS filed a stipulated settlement agreement in a case challenging its failure to timely make a twelve-month finding on a petition to list the dunes sagebrush lizard. Under the agreement, the FWS will submit a twelve-month finding on the petition no later than June 29, 2023. 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. In November 2022, following an extensive review, the FWS listed the northern distinct population segment of the Lesser Prairie Chicken, encompassing southeastern Colorado, southcentral to western Kansas, western Oklahoma, and the northeast Texas Panhandle, as threatened, and the southern district population segment, covering eastern New Mexico and the southwest Texas Panhandle, as endangered. 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 Sitio’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.

Operations on Sitio’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.

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.

Sitio 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.

The operations of the E&P operators of Sitio’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, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which Sitio operates also regulate one or more of the following:

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 Sitio’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 Sitio’s properties can produce from Sitio’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 Sitio 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 Sitio’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 Sitio’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.

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 Sitio’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 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 Sitio’s properties produce.

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

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, Sitio 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, Sitio believes that access to crude oil pipeline transportation services by E&P operators of Sitio’s properties will not materially differ from Sitio’s competitors’ access to crude oil pipeline transportation services.

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 Sitio 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 Sitio’s properties and the number of wells or locations the E&P operators of Sitio’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. Sitio does not believe that compliance with these laws will have a material adverse effect on its business.

On July 6, 2020, the U.S. District Court for the District of Columbia ordered vacatur of Dakota Access Pipeline’s (“DAPL”) easement from the “Corps” and further ordered the shutdown of the pipeline by August 5, 2020 while the Corps completes a full environmental impact statement for the project. On January 26, 2021, the Court of Appeals for the District of Columbia affirmed the vacatur of the easement, but declined to require the pipeline to shut down while an Environmental Impact Statement is prepared. Following the denial of a rehearing en banc, on September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and Plaintiffs and Dakota Access filed its reply. On May 21, 2021, the District Court denied the Plaintiff’s request for an injunction and, on June 22, 2021, terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. The pipeline continues to operate pending completion of the Environmental Impact Statement, with the Corps indicating a draft of which will be published in the Spring of 2023. We cannot determine when or how future lawsuits will be resolved or the impact they may have on the DAPL. If future legal challenges to DAPL are successful, we may be adversely affected by increased transportation costs, well shut ins, and future productive, negatively impacting our revenue costs.

On July 9, 2020, the U.S. Supreme Court ruled in McGirt v. Oklahoma that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Although the Court’s ruling indicates that it is limited to criminal law as applied within the Muscogee (Creek) Nation reservation, the ruling has significant potential implications for civil law within the Muscogee (Creek) Nation reservation, as well as other reservations in Oklahoma that may similarly be found to not have been disestablished. A subsequent ruling in July 2022 in Oklahoma v. Castro-Huerta narrowed McGirt’s holding to find concurrent tribal and state jurisdiction with respect to crimes committed by non-Native Americans against Native Americans on tribal lands. However, this has lead to substantial uncertainty with respect to matters over which tribes may have exclusive or concurrent jurisdiction. We cannot predict the full extent to which civil jurisdiction may be affected by these cases, but this issue could adversely affect title to our interests, to the extent they are found to be located within reservation areas, and significantly impact laws and regulations to which we are subject to in Oklahoma, such as taxation, environmental regulation, and the permitting and siting of energy assets.

On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to many areas of Indian Country within Oklahoma, effectively extending Oklahoma’s authority for existing EPA-approved regulatory programs to lands within Oklahoma previously under the jurisdiction of the State before the U.S. Supreme Court’s ruling in McGirt. However, several Tribes have expressed dissatisfaction with the consultation process performed in relation to this approval, and, in December 2021, the EPA proposed to withdraw and reconsider the October 2020 decision. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from the EPA.

Prior to completing an acquisition of mineral and royalty interests, Sitio performs a title review on each tract to be acquired. Sitio’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 Sitio’s properties.

In addition to Sitio’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 Sitio 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.

Sitio 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, Sitio believes that none of these encumbrances will materially detract from the value of these properties or from its interest in these properties.

The crude oil and natural gas mineral and royalty business is highly competitive; Sitio primarily competes with public and private royalty aggregator companies, private equity firms, and select E&P companies for the acquisition of mineral and royalty interests. Some of Sitio’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, Sitio’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 Sitio’s competitors may possess financial or other resources substantially larger than Sitio possesses. Sitio’s ability to acquire additional minerals and properties 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.

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting Sitio’s overall business plans. Additionally, some of the areas in which Sitio’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, Sitio’s E&P operators may be unable to move their equipment between locations, thereby reducing their ability to operate Sitio’s wells, reducing the amount of crude oil and natural gas produced from the wells on Sitio’s properties during such times. Additionally, extended drought conditions in the areas in which Sitio’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 Sitio’s natural gas production during its first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other crude oil and natural gas operations in a portion of Sitio’s operating areas. Due to these seasonal fluctuations, Sitio’s results of operations for individual quarterly periods may not be indicative of the results that it may realize on an annual basis.

We consider our workforce to be our most important asset, and we have sought to structure our hiring practices, compensation and benefits programs, and employee practices to attract and retain high-quality personnel and to provide a comfortable and collegial work environment. We continue to invest in our employees by providing training opportunities, promoting diversity and inclusion, and maintaining focus on corporate ethics. We are managed and operated by the executive officers of our Company and our Board oversees the management of the Company.

Sitio had 49 employees as of December 31, 2022, of which 14 were retained from Brigham and approximately one-half of whom are women or minorities.

As a small, tight-knit community, our employees have broad responsibilities, and we encourage continuing development in their careers. When new opportunities arise within our organization, we may look within our organization for talent to fill those needs, ask for referrals from our team (who understand the diverse skill sets, high energy and forward-thinking attitude that contributes to delivering exceptional results), or work with recruiters who specialize in the areas of our vacancies.

As part of our efforts to hire and retain highly qualified employees, we have structured compensation and benefits programs that, we believe, are extremely competitive and reward outstanding performance. In addition to the incentive programs in place for our named executive officers, which are described in detail in our proxy statement, we have structured an incentive bonus program for non-officer employees that is dependent on an employee’s individual performance and our performance as a company. Our employees also receive restricted-share and performance-unit awards to encourage retention and align compensation with our company performance.

We provide a robust suite of benefits to our employees covering all aspects of life, including 401(k) contributions, medical-insurance options, and programs to encourage and support the employees’ development.

Sitio was initially formed through the Falcon Merger on June 7, 2022. Pursuant to the Falcon Merger, DPM Holdco, LLC (“Desert Peak”) became a wholly-owned subsidiary of Falcon Minerals Operating Partnership, LP. Following the completion of the Falcon Merger, Sitio is managed by the legacy Desert Peak management team and Falcon Minerals Corporation and Falcon Minerals Operating Partnership, LP were renamed “Sitio Royalties Corp.” and “Sitio Royalties Operating Partnership, LP,” respectively. The Falcon Merger contributed 34,000 NRAs in the Eagle Ford and Appalachia Basin.

On December 29, 2022, we consummated the previously announced merger transactions contemplated by the Agreement and Plan of Merger, dated as of September 6, 2022 (the “Brigham Merger Agreement”) by and among STR Sub Inc. (formerly Sitio Royalties Corp.)(“Former Sitio”), MNRL Sub Inc. (formerly Brigham Minerals Inc.)(“Brigham”), Brigham Minerals Holdings, LLC, Sitio Royalties Operating Partnership, LP, successor Sitio Royalties Corp. (formerly Snapper Merger Sub I, Inc.)(“New Sitio”), Snapper Merger Sub IV, Inc., Snapper Merger Sub V, Inc., and Snapper Merger Sub II, LLC. The Brigham Merger Agreement provides for the acquisition of Brigham by Former Sitio in an all stock transaction (the “Brigham Merger”). The Brigham assets consisted of approximately 86,500 NRAs in aggregate, including 30,300 NRAs in the Delaware Basin, 13,200 NRAs in the Midland Basin, 24,800 NRAs in the DJ Basin, 10,000 NRAs in the Anadarko Basin and 8,200 NRAs in the Williston Basin.

For the year ended December 31, 2022, in addition to the Falcon Merger and Brigham Merger, Sitio completed multiple acquisitions totaling approximately 26,800 NRAs in the Delaware Basin and 7,700 NRAs in the Midland Basin from private, unrelated sellers (the “Other Acquisitions”).

Sitio’s corporate headquarters is located at 1401 Lawrence Street, Suite 1750, Denver, CO 80202 and its main office number is (720) 640-7620. Sitio also has office locations at 609 Main Street, Suite 3950, Houston, TX 77002 and 5914 W. Courtyard Drive, Suite 150, Austin, TX 78730.

Sitio’s website address is www.sitio.com. Sitio makes periodic reports and other information filed with or furnished to the SEC available free of charge through its website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on Sitio’s website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Annual Report, including our Consolidated Financial Statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.

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

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

These factors and the volatility of the energy markets make it extremely difficult to predict future crude oil, natural gas and NGL price movements with any certainty. For example, during the past five years, the posted price for WTI light sweet crude oil has ranged from a historic, record low price of negative ($36.98) per Bbl in April 2020 to a high of $123.64 per Bbl in March 2022, and the Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. Certain actions by OPEC+ in the first half of 2020, combined with the impact of the COVID-19 pandemic and a shortage in available storage for hydrocarbons in the U.S., contributed to the historic low price for crude oil in April 2020. While the prices for crude oil have generally increased since then, such prices have historically remained volatile, which has adversely affected the prices at which production from Sitio’s properties is sold as well as the production activities of operators on Sitio’s properties and may continue to do so in the future. This, in turn, has and will materially affect the amount of royalty payments that Sitio receives from such operators.

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

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

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

Title to the properties in which Sitio has an interest may be impaired by title defects.

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

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

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

Sitio depends on various unaffiliated E&P operators for all of the exploration, development and production on the properties underlying its mineral and royalty interests. Substantially all of Sitio’s revenue is derived from royalty payments made by these E&P operators. A reduction in production from wells and/or the expected number of wells to be drilled on Sitio’s acreage by these E&P operators or the failure of its E&P operators to adequately and efficiently develop and operate the wells on its acreage could have an adverse effect on its results of operations and cash flows. Some of the E&P operators of the properties underlying Sitio’s mineral and royalty interests are not contractually obligated to undertake any development activities, so any development and production activities will be subject to their discretion.

Sitio’s assets consist of mineral and royalty interests. Because Sitio depends on third-party E&P operators for all of the exploration, development and production on its properties, it has little to no control over the operations related to its properties. For the year ended December 31, 2022, Sitio received revenue from 133 E&P operators, with approximately 61% coming from the top ten E&P operators on its properties, one of which accounted for more than 10% of such royalty revenues. The failure of Sitio’s E&P operators to adequately or efficiently perform operations or an E&P operator’s failure to act in ways that are in Sitio’s best interests could reduce production and revenues. For example, in response to the significant decrease in prices for crude oil during 2020, many of Sitio’s E&P operators substantially reduced their development activities in 2020. Additionally, certain investors have requested that operators adopt initiatives to return capital to investors, which could also reduce the capital available to Sitio’s E&P operators for investment in exploration, development and production activities. Sitio’s E&P operators may further reduce capital expenditures devoted to exploration, development and production on its properties in the future, which could negatively impact revenues it receives.

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

The E&P operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in Sitio’s results of operations and cash flows. Sustained reductions in production by the E&P operators on Sitio’s properties may also adversely affect Sitio’s results of operations and cash flows. Additionally, if an E&P operator were to experience financial difficulty, the E&P operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on Sitio’s cash flows.

Sitio’s future success depends on finding and replacing reserves through acquisitions and the exploration and development activities of its E&P operators.

Producing crude oil and natural gas wells are characterized by declining production rates as reserves are depleted, which such rates vary depending upon reservoir characteristics and other factors. Sitio’s future crude oil, natural gas and NGL reserves and its E&P operators’ production thereof and Sitio’s cash flows are highly dependent on the successful development and exploitation of Sitio’s current reserves and its ability to successfully acquire additional reserves that are economically recoverable. Moreover, the production decline rates of Sitio’s properties may be significantly higher than currently estimated if the wells on its properties do not produce as expected. Sitio may not have sufficient resources to acquire additional reserves and may also not be able to find, acquire or develop additional reserves to replace the current and future production of its properties at economically acceptable terms, or at all.

Furthermore, although revenues may increase if prevailing crude oil and natural gas prices increase significantly, finding costs for additional reserves could also increase. Aside from acquisitions, Sitio has little to no control over the exploration and development of its properties. If Sitio is not able to replace or grow its oil, natural gas and NGL reserves, its business, financial condition and results of operations would be adversely affected.

Project areas on our properties, which are in various stages of development, may not yield oil, natural gas or NGLs in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition and results of operations may be adversely affected.

Sitio’s failure to successfully identify, complete and integrate acquisitions of properties or businesses could materially and adversely affect its growth, results of operations and cash flows.

Sitio depends in part on acquisitions to grow its reserves, production and cash flows. Sitio’s decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

The accuracy of these assessments is inherently uncertain and Sitio may not be able to identify attractive acquisition opportunities. In connection with these assessments, Sitio performs a review of the subject properties that it believes to be generally consistent with industry practices, given the nature of its interests. Sitio’s review will not reveal all existing or potential problems, nor will it permit it to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if Sitio does identify attractive acquisition opportunities, it may not be able to complete the acquisition or do so on commercially acceptable terms. Unless Sitio’s E&P operators further develop its existing properties, it will depend on acquisitions to grow its reserves, production and cash flow.

There is intense competition for acquisition opportunities in Sitio’s industry. Competition for acquisitions may increase the cost of, or cause Sitio to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time. For example, in connection with the COVID-19 pandemic and resulting market and commodity price challenges, Sitio’s acquisition activity saw a significant decline as it experienced a meaningful difference in sellers’ pricing expectations and the prices Sitio was willing to offer. Sitio’s ability to complete acquisitions is dependent upon, among other things, its ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which Sitio does not currently hold assets, which could result in unforeseen difficulties. In addition, if Sitio acquires interests in new geographic regions, it may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on Sitio and its management, cause it to expend additional time and resources in compliance activities and increase its exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on Sitio’s ability to integrate effectively the acquired business into its existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of Sitio’s managerial and financial resources. In addition, potential future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

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

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

Acquiring crude oil, natural gas and NGL properties requires Sitio to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, Sitio performs diligence of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of Sitio’s due diligence, it may not inspect every well or pipeline. Sitio may not be able to obtain contractual indemnities from the seller for liabilities created prior to its purchase of the property.

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

Even if Sitio makes acquisitions that it believes will increase its cash generated from operations, these acquisitions may nevertheless result in a decrease in its cash flows. Any acquisition involves potential risks, including, among other things:

Sitio’s E&P operators’ identified potential drilling locations, which are scheduled out over many years and are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

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

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

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

Sitio is unable to determine with certainty which E&P operators will ultimately operate its properties.

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

Sitio relies on its E&P operators, third parties and government databases for information regarding its assets and, to the extent that information is incorrect, incomplete or lost, Sitio’s financial and operational information and projections may be incorrect.

As an owner of mineral and royalty interests, Sitio relies on the E&P operators of the properties to notify it of information regarding production on its properties in a timely and complete manner, as well as the accuracy of information obtained from third parties and government databases. Sitio uses this information to evaluate its operations and cash flows, as well as to predict its expected production and possible future locations. To the extent Sitio does not timely receive this information or the information is incomplete or incorrect, Sitio’s results may be incorrect and its ability to project potential growth may be materially adversely affected. Furthermore, to the extent Sitio has to update any publicly disclosed results or projections made in reliance on this incorrect or incomplete information, investors could lose confidence in its reported financial information. If any of such third-parties’ databases or systems were to fail for any reason, including as a result of a cyber-attack, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any of the foregoing consequences could material adversely affect Sitio’s business.

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

Sitio has completed numerous acquisitions of mineral and royalty interests that are not “significant” under Rule 3-05 of Regulation S-X (“Rule 3-05”). Therefore, Sitio is not required to, and has elected not to, provide separate historical financial information in its public filings relating to those acquisitions. While these acquisitions are not individually or collectively significant for purposes of Rule 3-05, they have or will have an impact on Sitio’s financial results and their aggregated effect on its business and results of operations may be material.

Acquisitions and Sitio’s E&P operators’ development of Sitio’s leases will require substantial capital, and Sitio and its E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of recent increases in cost of capital resulting from Federal Reserve policies and otherwise.

The crude oil and natural gas industry is capital intensive. Sitio makes and may continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, Sitio has financed capital expenditures primarily with funding from capital contributions, cash generated by operations and borrowings from its revolving credit facilities and 2026 Senior Notes.

In the future, Sitio may need capital in excess of the amounts it retains in its business, borrows under its revolving credit facilities or has access to in capital markets. The level of borrowing base available under Sitio’s revolving credit facilities is largely based on its estimated proved reserves and its lenders’ price decks and underwriting standards in the reserve-based lending space and will be reduced to the extent commodity prices decrease or remain depressed, underwriting standards tighten or the lending syndication market is not sufficiently liquid to obtain lender commitments to a full borrowing base in an amount appropriate for Sitio’s assets.

Furthermore, Sitio cannot assure you that it will be able to access other external capital on terms favorable to it or at all. For example, a significant decline in prices for crude oil, rising interest rates, inflationary pressure and broader economic turmoil may adversely impact Sitio’s ability to secure financing in the capital markets on favorable terms. Additionally, Sitio’s ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If Sitio is unable to fund its capital requirements, Sitio may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on its results of operation and financial condition.

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

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

As of December 31, 2022, approximately 19% of Sitio’s total estimated proved reserves were PUDs and may not be ultimately developed or produced by the E&P operators of its properties. Recovery of PUDs requires significant capital expenditures and successful drilling operations by the E&P operators of Sitio’s properties. The reserve data included in the reserve report of Sitio’s independent petroleum engineer assume that substantial capital expenditures by the E&P operators of Sitio’s properties are required to develop such reserves. Sitio typically does not have access to the estimated costs of development of these reserves or the scheduled development plans of its E&P operators. Even when Sitio does have such information, Sitio cannot be certain that the estimated costs of the development of these reserves are accurate, that its E&P operators will develop the properties underlying its mineral and royalty interests as scheduled or that the results of such development will be as estimated. The development of such reserves may take longer and may require higher levels of capital expenditures from the E&P operators than Sitio anticipates. Delays in the development of Sitio’s reserves, increases in costs to drill and develop such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of its estimated PUDs and may result in some projects becoming uneconomical for the E&P operators of its properties. In addition, delays in the development of reserves could force Sitio to reclassify certain of its proved reserves as PUDs.

Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the costs incurred by our E&P operators, which in turn could have a negative effect on Sitio’s results of operations and financial condition.

The U.S. inflation rate has been steadily increasing during 2021 and 2022. These inflationary pressures have resulted in and may result in additional increases to the costs incurred by Sitio’s E&P operators, which would in turn have a negative effect on Sitio’s business and financial condition. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022 and the U.S. Federal Reserve has indicated its intention to continue to raise benchmark interest rates into 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which has had the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial results of Sitio’s business.

Events beyond Sitio’s control, including the COVID-19 pandemic or any other future global or domestic health crisis, the ongoing military conflict between Russia and Ukraine, and other risks and uncertainties associated with global economic conditions may result in unexpected adverse financial results.

The continuing or worsening impact of the COVID-19 pandemic or future outbreaks of disease may materially and adversely affect Sitio’s business, financial results and liquidity, due to governmental restrictions, associated repercussions and operational challenges to supply and demand for oil and natural gas and the economy generally. The continued impact of the COVID-19 pandemic is uncertain and hard to predict. While the ongoing effects of the COVID-19 pandemic on Sitio’s business have decreased recently, this pandemic has had a material negative impact on Sitio’s financial results. Although there has been economic recovery and higher oil prices through the year ended December 31, 2022, such negative impact may continue well beyond the containment of the pandemic. While oilfield activity has improved considerably and global inventories have rapidly normalized with continued demand growth since the low point experienced in 2020, considerable uncertainty remains. An extended period of global supply chain and economic disruption, as well as significantly decreased demand for oil and gas, due to the COVID-19 pandemic, any future outbreak of diseases or otherwise, could materially affect Sitio’s business, access to sources of liquidity and financial condition. Additionally, the financial markets and the global economy may also be adversely affected by the current or anticipated impact of military conflict, including the ongoing conflict between Russia and Ukraine, terrorism or other geopolitical events. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which crude oil, natural gas and NGLs from Sitio’s properties are sold, affect the ability of Sitio’s E&P operators to continue operations and ultimately materially adversely impact Sitio’s results of operations, financial condition and cash flows.

Sitio’s hedging activities could result in financial losses and reduce earnings.

To achieve a more predictable cash flow and to reduce Sitio’s exposure to adverse fluctuations in the prices of oil, natural gas and NGLs, Sitio currently has entered, and may in the future enter, into derivative contracts for a portion of its future oil, natural gas and NGL production, including fixed price swaps, collars, and basis swaps. Sitio has not designated and does not plan to designate any of its derivative contracts as hedges for accounting purposes and, as a result, record all derivative contracts on its balance sheet at fair value with changes in fair value recognized in current period earnings. Accordingly, Sitio’s earnings may fluctuate significantly as a result of changes in the fair value of its derivative contracts. Derivative contracts also expose Sitio to the risk of financial loss in some circumstances, including when:

In addition, these types of derivative contracts can limit the benefit Sitio would receive from increases in the prices for oil, natural gas and NGLs.

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

It is not possible to measure underground accumulation of crude oil, natural gas or NGLs in an exact way. Crude oil, natural gas and NGL reserve engineering is not an exact science and requires subjective estimates of underground accumulations of crude oil, natural gas and NGLs and assumptions concerning future crude oil, natural gas and NGL prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may turn out to be incorrect. Over time, Sitio may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. In addition, certain assumptions regarding future crude oil, natural gas and NGL prices, production levels and operating and development costs may prove incorrect. For example, due to the deterioration in commodity prices and operator activity in 2020 as a result of the COVID-19 pandemic and other factors, the commodity price assumptions used to calculate reserves estimates declined, which in turn lowered its proved reserve estimates. A substantial portion of Sitio’s reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect Sitio’s estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery and future cash generated from operations.

Furthermore, certain of the operators of Sitio’s properties are not contractually obligated to provide it with information regarding drilling activities or historical production data with respect to the properties underlying its mineral and royalty interests, which may affect Sitio’s estimates of reserves. Numerous changes over time to the assumptions on which Sitio’s reserve estimates are based, as described above, often result in the actual quantities of crude oil, natural gas and NGLs that are ultimately recovered being different from its reserve estimates.

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

Sitio relies on a small number of key individuals whose absence or loss could adversely affect its business.

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

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Sitio’s E&P operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities. In addition, Sitio’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.

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

Any reduction in Sitio’s E&P operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the expiration of existing leases. If the lease governing any of Sitio’s mineral interests expires or terminates, all mineral rights revert back to Sitio and Sitio will have to seek new lessees to explore and develop such mineral interests. If the lease underlying any of Sitio’s ORRIs expires or terminates, Sitio’s ORRIs that are derived from such lease will also terminate. Any such expirations or terminations of Sitio’s leases or its ORRIs could materially and adversely affect its financial condition, results of operations and cash flows.

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

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

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

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

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

Accounting rules require that Sitio periodically review the carrying value of its properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, production data, economics and other factors, Sitio may be required to write down the carrying value of its properties. Sitio reviews and evaluates the carrying amount of its proved oil, natural gas and NGL properties for impairment whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying value exceeds the estimated undiscounted future cash flows, Sitio would estimate the fair value of its properties and record an impairment charge for any excess of the carrying value of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates and a commensurate discount rate. Because estimated undiscounted future cash flows have exceeded the carrying value of Sitio’s proved properties to date, it has not been necessary for Sitio to estimate the fair value of its properties under GAAP for successful efforts accounting. As a result, Sitio has not recorded any impairment expenses associated with its proved properties. While Sitio did not record any impairment during the years ended December 31, 2022 or 2021, for the year ended December 31, 2020, Sitio recorded an impairment charge of $812,000 in connection with capitalized acquisition costs for a prospective mineral interest acquisition that it did not

complete. The risk that Sitio will be required to recognize impairments of its crude oil, natural gas and NGL properties increases during periods of low commodity prices. In addition, impairments would occur if Sitio were to experience sufficient downward adjustments to its estimated proved reserves or the present value of estimated future net revenues. With respect to estimated unproved reserves, impairments could occur if operators do not drill or sufficiently develop our acreage. An impairment recognized in one period may not be reversed in a subsequent period. Sitio may incur impairment charges in the future, which could materially adversely affect its results of operations for the periods in which such charges are taken.

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

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

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

The marketability of Sitio’s or its E&P operators’ production depends in part on the operation, availability, proximity, capacity and, in some cases, expansion of gathering and transportation facilities, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. Neither Sitio nor its E&P operators control these third-party facilities and Sitio’s E&P operators’ access to them may be limited or denied. Insufficient production from the wells on Sitio’s acreage or a significant disruption in the availability of third-party gathering and transportation facilities or other production facilities could adversely impact Sitio’s E&P operators’ ability to deliver, to market or produce oil and natural gas and thereby cause a significant interruption in Sitio’s operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of crude oil that can be produced and sold is subject to curtailment in certain other circumstances outside of Sitio’s or its operators’ control, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, production from Sitio’s wells may be insufficient to support the construction of pipeline facilities, and the shipment of Sitio’s or its E&P operators’ crude oil, natural gas and NGLs on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, Sitio and its E&P operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any shut in or significant curtailment in gathering system or transportation, processing or refining-facility capacity, or an inability to obtain favorable terms for delivery of the crude oil and natural gas produced from Sitio’s acreage, could reduce Sitio’s or its E&P operators’ ability to market the production from Sitio’s properties and have a material adverse effect on Sitio’s financial condition, results of operations and cash flows. Sitio’s or its E&P operators’ access to transportation options and the prices Sitio or its E&P operators receive can also be affected by federal and state regulation—including regulation of crude oil, natural gas and NGL production, transportation and pipeline safety—as well by general economic conditions and changes in supply and demand.

In addition, the third parties on whom Sitio or its E&P operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting Sitio’s business.

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

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

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

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

The crude oil and natural gas industry is intensely competitive, and the E&P operators of Sitio’s properties compete with other companies that may have greater resources. Many of these companies explore for and produce crude oil, natural gas and NGLs, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low crude oil, natural gas and NGL market prices. Sitio’s E&P operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than Sitio’s E&P operators can, which would adversely affect Sitio’s E&P operators’ competitive position. Sitio’s E&P operators may have fewer financial and human resources than many companies in Sitio’s E&P operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing crude oil and natural gas properties. Furthermore, the crude oil and natural gas industry has experienced consolidation among some operators, which has resulted in certain instances of combined companies with larger resources. Such

combined companies may compete against Sitio’s E&P operators or, in the case of consolidation among Sitio’s E&P operators, may choose to focus their operations on areas outside of Sitio’s properties. In addition, Sitio’s ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transaction in a highly competitive environment.

The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and will impose, separately, new costs on the operations of Sitio’s E&P operators.

On August 16, 2022, President Biden signed the IRA 2022 into law pursuant to the budget reconciliation process. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for oil and gas and consequently materially and adversely affect Sitio’s business. In addition, the IRA 2022 imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge will start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter. Calculation of the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase the operating costs of Sitio’s E&P operators and adversely affect Sitio’s business.

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

Sitio’s E&P operators’ activities on the properties in which Sitio holds interests are subject to various federal, state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity to conserve supplies of crude oil, natural gas and NGLs. For example, in January 2021, President Biden signed an Executive Order that, among other things, instructed the Secretary of the Interior to pause new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices; however, in June 2021, a federal judge for the U.S. District Court of the Western District of Louisiana issued a nationwide preliminary injunction against the pause of new oil and natural gas leases, an injunction which became permanent in August 2022, effectively halting implementation of the leasing suspension with respect to leases canceled or postponed prior to March 24, 2021. In November 2021, the Department of the Interior issued a report recommending various changes to the federal leasing program, and though many such changes would require Congressional action, some recommendations, including royalty rate increases and significant decreases in total offered acreage, have been adopted in recent lease sales. The Inflation Reduction Act of 2022 also incorporated royalty rate increases, raising onshore royalty rates to 16 ⅔%. Substantially all of Sitio’s interests are located on private lands, but Sitio cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. President Biden also issued an Executive Order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency actions during the prior administration that may be inconsistent with the current administration’s policies. For example, in October 2021, the EPA announced that it is reconsidering its 2020 decision to maintain the 2015 National Ambient Air Quality Standards for ground-level ozone and is targeting to complete its reconsideration by the end of 2023. A draft assessment released in April 2022 indicates EPA staff have reached a preliminary conclusion that the December 2020 decision will stand, but uncertainty remains until a final decision is reached. State implementation of the revised standards could, among other things, require installation of new emission controls on some of Sitio’s operators’ equipment, result in longer permitting timelines, and significantly increase the capital expenditures and operating costs of Sitio’s E&P operators.

Further actions of President Biden, and the Biden Administration, including actions focused on addressing climate change, may negatively impact oil and gas operations and favor renewable energy projects in the United States, which may negatively impact the demand for oil and natural gas.

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

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

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

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

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

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

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

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater

from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study, which began in 2018, of private wastewater treatment facilities (also known as centralized waste treatment (“CWT”) facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities. Other government agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and ultimately make it more difficult or costly for Sitio’s E&P operators to perform fracturing activities. Also, from time to time, legislation has been introduced, but not enacted, in the U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. This or other federal legislation related to hydraulic fracturing may be considered again in the future, though Sitio cannot predict the extent of any such legislation at this time.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which Sitio’s properties are located. For example, Texas, Colorado and North Dakota, among others, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. In April 2019, Colorado adopted Senate Bill 19-181, which made sweeping changes in Colorado oil and gas law, including among other matters, requiring the COGCC to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. In keeping with SB 19-181, the COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions established more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminated routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. Additionally, on December 17, 2021, the Colorado Air Quality Control Commission adopted regulations aimed at curbing methane emissions from oil and gas operations to include setting methane emission limits per 1,000 BOE produced, more frequent inspections and limits on emissions during maintenance.

Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water gathered from drilling and production activities, could lead to greater opposition to, and litigation concerning, crude oil, natural gas and NGL production activities using hydraulic fracturing techniques in areas where Sitio owns mineral and royalty interests. Additional legislation or regulation could also lead to operational delays or increased operating costs for Sitio’s E&P operators in the production of crude oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult for Sitio’s E&P operators to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in Sitio’s E&P operators’ completion of new crude oil and natural gas wells on Sitio’s properties and an associated decrease in the production attributable to Sitio’s interests, which could have a material adverse effect on Sitio’s business, financial condition and results of operations.

Conservation measures, technological advances and increasing attention to ESG matters could materially reduce demand for crude oil, natural gas and NGLs, availability of capital and adversely affect Sitio’s results of operations.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy-generation devices, and passage of incentive or funding for renewable energy projects such as those contained in the IRA 2022 could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGL services and products may have a material adverse effect on Sitio’s business, financial condition, results of operations and cash flows. It is also possible that the concerns about the production and use of fossil fuels will reduce the sources of financing available to Sitio. For example, certain segments of the investor community have developed negative sentiment towards investing in the oil and gas industry. Historical equity returns in the sector versus other industry

sectors have led to lower oil and gas representation in certain key equity market indices. While these trends began to reverse in 2022, oil and gas representation in certain key equity market indices remains below its historical peak. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and gas sector based on their social and environmental considerations. Furthermore, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. For further information, see our risk factor entitled “Increased attention to ESG matters and conservation measures may adversely impact Sitio’s business or the business of its operators.” Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. If this negative sentiment continues, it may reduce the availability of capital funding for potential development projects, which could have a material adverse effect on Sitio’s business, financial condition, results of operations and cash flows.

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

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

In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, the Texas Railroad Commission has previously published a 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. In December 2021, the Texas Railroad Commission suspended all disposal well permits to inject oil and gas waste within the boundaries of the Gardendale Seismic Response Area. Relatedly, in March 2022, the Texas Railroad Commission began implementation of its Northern Culberson-Reeves Seismic Response Area Plan to address injection-induced seismicity with the goal to eliminate 3.5 magnitude or greater earthquakes no later than December 31, 2023. 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, Sitio’s operators may be required to curtail operations or adjust development plans, which may adversely impact Sitio’s business.

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. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. In some instances, regulators may also order that disposal wells be shut in.

Sitio’s E&P operators will likely dispose of large volumes of produced water gathered from their drilling and production operations by injecting it into wells pursuant to permits issued by governmental authorities overseeing

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

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

Under the Relinquishment Act of 1919, as amended (the “Relinquishment Act”), the State of Texas owns mineral rights in certain lands. As a result of judicial interpretation of the Relinquishment Act, the surface owner of such lands may act as an agent for the state in negotiating and executing mineral leases, and, if the state approves the lease terms, the applicable surface owner receives an interest in the resulting royalty interest. Approximately 5% of Sitio’s NRAs as of December 31, 2022 were from the rights it received in this manner. However, if the Relinquishment Act were to be amended or repealed or if Sitio were subject to an unfavorable ruling under the Relinquishment Act, Sitio may no longer be able to derive revenue from the corresponding mineral rights, which may have a material adverse effect on its results of operations and cash flows.

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

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

Sitio’s operations, and those of its E&P operators, are subject to a series of risks arising from climate change, which could result in increased operating costs, limit the areas in which natural gas, oil and NGLs production may occur, and reduce demand for the natural gas, oil and NGLs Sitio’s E&P operators produce.

In the United States, no comprehensive climate change legislation has been implemented at the federal level, though the IRA 2022 advances numerous climate-related objectives. However, President Biden has highlighted addressing climate change as a priority of his administration and has issued several Executive Orders to that effect. 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 U.S. Department of Transportation (the “DOT”), implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove

the transmission and storage segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act (“CRA”) to repeal certain provisions of 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 make existing regulations more stringent, expand emission reduction requirements for new, modified, and reconstructed oil and gas emission sources, and require states to develop plans to reduce methane emissions from existing sources. In November 2022, the EPA published a supplemental methane proposal which, among other items, sets forth specific revisions strengthening the first nationwide emission guidelines for states to limit methane emissions from existing crude oil and natural gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys and establishes a “super-emitter” response program to timely mitigate emissions events. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that it will be subject to legal challenges. The scope of any final methane regulatory requirements or the cost to comply with such requirements cannot be predicted at this time. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

At the state level, 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. Additionally, several states, including Pennsylvania and New York, have proceeded with a number of state and regional efforts aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In April 2022, Pennsylvania finalized regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, enabling Pennsylvania to join the Regional Greenhouse Gas Initiative, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states, including New York and Virginia, among others. And, in December 2022, the New York State Climate Action Council approved a Scoping Plan which, among other items, recommends an economy-wide cap-and-invest program to facilitate emission reduction efforts, to include establishment of an enforceable annual cap on GHG emissions for all sectors which would be reduced every year. In January 2023, the Governor of New York directed the Department of Environmental Conservation and the New York State Energy Research and Development Authority to advance such a cap-and-invest program. As a result of these state actions, Sitio’s E&P operators in those areas may experience increased operating costs if they are required to purchase emission allowances in connection with their 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, in November 2021, at the COP26 in Glasgow, 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% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. The full impact of these actions, and any legislation or regulation promulgated to fulfill the United States’ commitments thereunder, is uncertain at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon Sitio’s operations and those of its operators.

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 and in November 2021, the Department of the Interior released a comprehensive report on the federal leasing program, which stated an intent to modernize the federal oil and gas leasing program and resulted in a reduction in the volume of onshore land available for lease and an increased royalty rate. Substantially all of Sitio’s interests are located on private lands, but Sitio 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 liquefied natural gas (“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. Should Sitio be targeted by any such litigation, it may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors. An unfavorable ruling in any such case could significantly impact Sitio’s operations and could have an adverse impact on Sitio’s financial condition.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, 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, and, in September 2022, announced that six of the U.S.’ largest banks would participate in a pilot climate scenario analysis exercise to enhance the ability of firms and supervisors to measure and manage climate-related financial risks. The Federal Reserve released its pilot exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. Although the effects of these actions cannot be fully predicted at this time, any 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, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes; climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook; climate-related targets, goals and transition plan (if any); certain climate-related financial statement metrics in a note to their audited financial statements; Scope 1 and Scope 2 GHG emissions; and Scope 3 GHG emissions and intensity, if material or if the registrant has set a GHG emissions reduction target or goal that includes Scope 3 emissions. If the proposed rule is adopted in its current form, an attestation report from an independent GHG emissions attestation provider will be required to cover Scope 1 and 2 GHG emissions metrics for large accelerated and accelerated filers after the first disclosure year. Additionally, the proposed rule would provide a safe harbor for liability for Scope 3 GHG emissions disclosure and an exemption from the Scope 3 GHG emissions disclosure requirement for smaller reporting companies. A final rule is anticipated to be released in the second quarter of 2023. Although the final form and substance of these requirements is not yet known and the ultimate scope and impact on Sitio’s business is uncertain, compliance with the proposed rule, if finalized, may result in additional legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on Sitio’s personnel, systems and resources. 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 Sitio’s interests. Additionally, political, litigation and financial risks may result in Sitio’s E&P operators restricting or

canceling 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 its interests. One or more of these developments could have a material adverse effect on Sitio’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 Sitio’s operations, as well as those of its 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, which may adversely impact the production or attractiveness of Sitio’s interests.

Increased attention to ESG matters and conservation measures may adversely impact Sitio’s business or the business of its operators.

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

Moreover, while Sitio may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, voluntary disclosures regarding ESG matters, as well as any ESG disclosures mandated by law, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG reduction or neutralization goals or commitments, could result in private litigation and damage Sitio’s reputation, cause Sitio’s investors or consumers to lose confidence in Sitio, or otherwise negatively impact its operations.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward Sitio and its industry and to the diversion of investment to other industries, which could have a negative impact on Sitio’s or its operators’ access to and costs of capital. Also, institutional lenders may, on their own accord, decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect Sitio’s or its operators’ access to capital for potential growth projects. Similarly, insurers may decide not to provide insurance for fossil fuel energy companies, which could impact the price Sitio or its operators must pay for appropriate insurance. Additionally, to the extent ESG matters negatively impact Sitio’s or its operators’ reputation, Sitio or its operators may not be able to compete as effectively to recruit or retain employees, which may adversely affect Sitio’s or its operators’ operations. ESG matters may also impact Sitio’s or its operators’ suppliers and customers, which may ultimately have adverse impacts on Sitio’s or its operators’ operations.

Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have

also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny.

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

Concerns over the risk of climate change have increased the focus by global, regional, national, state and local regulators on GHG emissions, including carbon dioxide emissions, and on transitioning to a lower-carbon future. A number of countries and states have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These regulatory measures may include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency standards, prohibitions on the sales of new automobiles with internal combustion engines, and incentives or mandates for battery-powered automobiles and/or wind, solar or other forms of alternative energy. Compliance with changes in laws, regulations and obligations relating to climate change could result in increased costs of compliance for Sitio’s E&P operators or costs of consuming crude oil, natural gas and NGLs for such products, and thereby reduce demand, which could reduce the profitability of Sitio’s interests. For example, Sitio’s E&P operators may be required to install new emission controls, acquire allowances or pay taxes related to their greenhouse gas emissions, or otherwise incur costs to administer and manage a GHG emissions program. Additionally, Sitio or its operators could incur reputational risk tied to changing customer or community perceptions of its, its E&P operators’ or its E&P operators’ customers contribution to, or detraction from, the transition to a lower-carbon economy. These changing perceptions could lower demand for oil and gas products, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries, and could also pressure banks and investment managers to shift investments and reduce lending.

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

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

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

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). In August 2019, the United States Fish and Wildlife Services (“FWS”) and National Marine Fisheries Service (“NMFS”) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states challenged the three rules and the litigation was stayed after President Biden issued an Executive Order directing the agencies to review the rules. Following this review, the FWS and NMFS requested remand of the final rules without vacatur; however, in July 2022, the United States District Court for the Northern District of California vacated and remanded the three rules. The United States Court of Appeals for the Ninth Circuit later stayed the vacatur, requiring the District Court to reconsider its decision. Subsequent to the decision, the FWS and NMFS informed the District Court that potential revisions to the rules could be completed on or before May 2023 with final revisions to be completed by May 2024. Separately, on December 18, 2020, the FWS amended its regulations governing critical habitat designations. However, in July 2022, the FWS issued a final rule rescinding these amendments. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where Sitio’s E&P operators operate, Sitio’s E&P operators’ abilities to conduct or expand operations could be limited, or Sitio’s E&P operators could be forced to incur material additional costs. Moreover, Sitio’s E&P operators’ drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. For

example, in November 2022, following an extensive review, the FWS listed two distinct population segments of the Lesser Prairie Chicken. The northern distinct population segment, encompassing southeastern Colorado, southcentral to western Kansas, western Oklahoma, and the northeast Texan Panhandle, is listed as threatened while the southern district population segment, covering eastern New Mexico and the southwest Texas Panhandle, is listed as endangered. Relatedly, in June 2022, FWS approved a habitat conservation plan for the Lesser Prairie Chicken, which allows oil and gas operators to receive an “incidental take” permit in exchange for purchasing credits from a conservation bank and agreeing to certain conservation practices. Recently, there have also been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, and to reconsider listing the species under the ESA. In August 2022, the FWS filed a stipulated settlement agreement in a case challenging its failure to timely make a twelve-month finding on a petition to list the dunes sagebrush lizard. Under the agreement, the FWS will submit a twelve-month finding on the petition no later than June 29, 2023.

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

We are subject to extensive government laws and regulations concerning our employees, and the cost of compliance with such laws and regulations could be material.

Regulations related to wages and other compensation affect our business. Any appreciable increase in applicable employment laws and regulations, including the statutory minimum wage, exemption levels, or overtime regulations, could result in an increase in labor costs. Such cost increases, or the penalties for failing to comply with such statutory minimums, could adversely affect our business, financial condition, results of operations and cash available for distribution to our shareholders. In addition, we are directly and indirectly affected by new tax legislation and regulation and the interpretation of tax laws and regulations. Any changes in employment, benefit plan, tax or labor laws or regulations or new regulations proposed from time to time, could have a material adverse effect on our employment practices, our business, financial condition, results of operations and cash available for distribution to our shareholders.

We have relied on an exclusion from the definition of “investment company” in order to avoid being subject to the Investment Company Act of 1940, or the 1940 Act. To the extent the nature of our business changes in the future, we may become subject to the requirements of the 1940 Act, which would limit our business operations and require us to spend significant resources in order to comply with such Act.

The 1940 Act defines an “investment company,” among other things, as an issuer that is engaged in the business of investing, reinvesting, owning, holding or trading in securities and owns investment securities having a value exceeding 40 percent of the issuer’s unconsolidated assets, excluding cash items and securities issued by the federal government. The definition of “securities” under the 1940 Act includes “fractional undivided interest in oil, gas, or other mineral rights.” However, the 1940 Act excludes from this definition any person substantially all of whose business consists of owning or holding such oil, gas or other mineral royalties or leases or fractional interests therein, or certificates of interest or participation relating to such mineral royalties or leases. We believe that we satisfy this mineral company exception to the definition of “investment company.” If our reliance on the mineral company exclusion from the definition of investment company is misplaced, we may have been in violation of the 1940 Act, the consequences of which can be significant. For example, investment companies that fail to register under the 1940 Act are prohibited from conducting business in interstate commerce, which includes selling securities or entering into other contracts in interstate commerce.

Moreover, we are a holding company and our sole material asset is our equity interest in Sitio OpCo. As the sole general partner of Sitio OpCo, we manage and control Sitio OpCo. On that basis, we believe that our interest in Sitio OpCo is not an “investment security” under the 1940 Act. However, if we were to lose the right to manage and control Sitio OpCo, interests in Sitio OpCo could be deemed to be “investment securities” under the 1940 Act.

If in the future the nature of our business changes, or a regulatory agency would disagree with our analysis regarding the exclusion from the 1940 Act, such that the mineral company exception to the threshold definition of investment company is not available to us, and we cease to manage and control Sitio OpCo and our interest in OpCo is determined to be an “investment security,” we will be required to register as an investment company with the SEC. The ramifications of becoming an investment company, both in terms of the restrictions it would have on our Company and the cost of compliance, would be significant. For example, in addition to expenses related to initially registering as an investment company, the 1940 Act also imposes various restrictions with regard to our ability to enter into affiliated transactions, the diversification of our assets and our ability to borrow money. If we became subject to the 1940 Act at some point in the future, our ability to continue pursuing our business plan would be severely limited as it would be significantly more difficult for us to raise additional capital in a manner that would comply with the requirements of the 1940 Act.

Any significant contraction in the reserve-based lending syndication market may negatively impact Sitio’s ability to fund its operations.

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

In addition, during previous periods of economic instability, it has been difficult for many companies to obtain financing in the public markets or to obtain debt financing, and during any future period of economic instability Sitio may not be able to obtain additional financing on commercially reasonable terms, if at all, including as a result of recent increases in cost of capital resulting from Federal Reserve policies and otherwise. If Sitio is unable to obtain adequate financing or financing on terms satisfactory to it, Sitio could experience a material adverse effect on its business, financial condition and results of operations.

Restrictions in our Third Amended and Restated Credit Agreement, the 2026 Senior Notes and future debt agreements of Sitio and Sitio OpCo could limit its growth and its ability to engage in certain activities.

On May 16, 2019, Brigham Resources, LLC (“Brigham Resources”) entered into that certain Credit Agreement (as amended or otherwise modified and as in effect immediately prior to the Closing Date, the “Brigham Credit Agreement”) with Wells Fargo Bank, N.A., as the administrative agent, letter of credit issuer, sole lead arranger and bookrunner, pursuant to which the lenders thereunder made loans and other extensions of credit to Brigham Resources. Certain subsidiaries of Brigham Resources (together with Brigham Resources and Brigham Minerals Holdings, LLC, a Delaware limited liability company, the “Brigham Entities”) guaranteed the obligations under the Brigham Credit Agreement.

On June 7, 2022, Sitio OpCo, as borrower, KMF Land, LLC, a Delaware limited liability company, Bank of America, N.A., as the administrative agent and issuing bank, and certain lenders entered into that certain Second Amended and Restated Credit Agreement (as amended, restated, supplemented or otherwise modified and as in effect immediately prior to the Closing Date, the “Existing Credit Agreement”), pursuant to which the lenders thereunder made loans and other extensions of credit to the borrower thereunder.

On February 3, 2023, the Existing Credit Agreement was amended and restated in its entirety pursuant to a Third Amended and Restated Credit Agreement (as amended, restated, supplemented or otherwise modified from time to time, the “New Credit Agreement”) entered into by Sitio OpCo, as borrower, JPMorgan Chase Bank, N.A., as the

administrative agent (as successor administrative agent to Bank of America, N.A.) and as issuing bank, the lenders and other financial institutions from time to time party thereto (the “Lenders”). The New Credit Agreement refinanced the Existing Credit Agreement in full and paid off the Brigham Credit Agreement in full. The New Credit Agreement has a scheduled maturity date that is the earlier of June 2027 or 180 days prior to the maturity of any outstanding senior notes.

Pursuant to the terms and conditions of the New Credit Agreement, the Lenders committed to providing a credit facility to Sitio OpCo in an aggregate principal amount of up to $1.5 billion. The availability under the New Credit Agreement, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of the proved reserves of Sitio OpCo and its subsidiaries and elected commitments provided by the Lenders. As of February 3, 2023, the New Credit Agreement has a $750 million borrowing base and $750 million elected commitment amount. As part of the aggregate commitments under the revolving advances, the New Credit Agreement provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15 million. Our New Credit Agreement contains customary affirmative and negative covenants, including, without limitation, reporting obligations, financial covenants, restrictions on asset sales, restrictions on additional debt and lien incurrence, restrictions on our ability to make certain fundamental changes to our business, restrictions on hedging arrangements and restrictions on making investments and distributions. Our ability to make distributions is subject to satisfaction of certain conditions, including no event of default, no borrowing base deficiency, liquidity of at least 10% of the total commitments under the New Credit Agreement, and a pro forma leverage ratio not to exceed 3.00:1.00. While the 2026 Senior Notes (as defined below) remain outstanding, the amount of such distributions may be further limited to 65% of discretionary cash flow if our leverage ratio at the end of the most recent fiscal quarter is above 1.00:1.00, or 100% of discretionary cash flow if our leverage ratio is under 1.00:1.00 unless the 2026 Senior Notes waive or do not impose such discretionary cash flow restriction.

On September 21, 2022, Sitio OpCo, as issuer, and certain subsidiaries of Sitio OpCo, as guarantors, entered into the Note Purchase Agreement (the “Note Purchase Agreement”) with certain institutional investors party thereto as holders (the “Holders”) and U.S. Bank Trust Company, National Association, as agent for the Holders (the “Agent”).

Pursuant to the Note Purchase Agreement, Sitio OpCo issued senior unsecured notes to the Holders in an aggregate principal amount of $450.0 million (the “2026 Senior Notes”). Sitio OpCo used $425.0 million of the proceeds from the 2026 Senior Notes to repay in full all amounts outstanding under the Bridge Loan Facility (as defined below) with the remainder used for general corporate purposes. The 2026 Senior Notes mature on September 21, 2026.

The Note Purchase Agreement includes, among other terms and conditions, a maximum leverage ratio covenant, as well as customary mandatory prepayments, representations, warranties, covenants and events of default, including, among others, a change of control event of default, as well as limitations on the incurrence of indebtedness and liens, stock buybacks, distributions, new lines of business, mergers, transactions with affiliates and burdensome agreements. During the continuance of an event of default, the Holders may take a number of actions, including, among others, declaring the entire amount of the 2026 Senior Notes and other amounts then outstanding under the Note Purchase Agreement to be due and payable. The Note Purchase Agreement requires Sitio OpCo to maintain a leverage ratio as of the last day of each fiscal quarter (beginning December 31, 2022) of not more than 3.50 to 1.00. As of December 31, 2022, Sitio OpCo was in compliance with the terms and covenants of the 2026 Senior Notes.

Sitio’s debt levels may limit its flexibility to obtain additional financing and pursue other business opportunities.

Sitio’s existing and any future indebtedness could have important consequences to it, including:

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

Sitio is a holding company whose sole material asset is its equity interest in Sitio OpCo. Accordingly, Sitio is dependent upon distributions from Sitio OpCo to pay taxes, cover its corporate and other overhead expenses and pay any dividends on its Class A Common Stock.

Sitio is a holding company with no material assets other than its equity interest in Sitio OpCo. Sitio has no independent means of generating revenue and to the extent Sitio OpCo has available cash, Sitio OpCo is generally required to make pro rata cash distributions to all its unitholders, including Sitio, in an amount sufficient for Sitio to pay its U.S. federal, state, local and non-U.S. tax liabilities. Sitio OpCo may also make non-pro rata cash distributions periodically to enable Sitio to cover its corporate and other overhead expenses. In addition, as the sole managing member of Sitio OpCo, Sitio intends to cause Sitio OpCo to make pro rata cash distributions to all of its unitholders, including to Sitio, in an amount sufficient to fund dividends to its stockholders, to the extent Sitio’s Board declares such dividends. Therefore, although Sitio expects to pay dividends on its Class A Common Stock in amounts determined from time to time by the Board, Sitio’s ability to do so may be limited to the extent Sitio OpCo and its subsidiaries are limited in their ability to make these and other distributions to Sitio. To the extent that Sitio needs funds and Sitio OpCo or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect Sitio’s liquidity and financial condition. Sitio’s ability to pay dividends to its stockholders may be limited by its holding company structure, contractual restrictions and regulatory requirements.

Although Sitio expects to pay dividends on its Class A Common Stock, the Board will take into account general economic and business conditions, including Sitio’s financial condition and results of operations, capital requirements, contractual restrictions, including restrictions and covenants contained in its debt agreements, business prospects and other factors that Sitio’s Board considers relevant in determining whether, and in what amounts, to pay such dividends.

Sitio’s sponsors hold a significant amount of the outstanding Class C Common Stock that provides them with significant influence over Sitio, and their interests may conflict with those of Sitio’s other stockholders.

Collectively, (i) KMF DPM HoldCo, LLC (“KMF”) and Chambers DPM HoldCo, LLC (“Chambers,” and together with KMF, “Kimmeridge”), (ii) BX Royal Aggregator LP, a Delaware limited partnership (“Royal Aggregator”) and Rock Ridge Royalty Company LLC, a Delaware limited liability company (together with Royal Aggregator, “Blackstone”) and (iii) Source Energy Leasehold, LP, a Delaware limited partnership (“Source”) and Permian Mineral Acquisitions, LP (together with Source, “the Source Stockholders”) (collectively, the “Sponsors”) hold the substantial majority of the outstanding Class C Common Stock of the Company (the “Class C Common

Stock”). Each share of Class C Common Stock has no economic rights, but entitles the holder thereof to one vote for each share of Class C Common Stock held by such holder. Holders of Class C Common Stock are entitled to one vote for each share held on all matters to be voted on by Sitio’s stockholders and, with the holder of Class A Common Stock, vote together as a single class on all matters submitted to a vote of Sitio’s stockholders, except as required by law or Sitio’s Amended and Restated Certificate of Incorporation (the “A&R Charter”). As a result, the Sponsors hold approximately 45% of the voting power over Sitio, which may provide them with significant influence over matters requiring stockholder approval, including the election of directors, changes to organizational documents and significant corporate transactions. This concentration of ownership and relationship with the sponsors makes it unlikely that any other holder or group of holders of our Common Stock will be able to affect the way we are managed or the direction of our business. As a result of their significant influence, the sponsors may support certain decisions that could involve risks to, or that may conflict with the interests of, our other stockholders.

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

Distributions of cash or property on Sitio’s Class A Common Stock, if any, will constitute dividends for U.S. federal income tax purposes to the extent paid from its current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed Sitio’s current and accumulated earnings and profits, the distributions will be treated as a non-taxable return of capital to the extent of the holder’s tax basis in Sitio’s Class A Common Stock and thereafter as capital gain from the sale or exchange of such common stock. Also, if any holder sells its Class A Common Stock, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in such Class A Common Stock.

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

Prospective investors in Sitio’s Class A Common Stock are encouraged to consult their tax advisors as to the tax consequences of receiving distributions on its Class A shares that are not treated as dividends for U.S. federal income tax purposes.

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

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

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

There is no guarantee that the Public Warrants will be in the money and they may expire worthless.

Four whole Warrants (as defined below) are exercisable for one share of Class A Common Stock at an exercise price of $44.84 per share of Class A Common Stock. Pursuant to the Contribution Agreement, to the extent that any common stock dividend paid by Sitio, when combined with other common stock dividends paid in the prior 365 days, exceeds $2.00, it is categorized as an “Extraordinary Dividend.” Extraordinary Dividends reduce, penny for penny, the exercise price of Warrants. There is no guarantee that the Warrants will be in the money prior to their expiration, and as such, the Warrants may expire worthless.

Sitio may amend the terms of the Warrants in a manner that may be adverse to holders with the approval by the holders of at least 65% of the then outstanding Public Warrants. As a result, the exercise price of the Warrants could be increased, the exercise period could be shortened and the number of shares of Sitio’s Class A Common Stock purchasable upon exercise of a warrant could be decreased, all without the warrantholder’s approval.

In connection with its initial public offering, Sitio issued warrants by private placement (each, a “Private Placement Warrant”) and sold warrants to the public (each, a “Public Warrant,” and together with the Private Placement Warrants, the “Warrants”). The Warrants were issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us. The warrant agreement provides that the terms of the Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision but requires the approval by the holders of at least 65% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders. Accordingly, Sitio may amend the terms of the Public Warrants in a manner adverse to a holder if holders of at least 65% of the then outstanding Public Warrants approve of such amendment. Although Sitio’s ability to amend the terms of the Public Warrants with the consent of at least 65% of the then outstanding Public Warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the Warrants, shorten the exercise period, or decrease the number of shares of Class A Common Stock purchasable upon exercise of a Warrant.

Sitio may redeem unexpired Warrants prior to their exercise at a time that is disadvantageous to warrant holders, thereby making their warrants worthless.

Sitio has the ability to redeem outstanding Warrants at any time prior to their expiration, at a price of $0.01 per Warrant, provided that the last reported sales price of Class A Common Stock equals or exceeds $72.00 per share for any 20 trading days within a 30-trading day period ending on the third trading day prior to the date Sitio sends the notice of redemption to the warrantholders. If and when the Warrants become redeemable by Sitio, it may exercise its redemption right even if it is unable to register or qualify the underlying securities for sale under all applicable state securities laws. Redemption of the outstanding Warrants could force the warrantholders (a) to exercise their Warrants and pay the exercise price therefor at a time when it may be disadvantageous for them to do so, (b) to sell their Warrants at the then-current market price when they might otherwise wish to hold their Warrants or (c) to accept the nominal redemption price which, at the time the outstanding Warrants are called for redemption, is likely to be substantially less than the market value of their Warrants. None of the Private Placement Warrants will be redeemable by Sitio so long as they are held by Sitio’s sponsor, Osprey Sponsor, LLC (“Falcon Sponsor”), or its permitted transferees.

Warrants may be exercised for Class A Common Stock, which would increase the number of shares eligible for future resale in the public market and result in dilution to stockholders.

Sitio issued Warrants to purchase 13,749,998 shares of Class A Common Stock as part of its initial public offering and concurrent with its initial public offering, Sitio issued an aggregate of 7,500,000 Private Placement Warrants to Falcon Sponsor. Four whole Warrants are exercisable for one share of Class A Common Stock at an exercise price of $44.84 per share of Class A Common Stock. To the extent such Warrants are exercised, additional shares of Class A

Common Stock will be issued, which will result in dilution to the then existing holders of Class A Common Stock and increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of Sitio’s Class A Common Stock. The Private Placement Warrants are identical to the warrants sold as part of the units issued in the initial public offering, except that, so long as they are held by Falcon Sponsor or its permitted transferees, (a) they will not be redeemable by Sitio and (b) they may be exercised by the holders on a cashless basis.

If additional stock consideration is issued to Royal pursuant to the earn-out provided for in the Contribution Agreement, it would increase the number of shares eligible for future resale in the public market and result in dilution to Sitio’s stockholders.

Pursuant to the Contribution Agreement, dated as of June 3, 2018, by and among Sitio, Royal Resources L.P. (“Royal”), Royal Resources GP L.L.C., Noble Royalties Acquisition Co., LP (“NRAC”), Hooks Ranch Holdings LP (“Hooks Holdings”), DGK ORRI Holdings, LP (“DGK”), DGK ORRI GP LLC (“DGK GP”) and Hooks Holding Company GP, LLC (“Hooks GP,” and collectively with NRAC, Hooks Holdings, DGK, and DGK GP, the “Contributors”) (the “Contribution Agreement”), Royal is entitled to receive earn-out consideration to be paid in the form of Sitio OpCo Partnership Units (and a corresponding number of shares of Class C Common Stock) if the 30-Day VWAP of the Class A Common Stock equals or exceeds certain hurdles set forth in the Contribution Agreement. Royal can potentially receive up to an additional 20.0 million Sitio OpCo Partnership Units as a part of the earn-out consideration. Royal is also entitled to the earn-out consideration described above in connection with certain liquidity events of Sitio, including a merger or sale of all or substantially all of Sitio’s assets, if the consideration paid to holders of the Class A Common Stock in connection with such liquidity event is greater than any of the 30-Day VWAP hurdles. Because any Sitio OpCo Partnership Units issued pursuant to the earn-out are redeemable on a one-for-one basis for shares of Class A Common Stock at the option of the Contributors, the issuance of additional stock consideration pursuant to the earn-out will result in dilution to the then existing holders of Class A Common Stock and increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of Class A Common Stock.

A significant portion of Sitio’s total outstanding shares may be sold into the market in the near future. This could cause the market price of its Class A Common Stock to drop significantly, even if Sitio’s business is doing well.

Sales of a substantial number of shares of Class A Common Stock in the public market could occur at any time. These sales, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of Sitio’s Class A Common Stock.

Additionally, the Sponsors and Sitio’s executive officers own over 94% of the outstanding Class C Common Stock and hold an equivalent number of Sitio OpCo Partnership Units for each such share of Class C Common Stock. Each share of Class C Common Stock has no economic rights. However, holders of Class C Common Stock are entitled to one vote for each share held on all matters to be voted on by Sitio’s stockholders and, with the holder of Class A Common Stock, vote together as a single class on all matters submitted to a vote of Sitio’s stockholders, except as required by law or the A&R Charter. Each holder of Sitio OpCo Partnership Units has the right to cause Sitio OpCo to redeem all or a portion of its Sitio OpCo Partnership Units for shares of Class A Common Stock or, under certain circumstances and at Sitio OpCo’s election, an equivalent amount of cash. In connection with any such redemption, a corresponding number of shares of Class C Common Stock will be canceled. If the holders of Sitio OpCo Partnership Units redeem or exchange all of their Sitio OpCo Partnership Units for shares of Class A Common Stock, and no shares of Class A Common Stock are otherwise issued, they will own approximately 48% of Sitio’s Class A Common Stock.

Sitio has filed a registration statement registering (A) shares of Class A common stock issuable upon the exercise of warrants initially purchased from Sitio’s predecessor by Osprey Sponsor, LLC, and (B) shares of Class A Common Stock issued or issuable upon the redemption of common units representing limited partnership interests in Sitio OpCo (together with the cancellation of an equal number of shares Class C Common Stock), held by the parties to (1) a registration rights agreement, dated as of August 23, 2018, entered into by Sitio’s predecessor in connection with Sitio’s predecessor’s initial public offering, (2) a registration rights agreement, dated as of January 11, 2022, entered into in connection with the Falcon Merger, and (3) a registration rights agreement, dated as of December 29, 2022, entered into in connection with the Brigham Merger.

If securities or industry analysts do not publish research or reports or publish unfavorable research about Sitio’s business, the price and trading volume of Sitio’s Class A Common Stock could decline.

The trading market for Sitio’s Class A Common Stock depends in part on the research and reports that securities or industry analysts publish about Sitio or its business. In the event one or more of the analysts who covers Sitio downgrades its securities, the price of its securities would likely decline. If one or more of these analysts ceases to cover Sitio or fails to publish regular reports on Sitio, interest in the purchase of Sitio’s securities could decrease, which could cause the price of its Class A Common Stock and other securities and their trading volume to decline.

If Sitio fails to develop or maintain an effective system of internal controls over its financial reporting, its financial results may not be reported accurately and timely or prevent fraud, which may result in material misstatements in its financial statements or failure to meet periodic reporting obligations. As a result, current and potential stockholders could lose confidence in Sitio’s financial reporting, which would harm its business and the trading price of its Class A Common Stock.

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

Effective internal controls are necessary to provide reliable financial reports, prevent fraud and operate successfully as a public company. If Sitio cannot provide reliable financial reports or prevent fraud, its reputation and operating results may be harmed. Sitio cannot be certain that its efforts to maintain its internal controls will be successful, that it will be able to maintain adequate controls over its financial processes and reporting in the future or that it will be able to comply with its obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving internal controls, could harm Sitio’s operating results or cause it to fail to meet its reporting obligations. Ineffective internal controls could also cause investors to lose confidence in its reported financial information, which would likely have a negative effect on the trading price of Sitio’s Class A Common Stock. Additional material weaknesses may be identified in the future. If Sitio identifies such issues or if it is unable to produce accurate and timely financial statements, the trading price of its Class A Common Stock may decline and Sitio may be unable to maintain compliance with the NYSE listing standards.

Provisions in the A&R Charter may prevent or delay an acquisition of us, which could decrease the trading price of Class A Common Stock, or otherwise may make it more difficult for certain provisions of the A&R Charter to be amended.

The A&R Charter contains provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with the Board rather than to attempt a hostile takeover. These provisions include:

These provisions apply even if the offer may be considered beneficial by some stockholders and could delay or prevent an acquisition that the Board determines is not in Sitio and its stockholders’ best interests.

In addition, the A&R Charter requires the affirmative vote of the holders of at least 75% of the voting power of all outstanding shares of capital stock of Sitio to amend, repeal or adopt certain provisions of the A&R Charter relating to the board of directors, the bylaws, meetings of stockholders, indemnification of officers and directors, waiver of corporate opportunities, exclusive forum, amendments to the A&R Charter and Delaware’s business combinations statute. This requirement will make it more difficult for these provisions of the A&R Charter, which include the provisions intended to deter coercive takeover practices and inadequate takeover bids, to be amended.

Sitio may issue preferred stock whose terms could adversely affect the voting power or value of its Class A Common Stock.

The A&R Charter authorizes the Board to issue, without the stockholder approval, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over Sitio’s Class A Common Stock respecting dividends and distributions, as the Board may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of Class A Common Stock. For example, holders of a class or series of Sitio’s preferred stock may be granted the right to elect some number of directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, holders of preferred stock may be assigned the repurchase or redemption rights or liquidation preferences which could affect the residual value of Sitio’s Class A Common Stock.

The A&R Charter designates the Court of Chancery of the State of Delaware (or, if the Court of Chancery of the State of Delaware does not have jurisdiction, any state or the federal court sitting in the State of Delaware with jurisdiction over the matter) to the fullest extent permitted by applicable law, as the sole and exclusive forum for (a) any derivative action or proceeding brought on Sitio’s behalf, (b) any action asserting a claim of breach of a fiduciary duty owed by any of Sitio’s directors, officers, employees or agents to Sitio or Sitio’s stockholders, (c) any action asserting a claim arising pursuant to any provision of Delaware General Corporation Law (the “DGCL”), the A&R Charter or Sitio’s bylaws or (d) any action asserting a claim against Sitio that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of Sitio’s capital stock is deemed to have notice of, and consented to, the provisions of the A&R Charter described in the preceding sentence. This provision does not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. This choice of forum provision may limit the ability of stockholders to obtain a favorable judicial forum for disputes with Sitio or with Sitio’s directors, officers or employees and may discourage stockholders from bringing such claims. Alternatively, if a court were to find these provisions of the A&R Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, Sitio may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect Sitio’s business, financial condition, and results of operations.

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

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

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

Like many crude oil and natural gas companies, Sitio may from time to time be involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of its business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on Sitio because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in Sitio’s business practices, which could materially and adversely affect its business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

We are subject to cybersecurity risks. A cyber incident or systems failure could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and gas industry, including the mineral and royalty space, has become increasingly dependent on digital technologies to conduct certain activities. For example, we depend on digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. For example, in May 2021 the Colonial Pipeline’s digital systems were infected by a ransomware attack that caused the shutdown of the pipeline for several days and the payment of an approximate $4.4 million ransom. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. Our insurance coverage for cyber-attacks may not be sufficient to cover all the losses we may experience as a result of such cyber-attacks.

Our executive offices are located at 1401 Lawrence Street, Suite 1750, Denver, CO 80202. We have additional leased office space at 609 Main Street, Suite 3950 Houston, TX 77002 and 5914 W. Courtyard Drive, Suite 150, Austin, TX 78730. We believe that these facilities are adequate for our current operations. Additional information regarding our properties in contained in Item 1. “Business” and is incorporated herein.

From time to time, the Company may be involved in various legal proceedings, lawsuits, and other claims in the ordinary course of business. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance. Management does not believe that the resolution of these matters will have a material adverse impact on our financial condition, cash flows or results of operations.

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Class A common stock is listed on the New York Stock Exchange under the symbol “STR.” Our warrants are listed on the NYSE American under the symbol “STR WS.” Our Class C Common Stock is not listed on any exchange.

Pursuant to the records of our transfer agent, as of March 3, 2023, there were approximately 60 holders of record of our Class A common stock, 64 holders of record of our Class C common stock and five holders of record for our warrants. This number does not include owners, stockholders or warrant holders who beneficially own our shares through a broker or other entity who may hold shares in “street name.” There is no public market for our Class C Common Stock.

On November 8, 2022, the Company declared a cash dividend of $0.72 per share of Class A common stock with respect to the third quarter of 2022. The dividend was paid on November 30, 2022 to the stockholders of record at the close of business on November 21, 2022. The Company’s dividend policy is within the discretion of the Board, and all future dividend payments are subject to quarterly review and approval by the Board and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in the Company’s revolving credit facilities, and other factors the Board may deem relevant.

See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

The performance graph below compares the cumulative total returns of our Class A common stock over the period from December 31, 2017 through December 31, 2022 with the cumulative total returns for the same period for the Standard and Poor’s (“S&P”) 500 Index and the SPDR S&P Oil & Gas Exploration & Production ETF (“XOP”). XOP is a weighted composite of 59 oil and gas exploration and productions companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our Class A common stock on December 31, 2017, and in the S&P 500 Index and XOP on the same date. The results shown in the graph below are not necessarily indicative of future performance.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements and notes thereto included elsewhere in this Annual Report. Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for periods prior the Falcon Merger and the Brigham Merger reflect only the historical financial results of Desert Peak prior to the consummation of the Falcon Merger and Brigham Merger, respectively.

The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to several factors which include, but are not limited to market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital for mineral acquisitions, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and those discussed in the sections entitled Item 1A. “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

As of December 31, 2022, we owned mineral and royalty interests representing over 260,600 NRAs when adjusted to a 1/8th royalty. For the year ended December 31, 2022, the average net daily production associated with our mineral and royalty interest was 15,204 BOE/d, consisting of 7,838 Bbls/d of oil, 26,112 Mcf/d of natural gas and 3,015 Bbls/d of NGLs. Prior to the closing of the Falcon Merger, the Company’s financial statements that were filed with the SEC were derived from the accounting records of Falcon Minerals Corporation. As such, the historical consolidated financial statements included in this report are based on the financial statements of Desert Peak’s predecessor, Kimmeridge Mineral Fund, LP (“KMF” or the “Predecessor”), prior to our corporate reorganization. Since our Predecessor’s formation in November 2016, we have accumulated our acreage position by making 187 acquisitions. We expect to continue to grow our acreage position by making acquisitions that meet our investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

Our mineral and royalty interests entitle us to receive a fixed percentage of the revenue from crude oil, natural gas and NGLs produced from the acreage underlying our interests. We are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production and we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs which reduce the amount of revenue we recognize. For the year ended December 31, 2022, our production and ad valorem taxes were approximately $4.61 per BOE, relative to an average realized price of $64.05 per BOE. We do not anticipate engaging in any upstream activities such as engaging in drilling and completing oil and natural gas wells that would incur capital costs. We believe our cost structure and business model will allow us to return a significant amount of our cash flows to stockholders.

On February 3, 2023, the Sitio Credit Agreement was amended, restated and refinanced in its entirety pursuant to a Third Amended and Restated Credit Agreement (the “New Credit Agreement”). The New Credit Agreement refinanced the Sitio Credit Agreement in full and paid off the Brigham Revolving Credit Facility in full.

Pursuant to the terms and conditions of the New Credit Agreement, the Lenders committed to provide a senior secured revolving credit facility to Sitio Operating Partnership, LP, (“Sitio OpCo”) in an aggregate principal amount of up to $1.5 billion. The availability under the New Credit Agreement, including availability of letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating the loan value of the proved reserves of Sitio OpCo and its subsidiaries and elected commitments provided by the Lenders. At the time of close, the New Credit Agreement had a $750.0 million borrowing base and $750.0 million elected commitment amount. As part of the aggregate commitments under the revolving advances, the New

Credit Agreement provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15.0 million.

On December 29, 2022, the Company, consummated the previously announced merger transactions contemplated by the Brigham Merger Agreement, dated as of September 6, 2022. The Brigham Merger Agreement provides for the acquisition of Brigham by Former Sitio in an all stock transaction (the “Brigham Merger”).

On the terms and subject to the conditions set forth in the Brigham Merger Agreement, (i) at the First Effective Time (as defined in the Brigham Merger Agreement), (A) each share of Brigham’s Class A common stock, par value $0.01 per share, issued and outstanding immediately prior to the First Effective Time was converted into the right to receive 1.133 fully-paid and nonassessable shares of Class A Common Stock, (B) each share of the Brigham’s Class B common stock, par value $0.01 per share, issued and outstanding immediately prior to the First Effective Time was converted into the right to receive 1.133 fully-paid and nonassessable shares of Class C Common Stock, (C) each share of Former Sitio’s Class A Common Stock, issued and outstanding immediately prior to the First Effective Time was converted into one share of Class A Common Stock and (D) each share of Former Sitio’s Class C Common Stock issued and outstanding immediately prior to the First Effective Time, was converted into one share of Class C Common Stock, in each case, excluding shares owned by Former Sitio, Brigham or any wholly owned subsidiary of Former Sitio or Brigham and, to the extent applicable, shares owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to the DGCL and, (ii) at the Second Effective Time, each Brigham Opco Unit (as defined in the Brigham Merger Agreement) issued and outstanding immediately prior to the Second Effective Time was converted into the right to receive 1.133 Sitio OpCo Partnership Units.

As of December 31, 2022, we have evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 187 acquisitions from landowners and other mineral interest owners. We intend to capitalize on our management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in premier basins designed to increase our cash flows per share.

Our average daily production during the years ended December 31, 2022, 2021 and 2020 was 15,204 BOE/d (52% crude oil), 6,989 BOE/d (49% crude oil) and 5,764 BOE/d (44% crude oil), respectively. For the year ended December 31, 2022, we received an average of $93.05 per Bbl of crude oil, $5.50 per Mcf of natural gas and $33.51 per Bbl of NGLs, for an average realized price of $64.05 per BOE. For the year ended December 31, 2021, we received an average of $67.29 per Bbl of crude oil, $3.61 per Mcf of natural gas and $33.22 per Bbl of NGLs, for an average realized price of $46.47 per BOE. For the year ended December 31, 2020, we received an average of $37.40 per Bbl of crude oil, $1.03 per Mcf of natural gas and $10.32 per Bbl of NGLs, for an average realized price of $20.95 per BOE.

As of December 31, 2022, we had 32,451 gross (239.9 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2022, there were 4,254 gross (31.1 net) horizontal wells in various stages of drilling or completion and 3,223 (16.8 net) active horizontal drilling permits on our acreage. As of December 31, 2021, we had 7,722 gross (59.4 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2021, there were 1,408 gross (10.2 net) horizontal wells in various stages of drilling or completion and 1,093 active (6.7 net) horizontal drilling permits on our acreage. As of December 31, 2020, we had 2,537 gross (25.7 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2020, there were 362 gross (3.8 net) horizontal wells in various stages of drilling or completion and 383 (2.4 net) active horizontal drilling permits on our acreage.

The economy is experiencing elevated inflation levels as a result of global supply and demand imbalances, where global demand continues to outpace current supplies. The U.S. Bureau of Labor Statistics Consumer Price Index for all urban consumers increased 8% from December 2021 to December 2022 as compared to the average annual increase of 3% over the previous 10 years. In order to manage the inflation risk currently present in the United States’ economy,

the Federal Reserve has utilized monetary policy in the form of interest rate increases in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. These interest rate increases generally impact our borrowing costs as borrowings on our credit facilities and our 2026 Senior Notes are at variable rates which fluctuate with broader interest rates in the market.

The global economy also continues to be impacted by the effects of the COVID-19 pandemic, as discussed in more detail below, and global events, among other factors. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia, as discussed in more detail below, and other global trade restrictions, among others. As we do not explore, develop or operate on our oil and gas properties, we have not experienced any significant supply chain interruptions as a result of the COVID-19 pandemic or global supply and demand imbalances. However, our operators may experience supply chain disruptions which could impact their ability to develop our properties.

Inflationary pressures could result in increases to our operating expenses that are not fixed such as personnel retention, among other things. Increases in interest rates as a result of inflation and a potentially recessionary economic environment in the United States could also have a negative effect on the demand for oil and natural gas, as well as our borrowing costs.

The initial outbreak of COVID-19 caused a disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil in 2020. This disruption was somewhat alleviated in 2021 and 2022, with the increase in domestic vaccination programs and reduced spread of the COVID-19 virus contributing to an improvement in the economy and higher realized prices for commodities. Since mid-2020 through mid-2022, oil prices have generally improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants, which have continued to inhibit a full global demand recovery. However, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Many operators have resumed or increased drilling and completion activities compared to activity levels in 2020 in connection with the increase in commodity prices since mid-2020. Given the dynamic nature of these events, the Company cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist and the impacts on our business from the COVID-19 pandemic, efforts to fight the pandemic and other market events.

In February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, has contributed to significant increases and volatility in the price for oil and natural gas, with the posted price for WTI reaching a high of $123.64 per barrel in March 2022. This volatility could negatively impact commodity prices and cause rising inflation that could impact demand for refined products. Given the uncertain timing of a return of refined product demand to historical levels, the extent these events will have an impact on our results of operations is unclear. The geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and may adversely affect our financial condition. The Russian conflict with Ukraine continues to evolve, and the extent to which these events may impact our business, financial condition, liquidity, results of operations, and prospects will depend highly on future developments, which are very uncertain and cannot be predicted with confidence.

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

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

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

Historically, oil, natural gas and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a low of negative ($36.98) per barrel in April 2020 to a high of $123.64 per barrel in March 2022. The Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas and NGLs that our operators can produce economically.

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

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

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

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

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

Natural gas, which currently has limitations on transportation in certain regions, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

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

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

We define Adjusted EBITDA as net income (loss) plus (a) interest expense, (b) provisions for taxes, (c) depreciation, depletion and amortization, (d) non-cash share-based compensation expense, (e) impairment of oil and natural gas properties, (f) gains or losses on unsettled derivative instruments, (g) change in fair value of warrant liability, (h) write off of deferred offering costs, (i) management fee to affiliates, (j) loss on extinguishment of debt (k) one-time transaction costs and (l) write off of financing costs. Adjusted EBITDA is not a measure determined by GAAP.

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

Our revenues are primarily derived from mineral and royalty payments received from our E&P operators based on the sale of crude oil, natural gas and NGLs production from our interests. Our revenues may vary significantly from period to period because of changes in commodity prices, production mix and volumes of production sold by our E&P operators. For the years ended December 31, 2022, 2021 and 2020, mineral and royalty revenue made up 96%, 98% and 96%, respectively, of our total revenues. As a result of our royalty income production mix, our income is more sensitive to fluctuations in crude oil prices than it is to fluctuations in natural gas or NGLs prices. Crude oil, natural gas and NGL prices have historically been volatile, and we expect this volatility to continue. Additionally, we earn lease bonus income by leasing our mineral interests to exploration and production companies and income from delay rentals and easements.

The following table presents the breakout of our revenues for the following periods:

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

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

the counties where our properties are located. Ad valorem taxes are generally based on the appraised value of our crude oil, natural gas and NGLs properties.

General and administrative expenses consist of costs incurred related to overhead, including executive and other employee compensation and related benefits, office expenses and fees for professional services such as audit, tax, legal and other consulting services. Some of those costs were incurred on our behalf by the Predecessor’s general partner and its affiliates and reimbursed by the Predecessor. For example, the Predecessor reimbursed an affiliate of our general partner for personnel costs on our behalf. As a result of the Falcon Merger, we incur incremental general and administrative expenses relating to SEC reporting requirements, including annual and quarterly reports, tax return preparation expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our common stock, independent auditor fees, legal expenses and investor relations expenses. These incremental general and administrative expenses are not reflected in the Predecessor financial statements.

Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of capitalized costs. Under the successful efforts method of accounting, capitalized costs of our proved crude oil, natural gas and NGLs mineral interest properties are depleted on a unit-of-production basis based on proved crude oil, natural gas and NGLs reserve quantities. Our estimates of crude oil, natural gas and NGLs reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the rate of depletion related to our crude oil, natural gas and NGLs properties. DD&A also includes the expensing of office leasehold costs and equipment.

We have financed a portion of our working capital requirements and acquisitions with borrowings under our revolving credit facilities and the 2026 Senior Notes. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facilities and the 2026 Senior Notes and amortization of debt issuance costs in interest expense on our statements of operations.

As a result of the Falcon Merger, we are subject to U.S. federal and state taxes as a corporation. We are also subject to the Texas margin tax, which is a state franchise tax, and certain state income taxes.

Our future results of operations may not be comparable to our Predecessor’s results of operations for the periods presented, primarily for the reasons described below.

The Predecessor’s historical consolidated financial statements are based on our financial statements prior to the Falcon Merger. The assets acquired in connection with the Falcon Merger did not include the Predecessor’s surface rights, which generate revenue from the sale of water, payments for rights-of-way and other rights associated with the ownership of the surface acreage, which are included in our Predecessor’s historical financial statements but were not contributed to the post-combination company following the closing of the Falcon Merger. Subsequent to the Falcon Merger, we have acquired additional surface rights in connection with multiple acquisitions. As a result, the historical consolidated financial data may not give you an accurate indication of what the actual results would have been if the Falcon Merger had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

The Predecessor incurred and paid annual fees under an investment management agreement with Kimmeridge Energy Management Company, LLC, an affiliate of Kimmeridge, of which Noam Lockshin, Sitio’s Chairman, is a managing member. Fees incurred under the agreement totaled approximately $3.2 million, $7.5 million and $7.5 million for the years ended December 31, 2022, 2021 and 2020, respectively. We will not incur future expense under the agreement as a result of the Falcon Merger. Additionally, certain other expenses associated with the limited partnership structure of the Predecessor will not be incurred by us in future periods.

Our Predecessor’s financial statements as of and for the years ended December 31, 2022, 2021 and 2020 do not include the results of operations for the assets acquired in the Chambers Acquisition, Rock Ridge Acquisition, Source Acquisition, the Falcon Merger, Foundation Acquisition, Momentum Acquisition, and Brigham Merger (defined in “Note 7 – Acquisitions” included elsewhere in this Form 10-K) prior to the respective dates of acquisition. As a result, our Predecessor’s financial results do not give an accurate indication of what the actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results are likely to be.

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

As a public company, we may finance a portion of our acquisitions with borrowings under our revolving credit facilities or other debt instruments. As a result, we will incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

We incur incremental general and administrative expenses as a result of operating as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our common stock, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in our Predecessor’s financial statements. Additionally, as a result of the Falcon Merger and Brigham Merger, we have hired additional employees, including accounting, engineering and land personnel, in order to comply with requirements of being a publicly traded company.

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

The following table summarizes our consolidated revenue and expenses and production data for the years ended December 31, 2022 and 2021 (in thousands):

Our consolidated revenues for the year ended December 31, 2022 totaled $369.6 million as compared to $120.6 million for the year ended December 31, 2021, an increase of 207%. The increase in revenues was due to an increase of $236.9 million in mineral and royalty revenue and an increase of $12.1 million in lease bonus and other income. The increase in mineral and royalty revenue was primarily due to increased commodity prices, production volumes from our acquisitions of additional mineral and royalty interests, and production volumes from existing interests. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing.

Oil revenue for the year ended December 31, 2022 was $266.2 million as compared to $84.8 million for the year ended December 31, 2021, an increase of $181.4 million. An increase of $25.76/Bbl in our average price received for oil production, from $67.29/Bbl for the year ended December 31, 2021 to $93.05/Bbl for the year ended December 31, 2022, accounted for an approximate $73.7 million increase in our year-over-year oil revenue. Additionally, we realized a $107.7 million increase in year-over-year oil revenue due to a 127% increase in oil production volumes, which increased from 1,261 MBbls for the year ended December 31, 2021 to 2,861 MBbls for the year ended December 31, 2022.

Natural gas revenue for the year ended December 31, 2022 was $52.4 million as compared to $17.1 million for the year ended December 31, 2021, an increase of $35.3 million. An increase of $1.89/Mcf in our average price received for gas production, from $3.61/Mcf for the year ended December 31, 2021 to $5.50/Mcf for the year ended December 31, 2022, accounted for an approximate $18.0 million increase in our year-over-year gas revenue. Additionally, we realized an $17.3 million increase in year-over-year gas revenue due to a 101% increase in gas production volumes, which increased from 4,746 MMcf for the year ended December 31, 2021 to 9,531 MMcf for the year ended December 31, 2022.

NGLs revenue for the year ended December 31, 2022 was $36.9 million as compared to $16.6 million for the year ended December 31, 2021, an increase of $20.3 million. An increase of $0.29/Bbl in our average price received for NGLs production, from $33.22/Bbl for the year ended December 31, 2021 to $33.51/Bbl for the year ended December 31, 2022, accounted for an approximate $319,000 increase in our year-over-year NGLs revenue. Additionally, we realized a $20.0 million increase in year-over-year NGLs revenue due to a 120% increase in NGLs production volumes, which increased from 499 MBbls for the year ended December 31, 2021 to 1,100 MBbls for the year ended December 31, 2022.

Lease bonus revenue for the year ended December 31, 2022 was $13.4 million as compared to $1.3 million for the year ended December 31, 2021. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues for the year ended December 31, 2022 were $777,000 as compared to $692,000 for the year ended December 31, 2021, which include payments for right-of-way and surface damages, which are also subject to significant variability.

The Predecessor entered into a management services arrangement with Kimmeridge Energy Management Company, LLC. Management fees to the Predecessor’s affiliates expense was $3.2 million and $7.5 million for the year ended December 31, 2022 and 2021, respectively. The management services arrangement was terminated in connection with the Falcon Merger and the Company is no longer incurring any management fees.

Depreciation, depletion and amortization expense was $104.5 million for the year ended December 31, 2022 as compared to $40.9 million for the year ended December 31, 2021, an increase of $63.6 million, or 155%. The increase was due to a 118% increase in year-over-year production as well as a higher depletion rate, which increased from $15.80 per BOE for the year ended December 31, 2021 to $18.72 per BOE for the year ended December 31, 2022.

General and administrative expense was $42.2 million for the year ended December 31, 2022 as compared to $4.1 million for the year ended December 31, 2021, an increase of $38.1 million. The increase was primarily due to increased personnel costs captured here for the year ended December 31, 2022, transaction costs related to the Falcon Merger and Brigham Merger, and expenses as a result of operating as a publicly traded company.

General and administrative—affiliates expense was $74,000 for the year ended December 31, 2022 as compared to $8.9 million for the year ended December 31, 2021, a decrease of $8.8 million. The decrease was primarily a result of decreased reimbursement to our Predecessor’s general partner for services provided on our behalf, including personnel costs and costs relating to the performance of land and administrative services in respect of our acquisition of mineral and royalty interests. These costs were primarily captured in the General and administrative expense line item for the year ended December 31, 2022.

On a combined basis, the General and administrative expense and General and administrative expense—affiliates expense was $42.3 million for the year ended December 31, 2022 as compared to $13.0 million for the year ended December 31, 2021, an increase of $29.3 million, or 225%, primarily due to $16.7 million of transaction costs related to the Falcon Merger and Brigham Merger, $9.2 million of share-based compensation, $3.1 million of additional other professional services, and $0.3 million of additional rent expense.

Severance and ad valorem taxes were $25.6 million for the year ended December 31, 2022 as compared to $6.9 million for the year ended December 31, 2021, an increase of $18.7 million or 269%. The increase was primarily due to the year-over-year increase in commodity prices and increased production volumes from our acquisitions of additional mineral and royalty interests and existing interests.

During the year ended December 31, 2021, we recognized approximately $2.4 million of expense in connection with the cancellation of an initial public offering. No such expense was recognized for the year ended December 31, 2022.

Interest expense of approximately $35.5 million and $1.9 million during the year ended December 31, 2022 and 2021, respectively, relates to interest incurred on borrowings under our revolving credit facilities, 2026 Senior Notes and Bridge Loan Facility. The increase in interest expense was due to higher average borrowings during the year ended December 31, 2022 as compared to the year ended December 31, 2021 related to funding the Falcon Merger, the Brigham Merger, and Other Acquisitions during the year ended December 31, 2022.

The fair value of the warrant liability decreased by $3.7 million from the date of the Falcon Merger through December 31, 2022, whereas there were no changes to the fair value of the warrant liability for the year ended December 31, 2021. The change is attributable to a decrease in the market price of both the Public Warrants and Private Placement Warrants.

Commodity derivative gains totaled $39.0 million for the year ended December 31, 2022, whereas there were no commodity derivatives gains or losses for the year ended December 31, 2021. In 2022, we entered into oil and gas fixed price swaps and two-way collars to manage commodity price risks associated with production from our recent acquisitions.

Interest rate derivative gains totaled $110,000 for the year ended December 31, 2022, whereas there were no interest rate derivative gains or losses for the year ended December 31, 2021. In 2022, we entered into an interest rate swap to manage exposures to changes in interest rates from variable rate borrowings.

Income tax expense increased from $486,000 for the year ended December 31, 2021 to $5.7 million for the year ended December 31, 2022. The increase was primarily due to current and deferred income taxes due to our classification as a taxable corporation subsequent to the Falcon Merger, whereas the Predecessor was not subject to Federal income taxes during the year ended December 31, 2021.

The following table summarizes our consolidated revenue and expenses and production data for the years ended December 31, 2021 and 2020 (in thousands):

Our consolidated revenues for the year ended December 31, 2021 totaled $120.6 million as compared to $45.7 million for the year ended December 31, 2020, an increase of 164%. The increase in revenues was due to an increase of $74.4 million in mineral and royalty revenue, and an increase of $0.5 million in lease bonus and other income. The increase in mineral and royalty revenue was primarily due to increased commodity prices, increased production volumes from our acquisitions of additional mineral and royalty interests, and increased production volumes from existing interests. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing. In April 2020, the Predecessor entered into an agreement with a third-party water services company to manage its water assets and operations. Contingent rental income earned under this arrangement was $205,000 and $13,000 for the years ended December 30, 2021 and 2020, respectively.

Oil revenue for the year ended December 31, 2021 was $84.8 million as compared to $34.9 million for the year ended December 31, 2020, an increase of $49.9 million. An increase of $29.89/Bbl in our average price received for oil production, from $37.40/Bbl for the year ended December 31, 2020 to $67.29/Bbl for the year ended December 31, 2021, accounted for an approximate $37.7 million increase in our year-over-year oil revenue. Additionally, we realized a $12.2 million increase in year-over-year oil revenue due to a 35% increase in oil production volumes, which increased from 933 MBbls for the year ended December 31, 2020 to 1,261 MBbls for the year ended December 31, 2021.

Natural gas revenue for the year ended December 31, 2021 was $17.1 million as compared to $4.3 million for the year ended December 31, 2020, an increase of $12.8 million. An increase of $2.58/Mcf in our average price received for gas production, from $1.03/Mcf for the year ended December 31, 2020 to $3.61/Mcf for the year ended December 31, 2021, accounted for an approximate $12.2 million increase in our year-over-year gas revenue. Additionally, we realized a $0.6 million increase in year-over-year gas revenue due to a 15% increase in gas production volumes, which increased from 4,134 MMcf for the year ended December 31, 2020 to 4,746 MMcf for the year ended December 31, 2021.

NGLs revenue for the year ended December 31, 2021 was $16.6 million as compared to $5.0 million for the year ended December 31, 2020, an increase of $11.6 million. An increase of $22.90/Bbl in our average price received for NGLs production, from $10.32/Bbl for the year ended December 31, 2020 to $33.22/Bbl for the year ended December 31, 2021, accounted for an approximate $11.5 million increase in our year-over-year NGLs revenue, and a $0.1 million increase in year-over-year NGLs revenue due to a 2% increase in NGLs production volumes, which increased from 488 MBbls for the year ended December 31, 2020 to 499 MBbls for the year ended December 31, 2021.

Lease bonus revenue for the year ended December 31, 2021 was $1.2 million as compared to $0.7 million for the year ended December 31, 2020. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing. Other revenues for the years ended December 31, 2021 and 2020, were $0.8 million, which include payments for right-of-way and surface damages, which are also subject to significant variability.

Management fees to affiliates expense remained consistent at $7.5 million for the years ended December 31, 2021 and 2020.

Depreciation, depletion and amortization expense was $40.9 million for the year ended December 31, 2021 as compared to $32.0 million for the year ended December 31, 2020, an increase of $8.9 million, or 28%. The increase was primarily due to our 21% increase in year-over-year production as well as a higher depletion rate, which increased from $14.90/BOE for the year ended December 31, 2020 to $15.80/BOE for the year ended December 31, 2021 due to reserves increasing at a slower rate than our net depletable capitalized costs from December 31, 2020 to December 31, 2021.

General and administrative expense was $4.1 million for the year ended December 31, 2021 as compared to $5.0 million for the year ended December 31, 2020, a decrease of $0.9 million, or 17%. The decrease was primarily due to decreased personnel costs captured here for the first half of 2020 as noted below and professional services costs.

General and administrative—affiliates expense was $8.9 million for the year ended December 31, 2021 as compared to $4.4 million for the year ended December 31, 2020, an increase of $4.5 million, or 101%. The increase was primarily a result of increased reimbursement to the Predecessor's general partner for services provided on our behalf, including personnel costs. These costs were captured in the general and administrative expense line item for the first half of 2020.

On a combined basis, the general and administrative expense and general and administrative expense— affiliates expense was $13.0 million for the year ended December 31, 2021 as compared to $9.4 million for the year ended December 31, 2020, an increase of $3.6 million, or 38%. The increase was a result of increased reimbursement to our general partner for services provided on our behalf, including personnel costs.

Severance and ad valorem taxes was $6.9 million for the year ended December 31, 2021 as compared to $3.2 million for the year ended December 31, 2020, an increase of $3.7 million or 119%. The increase was primarily due to an increase in severance taxes in conjunction with the year-over-year increase in commodity prices and increased production volumes from our acquisitions of additional mineral and royalty interests.

Impairment of oil and gas properties of approximately $812,000 for the year ended December 31, 2020 was recognized in connection with capitalized acquisition costs for a prospective mineral interest acquisition that we did not complete. We did not recognize impairment of oil and gas properties for the year ended December 31, 2021.

During the years ended December 31, 2021 and 2020, we recognized approximately $2.4 million and $2.7 million of expense, respectively, in connection with the cancellation of an initial public offering.

During the year ended December 31, 2020, we reversed approximately $251,000 of bad debt expense due to the collection of accounts receivable of the Predecessor's water business for which an allowance had previously been established. No such charges or benefits were recorded during the year ended December 31, 2021.

Interest expense of approximately $1.9 million and $2.0 million during the years ended December 31, 2021 and 2020, respectively, relates to interest incurred on borrowings under the Sitio Revolving Credit Facility. The decrease in interest expense was due to lower average borrowings under the facility during the majority of the year ended December 31, 2021 as we continued to make payments to reduce the outstanding balance throughout 2020 and into 2021. During the second half of 2021, we funded acquisitions and the distributions to the members of Desert Peak with increased borrowings.

Income tax expense primarily relates to state franchise taxes and totaled approximately $486,000 and $22,000 for the years ended December 31, 2021 and 2020, respectively.

Prior to the completion of the Falcon Merger, our Predecessor’s primary sources of liquidity were contributions of capital from its limited partners, cash flows from operations and borrowings under our revolving credit facility. After the closing of the Falcon Merger, cash flows from operations and borrowings under the Sitio Revolving Credit Facility, Brigham Revolving Credit Facility and 2026 Senior Notes are the primary day-to-day sources of our funds. Future sources of liquidity may also include other credit facilities we may enter into in the future and additional issuances of debt or equity securities. Our primary uses of cash have been, and are expected to continue to be, the acquisition of mineral and royalty interests, the reduction of outstanding debt balances and the payment of dividends. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, legislative, regulatory and other factors.

We believe internally generated cash flows from operations, available borrowing capacity under our revolving credit facilities, and access to capital markets will provide us with sufficient liquidity and financial flexibility to meet our cash requirements, including normal operating needs, debt service obligations and capital expenditures, for at least the next 12 months and allow us to continue to execute our strategy of acquiring attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. As an owner of mineral and royalty interests, we incur the initial cost to acquire our interests but thereafter do not incur any development or maintenance capital expenditures, which are entirely borne by the E&P operator and the other working interest owners. As a result, our only capital expenditures are related to our acquisition of additional mineral and royalty interests, and we have no subsequent capital expenditure requirements related to acquired properties. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities and our ability to integrate acquisitions. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather, general economic, financial and competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us.

As of December 31, 2022, our liquidity was $98.8 million, comprised of $18.8 million of cash and cash equivalents and $80.0 million of availability under the Sitio Revolving Credit Facility and Brigham Revolving Credit Facility.

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators, as well as the timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2022 were $165.0 million as compared to $65.9 million for the year ended December 31, 2021, primarily as a result of increases in realized prices and production volumes from our royalty revenue.

Cash flows used in investing activities totaled $558.1 million for the year ended December 31, 2022 as compared $38.7 million for the year ended December 31, 2021, an increase of $519.4 million. Our expenditures for purchases of oil and gas properties increased by $519.1 million due to several cash acquisitions completed during the year ended December 31, 2022. During the year ended December 31, 2022, we purchased other property and equipment for $840,000. During the year ended December 31, 2022, we also realized a net increase in cash of $0.3 million associated with the Falcon Merger and Brigham Merger, net of certain cash balances not contributed by our Predecessor.

Cash flows provided by financing activities for the year ended December 31, 2022 totaled $399.6 million as compared to cash flows used in financing activities of $22.3 million for the year ended December 31, 2021. Borrowings under our credit facilities for the years ended December 31, 2022 and 2021 were $348.9 million and $147.0 million, respectively, which were used to fund the Falcon Merger, Brigham Merger and Other Acquisitions of mineral and royalty interests. Repayments on our credit facilities for the years ended December 31, 2022 and 2021 were $209.0 million and $46.5 million, respectively, largely provided by cash flows from operations. During the year ended December 31, 2022, we borrowed and repaid $425.0 million under the Bridge Loan Facility, the proceeds from which were used to fund acquisitions of mineral and royalty interests. During the year ended December 31, 2022, we received proceeds of $444.5 million from the issuance of the 2026 Senior Notes, which were used to repay and extinguish the Bridge Loan Facility and for other general corporate purposes. Other financing cash outflows during the year ended December 31, 2022, included $15.4 million of costs incurred in connection with our entry into the Bridge Loan Facility, costs of $11.3 million incurred in connection with the issuance of the 2026 Senior Notes, costs of $5.0 million incurred in connection with amendments and restatements to the Sitio Revolving Credit Facility, dividends of $18.2 million paid to holders of Class A Common Stock, $115.4 million of distributions paid to temporary equity holders and $13.3 million of distributions paid to noncontrolling interest by our Predecessor. Other financing cash inflows during the year ended December 31, 2021 included $1.5 million of contributions by noncontrolling interest in our Predecessor and $8.0 million of partners’ capital contributions to our Predecessor. Other financing cash outflows during the year ended December 31, 2021 included $128.4 million of distributions by the Predecessor, $1.6 million of costs incurred in connection with amendments and restatements to the Sitio Revolving Credit Facility.

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators and timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2021 were $65.9 million as compared to $26.0 million for the year ended December 31, 2020, primarily as a result of increases in realized prices and production volume from our royalty revenue.

Cash flows used in investing activities totaled $38.7 million for the year ended December 31, 2021 as compared to $21.6 million for the year ended December 31, 2020, an increase of $17.1 million. Our expenditures for crude oil and gas properties increased by $2.9 million in the year ended December 31, 2021 as compared to the year ended December 31, 2020. We paid $137,000 related to purchase price adjustments from prior property sales for the year ended December 31, 2021, whereas we received proceeds from the sale of mineral interests of $14.1 million for the year ended December 31, 2020. Although we completed several acquisitions during the year ended December 31, 2021, the three largest acquisitions were completed through the issuance of equity in one of our consolidated subsidiaries with no cash consideration provided. The properties acquired through these acquisitions increased the balance of our oil and gas properties by $572.2 million.

Cash flows used in financing activities for the year ended December 31, 2021 totaled $22.3 million as compared to $15.1 million for the year ended December 31, 2020, an increase of $7.2 million. Capital contributions from our Predecessor's partners totaled $8.0 million and $13.0 million during the years ended December 31, 2021 and 2020, respectively, which were primarily used for the acquisition of mineral and royalty interests. Borrowings on the Sitio Revolving Credit Facility for the years ended December 31, 2021 and 2020 totaled $147.0 million and $10.0 million, respectively, which were also used for the acquisition of mineral and royalty interests and distributions to members of DPM HoldCo. Repayments on the Sitio Revolving Credit Facility for the years ended December 31, 2021 and 2020 were $46.5 million and $36.5 million, respectively, largely provided by cash flows from operations as well as the sale of certain properties to another mineral owner during the year ended December 31, 2020.

The Predecessor was party to the Predecessor Credit Agreement. In October 2021, KMF Land as borrower, and Desert Peak, as parent, entered into the A&R Credit Agreement.

Upon closing of the Falcon Merger on June 7, 2022, the Predecessor Credit Agreement was amended, restated, and refinanced in its entirety pursuant to the Second Amended and Restated Credit Agreement (the “Sitio Credit Agreement”), led by Bank of America N.A. as Administrative Agent, Issuing Bank and Syndication Agent. Pursuant to the terms and conditions of the Sitio Revolving Credit Facility, the Lenders committed to provide a senior secured revolving credit facility to Sitio OpCo in an aggregate principal amount of up to $750.0 million (as amended or otherwise modified from time to time the “Sitio Revolving Credit Facility”). The Sitio Credit Agreement has a scheduled maturity date in June 2026. Pursuant to the terms and conditions of the Sitio Credit Agreement, the Lenders committed to providing a credit facility to Sitio OpCo in an aggregate principal amount of up to $750 million. The availability under the Sitio Credit Agreement, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of the proved reserves of Sitio OpCo and its subsidiaries and elected commitments provided by the Lenders. As of the date of the closing of the Falcon Merger, the Sitio Credit Agreement had a $300 million borrowing base and $300 million elected commitment amount. As part of the aggregate commitments under the revolving advances, the Sitio Credit Agreement provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15 million. Existing letters of credit in place under the Sitio Revolving Credit Facility immediately prior to the closing date of the Falcon Merger are continued and now deemed issued under and governed by the terms of the Sitio Credit Agreement.

Interest accrues on advances, at the borrower’s option, at an adjusted Term SOFR rate or a base rate, plus an applicable margin and credit spread adjustment. The fees for letters of credit are also based on the applicable margin. The applicable margin used in connection with interest rates and fees is based on the Borrowing Base Utilization Percentage (as defined in the Sitio Credit Agreement). The applicable margin for Term SOFR rate loans and letter of credit fees ranges from 2.500% to 3.500%, and the applicable margin for base rate loans ranges from 1.500% to 2.500%. The credit spread adjustment ranges from 0.100% to 0.250% depending on the applicable interest rate and interest rate period. The borrower will also pay a fee based on the borrowing base utilization percentage on the actual daily unused amount of the aggregate revolving commitments ranging from 0.375% to 0.500%.

The borrowings under the Sitio Credit Agreement are secured by liens on certain assets of the borrower, the borrower’s subsidiaries and Sitio Royalties GP, LLC, a Delaware limited liability company, and guaranteed by the borrower and the borrower’s subsidiaries. Proceeds from borrowings under the Sitio Credit Agreement may be used (a) for working capital, exploration and production operations, and other general company purposes including acquisitions, (b) for dividends to stockholders, (c) for payment of certain transaction fees and expenses, and (d) to repay third party debt of the borrower and its subsidiaries existing prior to the Closing Date.

The Sitio Credit Agreement contains customary representations, warranties, covenants and events of default, including, among others, a change of control event of default and limitations on the incurrence of indebtedness and liens, new lines of business, mergers, transactions with affiliates and burdensome agreements. During the continuance of an event of default, the Lenders may take a number of actions, including, among others, declaring the entire amount then outstanding under the Sitio Credit Agreement to be due and payable.

The Sitio Credit Agreement includes a financial covenant limiting, as of the last day of each fiscal quarter, the ratio of (a) (i) Total Net Debt (as defined in the Credit Agreement) as of such date to (ii) EBITDA (as defined in the Sitio Credit Agreement) for the period of four fiscal quarters ending on such day (the “Leverage Ratio”), to not more than 3.50 to 1.00, and (b) (i) consolidated current assets (including the available commitments under the Sitio Credit Agreement) to (ii) consolidated current liabilities (excluding current maturities under the Sitio Credit Agreement), to not less than 1.00 to 1.00, in each case, with certain rights to cure.

In conjunction with the closing of the Brigham Merger, the Company assumed the Brigham Revolving Credit Facility. As of December 31, 2022, the borrowing base under the Brigham Revolving Credit Facility (the “Brigham Borrowing Base”) as determined by the lenders was $290.0 million. The Brigham Revolving Credit Facility has a scheduled maturity of May 2024.

Interest accrues on advances, at the borrower’s option, at an adjusted Term SOFR rate or a base rate, plus an applicable margin and credit spread adjustment. The applicable margin used in connection with interest rates and fees is based on the Borrowing Base Utilization Percentage (as defined in the Brigham Credit Agreement). The applicable margin for Term SOFR rate loans ranges from 2.500% to 3.500%, and the applicable margin for base rate loans ranges from 1.500% to 2.500%. The credit spread adjustment is 0.100%. The borrower will also pay a fee based on the borrowing base utilization percentage on the actual daily unused amount of the aggregate revolving commitments ranging from 0.375% to 0.500%.

The Brigham Credit Agreement contains customary representations, warranties, covenants and events of default, including, among others, a change of control event of default and limitations on the incurrence of indebtedness and liens, new lines of business, mergers, transactions with affiliates and burdensome agreements. During the continuance of an event of default, the Lenders may take a number of actions, including, among others, declaring the entire amount then outstanding under the Brigham Credit Agreement to be due and payable.

The Brigham Credit Agreement includes a financial covenant limiting, as of the last day of each fiscal quarter, the ratio of (a) (i) Total Net Debt (as defined in the Brigham Credit Agreement) as of such date to (ii) EBITDA (as defined in the Brigham Credit Agreement) for the period of four fiscal quarters ending on such day (the “Leverage Ratio”), to not more than 3.50 to 1.00, and (b) (i) consolidated current assets (including the available commitments under the Brigham Credit Agreement) to (ii) consolidated current liabilities (excluding current maturities under the Brigham Credit Agreement), to not less than 1.00 to 1.00, in each case, with certain rights to cure.

On September 21, 2022, Sitio OpCo, as issuer, and certain subsidiaries of Sitio OpCo, as guarantors, entered into a Note Purchase Agreement (the “Note Purchase Agreement”), pursuant to which Sitio OpCo issued unsecured notes to certain institutional investors in an aggregate principal amount of $450.0 million (the “2026 Senior Notes”). Sitio OpCo used the net proceeds from the 2026 Senior Notes to repay in full all amounts outstanding under the Bridge Loan Facility, with the remainder used for general corporate purposes. The 2026 Senior Notes mature on September 21, 2026.

Sitio OpCo may elect, at its option, to redeem the 2026 Senior Notes in whole or in part at any time, subject to (except as described below) payment of a premium determined in accordance with the table below based on the length of time between the issuance date and the redemption date:

Interest accrues on the 2026 Senior Notes at an adjusted Term SOFR rate (including a 0.150% spread adjustment) for a three-month period plus a margin of 6.50%, unless the Agent determines that adequate and reasonable means do not exist for ascertaining the Term SOFR rate or the Requisite Holders (as defined in the Note Purchase Agreement) determine that the Term SOFR rate will not reflect the cost of maintaining their 2026 Senior Notes for the relevant period, in which case the 2026 Senior Notes will bear interest at a base rate (defined on the basis of the prime rate) plus a margin of 5.50%. From and after the closing date of the Brigham Merger, the applicable margin was reduced to 5.75% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and to 4.75% for 2026 Senior Notes bearing interest based on the base rate. Interest payments on the 2026 Senior Notes are due quarterly.

Sitio OpCo may elect, at its option, to redeem the 2026 Senior Notes, on the last business day of each calendar quarter in an amount equal to 2.50% of the initial principal amount of all the 2026 Senior Notes issued under the Notes Purchase Agreement, which prepayments will not require the payment of any premium (each, an “Optional Quarterly Payment”). If Sitio OpCo does not make an Optional Quarterly Payment on any quarterly payment date, the applicable margin on the 2026 Senior Notes will increase to 9.50% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and 8.50% for 2026 Senior Notes bearing interest based on the base rate. Subsequent to the closing of the Brigham Merger, if an Optional Quarterly Payment is not made, the margin will increase to 7.75% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and 6.75% for 2026 Senior Notes bearing interest based on the base rate. The increased margin will apply until the earlier of the date on which Sitio OpCo makes such Optional Quarterly Payment or the next quarterly payment date.

The Note Purchase Agreement includes, among other terms and conditions, a maximum leverage ratio covenant, as well as customary mandatory redemptions, representations, warranties, covenants and events of default, including, among others, a change of control event of default and limitations on the incurrence of indebtedness and liens, new lines of business, mergers, transactions with affiliates and burdensome agreements. During the continuance of an event of default, the Holders may take a number of actions, including, among others, declaring the entire amount of the 2026 Senior Notes and other amounts then outstanding under the Note Purchase Agreement to be due and payable. The Note Purchase Agreement requires Sitio OpCo to maintain a leverage ratio as of the last day of each fiscal quarter of not more than 3.50 to 1.00.

On June 24, 2022, Sitio OpCo, as borrower, entered into an unsecured 364-Day Bridge Loan Agreement with Bank of America, N.A. as Administrative Agent for the Lenders, BofA Securities, Inc., as joint lead arranger and sole bookrunner, and Barclays Bank PLC and KeyBank National Association, as joint lead arrangers (the “Bridge Loan Agreement”). The Bridge Loan Agreement provides for a 364-day Bridge Loan Facility in the aggregate principal amount of $250.0 million. The Bridge Loan Facility was fully repaid and extinguished on September 21, 2022 using proceeds from the issuance of the 2026 Senior Notes. Upon the closure of the facility, the Company recognized a loss on extinguishment of debt of $11.5 million associated with unamortized debt issuance costs and other fees incurred in connection with the payoff.

Refer to “Recent Accounting Pronouncements” in “Note 2 - Summary of Significant Accounting Policies” to our consolidated financial statements for the years ended December 31, 2022, 2021 and 2020 for a discussion of recent accounting pronouncements.

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

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

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

Our estimates and classification of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering, and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions. These factors and assumptions include historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and natural gas prices. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas and estimates of the future net cash flows may vary substantially.

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

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

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

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

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

Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGLs, less production taxes and post-production expenses. The prices of oil, natural gas, and NGLs from the properties in which we own a mineral or royalty interest are primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no working interest or operational control over the volumes and methods of sale of the oil, natural gas, and NGL produced and sold from our properties. We do not explore, develop, or operate the properties and, accordingly, do not incur any of the associated costs. As we do not operate any of the wells for which we receive royalties, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that we will receive for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accrued revenue and accounts receivable, net line item in the accompanying consolidated balance sheets. Differences between our estimates and the actual amounts received for oil and natural gas sales are recorded in the month that payment is received from the third party.

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

We also earn revenue related to lease bonuses by leasing our mineral interests to E&P companies. We recognize lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.

As of December 31, 2022, we did not have any debt, capital lease obligations, operating lease obligations or long-term liabilities, other than borrowings under the Sitio Revolving Credit Facility, borrowings under the Brigham Revolving Credit Facility, borrowings under the 2026 Senior Notes and four operating lease agreements for office space. Please see “—Sitio's Revolving Credit Facility” for a description of the Sitio Revolving Credit Facility, “—Brigham's Revolving Credit Facility” for a description of the Brigham Revolving Credit Facility, “2026 Senior Notes” for a description of the 2026 Senior Notes and “Note 15 – Leases” to our consolidated financial statements for the year ended December 31, 2022, 2021 and 2020 for our contractual obligations under the office lease agreements.

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

A $1.00 per Bbl change in our realized oil price would have resulted in a $2.9 million change in our oil revenues for the year ended December 31, 2022. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $953,000 change in our natural gas revenues for the year ended December 31, 2022. A $1.00 per Bbl change in NGL prices would have resulted in a $1.1 million change in our NGL revenues for the year ended December 31, 2022. Royalties on oil sales contributed 75% of our mineral and royalty revenues for the year ended December 31, 2022. Royalties on natural gas sales contributed 15% and royalties on NGL sales contributed 10% of our total mineral and royalty revenues for the year ended December 31, 2022.

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

For the year ended December 31, 2022, revenue from Callon Petroleum Company represented approximately 12% of total revenue.

For the year ended December 31, 2021, revenue from Coterra Energy Inc., Diamondback Energy, Inc, Callon Petroleum Company, and Oxy USA Inc represented approximately 12%, 11%, 11%, and 10% of total revenue, respectively.

For the year ended December 31, 2020, revenue from Diamondback Energy, Inc, Cimarex Energy, and Oxy USA Inc represented approximately 15%, 12% and 10% of total revenue, respectively.

Although we are exposed to a concentration of credit risk, we do not believe the loss of any single purchaser would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. If multiple purchasers were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving our E&P operators have stipulated that royalty owners must still be paid for oil, gas and NGLs extracted from their mineral acreage during the bankruptcy process. In light of this, we do not expect the entry of one of our operators into bankruptcy proceedings to materially affect our operating results.

Our primary exposure to interest rate risk results from outstanding borrowings under the Sitio Revolving Credit Facility, Brigham Revolving Credit Facility and 2026 Senior Notes, each of which has a floating interest rate. The average annual interest rate incurred on our borrowings under the various debt agreements during the year ended December 31, 2022 was 7.0%. We estimate that an increase of 1.0% in the average interest rate during the year ended December 31, 2022 would have resulted in an approximately $4.3 million increase in interest expense.

The Company's consolidated financial statements required by this item are included in this Annual Report beginning on page F-1 and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

We maintain disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that are designed to provide reasonable assurance that information required to be disclosed in our reports filed pursuant to the Exchange Act is properly and timely reported and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

An effective internal control system, no matter how well designed and operated, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time, certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

We have evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2022 with the participation, and under the supervision, of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2022, our disclosure controls and procedures were effective at a reasonable level of assurance.

Our management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed by and/or under the supervision of our Chief Executive Officer and Chief Financial Officer, and effected by the Board, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with GAAP.

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

As described in this Annual Report on Form 10-K, we completed the Falcon Merger and the Brigham Merger during the year ended December 31, 2022. As contemplated by SEC Compliance and Disclosure Interpretation 215.02, we have excluded the report by our management of its assessment of internal control over financial reporting required by Item 308(a) of Regulation S-K in this Annual Report on Form 10-K, and in lieu of such report, we are providing the following disclosure as to why management’s assessment has not been included. Since management’s report is being excluded, the report of our independent registered public accounting firm under Item 308(b) of Regulation S-K is also being excluded.

As a result of the Falcon Merger and Brigham Merger, taken separately and as a whole, we believe it would not be meaningful to include management’s report on internal control over financial reporting in this Annual Report on Form 10-K since the internal controls of both Falcon and Brigham prior to the Falcon Merger and Brigham Merger, respectively, no longer exist. The system of internal controls in place following both the Falcon Merger and the Brigham Merger is that previously in place at Desert Peak. Further, all of the material information technology systems currently used by us are those previously used by Desert Peak, which was a private company prior to the completion of the Falcon Merger.

In our Annual Report on Form 10-K for the year ending December 31, 2023, we will include a report by our management of its assessment of internal control over financial reporting required by Item 308(a) of Regulation S-K. In making this assessment, management will use the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework Scope of the Controls Evaluation. In such Annual Report on Form 10-K, we will also include the report of our registered public accounting firm under Item 308(b) of Regulation S-K.

Except as described above, there has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

The information required by this item is incorporated by reference to our Proxy Statement for the 2023 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2022.

Our Board has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is available on the Investor Relations section of our website (http://investors.sitio.com) under “Governance Documents.” We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on the website address and location specified above.

Item 12. Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes hereto.

The following documents are filed as part of this Annual Report and incorporated by reference:

# Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request.

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

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Christopher L. Conoscenti, Carrie L. Osicka and Jim Norris, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

We have audited the accompanying consolidated balance sheets of Sitio Royalties Corp. and subsidiaries (the Company) as of December 31, 2022 and 2021, the related consolidated statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2022, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Estimated proved oil and natural gas reserves used in the depletion of proved oil and natural gas properties

As discussed in Note 2 to the consolidated financial statements, the Company uses the successful efforts method of accounting for its oil and natural gas producing properties and depletes capitalized costs using the unit-of-production basis over total proved oil and natural gas reserves. The Company had $4,947.4 million of net oil and natural gas properties as of December 31, 2022, and recorded depletion expense of proved oil and natural gas properties of $103.9 million for the year ended December 31, 2022. The Company engages external petroleum engineers to prepare the estimates of proved oil and natural gas reserves.

We identified the assessment of the estimated proved oil and natural gas reserves used in the depletion of proved oil and natural gas properties as a critical audit matter. Complex auditor judgement was required to evaluate the key assumptions used by the Company related to forecasted production and oil and natural gas prices, inclusive of market differentials, because changes to these assumptions could have had a significant impact on the estimated oil and natural gas reserves.

The following are the primary procedures we performed to address this critical audit matter. We evaluated (1) the professional qualifications of the lead internal petroleum engineer as well as the engineer assigned to the Company by the external petroleum

engineering firm engaged by the Company, (2) the knowledge, skills, and ability of the lead internal petroleum engineer, the engineer assigned to the Company by the external petroleum engineering firm, as well as the external petroleum engineering firm engaged by the Company, and (3) the relationship of the external petroleum engineering firm and the engineer assigned to the Company. We assessed the method used by the Company’s external petroleum engineers to estimate the proved oil and natural gas reserves for consistency with industry and regulatory standards. We compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and we compared the future forecasted production used by the Company in the current period to historical production. We evaluated the oil and natural gas prices used by the Company’s external petroleum engineers by comparing them to publicly available prices and tested the relevant price differentials by comparing them to historical differentials. We read and considered the findings of the external petroleum engineers engaged by the Company in connection with our evaluation of the Company’s reserve estimates. We analyzed the depletion expense calculation for compliance with regulatory standards and checked the accuracy of the depletion expense calculation.

As discussed in Note 2 to the consolidated financial statements, the Company recognizes oil, natural gas and NGL revenues from its mineral and royalty interests when control of the product is transferred to the customer and the performance obligations under the terms of the contracts with customers are satisfied. As a mineral and royalty interest owner, the Company has limited visibility into the timing of when new wells start producing as production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within accrued revenue and accounts receivable, net. The difference between the Company’s estimates of mineral and royalty income and the actual amounts received for oil, natural gas and NGL sales are recorded in the month that the mineral and royalty payment is received from the customer. At December 31, 2022, the Company had accrued revenue and accounts receivable, net of $142.0 million, a portion of which related to accrued revenue.

We identified the assessment of accrued revenue for oil and natural gas sales as a critical audit matter. Complex auditor judgment was required to evaluate the estimated volume of production delivered to the related customers, as well as the price that will be received for the sale of the oil and natural gas produced.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design of certain internal controls related to the Company’s oil and natural gas revenue accrual process, including controls related to the development of the estimates of delivered production volumes and the price that will be received for the sale of such volumes. We compared the Company’s historical revenue accruals to actual cash collections to assess the Company’s ability to accurately estimate. For a selection of transactions, we compared subsequent receipts to accrued revenue. We recalculated management’s accrual by comparing the Company’s estimates obtained from internal petroleum engineers and geoscience professionals to amounts used in the determination of accrued revenue. We evaluated the prices used by the Company to estimate the price to be received for the sale of the oil and natural gas produced by independently developing an expectation of price using publicly available market prices and historical differentials.

Valuation of oil and natural gas properties related to Falcon Minerals Corporation and Brigham Minerals Inc. business combinations.

As discussed in Notes 3 and 4 to the consolidated financial statements, during 2022 the Company completed two mergers. The first merger with Falcon Minerals Corporation (Falcon) was for equity consideration of approximately $638.8 million and the second merger with Brigham Minerals Inc. (Brigham) was for equity consideration of approximately $2,149.4 million. The transactions were accounted for as business combinations using the acquisition method, and the Company was treated as the accounting acquirer. Under the acquisition method of accounting, the assets, liabilities, and equity are recorded at their respective fair values as of the acquisition date. As a result of the transactions, the Company acquired both proved and unproved oil and natural gas properties which were determined to have a total acquisition-date fair value of $692.0 and $2,656.2 million for Falcon and Brigham, respectively.

We identified the evaluation of the acquisition-date fair value measurement of oil and natural gas properties acquired in the mergers as a critical audit matter. Complex auditor judgment was required in evaluating the key assumptions used to estimate the discounted future cash flows of proved oil and natural gas properties. Specifically, future production quantities, forecasted commodity prices inclusive of market differentials, proved reserve risk adjustment factors, and the discount rate applied to determine fair value. Changes to these assumptions could have had a significant effect on the determination of the acquisition-date fair value.

The following are the primary procedures we performed to address this critical audit matter. We assessed the method used by the Company’s internal petroleum engineers to estimate proved oil and natural gas reserves for consistency with industry and regulatory standards. We compared the estimated future proved production quantities used by the Company to historical

production volumes of the acquired businesses. We evaluated the professional qualifications of the Company’s lead internal petroleum engineer and their knowledge, skills, and ability relative to the valuation process. We tested the relevant market differentials that were applied to the forecasted commodity price assumptions based on historical differentials. We tested the per acre cost of unproved acreage as compared to comparable market values. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating:

The accompanying notes are an integral part of these consolidated financial statements.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company’s wholly-owned subsidiaries and any entities in which the Company owns a controlling interest. All intercompany accounts and transactions have been eliminated in consolidation. Noncontrolling interest in the Company’s consolidated financial statements for periods prior to the Falcon Merger represented the ownership interests in a subsidiary of the Predecessor which were owned by outside parties. As a result of the Brigham Merger, the holders of Class C Common Stock no longer hold a majority of the voting share outstanding. Consequently, after December

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29, 2022, interests held in the form of Class C Common Stock and Sitio OpCo Partnership Units are presented as noncontrolling interest in the consolidated balance sheets. See “Note 10 – Temporary Equity and Noncontrolling Interest” for additional information.

Use of Estimates

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

The Company’s estimates and classification of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering, and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon several variable factors and assumptions. These factors and assumptions include historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and natural gas prices. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas and estimates of the future net cash flows may vary substantially.

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

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, Leases, which requires all leasing arrangements to be presented on the balance sheet as liabilities along with a corresponding asset. ASU 2016-02 does not apply to leases of mineral rights to explore for or use crude oil and natural gas. The ASU will replace most existing lease guidance in GAAP when it becomes effective. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11, Leases: Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The Company adopted the new standard during the fiscal year ended December 31, 2022. The primary effect of adoption was to record right-of-use assets and lease liabilities for office leases previously accounted for as operating leases under Topic 840. Refer to “Note 15 - Leases” for more information.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses, which amends current impairment guidance by adding an impairment model (known as the current expected credit loss model (“CECL”)) that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of lifetime expected credit losses, which the FASB believes will result in more timely recognition of such losses. The Company adopted the new standard during the fiscal year ended December 31, 2022 with a beginning period of adoption of January 1, 2022. The impact of the adoption of this standard on the Company’s consolidated financial statements was immaterial. ASU 2016-13 was applied using a modified retrospective approach, with a cumulative-effect adjustment to the opening balance of retained earnings as of the adoption date. However, the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2022 was immaterial.

Cash and Cash Equivalents

The Company considers all highly-liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

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Accrued Revenue and Accounts Receivable

Accrued revenue and accounts receivable represent amounts due to the Company and are uncollateralized, consisting primarily of royalty revenue receivable. Royalty revenue receivable consists of royalties due from operators for oil, natural gas and NGL volumes sold to purchasers. Those purchasers remit payment for production to the operator of the properties and the operator, in turn, remits payment to the Company. Receivables from third parties for which we did not receive actual production information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized, are estimated.

The Company’s accrued revenue and accounts receivable consisted of the following as of the dates indicated (in thousands):


	December 31, 2022		December 31, 2021
Accrued revenue	$	80,406	$	36,177
Accounts receivable		61,604		25
Total accrued revenue and accounts receivable, net	$	142,010	$	36,202

Accounts receivable at December 31, 2022 are primarily composed of accrued revenue acquired in conjunction with the Brigham Merger. Refer to “Note 3 - Brigham Merger” for more information. The Company routinely assesses the recoverability of all material accounts receivable to determine their collectability. The Company accrues a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. As of December 31, 2022 and 2021, the Company had no reserves for uncollectible amounts or deemed any amounts to be uncollectible.

Oil and Gas Properties

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

Impairment of Oil and Gas Properties

The Company evaluates its producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, the Company compares the expected undiscounted future net cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future net cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future net cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. There was no impairment of proved properties for the years ended December 31, 2022, 2021, and 2020. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Unproved oil and gas properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include but are not limited to commodity price outlooks and current and future operator activity in the respective Basins. The Company recognized no impairment of unproved properties for the years ended December 31, 2022 and 2021. The Company recognized approximately $812,000 of unproved property impairment for the year ended December 31, 2020. This impairment was related to capitalized acquisition costs for a prospective mineral interest acquisition that the Company did not complete.

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Other Property and Equipment

Other property and equipment, which includes leasehold improvements, is recorded at cost. Depreciation is calculated using the straight-line method over the shorter of the lease term or the useful lives of the assets. The Company recorded approximately $613,000, $588,000 and $609,000 in depreciation for other property and equipment for the years ended December 31, 2022, 2021, and 2020, respectively.

We evaluate our other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset that has been placed in service may not be recoverable. No impairment charges were recorded for the years ended December 31, 2022, 2021, and 2020.

Asset Acquisitions

The Company generally accounts for acquisitions of mineral and royalty interests as asset acquisitions, through which it allocates the purchase price between proved and unproved properties, with no recognition of goodwill. The Company may use different techniques to determine the allocation, including the discounted net present value of estimated future cash flows and market prices (where available).

Business Combinations

The Company accounts for all business combinations, including the Falcon Merger and Brigham Merger, using the acquisition method, which involves the use of significant judgment. Under the acquisition method, a business combination is accounted for based on the fair value of the consideration given. The assets acquired and liabilities assumed are measured at fair value and the purchase price is allocated to the assets and liabilities based on these fair values. The excess of the cost of an acquisition, if any, over the fair value of the assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over consideration given for an acquisition, if any, is recognized immediately in earnings as a gain. Determining the fair values of the assets and liabilities acquired involves the use of judgment as fair values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and the discounted net present value of estimated future cash flows, among others.

Derivative Financial Instruments

In order to manage its exposure to oil, natural gas, and NGL price volatility as well as interest rate volatility, the Company may periodically enter into derivative transactions, which may include commodity swap agreements, basis swap agreements, two- and three-way collars, and other similar agreements which help manage the price risk associated with the Company’s production. From time to time, the Company may periodically enter into various interest rate derivative contracts to manage exposures to changes in interest rates from variable rate obligations. These derivatives are not entered into for trading or speculative purposes. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. All derivative counterparties are current lenders under Sitio's Revolving Credit Facility (defined below). Accordingly, the Company is not required to provide any credit support to its derivative counterparties other than cross collateralization with the properties securing the Sitio Revolving Credit Facility.

The Company records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity and interest rate derivatives, including gains or losses on settled derivatives, are classified as other income or loss on the Company’s consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes.

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Accounts Payable and Accrued Expenses

The Company’s accounts payable and accrued expenses consisted of the following as of the dates indicated (in thousands):


	December 31, 2022		December 31, 2021
Ad valorem taxes payable	$	9,209	$	1,750
Brigham Merger accrued expenses		2,878		—
Other taxes payable		2,713		529
Payable to seller for pre-effective monies		2,243		104
General and administrative		1,931		904
Interest expense		1,377		274
Accrued prepaids		1,330		—
Deferred financing costs and debt issuance costs		206		13
Capital expenditures		12		391
Other		—		175
Total accounts payable and accrued expenses	$	21,899	$	4,140

Warrant Liability

Falcon issued the Public Warrants and Private Placement Warrants (both defined below) in connection with its initial public offering in 2017. The Warrants remain outstanding following the Falcon Merger. Warrants are accounted for in accordance with applicable accounting guidance provided in ASC 815-40 – Derivatives and Hedging – Contracts in Entity’s Own Equity (“ASC 815”), as either liabilities or as equity instruments depending on the specific terms of the warrant agreement. The Warrants were classified as liabilities and recorded at fair value at the time of the Falcon Merger and are subject to remeasurement at the end of each reporting period. Any change in fair value is recorded in our statements of operations.

Leases

The Company evaluates if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease, depending on lease classification guidance provided in ASC 842 – Leases. The Company leases office space under four operating leases. In December 2021, the Predecessor entered into a sublease of one of its office spaces with an unaffiliated third-party. We currently do not have any finance leases. We capitalize our operating leases through recognition of an operating lease right-of-use asset and a corresponding operating lease liability on our consolidated balance sheets. Right-of-use assets represent our right to use an underlying asset for the lease term and operating lease liabilities represent our obligation to make fixed payments under the terms of the lease agreement. Short-term leases that have an initial term of one year or less are not capitalized but are disclosed. Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

Operating lease right-of-use assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease right-of-use asset also includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Lease expense for operating leases is recognized on a straight-line basis over the lease term. See “Note 15 – Leases” for additional information.

Deferred Rent

Under ASC 840 – Leases (“ASC 840”), which was in effect prior to 2022, the Company recognized rental expense for operating leases on a straight-line basis over the term of the lease agreements. The deferred rent liability on the Company’s consolidated balance sheet as of December 31, 2021 is attributable to the difference between rental expense (recognized on a straight-line basis) and the variable lease payments over the terms of the agreements.

Temporary Equity

Subsequent to the Falcon Merger, the Company accounted for the interests attributable to Class C Common Stock and Sitio OpCo Partnership Units as temporary equity as a result of certain redemption rights held as discussed in “Note 10 – Temporary Equity and Noncontrolling Interest.” As such, the Company adjusted temporary equity to its maximum redemption amount at the balance sheet date, if higher than the carrying amount. Changes in the redemption value were recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to retained earnings or, if a retained deficit, to additional paid-in capital. Temporary equity is reclassified to permanent equity upon conversion of Class C Common Stock (and an

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equivalent number of Sitio OpCo Partnership Units) or when holders of the Class C Common Stock no longer effectively control the Company’s determination of whether to make a cash payment upon the Sitio OpCo Partnership Unit holder’s exercise of its Redemption Right.

As a result of the Brigham Merger on December 29, 2022, the holders of Class C Common Stock no longer hold a majority of the voting shares outstanding. Consequently, after December 29, 2022, interest held in the form of Class C Common Stock and Sitio OpCo Partnership Units are presented as noncontrolling interest in the consolidated balance sheets.

See “Note 10 – Temporary Equity and Noncontrolling Interest” for additional information.

Revenue Recognition

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

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

The Company also earns revenue related to lease bonuses. The Company earns lease bonus revenue by leasing its mineral interests to E&P companies. The Company recognizes lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.

See “Note 5 – Revenue from Contracts with Customers” for additional disclosures regarding revenue recognition.

Concentration of Revenue

Collectability of the Company’s royalty revenue is dependent upon the financial condition of the Company’s operators, the entities they sell their products to, as well as general economic conditions in the industry.

For the year ended December 31, 2022, revenue from Callon Petroleum Company represented approximately 12% of total revenue.

For the year ended December 31, 2020, revenue from Diamondback Energy, Inc, Cimarex Energy, and Oxy USA Inc represented approximately 15%, 12% and 10% of total revenue, respectively.

Although the Company is exposed to a concentration of credit risk, the Company does not believe the loss of any single operator or entity would materially impact the Company’s operating results as crude oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers. If multiple entities were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption.

Share-Based Compensation

The Company recognizes share-based compensation expense associated with restricted stock units, deferred share units, and restricted stock awards which are time-based awards and performance stock units, which are market-based awards. As the performance metric for the performance stock unit awards is absolute total shareholder return, the performance stock units awards are accounted for as market-based awards. The Company accounts for forfeitures of share-based compensation awards as they occur. Share-based compensation expense for all awards is recognized based on the estimated grant date fair value of the award. See “Note 11 – Share-Based Compensation” for additional information.

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Merger-Related Transaction Costs

General and administrative expense of $42.2 million for the year ended December 31, 2022 includes $16.7 million of costs incurred by the Company in connection with the Falcon Merger and the Brigham Merger (defined below). No such expense was recognized for the years ended December 31, 2021 and 2020.

Income Taxes

The Company, under ASC 740 – Income Taxes (“ASC 740”), uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (a) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (b) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future periods when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance will be provided for deferred tax assets if it is more likely than not the deferred tax assets will not be realized.

ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits (if any) as income tax expense. No amounts were accrued for the payment of interest and penalties at December 31, 2022 and 2021.

Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. A significant portion of our mineral and royalty interests are located in Texas. As such, the Company recognized approximately $1.7 million, $486,000, and $22,000, respectively, for the years ended December 31, 2022, 2021, and 2020, of state income tax expense, primarily attributable to the Texas margin tax.

The Company’s ASC 740 balances and income tax expense reporting is significantly affected by the portion of the Company’s consolidated net income attributable to the holders of Sitio OpCo Partnership Units, which is not taxable income to the Company. As the Company’s ownership interest in Sitio OpCo is 51.9%, only tax attributes allocated to the Company are recorded at this level, except for Texas Gross Margins tax which is imposed on Sitio OpCo and reported herein.

In December 2022, the Company completed the acquisition of approximately 86,500 NRAs in the Delaware and Midland Basin in West Texas and New Mexico, the SCOOP and STACK plays in the Anadarko Basin of Oklahoma, the DJ Basin Colorado and Wyoming and the Williston Basin in North Dakota from Brigham Minerals. At closing, subject to the terms and conditions of the Brigham Merger Agreement, provides for the acquisition of Brigham by Former Sitio in an all-stock transaction through: (i) the merger of Brigham Merger Sub with and into Brigham (the “Brigham Merger”), with Brigham surviving the Brigham Merger as a wholly owned subsidiary of New Sitio, (ii) the merger of Sitio Merger Sub with and into Former Sitio (the “Sitio Merger”), with Former Sitio surviving the Sitio Merger as a wholly owned subsidiary of New Sitio, and (iii) the merger of Opco Merger Sub LLC with and into Brigham Opco (the “Opco Merger,” and, together with the Brigham Merger and the Sitio Merger, the “Mergers”), with Brigham Opco surviving the Opco Merger as a wholly owned subsidiary of Opco LP, in each case on the terms set forth in the Brigham Merger Agreement.

Pursuant to the Brigham Merger Agreement, at closing each share of Brigham’s Class A common stock, par value $0.01 per share, issued and outstanding immediately prior to the First Effective Time was converted into 1.133 fully-paid and nonassessable shares of Class A Common Stock, par value $0.0001 per share, of New Sitio (the “New Sitio Class A Common Stock”), (B) each share of Brigham’s Class B common stock, par value $0.01 per share, issued and outstanding immediately prior to the First Effective Time was converted into 1.133 fully-paid and nonassessable shares of Class C Common Stock, par value $0.0001 per share, of New Sitio (the “New Sitio Class C Common Stock”), (C) each share of Class A Common Stock issued and outstanding immediately prior to the First Effective Time was converted into one share of New Sitio Class A Common Stock and (D) each share of Class C Common Stock issued and outstanding immediately prior to the First Effective Time, was converted into one share of New Sitio Class C Common Stock, in each case, excluding shares owned by Sitio, Brigham or any wholly owned subsidiary of Sitio or Brigham and, to the extent applicable, shares owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to the Delaware General Corporation Law (the “DGCL”) and, (ii) at the Second Effective Time, each Brigham Opco Unit issued and outstanding immediately prior to the Second Effective Time was converted into 1.133 Sitio OpCo Partnership Units. No fractional shares were outstanding following the conversion.

As a result of the Brigham Merger and as of the closing of the Brigham Merger (the “Brigham Closing”), Sitio stockholders immediately prior to the First Effective Time owned approximately 54% of the outstanding shares of New Sitio, and Brigham

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stockholders immediately prior to the First Effective Time own approximately 46% of the outstanding shares of New Sitio. Following the Closing, New Sitio operates under the name “Sitio Royalties Corp.”

The Brigham Merger was accounted for as a business combination and, therefore, the acquired interests were recorded based on the fair value of the total assets acquired and liabilities assumed on the acquisition date.

The following table summarized the consideration for the Brigham Merger:


Brigham Common Stock — issued and outstanding as of December 29, 2022:		71,290,265
Class A Common Stock price on December 29, 2022	$	30.15
Total consideration and fair value	$	2,149,401,490

Preliminary Purchase Price Allocation

The Brigham Merger was accounted for as a business combination using the acquisition method. The Company completed the determination of the fair value attributable to the identifiable assets acquired and liabilities assumed based on the fair value at the acquisition date. Certain data necessary to complete the purchase price allocation is subject to change, and includes, but is not limited to, settlement of pre-acquisition working capital balances and assessments of deferred tax assets and liabilities acquired. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed on December 29, 2022 (in thousands):


Brigham fair values:
Cash	$	11,054
Accrued revenue and accounts receivable		61,745
Prepaid expenses		11,339
Unproved oil and gas properties		1,783,162
Proved oil and gas properties		873,050
Property and equipment		200
Right-of-use asset		3,209
Other assets		1,064
Current liabilities		(83,425	)
Long-term debt		(193,000	)
Long-term operating lease liability		(2,387	)
Deferred tax liability		(316,571	)
Other long-term liability		(39	)
Total consideration and fair value	$	2,149,401

Transaction costs associated with the Brigham Merger incurred for the year ended December 31, 2022 were $13.3 million. These costs, which are comprised primarily of advisory, legal, and other professional and consulting fees, are included in General and administrative expense on our consolidated statements of operations.

The results of Brigham’s operations have been included in our consolidated financial statements since the December 29, 2022 acquisition date. The amount of revenue and direct operating expenses resulting from the acquisition included in our Consolidated Statements of Operations from December 29, 2022 through December 31, 2022 was approximately $2.4 million and $113,000, respectively.

Pro Forma Financial Information

The unaudited pro forma financial information for the years ended December 31, 2022 and 2021, respectively, gives effect to the Falcon Merger and Brigham Merger as if they had both occurred on January 1, 2021 (in thousands, except per share amounts):

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	For the Years Ended December 31,
	2022		2021
Total revenues	$	756,590	$	389,621
Pro forma income (loss) available to Class A stockholders		121,110		(8,435	)

Net income (loss) per share:
Basic	$	1.50	$	(0.12	)
Diluted	$	1.50	$	(0.12	)

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Falcon Merger and Brigham Merger been completed as of January 1, 2021 and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

In June 2022, the Company completed the acquisition of approximately 34,000 NRAs in the Eagle Ford and Appalachian Basin from Falcon Minerals Corporation in a reverse merger. At closing, subject to the terms and conditions of the Falcon Reverse Merger Agreement, Falcon merged with and into Desert Peak, with Desert Peak continuing as the surviving entity in the Falcon Merger as a wholly owned subsidiary of Sitio OpCo. On June 3, 2022, prior to the consummation of the Falcon Merger, Falcon effected the four-to-one Reverse Stock Split. As a result of the Reverse Stock Split, every four shares of the Company’s issued and outstanding Class C Common Stock were automatically converted into one share of Class C Common Stock, without any change in the par value per share, and every four shares of the Company’s Class A Common Stock were automatically converted into one share of Class A Common Stock, without any change in the par value per share. No fractional shares were outstanding following the Reverse Stock Split. Additionally, as a result of the Reverse Stock Split, the Warrants were adjusted such that four whole Warrants became exercisable for one share of Class A Common Stock at an exercise price of $44.84 per share of Class A Common Stock.

Pursuant to the terms of the Falcon Reverse Merger Agreement, following the closing of the Falcon Merger and the Reverse Stock Split, the issued and outstanding limited liability company interests in Desert Peak were converted into the right to receive aggregate Falcon Merger Consideration of (a) 61,905,339 shares of Class C Common Stock and (b) 61,905,339 Sitio OpCo Partnership Units.

The Falcon Merger was accounted for as a business combination and, therefore, the acquired interests were recorded based on the fair value of the total assets acquired and liabilities assumed on the acquisition date.

The following table summarized the consideration for the Falcon Merger:


Falcon Common Stock — issued and outstanding as of June 7, 2022:		21,935,492
Class A Common Stock price on June 7, 2022	$	29.12
Total consideration and fair value	$	638,761,527

Purchase Price Allocation

The Falcon Merger was accounted for as a business combination using the acquisition method. The Company completed the determination of the fair value attributable to the identifiable assets acquired and liabilities assumed based on the fair value at the acquisition date. The purchase price allocation was finalized during the three months ended December 31, 2022.

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The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed (in thousands):


	June 7, 2022			Adjustments			December 31, 2022
Falcon fair values:
Cash	$	4,484		$	—		$	4,484
Accrued revenue and accounts receivable		12,054			6,696			18,750
Unproved oil and gas properties		495,803			(4,572	)		491,231
Proved oil and gas properties		200,773			—			200,773
Property and equipment		278			—			278
Current liabilities		(22,315	)		(1,106	)		(23,421	)
Long-term debt		(43,105	)		—			(43,105	)
Deferred tax liability		(2,598	)		(1,018	)		(3,616	)
Warrant liability		(6,612	)		—			(6,612	)
Total consideration and fair value	$	638,762		$	—		$	638,762

In connection with the Falcon Merger, the Company assumed, and immediately repaid, $43.1 million of borrowings under Falcon’s credit facility. The repayment of Falcon’s long-term debt was funded using cash on hand and borrowings on the Sitio Revolving Credit Facility, see “Note 8 – Debt” for further information.

Transaction costs associated with the Falcon Merger incurred for the year ended December 31, 2022 were $3.4 million. These costs, which are comprised primarily of advisory, legal, and other professional and consulting fees, are included in General and administrative expense on our consolidated statements of operations.

The results of Falcon’s operations have been included in our consolidated financial statements since the June 7, 2022 acquisition date. The amount of revenue and direct operating expenses resulting from the acquisition included in our Consolidated Statements of Operations from June 7, 2022 through December 31, 2022 was approximately $43.5 million and $2.9 million, respectively.

Pro Forma Financial Information

See “Note 3 – Brigham Merger” for the pro forma financial information.

Sitio Revolving Credit Facility

As of December 31, 2022, the borrowing base under the Sitio Revolving Credit Facility (the “Sitio Borrowing Base”) as determined by the lenders was $300.0 million and the outstanding balance under the Sitio Revolving Credit Facility was $250.0 million. As of December 31, 2021, the Sitio Borrowing Base was $150.0 million as determined by the lenders and the outstanding balance under the Sitio Revolving Credit Facility was $134.0 million.

The Sitio Revolving Credit Facility bears interest at a rate per annum equal to, at our option, at an adjusted Term SOFR rate or a base rate, plus an applicable margin and credit spread adjustment. The applicable margin is based on utilization of the Sitio Revolving Credit Facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of Term SOFR rate loans and letters of credit, from 2.500% to 3.500%. The credit spread adjustment ranges from 0.100% to 0.250% depending on the applicable interest rate and interest rate period. Sitio OpCo may elect an interest period of one, three or six months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under the Sitio Revolving Credit Facility in an amount ranging from 0.375% to 0.500% based on utilization of the Sitio Revolving Credit Facility. The Sitio Revolving Credit Facility is subject to other customary fee, interest and expense reimbursement provisions.

As of December 31, 2022 and 2021, the weighted average interest rate related to our outstanding borrowings under the Sitio Revolving Credit Facility was 7.62% and 3.36%, respectively. As of December 31, 2022 and 2021, the Company had unamortized debt issuance costs of $6.0 million and $2.1 million, respectively, in connection with its entry into the Sitio Revolving Credit Facility, including amendments. Such costs are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. For the years ended December 31, 2022, 2021 and 2020, the Company recognized $1.2 million, $440,000, and $255,000, respectively, in interest expense related to the amortization of deferred financing costs under the Sitio Revolving Credit Facility.

The Sitio Revolving Credit Facility matures on the earlier of June 5, 2026 and 91 days prior to the final maturity date of the 2026 Senior Notes if any 2026 Senior Notes remain outstanding on such date. Loans drawn under the Sitio Revolving Credit Facility may be

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prepaid at any time without premium or penalty (other than customary breakage costs for Term SOFR rate loans) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected commitments of the lenders at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed, subject to compliance with the Sitio Revolving Credit Facility. In addition, Sitio OpCo may permanently reduce or terminate in full the commitments under the Sitio Revolving Credit Facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid and may not be reborrowed. Upon the occurrence of an event of default under the Sitio Revolving Credit Facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under the Sitio Revolving Credit Facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

The Sitio Revolving Credit Facility is subject to a borrowing base established by the lenders to reflect the loan value of our oil and gas mineral interests. The borrowing base under the Sitio Revolving Credit Facility is redetermined by the lenders on a semi-annual basis. Additionally, lenders holding two-thirds of the aggregate commitments are able to request one additional redetermination between regularly scheduled redeterminations. Sitio OpCo could also request one additional redetermination between regularly scheduled redeterminations, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of certain additional indebtedness. Increases to the borrowing base require unanimous approval of the lenders, while maintenance of the same borrowing base or decreases in the borrowing base only require approval of lenders holding two-thirds of the aggregate commitments at such time. The determination of the borrowing base takes into consideration the estimated value of the Company’s oil and gas mineral interests in accordance with the lenders’ customary practices for oil and gas loans. The Sitio Revolving Credit Facility is collateralized by substantially all of the assets of Sitio OpCo and its restricted subsidiaries.

The Sitio Revolving Credit Facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making dividends or distributions, restrictions on paying other debt and restriction on certain investments. The Sitio Revolving Credit Facility requires us to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than 3.50 to 1.00, with cash netting capped at $25.0 million. EBITDA for the period ending on December 31, 2022 is calculated as EBITDA for the period beginning on July 1, 2022 and ending on December 31, 2022 multiplied by two. The Company was in compliance with the terms and covenants of the Sitio Revolving Credit Facility at December 31, 2022 and 2021.

First Amended and Restated Credit Agreement

In October 2021, KMF Land, as borrower and Desert Peak, as parent, entered into the Amended and Restated Credit Agreement with a syndicate of banks led by Bank of America N.A. as Administrative Agent, Issuing Bank and Syndication Agent, pursuant to which the lenders thereunder made loans and extensions of credit to the borrower thereunder (the “Predecessor Credit Agreement”).

Falcon Credit Agreement

On June 7, 2022 and in connection with the closing of the Falcon Merger, the Company repaid the outstanding borrowings under the Credit Agreement, dated as of August 23, 2018 (the “Falcon Credit Agreement”), among Falcon Minerals Operating Partnership, LP, as the borrower, the lenders from time to time party thereto, Citibank, N.A., as administrative agent and collateral agent for the lenders from time to time party thereto and each other issuing bank from time to time party thereto and terminated the Falcon Credit Agreement.

Second Amended and Restated Credit Agreement

Upon closing of the Falcon Merger on June 7, 2022, the Predecessor Credit Agreement was amended, restated, and refinanced in its entirety pursuant to the Second Amended and Restated Credit Agreement (the “Sitio Credit Agreement”), led by Bank of America N.A. as Administrative Agent, Issuing Bank and Syndication Agent. Pursuant to the terms and conditions of the Sitio Revolving Credit Facility, the Lenders committed to provide a senior secured revolving credit facility to Sitio OpCo in an aggregate principal amount of up to $750.0 million (as amended or otherwise modified from time to time the “Sitio Revolving Credit Facility”). The availability under the Sitio Revolving Credit Facility, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders in good faith by calculating a loan value of the proved reserves of Sitio OpCo and its restricted subsidiaries and elected commitments provided by the Lenders. As of June 7, 2022, the Revolving Credit Facility had a $300.0 million borrowing base and $300.0 million elected commitment amount. As part of the aggregate commitments under the revolving advances, the Revolving Credit Facility provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15.0 million.

First Amendment to Second Amended and Restated Credit Agreement

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On June 24, 2022, Sitio OpCo and the other guarantors party thereto entered into the First Amendment to Credit Agreement (the “Sitio RBL First Amendment”). The Sitio RBL First Amendment, among other things, amended the Sitio Revolving Credit Facility to permit the borrowings under the Bridge Loan Agreement, defined below, and permitted the transactions contemplated by the Bridge Loan Agreement and the Foundation Acquisition described in “Note 7 – Acquisitions.” The Sitio RBL First Amendment waived the borrowing base reduction that would otherwise apply to the incurrence of permitted additional debt up to an aggregate amount of $400.0 million incurred prior to the next borrowing base redetermination.

Second Amendment to Second Amended and Restated Credit Agreement

On July 8, 2022, Sitio OpCo and the other guarantors party thereto entered into the Second Amendment to Credit Agreement (the “Sitio RBL Second Amendment”), pursuant to which the Sitio Revolving Credit Facility was amended to permit the additional borrowings under the Bridge First Amendment and permit the transactions contemplated by the Bridge First Amendment. The Sitio RBL Second Amendment waived the borrowing base reduction that would otherwise apply to the incurrence of Permitted Additional Debt (as defined in the Sitio RBL Second Amendment) for an additional amount of $50.0 million, up to an aggregate amount of $450.0 million, if incurred within 30 days of the closing of the Sitio RBL Second Amendment to fund a portion of the purchase price of the Momentum Acquisition described in “Note 7 – Acquisitions.”

Third Amendment to Second Amended and Restated Credit Agreement

On September 21, 2022, Sitio OpCo and the other guarantors party thereto entered into the Third Amendment to Credit Agreement, pursuant to which the Revolving Credit Facility was amended to permit the issuance of the 2026 Senior Notes and the transactions contemplated by the Note Purchase Agreement.

Fourth Amendment to Second Amended and Restated Credit Agreement

On December 29, 2022, Sitio OpCo and the guarantors entered into party thereto entered into the Fourth Amendment to Credit Agreement, pursuant to which, among other things, the Sitio Revolving Credit Facility was amended to (i) permit the consummation of, and the transactions contemplated by, the Brigham Merger, (ii) reaffirm the borrowing base under the Sitio Revolving Credit Facility at $300,000,000, (iii) designate certain subsidiaries of Brigham as unrestricted subsidiaries (the “Brigham Unrestricted Subsidiaries”), (iv) require that the Brigham Unrestricted Subsidiaries become restricted subsidiaries under the Sitio Revolving Credit Facility on or before June 30, 2023 and (v) include restrictions on the amount of debt that can be incurred by the Brigham Unrestricted Subsidiaries before they are designated as restricted subsidiaries under the Sitio Revolving Credit Facility.

Brigham Revolving Credit Facility

In conjunction with the closing of the Brigham Merger, the Company assumed the Brigham Revolving Credit Facility. As of December 31, 2022, the borrowing base under the Brigham Revolving Credit Facility (the “Brigham Borrowing Base”) as determined by the lenders was $290.0 million and the outstanding balance under the Brigham Revolving Credit Facility was $260.0 million.

The Brigham Revolving Credit Facility bears interest at a rate per annum equal to, at Brigham Resources, LLC’s (“Brigham Resources”) option, at an adjusted Term SOFR rate or a base rate, plus an applicable margin and credit spread adjustment. The applicable margin is based on utilization of the Brigham Revolving Credit Facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of Term SOFR rate loans and letters of credit, from 2.500% to 3.500%. The credit spread adjustment for Term SOFR Rate loans is 0.100%. Brigham Resources may elect an interest period of one, three or six months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under the Brigham Revolving Credit Facility in an amount ranging from 0.375% to 0.500% based on utilization of the Brigham Revolving Credit Facility. The Brigham Revolving Credit Facility is subject to other customary fee, interest and expense reimbursement provisions.

As of December 31, 2022, the weighted average interest rate related to Brigham Resources’ outstanding borrowings under the Brigham Revolving Credit Facility was 8.04%. As of December 31, 2022, the Company had unamortized debt issuance costs of $1.1 million in connection with Brigham Resources’ entry into the Brigham Revolving Credit Facility, including amendments. Such costs are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. No interest expense related to the amortization of deferred financing costs under the Brigham Revolving Credit Facility was incurred by the Company for the years ended December 31, 2022, 2021 and 2020.

The Brigham Revolving Credit Facility matures on May 16, 2024. Loans drawn under the Brigham Revolving Credit Facility may be prepaid at any time without premium or penalty (other than customary breakage costs for Term SOFR rate loans) and must be prepaid in the event that exposure exceeds the lesser of the borrowing base and the elected commitments of the lenders at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed, subject to compliance with the Brigham Revolving Credit Facility. In addition, Brigham Resources may

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permanently reduce or terminate in full the commitments under the Brigham Revolving Credit Facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid and may not be reborrowed. Upon the occurrence of an event of default under the Brigham Revolving Credit Facility, the administrative agent acting at the direction of the lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under the Brigham Revolving Credit Facility, provided that such acceleration and termination occurs automatically upon the occurrence of a bankruptcy or insolvency event of default.

The Brigham Revolving Credit Facility is subject to a borrowing base established by the lenders to reflect the loan value of Brigham Resources’ and its subsidiaries’ oil and gas mineral interests. The borrowing base under the Brigham Revolving Credit Facility is redetermined by the lenders on a semi-annual basis. Additionally, lenders holding two-thirds of the aggregate commitments are able to request one additional redetermination in each fiscal year. Brigham Resources could also request one additional redetermination in each fiscal year, and such other redeterminations as appropriate when significant acquisition opportunities arise. The borrowing base is subject to adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of certain additional indebtedness. Increases to the borrowing base required unanimous approval of the lenders, while maintenance of the same borrowing base or decreases in the borrowing base only required approval of lenders holding two-thirds of the aggregate commitments at such time. The determination of the borrowing base takes into consideration the estimated value of the Company’s oil and gas mineral interests in accordance with the lenders’ customary practices for oil and gas loans. The Brigham Revolving Credit Facility is collateralized by substantially all of the assets of Brigham Resources and its subsidiaries.

The Brigham Revolving Credit Facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making dividends or distributions, restrictions on paying other debt and restriction on certain investments. The Brigham Revolving Credit Facility requires the Brigham Unrestricted Subsidiaries to become restricted subsidiaries under the Sitio Revolving Credit Facility or terminate its commitments under the Brigham Revolving Credit Facility and repay all obligations outstanding thereunder on or before June 30, 2023. The Brigham Revolving Credit Facility requires Brigham Resources to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than 3.50 to 1.00, with cash netting capped at $25.0 million. The Company was in compliance with the terms and covenants of the Brigham Revolving Credit Facility at December 31, 2022.

Brigham Credit Agreement

On May 16, 2019, Brigham Resources entered into the Credit Agreement (as amended or otherwise modified from time to time, the “Brigham Credit Agreement”), led by Wells Fargo Bank, N.A. as Administrative Agent, Letter of Credit Issuer, Sole Lead Arranger and Bookrunner. Pursuant to the terms and conditions of the Brigham Revolving Credit Facility, the Lenders committed to provide a senior secured revolving credit facility to Brigham Resources in an aggregate principal amount of up to $500.0 million (as amended or otherwise modified from time to time the “Brigham Revolving Credit Facility”). The availability under the Brigham Revolving Credit Facility, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of lenders by calculating a loan value of the proved reserves of Brigham Resources and its subsidiaries and elected commitments provided by the Lenders.

Sixth Amendment to Brigham Credit Agreement

On December 29, 2022, Brigham Resources and the guarantors entered into party thereto entered into the Sixth Amendment to Credit Agreement (the “Brigham RBL Sixth Amendment”). The Brigham RBL Sixth Amendment, among other things (i) permits the consummation of the transactions contemplated by the Brigham Merger Agreement, (ii) modifies the financial reporting requirements applicable to Brigham Resources in respect of such transactions, (iii) provides that discretionary cash dividends or distributions to the equity owners of Brigham Resources are subject to (in addition to existing leverage and liquidity requirements) trailing twelve month distributable free cash flow, and (iv) establishes June 30, 2023 as an outside date for a refinancing or termination of the Former Brigham Credit Agreement.

2026 Senior Notes

On September 21, 2022, Sitio OpCo, as issuer, and certain subsidiaries of Sitio OpCo, as guarantors, entered into a Note Purchase Agreement (the “Note Purchase Agreement”) with certain institutional investors as holders (the “Holders”) and U.S. Bank Trust Company, National Association, as agent for the Holders (the “Agent”).

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Sitio OpCo may elect, at its option, to prepay the 2026 Senior Notes in whole or in part at any time, subject to (except as described below) payment of a premium determined in accordance with the table below based on the length of time between the issuance date and the prepayment date:


Period	Premium
Months 0 - 12	Customary “make-whole” premium plus 3.00%
Months 13 - 24		3.00	%
Months 25 - 36		1.00	%
Months 37 - 48		0.00	%

Interest accrues on the 2026 Senior Notes at an adjusted Term SOFR rate (including a 0.150% spread adjustment) for a three-month period plus a margin of 6.50%, unless the Agent determines that adequate and reasonable means do not exist for ascertaining the Term SOFR rate or the Requisite Holders (as defined in the Note Purchase Agreement) determine that the Term SOFR rate will not reflect the cost of maintaining their 2026 Senior Notes for the relevant period, in which case the 2026 Senior Notes will bear interest at a base rate (defined on the basis of the prime rate) plus a margin of 5.50%. From and after the Fold In Date (as defined below), the applicable margin will be reduced to 5.75% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and to 4.75% for 2026 Senior Notes bearing interest based on the base rate. Interest payments on the 2026 Senior Notes are due quarterly.

Sitio OpCo may elect, at its option, to prepay the 2026 Senior Notes on the last business day of each calendar quarter in an amount equal to 2.50% of the aggregate principal amount of all the 2026 Senior Notes issued under the Note Purchase Agreement, which prepayments will not require the payment of any premium (each, an “Optional Quarterly Payment”). If Sitio OpCo does not make an Optional Quarterly Payment on any quarterly payment date, the applicable margin on the 2026 Senior Notes will increase to 9.50% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and 8.50% for 2026 Senior Notes bearing interest based on the base rate. After the Fold In Date, if an Optional Quarterly Payment is not made, the margin will increase to 7.75% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and 6.75% for 2026 Senior Notes bearing interest based on the base rate. The increased margin will apply until the earlier of the date on which Sitio OpCo makes such Optional Quarterly Payment or the next quarterly payment date.

As of December 31, 2022, the Company had $438.8 million of 2026 Senior Notes outstanding. As of December 31, 2022, the weighted average interest rate of the 2026 Senior Notes was 11.23%. As of December 31, 2022, the Company had unamortized debt issuance costs of $4.7 million in connection with its issuance of the 2026 Senior Notes. Such costs are reported as a reduction to long-term debt on our consolidated balance sheets and are amortized over the life of the 2026 Senior Notes. For the year ended December 31, 2022, the Company recognized $342,000 of interest expense related to the amortization of issuance costs related to the Note Purchase Agreement. No such expense was recognized for the years ended December 31, 2021 and 2020.

The Note Purchase Agreement includes, among other terms and conditions, a maximum leverage ratio covenant, as well as customary mandatory prepayments, representations, warranties, covenants and events of default, including, among others, a change of control event of default and limitations on asset sales, restrictions on additional debt and lien incurrence and restrictions on making dividends or distributions and restrictions on certain investments. The Note Purchase Agreement requires Sitio OpCo to maintain a leverage ratio of not more than 3.50 to 1.00, which is tested as of the last day of each fiscal quarter. During the continuance of an event of default, the Holders may take certain actions, including declaring the entire amount of the 2026 Senior Notes and other amounts then outstanding under the Note Purchase Agreement to be due and payable. As of December 31, 2022, Sitio OpCo was in compliance with the terms and covenants of the 2026 Senior Notes.

First Amendment to Note Purchase Agreement

On December 29, 2022, Sitio OpCo and the guarantors entered into that certain First Amendment to Note Purchase Agreement (the “NPA First Amendment”), pursuant to which, among other things, the Note Purchase Agreement was amended to (i) designate the Brigham Unrestricted Subsidiaries as unrestricted subsidiaries under the Note Purchase Agreement, (ii) require that the Brigham Unrestricted Subsidiaries become restricted subsidiaries under the Note Purchase Agreement and the RBL Credit Agreement (as defined in the Note Purchase Agreement) on or before June 30, 2023 (iii) postpone the automatic 0.75% (or, in certain circumstances, 1.75%) reduction of the applicable margin on the 2026 Senior Notes from the date when the Mergers are consummated to the date when the Brigham Unrestricted Subsidiaries are designated as restricted subsidiaries under the Note Purchase Agreement (such date of designation, the “Fold In Date”) and (iv) include restrictions on the amount of debt that can be incurred by the Brigham Unrestricted Subsidiaries before they are designated as restricted subsidiaries under the Note Purchase Agreement.

364-Day Bridge Loan Agreement

F-26

PLC and KeyBank National Association, as joint lead arrangers (the “Bridge Loan Agreement”). The Bridge Loan Agreement was amended on July 8, 2022 (the “Bridge First Amendment”) to provide for additional delayed draw term loan commitment.

The Bridge Loan Agreement and Bridge First Amendment provide for a 364-day term loan credit facility (the “Bridge Loan Facility”) in the aggregate principal amount of $425.0 million. The Bridge Loan Facility was fully repaid and extinguished on September 21, 2022 using proceeds from the issuance of the 2026 Senior Notes. Upon the closure of the Bridge Loan Facility, the Company recognized a loss on extinguishment of debt of $11.5 million, associated with unamortized debt issuance costs and other fees incurred in connection with the payoff.

For year ended December 31, 2022, the Company recognized $3.4 million of interest expense related to the amortization of issuance costs under the Bridge Loan Agreement. No such expense was recognized for the years ended December 31, 2021 and 2020.

Prior to the effective time of the Falcon Merger, on June 3, 2022, Falcon filed with the Secretary of State of the State of Delaware the Third Amended and Restated Certificate of Incorporation to effect the previously announced four-to-one Reverse Stock Split for all of Falcon’s, and subsequently the Company’s, issued and outstanding shares of common stock and outstanding equity awards. As a result of the Reverse Stock Split, every four shares of the Company’s issued and outstanding Class C Common Stock were automatically converted into one share of Class C Common Stock, without any change in the par value per share, and every four shares of the Company’s Class A Common Stock were automatically converted into one share of Class A Common Stock, without any change in the par value per share. No fractional shares were outstanding following the Reverse Stock Split.

Class A Common Stock

The Company had 80,171,951 shares of its Class A Common Stock outstanding as of December 31, 2022. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s Board.

Class C Common Stock

The Company had 74,347,005 shares of its Class C Common Stock outstanding as of December 31, 2022. Shares of Class C Common Stock are non-economic but entitle the holder to one vote per share. Current holders of Class C Common Stock also hold an equivalent number of Sitio OpCo Partnership Units. Sitio OpCo Partnership Units are redeemable on a one-for-one basis for shares of Class A Common Stock at the option of the holder. Upon the redemption by any holder of Sitio OpCo Partnership Units for shares of Class A Common Stock, a corresponding number of shares of Class C Common Stock held by such holder will be canceled. During the year ended December 31, 2022, 1,361,966 Sitio OpCo Partnership Units were redeemed for shares of Class A Common Stock, and an equivalent number of shares of Class C Common Stock were canceled.

Treasury Shares

The Company held in treasury 633,005 shares of its Class A Common stock. The shares were repurchased by Brigham in 2020 and contributed to New Sitio as part of the Brigham Merger consideration. The treasury shares were recorded at a price of $30.15 per share at December 31, 2022.

Cash Dividends

On August 31, 2022, the Company paid a cash dividend of $0.71 per share of Class A Common Stock, totaling $9.0 million. The dividend related to the quarter ending June 30, 2022 and was paid to stockholders of record on August 18, 2022.

On November 30, 2022, the Company paid a cash dividend of $0.72 per share of Class A Common Stock, totaling $9.1 million. The dividend related to the quarter ending September 30, 2022 was paid to stockholders of record on November 21, 2022.

See “Note 19 – Subsequent Events” for additional information regarding cash dividends.

Earnings per Share

Earnings per share is computed using the two-class method. The two-class method determines earnings per share of common stock and participating securities according to dividends or dividend equivalents and their respective participation rights in undistributed earnings. Participating securities represent certain equity-based compensation awards in which the recipients have non-forfeitable rights to dividend equivalents during the performance period.

F-27

The following table sets forth the calculation of basic and diluted earnings per share for the periods indicated (in thousands, except per share data):


	For the Year Ended December 31,
	2022			2021		2020
Numerator:
Net income attributable to Class A stockholders	$	15,701		$	—	$	—
Less: Earnings allocated to participating securities		(579	)		—		—
Net income attributable to Class A stockholders - basic	$	15,122		$	—	$	—
Plus: net income attributable to temporary equity		90,377
Less: net loss attributable to noncontrolling interest		(51	)
Net income attributable to Class A stockholders - diluted	$	105,448		$	—	$	—
Denominator:
Weighted average shares outstanding - basic		13,723
Effect of dilutive securities		—
Weighted average shares outstanding - diluted		13,723

Net income per common share - basic	$	1.10
Net income per common share - diluted	$	1.10

The Company had the following shares that were excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods (in thousands):


	For the Year Ended December 31,
	2022		2021		2020
Warrants		5,312
Unvested share-based compensation awards		302
Total		5,614		—		—

Diluted net income per share also excludes the effects of Sitio OpCo Partnership Units (and related Class C Common Stock) associated with the earn-out, which are convertible into Class A Common Stock, because they are considered contingently issuable shares and the conditions for issuance were not satisfied as of December 31, 2022.

Earn-Out

Contributors of Falcon’s initial assets in 2018 will be entitled to receive earn-out consideration to be paid in the form of Sitio OpCo Partnership Units (with a corresponding number of shares of Class C Common Stock) if the volume-weighted average price of the trading days during any thirty (30) calendar days (the “30-Day VWAP”) of the Class A Common Stock equals or exceeds certain hurdles set forth in the Contribution Agreement. If the 30-Day VWAP of the Class A Common Stock is $50.00 or more per share (on a split-adjusted basis) at any time within the seven years following the 2018 closing, the contributors will receive (a) an additional 2.5 million Sitio OpCo Partnership Units (and an equivalent number of shares of Class C Common Stock), plus (b) an amount of Sitio OpCo Partnership Units (and an equivalent number of shares of Class C Common Stock) equal to (i) the amount by which annual cash dividends paid on each share of Class A Common Stock exceeds $2.00 in each year between the closing and the date the first earn-out is achieved (with any dividends paid in the stub year in which the first earn-out is achieved annualized for purposes of determining what portion of such dividends would have, on an annual basis, exceeded $2.00), multiplied by 2.5 million, (ii) divided by $50.00. If the 30-Day VWAP of the Class A Common Stock is $60.00 or more per share (on a split-adjusted basis) at any time within the seven years following the closing (which $60.00 threshold will be reduced by the amount by which annual cash dividends paid on each share of Class A Common Stock exceeds $2.00 in each year between the closing and the date the earn-out is achieved, but not below $50.00), the contributors will receive an additional 2.5 million Sitio OpCo Partnership Units (and an equivalent number of shares of Class C Common Stock). Upon recognition of the earn-out, as there is no consideration received, the Company would record the payment of the earn-out as adjustments through equity (noncontrolling interest and additional-paid-in-capital).

Partners’ Capital

Committed Capital

As of December 31, 2022, as a result of the Falcon Merger, the Company no longer had any Partners’ Capital.

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As of December 31, 2021, the Predecessor had aggregate capital commitments (the “Committed Capital”) of $618.4 million from Limited Partners and $8.0 million from the General Partner. At December 31, 2021, approximately $29.5 million of this Committed Capital remained available to call for purposes of satisfying investment commitments, management fees, and expenses over the remaining life of the Predecessor. Through December 31, 2021, the Predecessor’s contributed capital as a percentage of total Committed Capital was approximately 95%.

Distributions

In June 2022 prior to the Falcon Merger, DPM HoldCo distributed $13.3 million to its outside owners, including $1.9 million to an affiliate Kimmeridge fund.

In October 2021, DPM HoldCo distributed $60.9 million to its outside owners, including $8.7 million to an affiliate Kimmeridge fund. In November 2021, the Predecessor made a distribution of $67.5 million to its partners, comprised of approximately $66.6 million to Limited Partners and $0.9 million to its General Partner.

In connection with the Falcon Merger, the Company adopted the Sitio Royalties Corp. Long Term Incentive Plan (the “Plan”). An aggregate of 8,384,083 shares of Class A Common Stock are available for issuance under the Plan. The Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units (“RSUs”), stock awards, dividend equivalents, other stock-based awards, cash awards, and substitute awards. Shares that are canceled, forfeited, exchanged, settled in cash or otherwise terminated will be available for delivery pursuant to other awards. Dividend equivalent rights (“DERs”) are also available for grant under the Plan, either alone or in tandem with other specific awards, which will entitle the recipient to receive an amount equal to dividends paid on a Class A Common Stock. Dividends paid in connection with the DERs are accounted for as a reduction in retained earnings for those awards that are expected to vest. Awards that are forfeited could cause a reclassification of any previously recognized DERs payments from a reduction in retained earnings to additional compensation cost. The Plan is administered by the Compensation Committee of the Board (the “Compensation Committee”). As of December 31, 2022, a total of 7,535,151 shares of Class A Common Stock remain available for future grant under the Plan.

For the year ended December 31, 2022, the Company incurred $9.2 million of share-based compensation which is included in general and administrative expense in the accompanying consolidated statements of operations. There was no share-based compensation expense recognized for the years ended December 31, 2021 and 2020. For the year ended December 31, 2022, the Company paid $579,000 related to DERs. For the years ended December 31, 2021 and 2020, no DERs were paid.

Restricted Stock Units

In accordance with the Plan, the Compensation Committee is authorized to issue RSUs to eligible executive officers and employees. The Company estimates the fair value of the RSUs as the closing price of the Company’s Class A Common Stock on the grant date of the award, which is expensed over the applicable service period. RSUs granted by the Company include dividend equivalent rights, which entitle the holder to receive payments as if the unvested awards were shares of Class A Common Stock of record as of the dividend record dates. Such amounts are paid simultaneously with the general dividend to our stockholders.

In connection with the Falcon Merger, the Board granted one-time equity-based awards to our executive officers and employees under the Plan, consisting of RSUs subject to a vesting period of one year. The Board also granted an annual equity-based award to our executive officers under the Plan, which consists of RSUs that vest in equal installments on the first three anniversaries of June 7, 2022.

The Company has granted RSUs to certain employees, which represent the right to receive shares of Class A Common Stock at the end of the service periods in an amount equal to the number of RSUs that vest. The RSUs issued to employees generally vest in one-third increments over a three-year period. RSUs are subject to forfeiture if the award recipient ceases providing services to the Company prior to the date the award vests.

The following table summarizes activity related to unvested RSUs for the year ended December 31, 2022.


	Restricted Stock Units
	Number of Shares			Grant Date Fair Value
Unvested at January 1, 2022		—		$	—
Granted		447,519			29.11
Forfeited		(1,391	)		29.12
Vested		—			—
Unvested at December 31, 2022		446,128		$	29.11

For the year ended December 31, 2022, the Company recognized $4.5 million of share-based compensation expense related to RSUs. As of December 31, 2022, there was approximately $8.5 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of approximately 1.8 years. For the years ended December 31, 2021 and 2020 there was no share-based compensation expense related to RSUs.

Deferred Share Units

In accordance with the Plan, the Compensation Committee is authorized to issue deferred share units (“DSUs”) to our non-employee directors. The Company estimates the fair value of the DSUs as the closing price of the Company’s Class A Common Stock on the grant date of the award, which is expensed over the applicable service period.

F-30

In connection with the Falcon Merger, the Board granted awards of DSUs under the Plan to each of our non-employee directors. The DSUs are expected to vest in equal quarterly installments over the one-year period beginning on June 7, 2022. Any vested DSUs are settled in shares of Class A Common Stock when a recipient’s service relationship is terminated for any reason. In connection with the Brigham Merger, two of the non-employee directors resigned from the Company's Board of Directors. In recognition of their service to Sitio, their remaining unvested DSUs were accelerated to vest in full on December 29, 2022.

The following table summarizes activity related to unvested DSUs for the year ended December 31, 2022.


	Deferred Share Units
	Number of Shares			Grant Date Fair Value
Unvested at January 1, 2022		—		$	—
Granted		62,586			28.80
Forfeited		—			—
Vested		(20,862	)		28.17
Unvested at December 31, 2022		41,724		$	29.12

For the year ended December 31, 2022, the Company recognized $1.3 million of share-based compensation expense related to DSUs. As of December 31, 2022, there was approximately $526,000 of unamortized equity-based compensation expense related to unvested DSUs. That expense is expected to be recognized over a weighted average period of 0.4 years. For the years ended December 31, 2021 and 2020, there was no share-based compensation expense related to DSUs.

Performance Stock Units

In accordance with the Plan, the Compensation Committee is authorized to issue performance stock units (“PSUs”) to eligible employees and directors.

In connection with the Falcon Merger in June 2022, the Board granted an annual equity-based award to our executive officers under the Incentive Plan, which consisted of PSUs. The PSUs will be eligible to be earned based on achievement of certain pre-established goals for annualized absolute Total Shareholder Return (“TSR”) over a three-year period following the consummation of the Falcon Merger. In December 2022, the Board further granted an annual equity-based award to certain employees under the Incentive Plan, which consisted of PSUs. The PSUs will be eligible to be earned based on achievement of certain pre-established goals for annualized absolute TSR over a three-year period following December 30, 2022.

The performance targets associated with the PSU awards are outlined below:


	Annualized Absolute TSR Goal			Percentage of Target PSUs Earned
Base of Range	Less than 0%				0	%
Threshold		0	%		50	%
Target		10	%		100	%
Maximum		20	%		200	%

For purposes of determining our annualized absolute TSR over the performance period, the beginning stock price will be based on our 20-day volume weighted average stock price beginning on the applicable grant date. The ending price will generally be based on the 20-day volume weighted average stock price ending on the last day of the performance period. PSU payouts for results that fall in between a stated threshold will be interpolated linearly.

The grant date fair values of the PSUs were determined using Monte Carlo simulations, which use a probabilistic approach for estimating the fair value of the awards. The expected volatility was derived from the historical volatility of Falcon and Sitio. The risk-free interest rate was determined using the yield for zero-coupon U.S. Treasury bills that is commensurate with the performance measurement period. The PSU award agreements provide that TSR will be calculated assuming dividends distributed will be reinvested over the performance period. As such, we have applied a dividend yield of 0.00%, which is mathematically equivalent to reinvesting dividends.

The following table summarizes the assumptions used to determine the fair values of the PSUs:


Grant Year	Average Expected Volatility	Risk-Free Interest Rate	Expected Dividend Yield
2022	67.23% - 67.30%	2.89% - 4.18%	0.00%

F-31

The following table summarizes activity related to unvested PSUs for the year ended December 31, 2022.


	Performance Stock Units
	Number of Shares		Grant Date Fair Value
Unvested at January 1, 2022		—	$	—
Granted		308,953		39.12
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2022		308,953	$	39.12

For the year ended December 31, 2022, the Company recognized $2.2 million of share-based compensation expense related to PSUs. As of December 31, 2022, there was approximately $9.9 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of 2.5 years. For the years ended December 31, 2021 and 2020 there was no share-based compensation expense related to PSUs.

Restricted Stock Units Converted in the Brigham Merger

In connection with the Brigham Merger, several legacy Brigham employees joined Sitio. The Board approved the grant of RSUs to these employees through the conversion of legacy Brigham RSUs to New Sitio RSUs at an exchange ratio of 1.133 Sitio RSUs for each Brigham RSU. These newly-issued RSUs under the Plan will retain the original vesting schedules of the Brigham RSUs, which vest in one-third increments on the anniversaries of the original grant dates of the Brigham RSUs. The Company estimated the fair value of the RSUs as the closing price of the Company’s Class A Common Stock on the grant date of the award, which is expensed over the applicable service period.

The following table summarizes activity related to unvested RSUs converted in the Brigham Merger for the year ended December 31, 2022.


	Restricted Stock Units Converted in Brigham Merger
	Number of Shares		Grant Date Fair Value
Unvested at January 1, 2022		—	$	—
Granted		21,279		30.15
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2022		21,279	$	30.15

For the year ended December 31, 2022, the Company recognized $2,000 of share-based compensation expense related to the RSUs converted in the Brigham Merger. As of December 31, 2022, there was approximately $640,000 of unamortized equity-based compensation expense related to unvested RSUs converted in the Brigham Merger. That expense is expected to be recognized over a weighted average period of approximately 2.2 years. For the years ended December 31, 2021 and 2020, there was no share-based compensation expense related to these awards.

Performance Stock Units Converted in the Brigham Merger

In connection with the Brigham Merger, several legacy Brigham employees joined Sitio. The Board approved the grant of PSUs to these employees through the conversion of legacy Brigham PSUs to New Sitio PSUs at an exchange ratio of 1.133 Sitio PSUs for each Brigham PSU. The PSU grant carries over the remainder of the legacy three-year vesting period. The performance targets associated with the Brigham PSUs were deemed to have been achieved at 200% as of the date of the Brigham Merger. Because all performance targets were achieved prior to conversion and the number of Class A Common Shares to be issued upon satisfaction of the service requirements is known, the Company estimated the fair value of the PSUs as the closing price of the Company’s Class A Common Stock on the grant date of the awards, which is expensed over the applicable service period.

F-32

The following table summarizes activity related to unvested PSUs converted in the Brigham Merger for the year ended December 31, 2022.


	Performance Stock Units Converted in Brigham Merger
	Number of Shares		Grant Date Fair Value
Unvested at January 1, 2022		—	$	—
Granted		10,786		30.15
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2022		10,786	$	30.15

For the year ended December 31, 2022, the Company recognized $1,000 of share-based compensation expense related to PSUs converted in the Brigham Merger. As of December 31, 2022, there was approximately $324,000 of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of 2.2 years. For the years ended December 31, 2021 and 2020, there was no share-based compensation expense related to such awards.

Sitio OpCo Restricted Stock Awards

In connection with the Falcon Merger, legacy Desert Peak owners (the “Falcon Merger Sponsors”), desired to assign, transfer and convey their rights to receive a portion of their Falcon Merger Consideration to our executive officers as an incentive to continue to serve as executive officers following the Falcon Merger. The Falcon Merger Consideration consists of units of Sitio Royalties OpCo Partnership Units and an equal number of shares of Class C Common Stock. The conveyance of Falcon Merger Consideration, which consists of Class C Common Stock, is deemed to be a grant of restricted stock awards (each, an “RSA”) to our executive officers. Each Sitio OpCo RSA is expected to vest in equal installments on the first four anniversaries of June 6, 2022. The Company estimated the fair value of the RSAs as the closing price of the Company’s Class A Common Stock on the grant date of the award, which is expensed over the applicable service period.

The following table summarizes activity related to unvested Sitio OpCo RSAs for the year ended December 31, 2022.


	Sitio OpCo Restricted Stock Awards
	Number of Shares		Grant Date Fair Value
Unvested at January 1, 2022		—	$	—
Granted		309,527		29.12
Forfeited		—		—
Vested		—		—
Unvested at December 31, 2022		309,527	$	29.12

For the year ended December 31, 2022, the Company recognized $1.3 million of share-based compensation expense related to the Sitio OpCo RSAs. As of December 31, 2022, there was approximately $7.7 million of unamortized equity-based compensation expense related to the unvested Sitio OpCo RSAs. That expense is expected to be recognized over a weighted average period of approximately 3.4 years. For the years ended December 31, 2021 and 2020, there was no share-based compensation expense related to the Sitio OpCo RSAs.

Commodity Derivatives

The Company may enter into commodity derivative contracts to manage its exposure to oil and gas price volatility associated with its production. These derivatives are not entered into for trading or speculative purposes. While the use of these instruments limits the downside risk of adverse commodity price changes, their use may also limit future cash flows from favorable commodity price changes. Depending on acquisitions consummated, changes in oil and gas futures markets, and management’s view of underlying supply and demand trends, the Company may increase or decrease its derivative positions. The Company’s commodity derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses on commodity derivatives are recognized in the Company’s statements of operations.

The Company may utilize fixed price swaps, basis swaps, and two- and three-way collars to manage commodity price risks. The Company may enter into these contracts when management believes that favorable future sales prices for the Company’s production can be secured and acquisitions consummated are accretive. Under fixed price swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company receives the difference from the counterparty. The Company may also enter into basis swap contracts in order to hedge the difference between the New York Mercantile

F-34

Exchange (“NYMEX”) index price and a local index price that is representative of the price received by many of our operators. Under collar agreements, the Company receives the difference between the published index price and a floor price if the index price is below the floor price or the Company pays the difference between the ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index is between the floor and the ceiling. By utilizing a collar, the Company has fixed the minimum and maximum prices received on the underlying production.

The Company’s oil and gas swap contracts as of December 31, 2022 are summarized below:


	Oil (NYMEX WTI)
Remaining Term	Bbl per Day		Weighted Average Price per Bbl
January 2023 - December 2023		3,050	$	93.71
January 2024 - December 2024		3,300	$	82.66
January 2025 - June 2025		1,100	$	74.65


	Gas (NYMEX Henry Hub)
Remaining Term	MMBtu per Day		Weighted Average Price per MMBtu
January 2023 - December 2023		500	$	3.83
January 2024 - December 2024		500	$	3.41

The Company’s oil and gas two-way commodity collar contracts as of December 31, 2022 are summarized below:


	Oil (NYMEX WTI)
Remaining Term	Bbl per Day		Weighted Average Floor Price per Bbl		Weighted Average Ceiling Price per Bbl
January 2025 – June 2025		2,000	$	60.00	$	93.20


	Gas (NYMEX Henry Hub)
Remaining Term	MMBtu per Day		Weighted Average Floor Price per MMBtu		Weighted Average Ceiling Price per MMBtu
January 2023 - December 2023		8,500	$	4.82	$	7.93
January 2024 - December 2024		11,400	$	4.00	$	7.24
January 2025 – June 2025		11,600	$	3.31	$	10.34

The Company was not party to any basis swaps or three-way collar contracts as of December 31, 2022. The Company was not party to any derivative contracts as of December 31, 2021.

Interest Rate Derivatives

In November 2022, the Company entered into an interest rate swap agreement for an initial notional amount of $225.0 million. Such notional amount decreases by $5.625 million every 91 days. The interest rate swap manages exposure to changes in interest rates from variable rate obligations related to the 2026 Senior Notes. The interest rate swap term expires December 31, 2023. The Company’s interest rate derivative contract have not been designated as hedges for accounting purposes; therefore, all gains and losses on interest

F-35

rate derivatives are recognized in the Company’s statements of operation. The interest rate swap was not entered into for trading or speculative purposes.

Financial Summary

The following table presents a summary of the Company’s derivative instruments and where such values are recorded on the consolidated balance sheet as of December 31, 2022 and 2021 (in thousands):


	December 31, 2022			December 31, 2021
	Balance sheet location	Fair value		Balance sheet location	Fair value
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	18,555	Current assets	$	—
Interest rate contracts	Current assets		319	Current assets		—
Commodity contracts	Long-term assets		13,379	Long-term assets		—

Total asset derivatives		$	32,253		$	—

Liability derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current liabilities	$	—	Current liabilities	$	—
Commodity contracts	Long-term liabilities		—	Long-term liabilities		—

Total liability derivatives		$	—		$	—

Net derivatives		$	32,253		$	—

The following table presents the gross fair values of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented on the consolidated balances sheet (in thousands):


	December 31, 2022								December 31, 2021
	Gross Fair Value			Gross Amounts Offset			Net Fair Value		Gross Fair Value		Gross Amounts Offset		Net Fair Value
Commodity derivative assets	$	36,813		$	(4,879	)	$	31,934	$	—	$	—	$	—
Interest rate derivative assets		319			—			319		—		—		—
Commodity derivative liabilities		(4,879	)		4,879			—		—		—		—

The following table is a summary of derivative gains and losses, and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2022, 2021 and 2020 (in thousands):


		Year Ended December 31,
	Statement of income location	2022		2021		2020
Commodity derivative gains	Other income	$	39,037	$	—	$	2,573
Interest rate derivative gains	Other income	$	110	$	—	$	—

The fair values of commodity derivative instruments and interest rate derivative instruments were determined using Level 2 inputs.

Credit Risk in Derivative Instruments

The Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. All commodity derivative counterparties and interest rate derivative counterparty are current lenders under the Sitio Revolving Credit Facility. Accordingly, the Company is not required to provide any credit support to its derivative counterparties other than cross collateralization with the properties securing the Sitio Revolving Credit Facility. The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for each ISDA include credit support requirements, cross default provisions, termination events, and set-off provisions. The Company has set-off provisions with its lenders that, in the event of counterparty default, allow the Company to set-off amounts owed under the Sitio Revolving Credit Facility or other general obligations against amounts owed to the Company for derivative contract assets.

16. Income Taxes

The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period during which the change in rates is enacted.

The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2022 and 2021, the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions.

The Predecessor was a limited partnership that was not subject to U.S. federal income tax, but was subject to the Texas Margin Tax and state income taxes in New Mexico. As part of the Falcon Merger, the Predecessor contributed the interests in Desert Peak to Sitio OpCo in exchange for shares of Class C Common Stock and Sitio OpCo Units. On the date of the Falcon Merger, a corresponding “first day” deferred tax liability of approximately $3.6 million was recorded to establish a net deferred tax liability for differences between the tax and book basis of the Company’s investment in Sitio OpCo.

As part of the Brigham Merger, the Company acquired Brigham in exchange for shares of the Company’s Class A Common Stock or shares of the Company’s Class C Common Stock and Sitio OpCo Units, as applicable to each prior shareholder in Brigham. On the date of the Brigham Merger, a corresponding deferred tax liability of approximately $316.6 million was recorded to establish a net deferred tax liability for differences between the tax and book basis of the Company’s investment in Brigham Minerals Holdings, LLC.

Sitio Royalties Corp. is a corporation and is subject to U.S. federal income tax. The tax implications of the Falcon Merger, the Brigham Merger and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying consolidated financial statements.

The effective combined U.S. federal and state income tax rate for the year ended December 31, 2022 was 3.0%. During the twelve months ended December 31, 2022, 2021 and 2020, the Company recognized income tax expense of $5.7 million, $486,000, and $22,000. Total income tax expense for the years ended December 31, 2022, 2021 and 2020 differed from amounts computed by applying the U.S. federal statutory tax rate of 21% to pre-tax book income for those periods principally because of the Company’s temporary equity and noncontrolling interest, as well as the fact that the Predecessor was not subject to U.S. federal income taxes.

The components of the income tax provision were as follows for the periods indicated:

F-39


	Years Ended December 31,
	2022		2021		2021
Current	$	4,050	$	486	$	22
Deferred		1,631		—		—
Income tax expense (benefit)	$	5,681	$	486	$	22

The effective tax rate on pre-tax income differs from the Federal statutory rate of 21% for the years ended December 31, 2022, 2021, and 2020 due to the following:


	Years Ended December 31,
	2022			2021			2020
Income (loss) before income taxes	$	189,812		$	47,981		$	(14,192	)
Less: (income) loss before taxes attributable to Predecessor		(78,745	)		(47,981	)		14,192
Less: income before taxes attributable to temporary equity		(91,224	)		—			—
Less: loss before taxes attributable to noncontrolling interest		19			—			—
Income before tax attributable to stockholders	$	19,862		$	—		$	—

Income tax expense at Federal statutory rate	$	4,171			—			—
State taxes, net of federal benefit		1,707		486			22
Non-deductible transaction costs		452			—			—
Warranty liability adjustment		(769	)		—			—
Other, net		120			—			—
Provision for income taxes	$	5,681		$	486		$	22

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows:


	2022			2021		2020
Deferred tax assets:
Investment in subsidiary		—			—		—
Total deferred tax assets:	$	—		$	—	$	—
Deferred tax liabilities:
Investment in subsidiary		313,607			—		—
Total deferred tax liabilities	$	313,607		$	—	$	—
Net deferred tax assets (liabilities)	$	(313,607	)	$	—	$	—

There were no deferred tax assets or liabilities for the Company prior to the closing of the Falcon Merger.

The 2019 through 2022 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the state income tax returns of the Company for the year ended December 31, 2018, and prior are closed (except to the extent any net operating loss carryovers are used in open years).

As of December 31, 2022, the Company has not recorded a reserve for any uncertain tax positions.

20. Supplemental Oil and Gas Information (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows (in thousands):


	December 31, 2022			December 31, 2021
Oil and natural gas interests:
Unproved	$	3,244,436		$	817,873
Proved		1,926,214			447,369
Total oil and natural gas interests		5,170,650			1,265,242
Accumulated depletion and impairment		(222,072	)		(118,175	)
Net oil and natural gas interests capitalized	$	4,948,578		$	1,147,067

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows (in thousands):


	December 31, 2022		December 31, 2021
Acquisition costs
Unproved properties	$	283,341	$	20,192
Proved properties		274,228		18,278
Total	$	557,569	$	38,470

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas (in thousands). It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the net operating results of the Company’s oil, natural gas and NGL operations.

F-43


	Years Ended December 31,
	2022			2021			2020
Oil, natural gas and natural gas liquids revenues	$	355,430		$	118,548		$	44,194
Severance and ad valorem taxes		(25,572	)		(6,934	)		(3,167	)
Depletion		(103,898	)		(40,318	)		(31,440	)
Impairment of oil and natural gas properties		—			—			(812	)
Income tax expense		(5,681	)		(486	)		(22	)
Results of operations from oil, natural gas and natural gas liquids	$	220,279		$	70,810		$	8,753

The reserves at December 31, 2022, 2021 and 2020 presented below were prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), independent petroleum engineers. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in Texas, New Mexico, Oklahoma, Colorado, Wyoming, North Dakota, Pennsylvania, Ohio and West Virginia.

Guidelines prescribed in FASB ASC Topic 932 Extractive Industries – Oil and Gas (“ASC Topic 932”) have been followed for computing a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future cash inflows and future production costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the period-end estimated quantities of oil, natural gas and NGL to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future ad valorem taxes are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using period-end costs and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Analysis of Changes in Proved Reserves

The following table sets forth information regarding the Company’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for each of the periods presented:


	Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBOE)
Balance as of December 31, 2019		5,839			24,493			2,774			12,695
Revisions		(1,098	)		(867	)		65			(1,178	)
Extensions		995			3,486			423			1,999
Acquisition of reserves		445			633			77			628
Divestiture of reserves		(173	)		(209	)		(26	)		(234	)
Production		(933	)		(4,134	)		(488	)		(2,110	)
Balance as of December 31, 2020		5,075			23,402			2,825			11,800
Revisions		180			6,531			405			1,674
Extensions		610			1,991			216			1,158
Acquisition of reserves		7,240			19,165			2,076			12,511
Production		(1,261	)		(4,746	)		(499	)		(2,551	)
Balance as of December 31, 2021		11,844			46,343			5,023			24,592
Revisions		(231	)		2,926			1,093			1,349
Extensions		3,280			8,986			1,160			5,938
Acquisition of reserves		23,025			110,718			12,183			53,660
Production		(2,861	)		(9,531	)		(1,100	)		(5,550	)
Balance as of December 31, 2022		35,057			159,442			18,359			79,989

F-44


Proved developed and undeveloped reserves:	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBOE)
Developed as of December 31, 2019		4,223		20,293		2,298		9,903
Undeveloped as of December 31, 2019		1,616		4,200		476		2,792
Balance at December 31, 2019		5,839		24,493		2,774		12,695

Developed as of December 31, 2020		3,731		19,505		2,352		9,334
Undeveloped as of December 31, 2020		1,344		3,897		473		2,466
Balance at December 31, 2020		5,075		23,402		2,825		11,800

Developed as of December 31, 2021		9,285		40,747		4,417		20,494
Undeveloped as of December 31, 2021		2,559		5,596		606		4,098
Balance at December 31, 2021		11,844		46,343		5,023		24,592

Developed as of December 31, 2022		27,407		133,489		15,169		64,824
Undeveloped as of December 31, 2022		7,650		25,953		3,190		15,165
Balance at December 31, 2022		35,057		159,442		18,359		79,989

For the year ended December 31, 2022, the Company had downward revisions of 231 MBbls of oil, offset by upward revisions of 2,926 MMcf of gas and 1,093 MBbls of NGL. Total upward revisions of 1,349 MBOE were primarily due to upward revisions of 831 MBOE related to changes in estimated ultimate recovery and upward revisions of 377 MBOE due to increases in pricing. For the year ended December 31, 2022, the Company had extensions of 3,280 MBbls of oil, 8,986 MMcf of gas, and 1,160 MBbls of NGLs of which 814 MBbls of oil, 1,748 MMcf of gas, and 224 MBbls of NGLs were from conversions of non-proved resources to proved developed producing and proved developed not producing due to operator drilling activity and 2,466 MBbls of oil, 7,238 MMcf of gas, and 936 MBbls of NGLs were from additional proved undeveloped reserves. In 2022, the Company acquired royalty and mineral interests of 23,025 MBbls of oil, 110,718 MMcf of gas, and 12,183 MBbls of NGLs through multiple acquisitions. For the year ended December 31, 2022, the Company did not divest any royalty and mineral interests.

For the year ended December 31, 2021, the Predecessor had upward revisions of 180 MBbls of oil and 6,531 MMcf of gas and 405 MBbls of NGL. Total upward revisions of 1,674 MBOE were primarily due to upward revisions of 1,184 MBOE related to changes in estimated ultimate recovery and upward revisions of 490 MBOE due to increases in pricing. For the year ended December 31, 2021, the Predecessor had extensions of 610 MBbls of oil, 1,991 MMcf of gas, and 216 MBbls of NGLs of which 289 MBbls of oil, 883 MMcf of gas, and 96 MBbls of NGLs were from conversions of non-proved resources to proved developed producing and proved developed not producing due to operator drilling activity and 321 MBbls of oil, 1,108 MMcf of gas, and 120 MBbls of NGLs were from additional proved undeveloped reserves. In 2021, the Predecessor acquired royalty and mineral interests of 7,240 MBbls of oil, 19,165 MMcf of gas, and 2,076 MBbls of NGLs through multiple acquisitions. For the year ended December 31, 2021, the Predecessor did not divest any royalty and mineral interests.

For the year ended December 31, 2020, the Partnership had downward revisions of 1,098 MBbls of oil and 867 MMcf of gas and upward revisions of 65 MBbls of NGL. Total downward revisions of 1,178 MBOE were primarily due to downward revisions of 887 MBOE related to changes in estimated ultimate recovery and downward revisions of 239 MBOE due to decreases in pricing. For the year ended December 31, 2020, the Partnership had extensions of 995 MBbls of oil, 3,486 MMcf of gas, and 423 MBbls of NGLs of which 192 MBbls of oil, 672 MMcf of gas, and 81 MBbls of NGLs were from conversions of non-proved resources to proved developed producing due to operator drilling activity and 803 MBbls of oil, 2,814 MMcf of gas, and 342 MBbls of NGLs were from additional proved undeveloped reserves. In 2020, the Partnership acquired royalty and mineral interests of 445 MBbls of oil, 633 MMcf of gas, and 77 MBbls of NGLs through multiple acquisitions. For the year ended December 31, 2020, the Partnership divested royalty and mineral interests of 173 MBbls, 209 MMcf, and 26 MBbls of proved oil, natural gas, and NGL, respectively, in conjunction with the conveyances to DRC described in “Note 7 - Acquisitions.”

Standardized Measure of Oil and Gas

The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those

F-45

used; and actual costs may vary. Our calculations of the standardized measure of discounted future net cash flows and the related changes therein include Texas margin tax and include the effect of estimated federal income tax expenses.

As of December 31, 2022, the reserves are comprised of 44% crude oil, 33% natural gas and 23% NGL on an energy equivalent basis.

For the years ended December 31, 2022 and 2021, future cash inflows are calculated by applying the 12-month arithmetic average of the first-of-month price from January to December, of oil and gas relating to the Company’s proved reserves, to the year-end quantities of those reserves. The values for the December 31, 2022 and 2021 proved reserves were derived based on prices presented in the table below. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the NGL pricing was 37% of WTI for 2022 and 45% of WTI for 2021; the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.


	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2022 (Average)	$	93.05	$	5.70	$	34.97
December 31, 2021 (Average)	$	64.33	$	3.35	$	30.14

The following summary sets forth the future net cash flows related to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):


	Year Ended December 31,
	2022			2021			2020
Future oil and natural gas sales	$	4,812,767		$	1,068,652		$	238,977
Future production costs		(404,982	)		(90,137	)		(19,379	)
Future income tax expense		(438,049	)		(5,302	)		(1,236	)
Future net cash flows		3,969,736			973,213			218,362
10% annual discount		(1,792,681	)		(437,910	)		(94,803	)
Standardized measure of discounted future net cash flows	$	2,177,055		$	535,303		$	123,559

The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):


	Year Ended December 31,
	2022			2021			2020
Balance at the beginning of the period	$	535,303		$	123,559		$	183,225
Net change in prices and production costs		250,889			119,993			(59,911	)
Sales, net of production costs		(329,858	)		(111,691	)		(41,043	)
Extensions and discoveries		234,973			29,853			25,196
Acquisitions of reserves		1,645,909			326,192			9,137
Divestiture of reserves		—			—			(3,563	)
Revisions of previous quantity estimates		40,803			43,843			(18,140	)
Net change in income taxes		(244,815	)		(2,205	)		343
Accretion of discount		53,820			12,426			18,427
Changes in timing and other		(9,969	)		(6,667	)		9,888
Balance at the end of the period	$	2,177,055		$	535,303		$	123,559


Sitio Royalties Corp.
(Exact name of Registrant as specified in its Charter)

Delaware		88-4140242
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1401 Lawrence Street, Suite 1750 Denver, CO		80202
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code: (720) 640-7620


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Class A common stock, par value $0.0001 per share	STR	New York Stock Exchange
Warrants to purchase Class A common stock	STR WS	NYSE American


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)
	143,189		18.3	%		209,411		19,993		31,203		260,607		32,576		3,787,478		0.9	%


As of December 31, 2022
Resource Play/Basin	Net Mineral Acres		Net Royalty Acres (1)		100% Royalty Acres (2)		Gross DSU Acres		Implied Average Net Revenue Interest per Well (3)			Gross Horizontal Producing Well Count as of December 31, 2022 (4)		Average Daily Net Production for the Quarter Ended December 31, 2022 (5) BOE/d
Delaware		74,156		140,596		17,575		1,330,126		1.3	%		8,434		11,654
Midland		21,725		42,881		5,360		993,338		0.5	%		9,122		3,654
DJ		19,706		24,934		3,117		363,492		0.9	%		5,483		118
Eagle Ford		4,842		21,595		2,699		224,757		1.2	%		2,782		2,548
Anadarko		6,706		9,860		1,232		212,573		0.6	%		1,605		37
Williston		6,358		8,205		1,026		538,196		0.2	%		4,279		22
Appalachia		9,696		12,536		1,567		124,996		1.3	%		746		892
Total		143,189		260,607		32,576		3,787,478		0.9	%		32,451		18,925


	Proved Undeveloped Reserves (MBOE)
Balance, December 31, 2021		4,098
Acquisitions of Reserves		10,111
Extensions and Discoveries		4,607
Revisions of Previous Estimates		(107	)
Transfers to Estimated Proved Developed		(3,544	)
Balance, December 31, 2022		15,165


GLOSSARY		1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		5
SUMMARY RISK FACTORS		8

PART I

Item 1.	Business	10
Item 1A.	Risk Factors	33
Item 1B.	Unresolved Staff Comments	65
Item 2.	Properties	65
Item 3.	Legal Proceedings	65
Item 4.	Mine Safety Disclosures	66

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	67
Item 6.	[Reserved]	68
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	69
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	89
Item 8.	Financial Statements and Supplementary Data	90
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	90
Item 9A.	Controls and Procedures	90
Item 9B.	Other Information	91
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	91

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	92
Item 11.	Executive Compensation	92
Item 12.	Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters	92
Item 13.	Certain Relationships and Related Transactions, and Director Independence	92
Item 14.	Principal Accounting Fees and Services	92

PART IV

Item 15.	Exhibits and Financial Statement Schedules	93
Item 16.	Form 10-K Summary	97


Year	Number of Acquisitions		Total NRAs Acquired
2016		2		4,066
2017		50		18,056
2018		48		14,706
2019		67		11,026
2020		4		1,614
2021		9		56,095
2022		7		155,044
Total		187		260,607


	December 31, 2022(1)		December 31, 2021(2)		December 31, 2020(3)
Estimated proved developed reserves:
Crude oil (MBbls)		27,407		9,285		3,731
Natural gas (MMcf)		133,489		40,747		19,505
NGLs (MBbls)		15,169		4,417		2,352
Total (MBOE)		64,824		20,494		9,334
Estimated proved undeveloped reserves:
Crude oil (MBbls)		7,650		2,559		1,344
Natural gas (MMcf)		25,953		5,596		3,897
NGLs (MBbls)		3,190		607		473
Total (MBOE)		15,165		4,098		2,467
Estimated proved reserves:
Crude oil (MBbls)		35,057		11,844		5,075
Natural gas (MMcf)		159,442		46,343		23,402
NGLs (MBbls)		18,359		5,023		2,825
Total (MBOE)		79,989		24,592		11,800


Basin	Gross Horizontal Undeveloped Locations		Percentage of Total Portfolio			Net Horizontal Undeveloped Locations		Percentage of Total Portfolio
Delaware		28,091		56	%		321.6		74	%
Midland		15,099		30	%		66.8		15	%
DJ		2,527		5	%		27.3		6	%
Eagle Ford		430		1	%		6.5		1	%
Anadarko		958		2	%		7.4		2	%
Williston		2,649		5	%		4.3		1	%
Appalachia		604		1	%		3.7		1	%
Total		50,358		100	%		437.6		100	%


Basin	Gross DSU Acreage		Total NRAs		100% NRAs		Gross DSU Developed Acreage		Gross DSU Undeveloped Acreage		NRAs (Developed)		NRAs (Undeveloped)
Delaware		1,330,126		140,596		17,575		443,222		886,904		52,783		87,813
Midland		993,338		42,881		5,360		444,103		549,235		20,392		22,489
DJ		363,492		24,934		3,117		215,109		148,383		14,756		10,178
Eagle Ford		224,757		21,595		2,699		189,767		34,990		17,092		4,503
Anadarko		212,573		9,860		1,232		120,470		92,103		5,588		4,272
Williston		538,196		8,205		1,026		337,309		200,887		5,596		2,609
Appalachia		124,996		12,536		1,567		60,805		64,191		6,098		6,438
Total		3,787,478		260,607		32,576		1,810,785		1,976,693		122,305		138,302


	Year Ended December 31,
	2022			2021
Statement of Income Data:
Revenue:
Total revenue	$	369,612		$	120,588
Operating Expenses:
Management fees to affiliates		3,241			7,480
Depreciation, depletion and amortization		104,511			40,906
General and administrative		42,225			4,143
General and administrative—affiliates		74			8,855
Severance and ad valorem taxes		25,572			6,934
Deferred offering costs write off		—			2,396
Total operating expenses		175,623			70,714
Net income from operations		193,989			49,874
Interest expense (net)(1)		(35,499	)		(1,893	)
Change in fair value of warrant liability		3,662			—
Loss on extinguishment of debt		(11,487	)		—
Commodity derivatives gains		39,037			—
Interest rate derivatives gains		110			—
Net income before income tax expense		189,812			47,981
Income tax expense		(5,681	)		(486	)
Net income		184,131			47,495
Net income attributable to Predecessor		(78,104	)		(47,495	)
Net income attributable to temporary equity		(90,377	)		—
Net loss attributable to noncontrolling interest		51			—
Net income attributable to Class A stockholders	$	15,701		$	—


	For the year ended December 31,
	2021			2020
Statement of Operations Data:
Revenue:
Total revenue	$	120,588		$	45,699
Operating Expenses:
Management fees to affiliates	$	7,480		$	7,480
Depreciation, depletion and amortization		40,906			32,049
General and administrative		4,143			4,981
General and administrative—affiliates		8,855			4,407
Severance and ad valorem taxes		6,934			3,167
Impairment of oil and natural gas properties		—			812
Deferred offering costs write off		2,396			2,747
Bad debt recovered		—			(251	)
Gain on sale of other property		—			(42	)
Total operating expenses		70,714			55,350
Net income (loss) from operations		49,874			(9,651	)
Interest expense (net)(1)		(1,893	)		(1,968	)
Commodity derivatives gains (losses)		—			(2,573	)
Net income (loss) before income tax expense		47,981			(14,192	)
Income tax expense		(486	)		(22	)
Net income (loss)		47,495			(14,214	)
Net loss (income) attributable to Predecessor		(47,495	)		14,214
Net income attributable to Class A stockholders	$	—		$	—


Exhibit Number	Description
2.1#	Agreement and Plan of Merger, dated as of January 11, 2022, by and among Falcon Minerals Corporation, Falcon Minerals Operating Partnership, LP, Ferrari Merger Sub A LLC, and DPM HoldCo, LLC (incorporated by reference to Exhibit 2.1 to our predecessor's Current Report on Form 8-K filed on January 12, 2022).
2.2#	Agreement and Plan of Merger, dated as of September 6, 2022, by and among Sitio Royalties Corp., Sitio Royalties Operating Partnership, LP, Snapper Merger Sub I, Inc., Snapper Merger Sub II, LLC, Brigham Minerals, Inc. and Brigham Minerals Holdings LLC (incorporated by reference to Exhibit 2.1 to our predecessor’s Current Report on Form 8-K filed on September 12, 2022).
2.3	Contribution Agreement, dated as of June 3, 2018, by and among Royal Resources L.P., Royal Resources GP L.L.C., Nobel Royalties Acquisition Co. LP, Hooks Ranch Holdings LP, DGK ORRI Holdings, LP, DGK ORRI GP LLC, Hooks Holding Company GP, LLC and Osprey Energy Acquisition Corp. (incorporated by reference to Exhibit 2.1 to our predecessor’s Current Report on Form 8-K (File No. 001-38158) filed with the SEC on June 4, 2018).
3.1	Amended and Restated Certificate of Incorporation of the Company, dated as of December 28, 2022, effective as of December 29, 2022 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 29, 2022).
3.2	Second Amended and Restated Bylaws of the Company, adopted on December 29, 2022 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on December 29, 2022).
4.1	Note Purchase Agreement, dated as of September 21, 2022, by and among Sitio Royalties Operating Partnership, LP, as issuer, the subsidiary guarantors party thereto, the financial institutions from time to time party thereto as holders, and U.S. Bank Trust Company, National Association, as agent for the holders (incorporated by reference to Exhibit 10.2 to our predecessor’s Current Report on Form 8-K filed on September 23, 2022).
4.2	First Amendment to Note Purchase Agreement, dated as of December 29, 2022, by and among Sitio Royalties Operating Partnership, LP, as issuer, the subsidiary guarantors party thereto, the financial institutions from time to time party thereto as holders, and U.S. Bank Trust Company, National Association, as agent for the holders (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on December 29, 2022).


4.3	Warrant Agreement, dated as of July 20, 2017, between Falcon Minerals Corporation and Continental Stock Transfer & Trust Company, as warrant agent (incorporated by reference to Exhibit 4.1 to our predecessor’s Current Report on Form 8-K (File No. 001-38158) filed on July 26, 2017).
4.4	Warrant Agreement Assignment, Assumption and Amendment Agreement, dated as of December 29, 2022, among Sitio Royalties Corp., STR Sub Inc. and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on December 29, 2022).
4.5	Form of Registration Rights Agreement, dated as of December 29, 2022, by and among Sitio Royalties Corp., STR Sub Inc. and each of the other parties listed on the signature pages thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 29, 2022).
4.6	Registration Rights Agreement, dated as of January 11, 2022, by and among Falcon Minerals Corporation, Chambers DPM HoldCo, LLC, KMF DPM HoldCo, LLC, Source Energy Leasehold, LP, Permian Mineral Acquisitions, LP, Rock Ridge Royalty Company, LLC and Royal Resources L.P. (incorporated by reference to Exhibit 10.2 to our predecessor’s Current Report on Form 8-K filed on January 12, 2022).
4.7	Registration Rights Agreement dated as of August 23, 2018 by and among Falcon Minerals Corporation, Royal Resources L.P., Noble Royalties Acquisition Co., L.P., Hooks Ranch Holdings LP, DGK ORRI Holdings, LP, DGK ORRI GP LLC and Hooks Holdings Company GP, LLC (incorporated by reference to Exhibit 4.2 to our predecessor’s Current Report on Form 8-K (File No. 001-38158) filed on August 29, 2018).
4.8*	Description of Sitio Royalties Corp.’s registered securities.
10.1	Director Designation Agreement, dated as of January 11, 2022, by and among Falcon Minerals Corporation, Chambers DPM HoldCo, LLC, KMF DPM HoldCo, LLC, Source Energy Leasehold, LP, Permian Mineral Acquisitions, LP, Rock Ridge Royalty Company, LLC and Royal Resources L.P. (incorporated by reference to Exhibit 10.3 to our predecessor’s Current Report on Form 8-K filed on January 12, 2022).
10.2	Director Designation Agreement Assignment, Assumption and Amendment Agreement, dated as of December 29, 2022, by and among Sitio Royalties Corp., STR Sub Inc. and certain principal stockholders (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on December 29, 2022).
10.3	Second Amended and Restated Agreement of Limited Partnership of Sitio Royalties Operating Partnership, L.P., dated as of June 7, 2022 (incorporated by reference to Exhibit 10.3 to our predecessor’s Current Report on Form 8-K filed on June 10, 2022).
10.4	Amendment to Second Amended and Restated Agreement of Limited Partnership of Sitio Royalties Operating Partnership, L.P., dated as of December 28, 2022 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on December 29, 2022).
10.5	Sitio Royalties Corp. Long Term Incentive Plan (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8 filed on January 3, 2023).
10.6	Brigham Minerals, Inc. 2019 Long Term Incentive Plan (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on January 3, 2023).


10.7	Form of DPM HoldCo, LLC Assignment and Allocation Agreement (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8 filed on January 3, 2023).
10.8†	Sitio Royalties Corp. Severance Plan (incorporated by reference to Exhibit 10.6 our predecessor’s Current Report on Form 8-K filed on June 10, 2022).
10.9†	Form of Restricted Stock Unit Agreement under the Sitio Royalties Corp. Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to our predecessor’s Form 10-Q filed on August 8, 2022).
10.10†	Form of Performance Stock Unit Agreement under the Sitio Royalties Corp. Long Term Incentive Plan (incorporated by reference to Exhibit 10.8 to our predecessor’s Form 10-Q filed on August 8, 2022).
10.11†	Form of Deferred Share Unit Agreement under the Sitio Royalties Corp. Long Term Incentive Plan (incorporated by reference to Exhibit 10.9 to our predecessor’s Form 10-Q filed on August 8, 2022).
10.12†	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.7 to our predecessor’s Current Report on Form 8-K filed on June 10, 2022).
10.13	Second Amended and Restated Credit Agreement, dated as of June 7, 2022, among Sitio Royalties Operating Partnership, LP, as borrower, KMF Land, LLC, Bank of America, N.A., as the administrative agent and issuing bank, the lenders party thereto and other financial institutions from time to time party thereto (incorporated by reference to Exhibit 10.8 to our predecessor’s Current Report on Form 8-K filed on June 10, 2022).
10.14	First Amendment to Second Amended and Restated Credit Agreement, dated as of June 24, 2022, among Sitio Royalties Operating Partnership, LP, as borrower, the guarantors party thereto, the lenders party thereto and Bank of America, N.A., as the administrative agent and issuing bank (incorporated by reference to Exhibit 10.2 to our predecessor’s Current Report on Form 8-K filed on June 27, 2022).
10.15	Second Amendment to Second Amended and Restated Credit Agreement, dated as of July 8, 2022, among Sitio Royalties Operating Partnership, LP, as borrower, the guarantors party thereto, the lenders party thereto and Bank of America, N.A., as the administrative agent and issuing bank (incorporated by reference to Exhibit 10.2 to our predecessor’s Current Report on Form 8-K filed on July 13, 2022).
10.16	Third Amendment to Second Amended and Restated Credit Agreement, dated as of September 21, 2022, by and among Sitio Royalties Operating Partnership, LP, as borrower, the guarantors party thereto, the lenders from time to time party thereto as lenders, and Bank of America, N.A. as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to our predecessor’s Current Report on Form 8-K filed on September 23, 2022).
10.17	Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of December 29, 2022, by and among Sitio Royalties Operating Partnership, LP, as borrower, the guarantors party thereto, the lenders from time to time party thereto as lenders, and Bank of America, N.A. as administrative agent for the lenders (incorporated by reference to Exhibit 10.1 to our predecessor’s Current Report on Form 8-K filed on December 29, 2022).
10.18	Third Amended and Restated Credit Agreement, dated as of February 3, 2023, by and among Sitio Royalties Operating Partnership, LP, as borrower, each lender from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and any other parties from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 8, 2023).


	SITIO ROYALTIES CORP.


10.19	Credit Agreement, dated as of May 16, 2019, among Brigham Resources, LLC, the financial institutions party thereto, and Wells Fargo Bank, N.A.
10.20	First Amendment to Credit Agreement, dated as of November 7, 2019, among Brigham Resources, LLC, the financial institutions party thereto, and Wells Fargo Bank, N.A.
10.21	Second Amendment to Credit Agreement, dated as of February 25, 2020, among Brigham Resources, LLC, the financial institutions party thereto, and Wells Fargo Bank, N.A.
10.22	Third Amendment to Credit Agreement, dated as of July 7, 2021, among Brigham Resources, LLC, the financial institutions party thereto, and Wells Fargo Bank, N.A.
10.23	Fourth Amendment to Credit Agreement, dated as of December 15, 2021, among Brigham Resources, LLC, the financial institutions party thereto, and Wells Fargo Bank, N.A.
10.24	Fifth Amendment to Credit Agreement, dated as of June 3, 2022, among Brigham Resources, LLC, the financial institutions party thereto, and Wells Fargo Bank, N.A.
10.25	Sixth Amendment to Credit Agreement, dated as of December 29, 2022, among Brigham Resources, LLC, the financial institutions party thereto, and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on form 8-K filed on December 29, 2022).
10.26	364-Day Bridge Term Loan Agreement, dated as of June 24, 2022, among Sitio Royalties Operating Partnership, LP, as borrower, the lenders party thereto and Bank of America, N.A., as the administrative agent (incorporated by reference to Exhibit 10.1 to our predecessor’s Current Report on Form 8-K filed on June 27, 2022).
10.27	First Amendment to 364-Day Bridge Term Loan Agreement, dated as of July 8, 2022, among Sitio Royalties Operating Partnership, LP, as borrower, the lenders party thereto and Bank of America, N.A., as the administrative agent (incorporated by reference to Exhibit 10.1 to our predecessor’s Current Report on Form 8-K filed on July 13, 2022).
10.28	Support Agreement, dated as of September 6, 2022, by and among Sitio Royalties Corp., BX Royal Aggregator LP, Rock Ridge Royalty Company LLC and Brigham Minerals, Inc. (incorporated by reference to Exhibit 10.1 to our predecessor’s Current Report on Form 8-K filed on September 12, 2022).
10.29	Support Agreement, dated as of September 6, 2022, by and among Sitio Royalties Corp., KMF DPM HoldCo, LLC, Chambers DPM HoldCo, LLC and Brigham Minerals, Inc. (incorporated by reference to Exhibit 10.2 to our predecessor’s Current Report on Form 8-K filed on September 12, 2022).
10.30	Support Agreement, dated as of September 6, 2022, by and among Sitio Royalties Corp., Source Energy Leasehold, LP, Permian Mineral Acquisitions, LP and Brigham Minerals, Inc. (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 12, 2022).
10.31	Support Agreement, dated as of January 11, 2022, by and among Falcon Minerals Corporation, DPM Holdco, LLC and Royal Resources L.P. (incorporated by reference to Exhibit 10.1 to our predecessor’s Current Report on Form 8-K (file No. 001-38158) filed January 12, 2022).


21.1*	Subsidiaries of the Company.
23.1*	Consent of KPMG, LLP.
23.2*	Consent of Cawley, Gillespie & Associates, Inc.
31.1*	Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Cawley, Gillespie & Associates, Inc. Summary of Reserves of Sitio Royalties Corp. at December 31, 2022
101.INS	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Taxonomy Extension Schema Document.
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB	Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).


Date:	March 8, 2023	By:	/s/ Christopher L. Conoscenti
			Christopher L. Conoscenti
			Chief Executive Officer
			(Principal Executive Officer, Director)


Date:	March 8, 2023	By:	/s/ Carrie L. Osicka
			Carrie L. Osicka
			Chief Financial Officer
			(Principal Financial Officer)


Date:	March 8, 2023	By:	/s/ Jim Norris
			Jim Norris
			Vice President – Chief Accounting Officer
			(Principal Accounting Officer)


Name	Title	Date

/s/ Christopher L. Conoscenti	Chief Executive Officer	March 8, 2023
Christopher L. Conoscenti	(Principal Executive Officer, Director)

/s/ Carrie L. Osicka	Chief Financial Officer	March 8, 2023
Carrie L. Osicka	(Principal Financial Officer)

/s/ Jim Norris	Vice President – Chief Accounting Officer	March 8, 2023
Jim Norris	(Principal Accounting Officer)

/s/ Noam Lockshin	Director	March 8, 2023
Noam Lockshin

/s/ Alice Gould	Director	March 8, 2023
Alice Gould

/s/ Morris Clark	Director	March 8, 2023
Morris Clark

/s/ Claire Harvey	Director	March 8, 2023
Claire Harvey

/s/ Gayle L. Burleson	Director	March 8, 2023
Gayle L. Burleson

/s/ Jon-Al Duplantier	Director	March 8, 2023
Jon-Al Duplantier

/s/ Richard K. Stoneburner	Director	March 8, 2023
Richard K. Stoneburner

/s/ John R. Sult	Director	March 8, 2023
John R. Sult


Report of Independent Registered Public Accounting Firm (KPMG LLP, Denver, CO Auditor Firm ID: 185)			F-2
Consolidated Balance Sheets			F-5
Consolidated Statements of Operations			F-6
Consolidated Statements of Cash Flows			F-7
Consolidated Statements of Equity			F-8
Notes to Consolidated Financial Statements			F-9


	December 31,			December 31,
	2022			2021
ASSETS
Current assets
Cash and cash equivalents	$	18,818		$	12,379
Accrued revenue and accounts receivable, net		142,010			36,202
Prepaid assets		12,489			235
Derivative asset		18,874			—
Total current assets		192,191			48,816

Property and equipment
Oil and natural gas properties, successful efforts method:
Unproved properties		3,244,436			817,873
Proved properties		1,926,214			447,369
Other property and equipment		3,421			8,187
Accumulated depreciation, depletion and amortization		(223,214	)		(121,536	)
Net oil and gas properties and other property and equipment		4,950,857			1,151,893

Other long-term assets
Long-term derivative asset		13,379			—
Deferred financing costs		7,082			2,145
Operating lease right-of-use asset		5,679			—
Other long-term assets		1,714			—
Total long-term assets		27,854			2,145

TOTAL ASSETS	$	5,170,902		$	1,202,854

LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses		21,899			4,140
Due to affiliates		—			442
Warrant liability		2,950			—
Operating lease liability		1,563			—
Total current liabilities		26,412			4,582

Long-term liabilities
Long-term debt		938,896			134,000
Deferred tax liability		313,607			—
Deferred rent		—			1,129
Non-current operating lease liability		5,303			—
Other long-term liabilities		89			—
Total long-term liabilities		1,257,895			135,129

Total liabilities		1,284,307			139,711

Commitments and contingencies (see Note 17)

Equity
Class A Common Stock, par value $0.0001 per share; 240,000,000 shares authorized; 80,171,951 and 0 shares issued and outstanding at December 31, 2022 and December 31, 2021, respectively		8			—
Class C Common Stock, par value $0.0001 per share; 120,000,000 shares authorized; 74,347,005 and 0 shares issued and outstanding at December 31, 2022 and December 31, 2021, respectively		7			—
Additional paid-in capital		1,750,640			—
Accumulated deficit		(9,203	)		—
Treasury Shares, 633,005 and 0 shares at December 31, 2022 and 2021, respectively		(19,085	)		—
Partners’ Capital		-			560,622
Noncontrolling interest		2,164,228			502,521
Total equity		3,886,595			1,063,143

TOTAL LIABILITIES AND EQUITY	$	5,170,902		$	1,202,854


	Predecessor Equity						Stockholders’ Equity
							Class A				Class C					Additional
	Partners’			Noncontrolling			Common Stock				Common Stock					Paid-in			Accumulated			Treasury Shares						Noncontrolling			Total
	Capital			Interest			Shares		Amount		Shares			Amount		Capital			Deficit			Shares			Amount			Interest			Equity
Balance at January 1, 2020	$	563,611		$	—			—	$	—		—		$	—	$	—		$	—			—		$	—		$	—		$	563,611
Net loss		(14,214	)		—			—		—		—			—		—			—			—			—			—			(14,214	)
Capital contributions		13,000			—			—		—		—			—		—			—			—			—			—			13,000
Balance at December 31, 2020	$	562,397		$	—			—	$	—		—		$	—	$	—		$	—			—		$	—		$	—		$	562,397
Capital contributions	$	8,000		$	—			—	$	—		—		$	—	$	—		$	—			—		$	—		$	—		$	8,000
Distribution		(67,500	)		(60,882	)		—		—		—			—		—			—			—			—			—			(128,382	)
Issuance of equity by consolidated subsidiary		66,470			507,163			—		—		—			—		—			—			—			—			—			573,633
Deemed distribution in connection with common control acquisition		(37,459	)		37,459			—		—		—			—		—			—			—			—			—			—
Net income		28,714			18,781			—		—		—			—		—			—			—			—			—			47,495
Balance at December 31, 2021	$	560,622		$	502,521			—	$	—		—		$	—	$	—		$	—			—		$	—		$	—		$	1,063,143
Net income attributable to Predecessor		39,493			38,611			—		—		—			—		—			—			—			—			—			78,104
Capital distribution		—			(13,318	)		—		—		—			—		—			—			—			—			—			(13,318	)
Balance prior to Falcon Merger at June 6, 2022	$	600,115		$	527,814			—	$	—		—		$	—	$	—		$	—			—		$	—		$	—		$	1,127,929
Falcon Merger Transaction (effected for 1-for-4 reverse stock split)	$	(600,115	)	$	(527,814	)		12,089	$	1		71,752		$	7	$	352,019		$	—			—		$	—		$	—		$	(775,902	)
Net income attributable to stockholders		—			—			—		—		—			—		—			15,751			—			—			—			15,751
Share-based compensation		—			—			—		—		—			—		7,965			—			—			—			—			7,965
Conversion of Class C Common Stock to Class A Common Stock		—			—			1,361		—		(1,361	)		—		34,038			—			—			—			—			34,038
Deferred tax asset arising from conversion of shares of Class C Common Stock to Class A Common Stock		—			—			—		—		—			—		8,211			—			—			—			—			8,211
Dividends to Class A stockholders		—			—			—		—		—			—		—			(18,165	)		—			—			—			(18,165	)
Dividend equivalent rights paid		—			—			—		—		—			—		—			(579	)		—			—			—			(579	)
Adjustment of temporary equity to redemption amount		—			—			—		—		—			—		(700,779	)		(6,160	)		—			—			—			(706,939	)
Balance prior to Brigham Merger at December 28, 2022	$	—		$	—			13,450	$	1		70,391		$	7	$	(298,546	)	$	(9,153	)		—		$	—		$	—		$	(307,691	)
Brigham Merger Transaction		—			—			67,334		7		3,956			—		2,049,186			—			(633	)		(19,085	)		119,293			2,149,401
Reclassification from temporary equity to noncontrolling interest		—			—			—		—		—			—		—			—			—			—			2,044,986			2,044,986
Issuance of Class A Common Stock upon vesting of DSUs		—			—			21		—		—			—		—			—			—			—			—			—
Net income (loss) attributable to stockholders		—			—			—		—		—			—		—			(50	)		—			—			(51	)		(101	)
Balance at December 31, 2022	$	—		$	—			80,805	$	8		74,347		$	7	$	1,750,640		$	(9,203	)		(633	)	$	(19,085	)	$	2,164,228		$	3,886,595


Oil and natural gas properties:	December 31, 2022			December 31, 2021
Unproved properties	$	3,244,436		$	817,873
Proved properties		1,926,214			447,369
Oil and natural gas properties, gross		5,170,650			1,265,242
Accumulated depletion and impairment		(222,072	)		(118,175	)
Oil and natural gas properties, net	$	4,948,578		$	1,147,067


	Temporary equity adjustments
Balance – June 7, 2022(1)	$	1,395,799
Share-based compensation		1,283
Conversion of Class C Common Stock to Class A Common Stock		(34,038	)
Net income attributable to temporary equity		90,377
Distributions to holders of temporary equity		(115,375	)
Adjustment of temporary equity to redemption amount		706,940
Reclassification to noncontrolling interest (2)		(2,044,986	)
Balance – December 28, 2022	$	—


Stock price	$	28.85
Volatility		47.0	%
Risk-free rate		4.70	%
Dividend yield		6.93	%
Term	0.7 years


	Year Ended December 31,
	2022
Balance at June 7	$	2,213
Decrease in fair value		(844	)
Balance at December 31	$	1,369


	Balance sheet location	December 31, 2022
Operating leases:
Operating lease right-of-use asset	Long-term assets	$	5,679
Total assets		$	5,679
Operating leases:
Current operating lease liability	Current liabilities	$	1,563
Non-current operating lease liability	Long-term liabilities		5,303
Total liability		$	6,866


	December 31, 2022
Weighted average remaining lease term in years		5.4
Weighted average discount rate		7.0	%


Year	Total
2023	$	1,563
2024		1,603
2025		1,517
2026		1,530
2027		1,109
Thereafter		875
Total lease payments		8,197
Less imputed interest		(1,331	)
Total lease liabilities	$	6,866