UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2022

OR

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

For the transition period from to

Commission File Number 001-41585

 

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

Securities registered pursuant to Section 12(g) of the Act: None

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.

Large accelerated filer ☐ Accelerated filer 

Non-accelerated filer ☐ Smaller reporting company ☐

Emerging growth company ☐

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

Documents Incorporated by Reference:

Portions of the registrant’s definitive proxy statement for the 2023 annual meeting of stockholders, to be filed no later than 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS

Page

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

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GLOSSARY

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.

BOE/d. BOE per day.

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.

GAAP. Generally accepted accounting principles in the United States.

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.

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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.

MBbl. Thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

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.

Play. A geographic area with hydrocarbon potential.

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

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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.

SEC. U.S. Securities and Exchange Commission.

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

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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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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:

•our ability to identify, complete and integrate operations or realize any anticipated benefits, synergies, savings or growth of acquisitions of properties, businesses or technologies, including the Falcon Merger and Brigham Merger;

•our ability to retain and hire key personnel;

•our ability to finance our obligations (including the repayment of certain of Brigham’s indebtedness on acceptable terms or at all);

•our ability to execute our business strategy;

•changes in general economic, business or industry conditions, including the material and adverse negative consequences of the COVID-19 pandemic and its unfolding impact on the global and national economy, the continued impact of inflation and associated monetary policy and/or as a result of the armed conflict in Ukraine and associated economic sanctions on Russia;

•the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other significant producers and governments, including the armed conflict in Ukraine and the potential destabilizing effect such conflict may pose for the global oil and natural gas markets, and the ability of such producers to agree to and maintain oil price and production controls;

•the effect of change in commodity prices, including the volatility of realized oil and natural gas prices, as a result of the Russian invasion of Ukraine that has led to significant armed hostilities and a number of severe economic sanctions on Russia or otherwise;

•the level of production on our properties;

•overall and regional supply and demand factors, delays, or interruptions of production;

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

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•competition in the oil and natural gas industry;

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

•title defects in the properties in which we invest;

•risks associated with the drilling and operation of crude oil and natural gas wells, including uncertainties with respect to identified drilling locations and estimates of reserves;

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

•restrictions on the use of water;

•the availability of pipeline capacity and transportation facilities;

•the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

•the impact of environmental, health and safety and other governmental regulations and of current or pending legislation, including federal and state legislative and regulatory initiatives relating to hydraulic fracturing and the impact of the Inflation Reduction Act of 2022 (the “IRA 2022”) and any related legislation, regulations or changes in policy;

•future operating results;

•risk related to our hedging activities;

•exploration and development drilling prospects, inventories, projects, and programs;

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

•operating hazards faced by our operators;

•technological advancements;

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

•the other risks identified in this Annual Report on Form 10-K, including, without limitation, those under Item 1A. “Risk Factors,” Item 1. “Business,” and Item 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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.

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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.

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SUMMARY RISK FACTORS

Risks Related to Sitio’s Business

•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 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 the production from wells and/or 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 depends in part on acquisitions to grow its reserves, production and cash flows. 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 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.

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

•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.

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

•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.

•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. These derivative contracts may expose Sitio to the risk of financial loss and reduce earnings in some circumstances and may 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.

Risks Related to Sitio’s Industry

•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.

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•The marketability of crude oil, natural gas and NGL production is dependent upon transportation, pipelines 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.

Risks Related to Environmental and Regulatory Matters

•The IRA 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.

•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.

•Federal and state legislative and regulatory initiatives relating to hydraulic fracturing, methane emissions, freshwater sourcing, produced water transportation and/or disposal, and/or seismic activity, could cause Sitio’s E&P operators to incur increased costs, additional operating restrictions or delays and fewer potential drilling locations.

•Conservation measures, technological advances, general concern about the environmental impact of the production and use of fossil fuels and increasing attention to environmental, social and governance (“ESG”) matters could materially reduce demand for crude oil, natural gas and NGLs, availability of capital and adversely affect Sitio's results of operations.

Risks Relating to Sitio’s Financial and Debt Arrangements

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

•Restrictions in Sitio and Sitio OpCo’s current and future debt agreements and credit facilities could limit Sitio’s growth and its ability to engage in certain activities.

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

Risks Relating to Sitio’s Organization and Structure

•Because Sitio is a holding company whose sole material asset is its equity interest in Sitio OpCo, it 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’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.

•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.

•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.

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PART I

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.

Item 1. Business

Overview

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

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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.

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

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.

Sitio’s Key Producing Regions

Permian Basin

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

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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.

Other Basins

DJ Basin

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.

Eagle Ford

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.

Appalachian Basin

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.

Anadarko Basin – SCOOP and STACK Plays

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.

Williston Basin

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

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

Sitio’s Mineral and Royalty Interests

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.

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	%

(1)Sitio’s mineral interests are based on its average royalty interests across its net mineral acreage position normalized to reflect a 1/8th royalty interest per net mineral acre (i.e., NRAs from mineral and royalty interests are calculated by multiplying 143,189 net mineral acres multiplied by an average royalty of 18.28% and then divided by 12.5%).

(2)All unleased mineral interests are assumed at a 25% royalty interest or 12.5% royalty interest on Relinquishment Act land for the Permian Basin; 20% for Eagle Ford; Bakken, DJ, and Anadarko Basins; 17.5% for the Appalachia Basin.

(3)Calculated as 260,607 NRAs multiplied by 12.5%.

(4)Calculated as 32,576, 100% royalty acres divided by 3.79 MM gross DSU acres.

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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

Note: Individual amounts may not add up to totals due to rounding.

(1) Standardized to a 1/8th interest

(2) Standardized to a 100% interest.

(3) Calculated as number of 100% royalty acres per gross DSU acre.

(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.

Sitio’s Reserves and Production

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.

Sitio’s E&P Operators

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.

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ESG Philosophy

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.

Crude Oil, Natural Gas and NGLs Data

The information included in “—Crude Oil, Natural Gas and NGLs Data” and “—Crude Oil, Natural Gas and NGL Production Prices and Costs” presents 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.

Preparation of Proved Reserve Estimates

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

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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.

Internal Controls

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.

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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:

• review and verification of historical crude oil, natural gas and NGLs production data, which such data is based on actual production reported by the operators of Sitio’s properties;

• review by Mr. Marcoux of all of Sitio’s reported proved reserves, including the review of all significant reserve changes and all PUD additions or reductions;

• verification of property ownership by land department; and

• direct reporting responsibilities of Mr. Marcoux to our CEO.

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.

Summary of Reserves

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.

	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

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(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.”

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PUDs

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):

	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

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

•the acquisition of additional mineral and royalty interests located in the Delaware, Midland, DJ, Eagle Ford, Williston, Anadarko and Appalachia Basins in multiple transactions, which included 10,111 MBOE of additional PUDs;

•well additions, extensions and discoveries of approximately 4,607 MBOE, as 715 horizontal locations were converted to proved undeveloped;

•negative volume revisions of 107 MBOE primarily driven by uncertainty of development timing and well abandonments;

•and the conversion of approximately 3,544 MBOE in PUD reserves into proved developed reserves as 469 of 576 horizontal locations were drilled and completed.

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.

Prospective Undeveloped Horizontal Drilling Locations

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

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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.

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	%

Note: Individual amounts may not total due to rounding.

Crude Oil, Natural Gas and NGL Production Prices and Costs

Production and Price History

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:

	Year Ended December 31,
	2022		2021		2020
Production data:
Crude oil (MBbls)		2,861		1,261		933
Natural gas (MMcf)		9,531		4,746		4,134
NGLs (MBbls)		1,100		499		488
Total (MBOE)		5,550		2,551		2,110
Average realized prices:
Crude oil (per Bbl)	$	93.05	$	67.29	$	37.40
Natural gas (per Mcf)	$	5.50	$	3.61	$	1.03
NGLs (per Bbl)	$	33.51	$	33.22	$	10.32
Total (per BOE)(1)	$	64.05	$	46.47	$	20.95
Average cost (per BOE):
Production and ad valorem taxes	$	4.61	$	2.72	$	1.50

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

Drilling Results

Productive wells consist of producing horizontal wells, wells capable of production and exploratory, development or extension wells that are not dry wells. As of December 31, 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.

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Acreage

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

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

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.”

Regulation

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.

Environmental Matters

Crude oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the properties in which 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.

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Non-Hazardous and Hazardous Waste

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with 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.

Remediation

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and analogous state laws generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying 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.

Water Discharges

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

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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.

Air Emissions

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

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

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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

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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.

Regulation of Hydraulic Fracturing

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

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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.

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Endangered Species Act

The ESA restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, and to reconsider listing the species under the ESA. 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.

Employee Health and Safety

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.

Other Regulation of the Crude Oil and Natural Gas Industry

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

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

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.

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Drilling and Production

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:

• the location of wells;

•the method of drilling and casing wells;

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

•the rates of production or “allowables”;

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

•the plugging and abandoning of wells;

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

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce Sitio’s interest in the unitized properties. In addition, state c