STR Sub Inc. - Annual Report: 2021 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2021

or

For the transition period from                  to                 

Commission file number: 001-38158

FALCON MINERALS CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 814-4657

Securities registered pursuant to Section 12(b) of the Act:

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  ☐    No  ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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 controls 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.    ☐

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

As of June 30, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s voting securities held by non-affiliates was approximately $255.4 million, based on the number of shares held by non-affiliates and the last reported sales price of the registrant’s Class A common stock as of that date. The registrant does not have any non-voting common stock outstanding.  

As of March 3, 2022, there were 47,061,505 shares of the registrant’s Class A common stock, par value $0.0001 per share, issued and outstanding and there were 39,387,782 shares of the registrant’s Class C common stock, par value of $0.0001 per share, issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this Annual Report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this Annual Report, including those detailed under “Item 1A. Risk Factors” in this Annual Report, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted, or implied in such forward-looking statements.

Forward-looking statements may include statements about:

The forward-looking statements contained in this Annual Report are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, those factors described under the heading “Risk Factors”. Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.

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GLOSSARY OF TERMS

Adjusted EBITDA:    Represents net income before interest expense, income taxes and depreciation and amortization expense, as further adjusted for other non-cash charges and other charges that are not reflective of our ongoing operations. Adjusted EBITDA is not a presentation made in accordance with GAAP. Please see the reconciliation of Adjusted EBITDA to net income in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Results of Operations—Adjusted EBITDA.”

Barrel or bbl:  Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

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 oil.

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.

Condensate:  Liquid hydrocarbons associated with the production that is primarily natural gas.

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

Developed acreage: Acreage allocated or assignable to productive wells.  

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

GAAP:  Generally accepted accounting principles in the United States.

Gross acres or gross wells:  The total acres or wells, as the case may be, in which an overriding, royalty or mineral interest is owned.

MBbls:  Thousand barrels of crude oil or other liquid hydrocarbons.

MBOE:  One thousand BOE.

Mcf:  Thousand cubic feet of natural gas.

Mineral interests:  The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.  

MMBtu:  Million British Thermal Units.

MMcf:  Million cubic feet of natural gas.

Net royalty acres: Gross acreage multiplied by the net royalty interest.  

NGLs:  Natural gas liquids.

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

Proved reserves:  The estimated quantities of oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

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PUD:  Proved undeveloped, used to characterize reserves.

Reserves:  The estimated remaining quantities of 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 oil and natural gas or related substances to the market and all permits required to implement the project. Reserves are not 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 natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty interest:  An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

SEC:  U.S. Securities and Exchange Commission.

Undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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

PART I

ITEM 1.BUSINESS

Corporate History

Falcon (formerly named Osprey Energy Acquisition Corp.) was a blank check company, incorporated in Delaware in June 2016. The Company was formed for the purpose of acquiring, through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization, recapitalization, or other similar business transaction, one or more operating businesses or assets.

On August 23, 2018 (the “Closing Date”), the Company completed the acquisition of the equity interests (the “Equity Interests”) in certain of the subsidiaries (the “Royal Entities”) of Noble Royalties Acquisition Co., LP (“NRAC”), Hooks Ranch Holdings LP (“Hooks Holdings”), DGK ORRI Holdings, LP (“DGK”), DGK ORRI GP LLC (“DGK GP”) and Hooks Holding Company GP, LLC (“Hooks GP”, and collectively with NRAC, Hooks Holdings, DGK, and DGK GP, the “Contributors”). The acquisition was made pursuant to the Contribution Agreement, dated as of June 3, 2018 (the “Contribution Agreement”), by and among the Company, Royal Resources L.P. (“Royal”), Royal Resources GP L.L.C. (“Royal GP”) and the Contributors. The acquisition of the Royal Entities pursuant to the Contribution Agreement is referred to as the “Business Combination” and the Business Combination together with the other transactions contemplated by the Contribution Agreement are referred to herein as the “deSPAC Transactions.”

Pursuant to the Contribution Agreement, on the Closing Date, the Company contributed cash to Falcon Minerals Operating Partnership, LP, a Delaware limited partnership and wholly owned subsidiary of the Company (“OpCo”), in exchange for (a) a number of OpCo Common Units representing limited partnership interests in OpCo (the “OpCo Common Units”) equal to the number of shares of the Company’s Class A common stock, par value $0.0001 per share (the “Class A common stock”), outstanding as of the Closing Date and (b) a number of OpCo warrants exercisable for OpCo Common Units equal to the number of the Company’s warrants outstanding as of the Closing Date. The Company controls OpCo through Falcon Minerals GP, LLC, a Delaware limited liability company, a wholly owned subsidiary of the Company and the sole general partner of OpCo .

In connection with the Company’s entry into the Contribution Agreement, the Company agreed to issue and sell in a private placement an aggregate of 11,480,000 shares of Class A common stock for a purchase price of $10.00 per share, and aggregate consideration of $114.8 million (the “Private Placement”). The Private Placement was consummated concurrently with the deSPAC Transactions on the Closing Date and the proceeds of the Private Placement were used to fund a portion of the cash consideration paid to the Contributors.

On the Closing Date, Falcon completed the acquisition of the Equity Interests and in return the Contributors received (i) $400 million of cash and (ii) 40 million OpCo Common Units. The Company also issued to the Contributors 40 million shares of non-economic Class C common stock of the Company, which entitles each holder to one vote per share. The OpCo Common Units are redeemable on a one-for-one basis for shares of Class A common stock at the option of the Contributors. Upon the redemption by any Contributor of OpCo Common Units for Class A common stock, a corresponding number of shares of Class C common stock held by such Contributor will be cancelled.   

In connection with the closing of the Business Combination (the “Closing”), the Company changed its name from “Osprey Energy Acquisition Corp.” to “Falcon Minerals Corporation”. The Company is now structured as an “Up-C,” meaning that substantially all the assets of the Company are held by OpCo, and the Company’s only operating asset is its equity interest in OpCo. Each OpCo Common Unit, together with one share of Class C common stock, is exchangeable for one share of Class A common stock at the option of the holder pursuant to the terms of the Company’s and OpCo’s organizational documents, subject to certain restrictions.

Our Business

We were formed to own and acquire royalty interests, mineral interests, non-participating royalty interest and overriding royalty interests, or ORRIs (collectively, “Royalties”), in oil and natural gas properties in North America, substantially all of which are located in the Eagle Ford Shale. These Royalties entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of any applicable post-production expenses and taxes. The holder of these interests has no obligation to fund exploration and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life, which we believe results in low breakeven costs. As such, we have historically operated with high cash margins, converting a large percentage of revenue to free cash flow, the majority of which can be distributed to our shareholders. 

As of December 31, 2021, our assets consisted of Royalties underlying approximately 256,000 gross unit acres (approximately 2,670 net royalty acres not normalized to 1/8th) that are concentrated in what we believe is the “core-of-the-core” of the liquids-rich condensate region of the Eagle Ford Shale in Karnes, DeWitt, and Gonzales Counties, Texas. In all three of these counties, we also have substantial exposure to the Austin Chalk and Upper Eagle Ford formations (this overlapping acreage is included in the 256,000 gross unit acres), which have experienced increased horizontal development activity, in addition to the more established and historically developed Lower Eagle Ford formation. We believe that the wells and remaining drilling locations on the properties underlying our assets are among the most economic in North America, with operator break-even oil prices under $35 per barrel. In addition, our assets include Royalties related to approximately 95,000 gross unit acres in the Appalachian region, including Pennsylvania, West Virginia,

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and Ohio. Our acreage was extensively delineated by 2,827 producing wells as of December 31, 2021, of which 2,328 are located in Karnes, DeWitt, and Gonzales Counties, providing extensive subsurface data control and substantial confidence on individual well initial production rates, production profiles and estimated ultimate recoveries (“EURs”). The average net daily production attributable to our net royalty interests was 4,438 BOE/d (47% oil) for the year ended December 31, 2021.  This includes Eagle Ford production of 3,553 BOE/d (58% oil).  

The Eagle Ford Shale is the one of the largest oil field in North America and is one of the lowest-cost and most active unconventional shale trends. It has a world-class aerial extent that covers approximately 13 million surface acres and has extensive data control as a result of more than 18,000 producing horizontal wells. The Eagle Ford has top-tier single-well economics, is operated by premier oil and gas companies, and has access to abundant offtake infrastructure in close proximity to the U.S. Gulf Coast. In recent years, the entire Eagle Ford Shale play has undergone a technical transformation largely driven by utilization of modern drilling and completion techniques, resulting in improved oil and gas sectional recoveries, enhanced production rates, EURs, well economics and increased activity by operators. Our acreage is located in what we believe is the “core-of-the-core” of the Eagle Ford Shale and is characterized by high oil and liquids content and low finding and development costs as well as positive differentials that drive attractive economics to operators relative to other unconventional basins. We believe these factors make the development of our underlying acreage commercially viable and highly attractive in lower commodity price environments. Approximately 89% of our Eagle Ford and Austin Chalk acreage is operated by ConocoPhillips (“ConocoPhillips”), EOG Resources, Inc. (“EOG”), and Devon Energy Corporation (“Devon”) through a joint venture. 

Our revenues are primarily derived from royalty payments we receive from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. For the year ended December 31, 2021, our revenues were derived 69% from oil and condensate sales, 19% from natural gas sales, 10% from natural gas liquid sales and 2% from lease bonuses. For the year ended December 31, 2020 our revenues were derived 75% from oil and condensate sales, 18% from natural gas sales, and 7% from natural gas liquid sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas and NGL prices have historically been volatile, and from time to time the Company may utilize commodity derivative instruments to mitigate the given price risk associated with its operations. 

Our Properties

Our assets consist of Royalties related to 559 drilling units, concentrated in what we believe is the “core-of-the-core” of the Eagle Ford Shale as well as the Marcellus Shale and Point Pleasant formations. As of December 31, 2021, these interests entitled us to receive an average royalty of 1.25% from the producing wells on the acreage underlying our Royalties, with no additional future capital or operating expenses required. As of December 31, 2021, there were 2,827 wells producing on this acreage, and average net production for the year ended December 31, 2021 was approximately 4,438 BOE/d. In addition, there were 81 horizontal wells in various stages of completion. As of December 31, 2021, there were 72 additional permits outstanding for undrilled wells or wells currently being drilled on the acreage underlying our Royalties.

Comparison of Types of Interests

Mineral Interest. Mineral interests are perpetual real property rights of the owner to exploit, mine, and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to a working interest holder pursuant to an oil and gas lease. 

Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to a working interest holder pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. Holders of royalty interests are generally not responsible for capital expenditures or lease operating expenses, but may be responsible for certain post-production expenses, and typically have limited environmental liability. Royalty interests expire upon the expiration of the oil and gas lease. 

Non-Participating Royalty Interest (“NPRI”). NPRI is an interest in oil and gas production that is created from the mineral estate.  The NPRI is expense-free, bearing no operational costs of production. The term “non-participating” indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases. 

Overriding Royalty Interest (“ORRIs”). ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability, however ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying oil and gas lease that created the working interest, and therefore, such ORRIs are typically subject to expiration upon the expiration or termination of the oil and gas lease.

Working Interest. Working interest holders have the rights to extract minerals from acreage leased pursuant to an oil and gas lease from a mineral interest holder. Holders of working interests are responsible for their pro rata share of capital expenditures and lease operating expenses, but holders of working interests only receive revenues after distributions have first been made to holders of royalty interests and ORRIs. Working interests expire upon the termination or expiration of the underlying oil and gas lease. 

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Our Relationship with Royal Resources, L.P.

Our largest shareholder is Royal, which was formed by a subsidiary of The Blackstone Group L.P. (“Blackstone”) in 2011.  We were formed pursuant to the deSPAC Transactions through which Blackstone (through its ownership of Royal) has retained a significant ownership stake in us, representing approximately 41% of our voting interests through Royal’s ownership of our Class C common stock.  Pursuant to the Contribution Agreement, Blackstone also has the right to nominate six out of nine members of our Board of Directors. Falcon performs certain managerial operations for Royal with respect to assets that Royal owns that were not contributed to Falcon under a Master Services Agreement (“MSA”).  Under the MSA, Falcon is paid approximately $0.1 million per year, plus reimbursement of certain out of pocket expenses and an allocated amount of certain third-party costs.  See also, Part I, Item 1, Business, Corporate History.

Recent Developments

On January 11, 2022, Falcon, OpCo, Ferrari Merger Sub A LLC, a Delaware limited liability company and wholly owned subsidiary of OpCo (“Merger Sub”), and DPM HoldCo, LLC, a Delaware limited liability company (“Desert Peak”), entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, subject to the satisfaction or waiver of certain conditions in the Merger Agreement, Merger Sub will merge with and into Desert Peak (the “Merger”), with Desert Peak continuing as the surviving entity in the Merger as a wholly owned subsidiary of OpCo.

Pursuant to the terms of the Merger Agreement and subject to the conditions therein, at the effective time of the Merger (the “Merger Effective Time”), the limited liability company interests in Desert Peak (the “DPM Membership Units”) issued and outstanding immediately prior to the Merger Effective Time will be converted into the right to receive an aggregate of (a) 235,000,000 shares of Class C common stock, (b) 235,000,000 OpCo Common Units and (c) additional shares of Falcon Class C common stock (and a corresponding number of OpCo Common Units) equal to (i) the sum of (x) the difference between $140,000,000 and the Sierra Net Debt (as defined in the Merger Agreement) plus (y) the amount by which the Indebtedness (as defined in the Merger Agreement) for borrowed money of Falcon and its subsidiaries exceeds $45,000,000 as of immediately prior to the Merger Effective Time divided by (ii) $5.15 (collectively, the “Merger Consideration”).

Completion of the Merger is subject to certain customary conditions, including, among others, the following: (a) the affirmative vote of the holders of at least (i) a majority of the votes cast at Falcon’s stockholder meeting (the “Falcon Stockholder Meeting”) on the approval of the issuance of the Merger Consideration (the “Stock Issuance Proposal”) and (ii) a majority of the voting power of the outstanding capital stock of Falcon entitled to vote on the approval of the adoption of certain amendments to Falcon’s certificate of incorporation providing for a reverse stock split of the Class C common stock and the Class A common stock prior to the Merger Effective Time, at a ratio of four to one (the “Falcon Reverse Stock Split” and, together with the Stock Issuance Proposal, the “Required Falcon Stockholder Proposals”); (b) there being no law or injunction prohibiting consummation of the transactions contemplated under the Merger Agreement (the “Transactions”); (c) approval for listing on the Nasdaq Capital Market of the Class A common stock issuable upon exchange of the Merger Consideration; (d) the expiration or termination of all applicable waiting periods (and any extensions thereof) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, applicable to the Transactions, and any commitment to, or agreement (including any timing agreement) with, any government entity to delay the consummation of, or not to close before a certain date, the Transactions; (e) the effectiveness of the Falcon Reverse Stock Split and the adoption of a reverse unit split of the OpCo Common Units prior to the Merger Effective Time, at a ratio of four to one; (f) subject to specified materiality standards, the accuracy of certain representations and warranties of each party; (g) compliance by each party in all material respects with its covenants included in the Merger Agreement; (h) each of the Registration Rights Agreement (as defined in the Merger Agreement) and the Director Designation Agreement (as defined in the Merger Agreement) being in full force and effect; and (i) the Available Liquidity (as defined in the Merger Agreement) is no less than $65,000,000 and the Sierra Net Debt is not in excess of $140,000,000.

OIL AND NATURAL GAS DATA

Reserves Presentation

The reserves estimates as of December 31, 2021 and 2020, shown herein, have been independently evaluated by Ryder Scott Company, L.P. (“RSC”).  RSC was founded in 1937 and for over 80 years has provided worldwide services to the petroleum industry including but not limited to the issuance of reserve reports and audits, appraisals of oil and gas properties, enhanced recovery services, expert witness testimony, and management services under the Texas Board of Professional Engineers Registration No. F-1580.  Within RSC, the technical person primarily responsible for preparing the estimates set forth in the RSC summary reserves report incorporated herein was Ali A. Porbandarwala, P.E.  Mr. Porbandarwala, a Licensed Professional Engineering in the State of Texas (License No. 107652) has been practicing consulting petroleum engineering at RSC since 2008 and has over twenty years of industry experience.  Mr. Porbandarwala earned a Bachelor of Science degree in Chemical Engineering from The University of Kansas in 2001 and a Masters in Business Administration from The University of Texas at Austin in 2007 and is a licensed Professional Engineer in the State of Texas.  As technical principal, Mr. Porbandarwala meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum

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Engineers and is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. RSC does not own an interest in us or any of our properties, nor is it employed by us on a contingent basis. A copy of RSC’s estimated proved reserve report as of December 31, 2021 is incorporated by reference herein to Exhibit 99.1 to this Annual Report.

Proved Reserves

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2021 and 2020 were prepared by RSC. A reserve audit is not the same as a financial audit and is less vigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on its own.

Under SEC rules, proved reserves are those quantities of 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–prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2021 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 oil and 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 oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy, or a combination of both methods. Approximately 90% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 10% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, RSC considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical, and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Our petroleum engineers work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil, and gas production, well test data, commodity prices and operating and development costs. The Vice President–Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. The Vice President–Reservoir Engineering is a petroleum engineer with over 14 years of reservoir and operations experience. Our technical staff uses historical information for our properties such as ownership interest, oil, and gas production, well test data, commodity prices, and operating and development costs.

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

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The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2021 and 2020 based on the reserve reports prepared by RSC. Each reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.  

As of December 31, 2021, our historical proved developed reserves totaled 2,738 MBbls of oil, 19,098 MMcf of natural gas and 1,183 MBbls of natural gas liquids, for a total of 7,104 MBOE. Of the total proved developed reserves, 99% are producing and the remaining 1% are from wells that have been stimulated but are not yet producing hydrocarbons.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable 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 oil and natural gas that are ultimately recovered. Estimates of economically recoverable 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. See “Risk Factors” in this Annual Report. We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

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Proved Undeveloped Reserves

As of December 31, 2021, our historical proved undeveloped reserves totaled 5,025 MBbls of oil, 24,339 MMcf of natural gas and 1,059 MBbls of natural gas liquids, for a total of 10,141 MBOE. PUD reserves will be converted from undeveloped to developed as the applicable wells begin production.

During the year ended December 31, 2021, our PUD reserves changed due to:

In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, all of our PUD drilling locations are scheduled to be drilled prior to the end of December 2026. This development schedule is based on an 81 well inventory waiting to be brought online, 72 permits that identify activity and continued PUD conversion based on historical drilling activity and the publicly announced capital expenditure plans of our operators. As an owner of Royalties and not working interests, we are not required to make capital expenditures and did not make capital expenditures to convert PUD reserves from undeveloped to developed.

Identification of Drilling Locations

Our identification of drilling locations is based on specifically identified locations on our leasehold acreage based on our assessment of current geoscientific, engineering, land, well-spacing and historic production profile information derived from state agencies and public statements by our operators on the acreage underlying our interests. These drilling locations are identified on a detailed map and allocated a reserve profile and identifier. Further, RSC reviewed and confirmed our drilling locations in estimating our PUD reserves in connection with the preparation of our reserve report as of December 31, 2021. We update and revise our drilling locations on a periodic basis as our assessment of the information described above changes.

Production and Price History

The following table sets forth information regarding our net production of oil, natural gas, and natural gas liquids, substantially all of which is from the Eagle Ford Shale region in South Texas, and certain price and cost information for each of the periods indicated:

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Producing Wells

As of December 31, 2021, we owned Royalties in 2,827 producing wells located on the acreage in which we had an interest. The following table provides detailed information relating to our producing wells:

Acreage

The following tables set forth information as of December 31, 2021 relating to total gross and net acreage in the units associated with Royalties owned by us:

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Drilling Results

As of December 31, 2021, our operators associated with Royalties had 81 wells in the process of drilling, completing, or dewatering or shut-in awaiting infrastructure that are not reflected in the table below. The following table sets forth, for the periods indicated below, the number of net productive and dry wells completed, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value.

Competition

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and natural gas leases, and personnel required to find and produce reserves. Many companies not only explore for and produce oil and natural gas, but also conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highly competitive environment. Oil and natural gas products compete with other sources of energy available to customers, primarily based on price. These alternate sources of energy include coal, nuclear, solar, and wind. Changes in the availability or price of oil and natural gas or other sources of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the aggregate demand for oil and natural gas over time. 

Seasonal Nature of Business

Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for our operators in meeting well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

Regulation

The following disclosure describes regulation more directly associated with operators of oil and natural gas properties, including our current operators, and other owners of working interests in oil and natural gas properties. To the extent we elect in the future to engage in the exploration, development and production of oil and natural gas properties, we would be directly subject to the same regulations described below.

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 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 oil and natural gas industry increases the cost of doing business.

Environmental Matters

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. Numerous federal, state, and local governmental agencies, such as the Environmental Protection Agency (“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

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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 and joint and several liability nature of such laws and regulations could impose liability upon responsible parties (including the operators of the acreage underlying our Royalties) 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 Falcon’s business and prospects.

Waste Handling

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect 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. Although most wastes associated with the exploration, development, and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require oil and natural gas exploration, development, and production wastes to become subject to more stringent waste handling requirements. Any changes in the laws and regulations could have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect production from our properties and adversely affect our business and prospects.

Remediation of Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and analogous state laws, generally impose strict and 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 and 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 Falcon’s Royalties 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 Falcon’s Royalties 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 Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act” (“CWA”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“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 gas and oil wastes, into navigable waters of the United States, as well as state waters. 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 June 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”). Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule. In January 2020, the EPA and Corps replaced the WOTUS rule adopted in 2015 with the narrower Navigable Waters Protection Rule, and litigation ensued. In August 2021, a federal judge in the District of Arizona struck down the Navigable Waters Protection Rule. Soon after, the Biden administration and the Corps announced that they have stopped enforcing the Navigable Waters Protection Rule nationwide and that they are reverting back to the 1986 WOTUS definition. In November 2021, the EPA and Corps issued prepublication notice of a proposed rule to revise the definition of “waters of the United States” to put back into place the pre-2015 definition, updated to reflect consideration of Supreme Court decisions, including the Supreme Court’s April 2020 decision holding that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. In January 2022, the Supreme Court agreed to hear a case regarding the jurisdictional reach of

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WOTUS.  Therefore, the scope of jurisdiction under the CWA is uncertain at this time, and any increase in scope could result in increased costs or delays with respect to obtaining permits for certain activities for our operators. 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 oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.     

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, 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 oil into surface waters.

In addition, the SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans, which could result in orders prohibiting or limiting the operations of oil and natural gas production facilities. The EPA has asserted regulatory authority pursuant to the SDWA’s Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued guidance covering such activities. The SDWA also regulates saltwater disposal wells under the UIC Program. Recent concerns related to the operation of saltwater disposal wells and induced seismicity have led some states to impose limits on the total volume of produced water such wells can dispose of, order disposal wells to cease operations, or limit the construction of new wells. For example, the Railroad Commission of Texas (the “TRRC”) recently issued a notice to operators in the Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. These seismic events have also resulted in environmental groups and local residents filing lawsuits against operators in areas where the events occur seeking damages and injunctions limiting or prohibiting saltwater disposal well construction activities and operations. A lack of saltwater disposal wells in production areas could result in increased disposal costs for our operators if they are forced to transport produced water by truck, pipeline, or other method over long distances, or force them to curtail operations.

Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations, all of which could affect production from our properties and adversely affect our business and prospects.

Air Emissions

The federal Clean Air Act (“CAA”) and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards, and the agency completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay, or prohibit the ability of our operators to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Separately, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas exploration and development projects. All of these factors could impact production on our properties and adversely affect our business and results of operations.

Climate Change

The threat of climate change continues to attract considerable attention in the United States and in foreign countries, numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit existing emissions of greenhouse gases (“GHGs”) as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, the current administration has highlighted addressing climate change as a priority and has issued several executive orders addressing climate change, including one that calls for substantial action on climate change, such as 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

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government agencies and economic sectors. 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 and require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. The current administration has also issued an executive order calling for the suspension, revision, or rescission, of a September 2020 rule rescinding certain methane standards and removing transmission and storage segments from the source category for certain regulations, and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. In response, the U.S. Congress has approved, and President Biden has 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. In November 2021, as required by President Biden’s executive order, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA hopes to finalize such standards by the end of 2022.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored “Paris Agreement,” requires member states to submit non-binding, individually determined reduction goals every five years after 2020. Although the United States had withdrawn from the Paris Agreement, President Biden has recommitted the United States and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by some candidates now in political office. These have included promises to limit emissions and curtail certain production of oil and natural gas. The current administration’s January 2021 climate change executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands and in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices. A federal district court judge in Louisiana issued a nationwide preliminary injunction in June 2021, effectively preventing the Biden administration from implementing the pause of new oil and natural gas leases on federal lands and waters and forcing the lease sale.  In November 2021, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program,” which assessed the current state of oil and gas leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. Recently, in January 2022, a federal district court judge in Washington, DC vacated the results of the federal government’s Lease Sale 257, effectively canceling the sale, on the grounds that the federal government failed to consider foreign consumption of oil and natural gas from its greenhouse gas emissions analysis.  In February 2022, a federal district court judge in Louisiana blocked the Biden Administration’s method of calculating the social costs associated with greenhouse gases, and specifically blocked federal agencies from considering the findings from the White House Interagency Working Group, which had been tasked with devising new metrics based on the Obama-era calculations.  In response, also in February 2022, the Biden administration asked the court to stay the injunction and announced that it would be suspending or delaying new federal oil and gas leases.  These recent developments and the Biden administration’s and certain federal courts’ focus on the climate change impacts of federal projects could result in significant changes to the federal oil and gas leasing program in the future.  Restrictions surrounding onshore drilling, onshore federal lease availability, and restrictions on the ability to obtain required permits, could have a material adverse impact on our operators and, in turn, our operations.

Other actions that could be pursued by the current 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 cities and other local governments have sought to bring suit against the largest 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 failed to adequately disclose such impacts to their investors or customers.

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-energy 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. Additionally, financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. The Federal Reserve recently joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.

Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development or production activities.

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The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition, or results of operation.

Regulation of Hydraulic Fracturing

Our operators engage in hydraulic fracturing, a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions, but recently the EPA and other federal agencies have asserted jurisdiction over certain aspects of hydraulic fracturing. For example, the EPA issued effluent limitation guidelines in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. The EPA has not proposed to take any action in response to the report’s findings.

Several states where we own interests in oil and gas producing properties, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, Texas has imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. Recently, the TRRC issued a notice to operators in the Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. 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.

We cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states in which we own interests. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.

There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators 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 on our properties 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. Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Endangered Species Act

Some of the operations on acreage underlying our Royalties may be located in areas that are designated as habitats for endangered or threatened species under the Endangered Species Act. In February 2016, the U.S. Fish and Wildlife Service published a final policy that alters how it identifies critical habitat for endangered and threatened species. However, the Biden administration published two rules in October 2021 that reversed changes made by the Trump administration, namely to the definition of “habitat” and to a policy that made it easier to exclude territory from critical habitat. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, the U.S. Fish and Wildlife Service continues to make listing decisions and critical habitat designations where necessary, including for over 250 species as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. The designation of previously unprotected species as being endangered or threatened, if located in the areas where we have Royalties, could cause the operators of the operations

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on the acreage underlying our Royalties to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the 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 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 oil and natural gas industry increases the cost of doing business, these burdens generally do not affect the Company 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 cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and 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 oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on Falcon’s operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production

The operations of the Company’s operators 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 the Company operates also regulate one or more of the following: 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of 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 the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the Company’s operators can produce from our wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations operators can drill.

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

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of

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1938 (“NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.” Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which our operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that our operators produce, as well as the revenues our operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers, and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas-related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our operators’ costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

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

Further, interstate, and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to our operators to the same extent as to the Company or their competitors.

State Regulation

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations our operators can drill.

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

Human Capital

Overview and Structure. We consider our workforce to be our most important asset, and we have sought to structure our hiring practices, compensation and benefits programs, and employee practices to attract and retain high-quality personnel and to provide a comfortable and collegial work environment. We continue to invest in our employees by providing training opportunities, promoting

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diversity and inclusion, and maintaining focus on corporate ethics. We are managed and operated by the executive officers of our Company and our Board of Directors oversees the management of the Company.

Headcount. We rely principally on full-time employees but use independent contractors as needed to assist with special projects. As of December 31, 2021, the Company had 11 full-time employees and one contractor. None of Falcon’s employees are represented by labor unions or covered by any collective bargaining agreements.

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

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

Healthcare and Other Benefits. We provide a robust suite of benefits to our employees covering all aspects of life, including 401(k) matching, medical-insurance options, and programs to encourage and support the whole person, including physical, mental and emotional, financial, social, career, and community service initiatives.

Facilities

Our executive offices are located at 609 Main Street, Suite 3950, Houston, TX 77002.   We have additional leased office space in New York, NY and Philadelphia, PA. Our Philadelphia, PA office is shared with Hepco Capital Management, LLC (“Hepco”), which Company executive Jeffrey Brotman is also a director and officer of.  The related cost of our shared office is proportionately shared between the Company and Hepco.  We believe that these facilities are adequate for our current operations.

Available Information

We maintain an Internet website at www.falconminerals.com.  Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.falconminerals.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.

The following risk factors apply to our business and operations. These risk factors are not exhaustive, and investors are encouraged to perform their own investigation with respect to our business, financial condition, and prospects. You should carefully consider the following risk factors in addition to the other information included in this annual report, including matters addressed in the section entitled “Cautionary Statement Regarding Forward-Looking Statements.” We may face additional risks and uncertainties that are not presently known to us, or that we currently deem immaterial, which may also impair our business or financial condition. The following discussion should be read in conjunction with our financial statements and notes to the financial statements included herein.

Risks Related to Our Business

A majority of our revenues are derived from royalty payments that are based on the price at which oil, natural gas and natural gas liquids produced from the underlying acreage is sold. The volatility of these prices due to factors beyond our control greatly affects our business, financial condition, and results of operations.

Our revenues, operating results and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, oil and natural gas prices have been volatile, and they are likely to remain volatile due to a variety of additional factors that are beyond our control, including: 

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These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition and results of operations. 

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This may result in having to make substantial downward adjustments to our estimated proved reserves. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on the properties underlying its royalties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities thereby potentially causing some or all of the underlying oil and gas lease to expire along with our royalties therein.

Our hedging activities could result in financial losses and reduce earnings.

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

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

We depend on three third-party operators for substantially all of the exploration and production on the properties underlying our royalties. Substantially all of our revenue is derived from royalty payments made by these operators. Therefore, any reduction in production from the wells drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have a material adverse effect on our revenues, financial condition and results of operations. None of the operators of the properties underlying our royalties are contractually obligated to undertake any development activities, so any development and production activities will be subject to their discretion.

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Because we depend on third-party operators for all of the exploration, development, and production on our properties, we have no control over the operations related to our properties. For the year ended December 31, 2021, we received approximately 47%, 19%, and 15% of our revenue from ConocoPhillips, EOG, and Devon, respectively. The failure of the aforementioned operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Further, none of the operators of the properties underlying our royalties are contractually obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. The success and timing of drilling and development activities on the properties underlying our royalties, therefore, depends on a number of factors that will be largely outside of our control, including:

The third-party operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in our revenues, financial condition, and results of operations. If reductions in production by the operators are implemented on the properties underlying our royalties and sustained, our revenues may also be substantially affected. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on us.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures from our operators than we or they currently anticipate.

As of December 31, 2021, 58.8% of our total estimated proved reserves were proved undeveloped reserves and may not be ultimately developed or produced by our operators. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations by our operators. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by our operators are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our operators will develop the properties underlying our royalties as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill, and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical for our operators. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Our producing properties are located predominantly in the Eagle Ford Shale region of South Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a single producing horizon within this area.

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

Our success depends on finding or acquiring additional reserves, and our operators developing those additional reserves.

Our future success depends upon our ability to acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that successful exploration or development activities are conducted on the properties underlying our royalties by our operators or we acquire properties containing proved reserves, or both. Aside from acquisitions, we have no control over the exploration and development of our properties. To increase reserves and production, we would need our operators to undertake replacement activities or use third parties to accomplish these activities. Substantial capital expenditures will be necessary for the acquisition of oil and natural gas reserves. Neither we nor our third-party

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operators may have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and efforts to drill productive wells at low finding and development costs may be unsuccessful. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, finding costs for additional reserves could also increase.

Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could slow our growth and adversely affect our financial condition and results of operations.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

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

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

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

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

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

Identified drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. 

Proved undeveloped drilling locations represent a significant part of our growth strategy, however, we do not control the development of these locations. Our operators’ ability to drill and develop identified potential drilling locations will depend on a number of factors, including the availability of capital, seasonal conditions, regulatory changes and approvals, negotiation of agreements with

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third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure, inclement weather, and lease expirations. 

Further, identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional analysis of data. We will not be able to predict in advance of drilling and testing whether any particular drilling location will yield production in sufficient quantities for operators to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, the potentially productive hydrocarbon bearing formation may be damaged or mechanical difficulties may develop while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill dry holes in our current and future drilling locations, our business may be materially harmed. We will not be able to assure you that the analogies drawn from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or our operators in our areas of operations may not be indicative of future or long-term production rates.

Because of these uncertainties, we do not know if the potential drilling locations identified on our acreage will ever be drilled or if oil or natural gas reserves will be able to be produced from these or any other potential drilling locations. As such, actual drilling activities with respect to our acreage may materially differ from those presently identified, which could adversely affect our business, financial condition, and results of operations. 

Our method of accounting for investments in oil and natural gas properties may result in impairments in future periods.

We follow the successful efforts method of accounting. Accordingly, all costs incurred in the acquisition of mineral and royalty interests in oil and natural properties are capitalized.

Acquisition costs of proven royalty interests are amortized using the units of production method over the life of the property, which is estimated using proven reserves. Acquisition costs of royalty interests on exploration stage properties, where there are no proven reserves, are not amortized. At such time as the associated unproved interests are converted to proven reserves, the cost basis is amortized using the units of production methodology over the life of the property, using proven reserves. For purposes of amortization, interests in oil and natural gas properties are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic condition.

We review and evaluate our royalty interests in oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. No such impairment expense was recorded for the years ended December 31, 2021 or 2020. However, we may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are recorded.

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

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. 

Our historical estimates of proved reserves and related valuations as of December 31, 2021, were prepared by Ryder Scott, an independent petroleum engineering firm, which conducted a well-by-well review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. In addition, none of the operators of the properties underlying our royalties are contractually obligated to provide us with information regarding drilling activities or historical production data with respect to the properties underlying our interests, which may affect our estimates of reserves. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates. 

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. 

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The estimates of reserves as of December 31, 2021 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2021, in accordance with the revised SEC rules and regulations applicable to reserve estimates for such period. 

SEC rules and regulations could limit our ability to book additional proved undeveloped reserves in the future. 

SEC rules and regulations require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as our operators pursue their drilling programs. Moreover, we may be required to write down our proved undeveloped reserves if those wells are not drilled within the required five-year time frame.  

The PV-10 of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. 

The present value of future net cash flows from our proved reserves shown in this report, or PV-10, may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (“FASB”), we base the estimated discounted future net cash flows from our proved reserves on the historical 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. 

Unless we replace our reserves with new reserves that our operators develop, our reserves will decline, which would adversely affect our future cash flows and results of operations. 

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless our operators conduct successful ongoing development and exploration activities or we continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our operators’ success in efficiently developing and exploiting our current reserves and we economically finding or acquiring additional recoverable reserves. We may not be able to find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. 

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

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

Outbreaks of communicable diseases could adversely affect our business, financial condition, and results of operations.

Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks in several countries, including the United States, of a highly transmissible and pathogenic coronavirus (“COVID-19”). The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. The occurrence or continuation of any of these events could lead to decreased revenues and limit our ability to execute on our business plan, which could adversely affect our business, financial condition, and results of operations. 

Terrorist attacks or armed conflicts could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries, including the military conflict in Ukraine, may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may

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experience a significant disruption in their operations. Any such disruption could adversely affect our business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, which may adversely affect our third-party operators’ ability to succeed.

 The oil and natural gas industry is intensely competitive, and our third-party operators compete with other companies that may have greater resources. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national, or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws, and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. 

Increased costs of capital could adversely affect our business. 

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

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

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of our vendors, suppliers, and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.  

Our warrants are accounted for as liabilities and the changes in value of our warrants could have a material effect on our financial results. 

On April 12, 2021, the SEC issued the Staff Statement. Specifically, the Staff Statement focused on certain settlement terms and provisions related to certain tender offers following a business combination, which terms are similar to those contained in the warrant agreement governing the Warrants. As a result of the Staff Statement, we reevaluated the accounting treatment of the Company’s Public and Private Placement Warrants and determined to classify the Warrants as derivative liabilities measured at fair value, with changes in fair value each period reported in earnings. 

Due to certain settlement provisions contained within the Warrants, the Warrants are classified as derivative liabilities on our consolidated balance sheets as of December 31, 2021 and 2020. Accounting Standards Codification 815-40, Derivatives and Hedging – Contracts in Entity’s Own Equity (“ASC 815”), provides for the remeasurement of the fair value of such derivatives at each balance sheet date, with a resulting non-cash gain or loss related to the change in the fair value being recognized in earnings in the statement of operations. As a result of the recurring fair value measurement, our consolidated financial statements and results of operations may fluctuate quarterly, based on factors that are outside of our control. Due to the recurring fair value measurement, we expect that we will recognize non-cash gains or losses on the Warrants each reporting period and that the amount of such non-cash gains or losses could be material.

Our only significant assets are the ownership of the general partner interest and its limited partner interest in OpCo, and such ownership may not be sufficient to enable us to pay any dividends on our Class A common stock or satisfy our other financial obligations. 

We have no direct operations and no significant assets other than the ownership of the general partner interest and a 53% limited partner interest in OpCo. We depend on OpCo and its subsidiaries for distributions, loans and other payments to generate the funds necessary to meet our financial obligations or to pay any dividends with respect to our Class A common stock. Subject to certain restrictions, OpCo generally will be required to (i) as discussed below, make quarterly pro rata tax distributions to its partners, including

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us, in an amount equal to 50% of the total federal taxable income allocated by OpCo to the limited partners and (ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of OpCo and its subsidiaries, as well as the financial condition and operating requirements of OpCo and its subsidiaries, may limit our ability to obtain cash from OpCo. The earnings from, or other available assets of, OpCo and its subsidiaries, may not be sufficient to enable us to pay any dividends on our Class A common stock or satisfy our other financial obligations. OpCo is treated as a partnership for U.S. federal income tax purposes and, as such, is not subject to any entity-level U.S. federal income tax. Instead, taxable income is allocated to holders of its common units, including us. As a result, we generally will incur income taxes on our allocable share of any net taxable income of OpCo. Under the terms of the OpCo Limited Partnership Agreement, OpCo will be obligated to make tax distributions to holders of its common units, including us, equal to 50% of the total federal taxable income allocated by OpCo to the limited partners, except to the extent such distributions would render OpCo insolvent or are otherwise prohibited by law or any of our current or future debt agreements. In addition to tax expenses, we will also incur expenses related to our operations, our interests in OpCo and related party agreements, and expenses and costs of being a public company, all of which could be significant. To the extent that we need funds and OpCo or its subsidiaries is restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition, including our ability to pay our income taxes when due. 

We may change our dividend payout ratio at any time and there is no guarantee that we will pay dividends in the future. 

Although we have historically paid out substantially all of our free cash flow in the form of a regular quarterly dividend, there is no guarantee or requirement that we pay dividends in the future. Our organizational documents, including the Company’s Second Amended & Restated Charter (the “Second A&R Charter”), only require our Board of Directors or us to make any dividends or distributions to the holders of Class A common stock in certain limited circumstances that are generally within the control of our Board of Directors. Our dividend payout ratio may change at any time without notice to our stockholders. The declaration and amount of any future dividends to holders of our Class A common stock will be at the discretion of our Board of Directors in accordance with applicable law and after taking into account various factors, including our financial condition, results of operations, current and anticipated cash needs, cash flows, impact on our effective tax rate, indebtedness, contractual obligations, legal requirements and other factors that our Board of Directors deems relevant. As a result, we cannot assure you that we will pay dividends at any rate or at all. 

If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding our Class A common stock adversely, the price and trading volume of our Class A common stock could decline. 

The trading market for our Class A common stock is influenced by the research and reports that industry or securities analysts may publish about us, our business, our market, or our competitors. If any of the analysts who cover us change their recommendation regarding our stock adversely, or provide more favorable relative recommendations about our competitors, the price of our Class A common stock could potentially decline. If any analyst who may cover us were to cease their coverage or fail to regularly publish reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

Blackstone, Royal and the Contributors have significant influence over us. 

Blackstone, Royal and the Contributors beneficially own common stock representing approximately 46% of our outstanding voting power. As long as our Sponsor and the Contributors own or control a significant percentage of our outstanding voting power, subject to the terms of the Shareholders’ Agreement, they will have the ability to influence certain corporate actions requiring stockholder approval. In certain circumstances, Royal and the Contributors may transfer their equity interests in us and/or OpCo without the consent of the public stockholders or our Board of Directors, and the transferee would have significant influence over us.  

In addition, under the Shareholders’ Agreement, Blackstone is entitled to designate six directors for nomination by our Board of Directors for election as directors by our stockholders, representing a majority of our Board of Directors, and has certain other rights with respect to our Board of Directors composition, including consent rights with respect to individuals nominated by our Board of Directors for election as independent directors, and our governance.  

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

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

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

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

The Second A&R Charter designates the Court of Chancery of the State of Delaware (or, if the Court of Chancery of the State of Delaware does not have jurisdiction, any state or the federal court sitting in the State of Delaware with jurisdiction over the matter) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit the ability of our stockholders to obtain a favorable judicial forum for disputes with us or with directors, officers or employees of us and may discourage stockholders from bringing such claims. 

The Second A&R Charter designates the Court of Chancery of the State of Delaware (or, if the Court of Chancery of the State of Delaware does not have jurisdiction, any state or the federal court sitting in the State of Delaware with jurisdiction over the matter) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit the ability of our stockholders to obtain a favorable judicial forum for disputes with us or with directors, officers or employees of us and may discourage stockholders from bringing such claims. Alternatively, if a court were to find these provisions of the Second A&R Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, and results of operations.

Non-U.S. holders may be subject to U.S. federal income tax with respect to gain on disposition of their Class A common stock and warrants. 

We believe that we are a U.S. real property holding corporation (“USRPHC”), following our Business Combination. As a result, Non-U.S. holders that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A common stock or warrants during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A common stock or warrants and may be required to file a U.S. federal income tax return. If you are a Non-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.

Risks Related to our Industry

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In March 2020, members of OPEC and Russia considered extending and potentially increasing these oil production cuts. However, these negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed oil production cuts would expire on April 1, 2020. These actions led to an immediate and steep decrease in oil prices. In early April 2020, in response to significantly depressed global oil prices, 23 countries, led by Saudi Arabia and Russia, committed to withhold collectively 9.7 million barrels a day of oil from global markets. There can be no assurance that OPEC members and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could adversely affect our business, financial condition, and results of operations.

Declining general economic, business or industry conditions could have a material adverse effect on our financial condition and results of operations. 

Declines in general economic, business or industry conditions, including expectations of future declines or uncertainty with respect to such conditions, could adversely affect our financial condition and results of operations. Volatility in prices of oil, natural gas and natural gas liquids, as well as concerns about global economic growth, could also impact the price at which oil, natural gas and natural gas liquids from the properties underlying our royalties are sold, affect the ability of vendors, suppliers and customers associated with the properties underlying our royalties to continue operations and ultimately adversely impact our financial condition and results of operations.

Conservation measures and technological advances could reduce demand for oil and natural gas. 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the

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changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, and results of operations.  

Our operations are subject to a series of risks related to climate change.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. In the United States to date, no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has announced that climate change will be a focus of his administration. In January 2021, the Biden administration issued an executive order calling for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across agencies and economic sectors. Additionally, federal regulators, state and local governments, and private parties have taken (or announced that they plan to take) actions related to climate change that have or may have a significant impact on our operations. For example, in response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from certain sources in the United States on an annual basis, including certain of our operations; moreover, President Biden signed an executive order in January 2021 that, among other things, calls for the establishment of new or more stringent emissions standards for methane and volatile organic compounds from new, modified, and existing oil and gas facilities, including the transmission and storage segments. In November 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and VOC emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA hopes to finalize the standards by the end of 2022.

Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had withdrawn from the Paris Agreement in November 2020, President Biden has signed executive orders to re-enter the Paris Agreement and calling on the federal government to develop the United States' emissions reduction target. In April 2021, the Biden administration announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, President Biden released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which, among other things, explains that the U.S. and EU are co-leading the “Global Methane Pledge” that aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels.  President Biden also agreed that same month to cooperate with Chinese leader Xi Jinping on accelerating progress toward the adoption of clean energy. The impacts of President Biden's executive orders and the terms of any laws or regulations promulgated to implement the United States’ commitment under the Paris Agreement, are uncertain at this time. Increasingly, fossil fuel companies are also exposed to litigation risks from climate change.

Additionally, in response to concerns related to climate change, companies in the fossil fuel sector may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension, and endowment funds, may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to sustainable lending practices, and some of them may elect in future not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed an executive order calling for the development of a "climate finance plan," and, separately, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could in turn reduce demand for our services adversely impact our financial performance.

Finally, our operations are subject to disruption from natural or human causes beyond our control, including risks from extreme weather events, such as hurricanes, severe storms, floods, heat waves, and ambient temperature increases, as well as wildfires, each of which may become more frequent or more severe as a result of climate change.

Increasing attention to environmental, social and governance matters (“ESG”) may impact our business, financial results or stock price.

In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ board of directors, and promoting the use of energy saving building materials. These activities may result in demand shifts for oil and natural

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gas. In addition, a failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operation.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.

Risks Relating to Regulation

We may incur significant costs in the future associated with proposed climate change regulation and legislation.

The United States Congress and some states where we have operations may consider legislation or regulations related to greenhouse gas emissions, including methane emissions, which may compel reductions of such emissions. In addition, there have been international conventions and efforts to establish standards for the reduction of greenhouse gases globally, including the Paris accords in December 2015. While the Trump administration had begun the process of withdrawing from the Paris Agreement, in January 2021, President Biden signed an Executive Order directing that the United States rejoin the Paris Agreement. In April 2021, the Biden administration announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector.

Legislative proposals have included or could include limitations, or caps, on the amount of greenhouse gas that can be emitted, as well as a system of emissions allowances. For example, legislation passed by the U.S. House of Representatives in 2010, which was not taken up by the Senate, would have placed the entire burden of obtaining allowances for the carbon content of NGLs on the owners of NGLs at the point of fractionation. In June 2013, President Obama announced a climate action plan that targeted methane emissions from the oil and gas industry as part of a comprehensive interagency methane reduction strategy, and in June 2016, the EPA expanded the NSPS regulations for new or modified sources of VOCs to include methane emissions, which, among other things, imposes leak detection and repair requirements for VOCs and methane on producer well site equipment and on midstream equipment such as compressor and booster stations, imposes additional emission reduction requirements on specific pieces of oil and gas equipment, and is a regulatory pre-condition to the EPA acting to regulate existing oil and gas methane sources in the future under Section 111(d) of the Clean Air Act. The Trump administration targeted many of these actions. For example, in September 2020, the EPA finalized amendments to the 2012 and 2016 regulations that, among other things, removed the transmission and storage segment of the oil and gas industry from regulation and rescinded emissions standards for that sector and rescinded methane standards. However, in January 2021, the Biden administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. The executive order specifically called on the EPA to consider a proposed rule suspending, revising or rescinding the September 2020 deregulatory amendments by September 2021. In response, the U.S. Congress has approved, and President Biden has 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. In November 2021, as required by President Biden’s executive order, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA hopes to finalize the standards by the end of 2022. As a result, future implementation of the standards is uncertain at this time.

Relatedly, the D.C. Circuit Court challenge to the October 2015 EPA regulation reducing the ambient ozone standard from 75 parts per billion to 70 parts per billion under the Clean Air Act was put in abeyance temporarily while the EPA reviewed the regulation. The EPA later indicated it will not revise the rule, and challenges from industry and environmental groups moved forward. In August 2019, the D.C. Court of Appeals upheld the health-based ozone standards but remanded to the EPA the secondary, public welfare standards designed to protect environmental values. The 2015 Ozone standard is being implemented pursuant to the December 2018 final implementation rule. Separately, in 2011 the EPA issued permitting rules for sources of greenhouse gases; however, in June 2014, the U.S. Supreme Court reversed a D.C. Circuit Court of Appeals decision that had upheld these rules and struck down the EPA's greenhouse gas permitting rules to the extent they impose a requirement to obtain a permit based solely on emissions of greenhouse gases. Under the Court ruling and the EPA's subsequent proposed rules, major sources of other air pollutants, such as VOCs or nitrogen oxides, could still be required to implement process or technology controls and obtain permits regarding emissions of greenhouse gases. These proposed rules have not been finalized.

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The EPA has issued rules requiring reporting of greenhouse gases, on an annual basis, for certain onshore natural gas and oil production facilities, and in October 2015, the EPA amended and expanded those greenhouse gas reporting requirements to all segments of the oil and gas industry effective January 1, 2016. Similarly, some states can initiate and promulgate regulations affecting oil and gas operations and associated greenhouse gas emissions as a matter of their own statutory authority and programs. For example, in 2019, the Colorado legislature passed House Bill 19-1261, the "Climate Action Plan to Reduce Pollution" that sets greenhouse gas emission reduction targets for the state. Subsequently, the governor issued the Colorado Greenhouse Gas Pollution Roadmap, which identifies pathways to meet the reduction targets. The Roadmap identifies the oil and gas sector as one of the larger contributors to greenhouse gas emissions in the state and asserts that deep reductions in methane emissions from the oil and gas industry will be required to meet the targets. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges.

New regulatory suspensions, revisions, or rescissions, as well as new regulations and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. To the extent legislation is enacted or additional regulations are promulgated that regulate greenhouse gas emissions, it could significantly increase our costs to (i) acquire allowances; (ii) permit new large facilities; (iii) operate and maintain our facilities; (iv) install new emission controls or institute emission reduction measures; and (v) manage a greenhouse gas emissions program. If such legislation becomes law or additional rules are promulgated in the United States or any states in which we have operations and we are unable to pass these costs through as part of our services, it could have an adverse effect on our business and cash available for distributions.

Increased attention to environmental, social and governance (“ESG”) matters may impact our business.

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

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward the company and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may, of their own accord, elect not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing, including with respect to seismic activity allegedly related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect production on the acreage underlying our royalties. 

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, in February 2014, the EPA published permitting guidance under the federal Safe Drinking Water Act (“SDWA”) addressing the use of diesel fuels in certain hydraulic fracturing activities, and in May 2014, the EPA issued an Advance Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Further, in March 2015, the Bureau of Land Management (“BLM”) of the U.S. Department of the Interior published a final rule imposing requirements for hydraulic fracturing activities on federal and Indian lands, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water. Following years of litigation, the BLM rescinded the rule in December 2017. However, in January 2018, California and several environmental groups filed lawsuits challenging BLM’s rescission of the rule; those lawsuits are pending. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. If enacted, these or similar laws could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations and increased costs on the acreage underlying our royalties. 

There may be other attempts to further regulate hydraulic fracturing under the SDWA, TSCA and/or other statutory or regulatory mechanisms. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. 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. If new or more stringent

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federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we hold royalties, the operators of the acreage underlying our royalties could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells. 

In some instances, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. For example, the TRRC recently issued a notice to operators in the Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying our royalties.

New environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.  Also, the threat of climate change has resulted in increasing political risks in the United States.  For example, the Biden Administration has issued orders temporarily suspending the issuance of new authorizations and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters (but not tribal lands that the federal government merely holds in trust). Any of these environmental initiatives and regulations, could have a material adverse effect on our financial condition and results of operations.

The oil and gas operations on the acreage underlying our royalties are subject to environmental, health and safety laws and regulations that could adversely affect the cost, manner, or feasibility of conducting operations on them or result in significant costs and liabilities, which could adversely affect our financial condition and results of operations. 

The oil and natural gas exploration and production operations on the acreage underlying our royalties are subject to stringent and comprehensive federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or the health and safety of workers and other affected individuals. These laws and regulations may impose numerous obligations that apply to the operations on the acreage underlying our royalties, including the requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use; the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the protection of threatened or endangered species; and the imposition of substantial liabilities for pollution resulting from operations.

 There is an inherent risk of incurring significant environmental costs and liabilities in the operations on the acreage underlying our royalties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the operators could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether such operators were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties on or adjacent to well sites and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our royalties to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition, and results of operations.

  Changes in environmental laws and regulations occur frequently, and any changes that result in delays or restrictions in permitting or development of projects, more stringent or costly operational control requirements, or waste handling, storage, transport, disposal or cleanup requirements could require the operators of the acreage underlying our royalties to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition. 

Risks Related to our Capital Structure

The Contributors own an amount of Class C common stock that provides them with effective control over us. 

At the closing of the Business Combination, the Contributors received $400 million of cash and 40 million OpCo common units (together with 40 million shares of Class C common stock). As a result, the Contributors hold approximately 46% of the voting power over us. This voting percentage may provide the Contributors with effective control over us. In addition, we have agreed to provide Blackstone with a right to nominate six out of nine of the directors on our Board of Directors so long as Blackstone, together with its affiliates, holds at least 41% of the voting power over our common stock. Blackstone and the Contributors may exercise their control in a way that favors its respective interests to the detriment of the other stockholders of us.

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Restrictions in the Revolving Credit Facility and future debt agreements of ours and OpCo could limit its growth and its ability to engage in certain activities. 

At the closing of the Business Combination, OpCo entered into a revolving credit facility in the aggregate principal amount of up to $500 million. The Revolving Credit Facility, or other future debt agreements of ours and OpCo, will contain a number of restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make loans and advances, make capital expenditures, incur liens, and sell assets. These restrictions may also limit the ability of us and OpCo to pursue business opportunities that may arise in the future.

There is no guarantee that the public warrants will be in the money at the time they become exercisable, and they may expire worthless. 

The exercise price for our warrants is $11.34 per share of Class A common stock. Pursuant to the Contribution Agreement, to the extent that any common stock dividend paid by the Company, when combined with other common stock dividends paid in the prior 365 days, exceeds 50 cents, it is categorized as an Extraordinary Dividend.  Extraordinary Dividends reduce, penny for penny, the exercise price of the Company’s warrants. There is no guarantee that the public warrants will be in the money following the time they become exercisable and prior to their expiration, and as such, the warrants may expire worthless. Subsequent to December 31, 2021, the exercise price of the Company’s warrants was further reduced to $11.29 after the Extraordinary Dividend paid for the quarter ended December 31, 2021.  

We may amend the terms of the warrants in a manner that may be adverse to holders with the approval by the holders of at least 65% of the then outstanding public warrants. As a result, the exercise price of your warrants could be increased, the exercise period could be shortened and the number of shares of our Class A common stock purchasable upon exercise of a warrant could be decreased, all without your approval. 

Our warrants were issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us. The warrant agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision but requires the approval by the holders of at least 65% of the then outstanding public warrants to make any change that adversely affects the interests of the registered holders. Accordingly, we may amend the terms of the public warrants in a manner adverse to a holder if holders of at least 65% of the then outstanding public warrants approve of such amendment. Although our ability to amend the terms of the public warrants with the consent of at least 65% of the then outstanding public warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the warrants, shorten the exercise period, or decrease the number of shares of our Class A common stock purchasable upon exercise of a warrant.

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

We have the ability to redeem outstanding warrants at any time after they become exercisable and prior to their expiration, at a price of $0.01 per warrant, provided that the last reported sales price of our Class A common stock equals or exceeds $18.00 per share for any 20 trading days within a 30-trading day period ending on the third trading day prior to the date we send the notice of redemption to the warrant holders. If and when the warrants become redeemable by us, we may exercise our redemption right even if we are unable to register or qualify the underlying securities for sale under all applicable state securities laws. Redemption of the outstanding warrants could force the warrant holders (i) to exercise their warrants and pay the exercise price therefor at a time when it may be disadvantageous for them to do so, (ii) to sell their warrants at the then-current market price when they might otherwise wish to hold their warrants or (iii) to accept the nominal redemption price which, at the time the outstanding warrants are called for redemption, is likely to be substantially less than the market value of their warrants. None of the private placement warrants will be redeemable by us so long as they are held by our Sponsor or its permitted transferees.

Warrants will become exercisable for our Class A common stock, which would increase the number of shares eligible for future resale in the public market and result in dilution to our stockholders. 

We issued warrants to purchase 13,749,999 shares of Class A common stock as part of our IPO and concurrent with our IPO, we issued an aggregate of 7,500,000 private placement warrants to our Sponsor. Each warrant issued is exercisable to purchase one whole share of Class A common stock at $11.34 per whole share. Pursuant to the Warrant Agreement, to the extent that any common stock dividend paid by the Company, when combined with other common stock dividends paid in the prior 365 days, exceeds 50 cents, it is categorized as an Extraordinary Dividend.  Extraordinary Dividends reduce, penny for penny, the exercise price of the Company’s warrants. To the extent such warrants are exercised, additional shares of our Class A common stock will be issued, which will result in dilution to the then existing holders of our Class A common stock and increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of our Class A common stock. Subsequent to December 31, 2021, the exercise price of the Company’s warrants was further reduced to $11.29 after the Extraordinary Dividend paid for the quarter ended December 31, 2021.  

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The private placement warrants are identical to the warrants sold as part of the units issued in our IPO, except that, so long as they are held by our Sponsor or its permitted transferees, (i) they will not be redeemable by us and (ii) they may be exercised by the holders on a cashless basis.

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

Pursuant to the Contribution Agreement, Royal is entitled to receive earn-out consideration to be paid in the form of OpCo Common Units (and a corresponding number of shares of Class C common stock) if the 30-day volume-weighted average price (“30-Day VWAP”) of the Class A common stock equals or exceeds certain hurdles set forth in the Contribution Agreement. Royal can potentially receive up to an additional 20.0 million OpCo Common Units as a part of the earn-out consideration. Royal is also entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of the Company’s assets, if the consideration paid to holders of the Class A common stock in connection with such liquidity event is greater than any of the 30-Day VWAP hurdles. Because any OpCo Common Units issued pursuant to the earn-out are redeemable on a one-for-one basis for shares of Class A common stock at the option of the Contributors, the issuance of additional stock consideration pursuant to the earn-out will result in dilution to the then existing holders of our Class A common stock and increase the number of shares eligible for resale in the public market. Sales of substantial numbers of such shares in the public market could adversely affect the market price of our Class A common stock.

A significant portion of our total outstanding shares may be sold into the market in the near future. This could cause the market price of our Class A common stock to drop significantly, even if our business is doing well. 

Sales of a substantial number of shares of Class A common stock in the public market could occur at any time. These sales, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our Class A common stock. After the Business Combination, our Sponsor owned approximately 8.0% of our Class A common stock. Pursuant to the terms of a letter agreement entered into at the time of the IPO, the founder shares (which converted into shares of Class A common stock at the closing of the Business Combination) held by our Sponsor became freely tradable one year after the closing of the Business Combination. 

Additionally, the Contributors have the ability to redeem or exchange their common units for shares of Class A common stock on a one-to-one basis, provided that the ratio of the limited partner’s redeemed common units to the number of common units beneficially held by such limited partner remains equal to that of the Blackstone Funds. If the Contributors redeem or exchange all of their common units for shares of Class A common stock, and assuming no earn-out consideration is paid prior to such time and we do not otherwise issue shares of Class A common stock, the Contributors will own approximately 46% of our Class A common stock.

In connection with the closing of our IPO, we entered into a registration rights agreement with our Sponsor providing for registration rights to it. In addition, in connection with the closing of the Business Combination, we entered into a registration rights agreement with Royal LP and the Contributors, pursuant to which we filed a registration statement registering the shares of Class A common stock held by them for resale within 30 days following the closing of the Business Combination.

Risks Related to Our Operators 

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict the operations of our operators. 

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

Restrictions on our operators’ ability to obtain water may have an adverse effect on our financial condition and results of operations. 

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. During the last several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If our operators are unable to obtain water to use in their operations from local sources, or our operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition and results of operations. 

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The results of our operators’ exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production. 

The drilling by our operators involves a number of risks, including the risk of landing their well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running their casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that they will face while completing wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Furthermore, certain of the new techniques our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we will be less able to predict future drilling results in these areas. 

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled, and production profiles are established over a sufficiently long time period. If our operators’ drilling results are less than anticipated or they are unable to execute their drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate.  

The marketability of oil and natural gas production is dependent upon transportation and other facilities, certain of which neither we nor our operators’ control. If these facilities are unavailable, our operators’ operations could be interrupted, and our financial condition and results of operations could be adversely affected. 

The marketability of our operators’ oil and natural gas production will depend in part upon the availability, proximity, and capacity of transportation facilities, including gathering systems, trucks and pipelines, owned by third parties. Neither we nor our operators control these third-party transportation facilities and our operators’ access to them may be limited or denied. Insufficient production from the wells on the acreage underlying our royalties to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our operators’ ability to deliver to market or produce oil and natural gas and thereby cause a significant interruption in our operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we and our operators are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from the acreage underlying our royalty fields, could adversely affect our financial condition and results of operations. 

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

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

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

General Risk Factors

Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments, and results of operations. 

We are subject to laws, regulations and rules enacted by national, regional, and local governments and NASDAQ. In particular, we are required to comply with certain SEC, NASDAQ, and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments, and results of operations. In addition, a failure to comply with applicable laws, regulations, and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations. 

The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies. 

We qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year (a) following July 26, 2022, the fifth anniversary of our IPO, (b) in which we have total annual gross revenue of at least $1.07 billion or (c) in which we are deemed to be a large accelerated filer, which means the market value of our Class A common stock that is held by non-affiliates equals or exceeds $700 million as measured on the last business day of our most recently completed second fiscal quarter, or (ii) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period. 

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can, therefore, delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company that is neither an emerging growth company nor an emerging growth company that has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

We cannot predict if investors will find our Class A common stock less attractive because we will rely on these exemptions. If some investors find our Class A common stock less attractive as a result, there may be a less active trading market for our Class A common stock and our stock price may be more volatile.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential shareholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 requires us, among other things, to annually review and report on, and would require our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting once we are no longer exempt under the JOBS Act. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.

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Risks Related to the Merger  

The announcement and pendency of the proposed Merger may adversely affect our business, financial condition and results of operations, and, whether or not the Merger is consummated, we have incurred and will continue to incur significant costs, fees and expenses relating to professional services and transaction fees. 

The Merger Agreement generally requires us to, and cause each of our subsidiaries to, (i) conduct our business in all material respects in the ordinary course of business consistent with past practice and (ii) use our reasonable best efforts to maintain in all material respects our assets and properties in their current condition, preserve intact our business organizations in all material respects, and maintain existing relations and goodwill with governmental entities and customers in all material respects, pending consummation of the proposed Merger, and restricts us, without Desert Peak’s consent, from taking certain specified actions until the proposed Merger is completed. These restrictions may affect our ability to execute our business strategies, including our ability to acquire or dispose of certain assets and to enter into certain contracts, respond effectively to competitive pressures and industry developments, pursue alternative business opportunities or strategic transactions, undertake significant capital projects, undertake significant financing transactions, modify our lease arrangements and otherwise pursue other actions that are not permitted by the Merger Agreement, even if such actions would constitute appropriate changes to our business and help us attain our financial and other goals, and, as a result, these restrictions may impact our financial condition and results of operations.

Employee retention, motivation and recruitment may be challenging before the completion of the proposed Merger, as employees and prospective employees may experience uncertainty about their future roles with the Post-Combination Company following consummation of the proposed Merger. If, despite our retention efforts, key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with or join the post-combination company following consummation of the proposed Merger, or if an insufficient number of employees are retained to maintain effective operations, our business, financial condition and results of operations could be adversely affected.

The proposed Merger could also cause disruptions to our business or business relationships, which could have an adverse impact on our business, financial condition and results of operations. Parties with which we have business relationships may experience uncertainty as to the future of such relationships and may delay or defer certain business decisions concerning us, seek alternative relationships with third parties or seek to alter their present business relationships with us. Parties with whom we otherwise may have sought to establish business relationships may seek alternative relationships with third parties. Operators, lenders and other business partners may also seek to change existing agreements with us as a result of the proposed Merger. Any such delay or deferral of those decisions or changes in existing agreements could adversely impact our business, regardless of whether the proposed Merger is ultimately consummated. The consummation of the proposed Merger may adversely affect our relationship with our operators, lenders or other business partners.

The pursuit of the proposed Merger and the preparation for the integration may place a significant burden on management and internal resources. The diversion of management’s time, efforts, resources and attention away from day-to-day business concerns that could have been otherwise beneficial to us could adversely affect our business, financial condition and results of operations.

We could also be subject to litigation related to the proposed Merger, which could prevent or delay the consummation of the proposed Merger or result in significant costs and expenses. Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition or other business combination agreements similar to the Merger Agreement. It is possible that stockholders may file lawsuits challenging the proposed Merger or the other transactions contemplated by the Merger Agreement, which may name us, Desert Peak and/or our board of directors as defendants. We cannot assure you as to the outcome of such lawsuits, including the amount of costs associated with defending these claims or any other liabilities that may be incurred in connection with the litigation of these claims. If plaintiffs are successful in obtaining an injunction prohibiting the parties from completing the proposed Merger on the agreed-upon terms, such an injunction may delay the consummation of the proposed Merger in the expected timeframe, or may prevent the proposed Merger from being consummated altogether. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Regardless of whether any plaintiff’s claim is successful, this type of litigation may result in significant costs and divert management’s attention and resources, which could adversely affect the operation of our business. Further, there can be no assurance that any of the defendants in any potential future lawsuits will be successful in the outcome of such lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Merger is completed may adversely affect our business, financial condition, results of operations, and cash flows.

In addition to potential litigation-related expenses, we have incurred and will continue to incur other significant costs, expenses and fees for professional services and other transaction costs in connection with the proposed Merger, and many of these fees and costs are payable regardless of whether the Merger is consummated. Payment of these costs, fees and expenses could adversely affect our business, financial condition and results of operations.

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Our inability to complete the Merger, or to complete the Merger in a timely manner, including as a result of the failure to obtain the Required Falcon Stockholder Approvals, the failure to obtain required regulatory approvals or the failure to satisfy the other conditions to the consummation of the Merger could negatively affect our business, financial condition and results of operations. 

The Merger is subject to various closing conditions, such as the Required Falcon Stockholder Approvals and certain regulatory approvals in the United States, including the expiration or termination of any waiting period under the HSR Act, among other customary closing conditions. It is possible that we will not receive the Required Falcon Stockholder Approvals or that a governmental authority may prohibit, enjoin or refuse to grant approval for the consummation of the Merger. If any condition to the closing of the Merger (the “Closing”) is not satisfied or, if permissible, not waived, the Merger will not be completed. In addition, satisfying the conditions to the Closing may take longer than we expect. There can be no assurance that any of the conditions to the Closing will be satisfied or waived or that other events will not intervene to delay or result in the failure to consummate the Merger.

Depending on the circumstances that would have caused the Merger not to be completed, the price of shares of Class A common stock may decline materially, including as a result of negative reactions from the financial markets due to the fact that current prices may reflect a market assumption that the Merger will be completed. If that were to occur, it is uncertain when, if ever, shares of Class A common stock would return to the price levels at which the shares currently trade.

The Merger Agreement contains provisions that could discourage a potential competing acquirer of Falcon, including the payment by Falcon of a termination fee.

The Merger Agreement contains provisions that, subject to limited exceptions, restrict our ability to (i) initiate, solicit, propose, knowingly encourage or knowingly facilitate any inquiry or the making of a Competing Proposal (as defined in the Merger Agreement) or any inquiry, proposal or offer that constitutes or that would reasonably be expected to lead to a Competing Proposal, (ii) engage in, continue or otherwise participate in any discussions or negotiations with any person relating to, or in furtherance of a Competing Proposal or any inquiry, proposal or offer that would reasonably be expected to lead to a Competing Proposal, (iii) furnish any non-public information regarding us or our subsidiaries, or access to our or our subsidiaries’ properties, assets or employees, to any person in connection with or in response to any Competing Proposal or any inquiry, proposal or offer that would reasonably be expected to lead to a Competing Proposal, (iv) enter into any letter of intent or agreement in principal relating to, or other agreement providing for, a Competing Proposal (other than a confidentiality agreement as provided in the Merger Agreement) or (v) submit any Competing Proposal to the approval of our stockholders. In addition, before our board of directors withdraws, qualifies or modifies its recommendation of the proposed Merger or terminates the Merger Agreement to enter into a definitive agreement with respect to a competing transaction, Desert Peak generally has an opportunity to offer to modify the terms of the proposed Merger. In some circumstances, upon termination of the Merger Agreement, we will be required to pay Desert Peak a termination fee equal to $13.9 million.

These provisions could discourage a potential third-party acquirer that might have an interest in acquiring all or a significant portion of us from considering or proposing that acquisition, even if it were prepared to pay above market value, or might otherwise result in a potential third-party acquirer proposing to pay a lower price to Falcon stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.

If the Merger Agreement is terminated and we decide to seek another merger transaction, we may not be able to negotiate or consummate a transaction with another party on terms comparable to, or better than, the terms of the Merger Agreement.

If the benefits of the Merger do not meet the expectations of investors or securities analysts, the market price of the post-combination company’s securities may decline.

If the benefits of the Merger do not meet the expectations of investors or securities analysts, the market price of the post-combination company’s securities following Closing may decline. The market values of Falcon’s securities at the time of the Merger may vary significantly from their prices on the date the Merger Agreement was executed, the date of this Annual Report, or the date on which our stockholders vote on the proposals. Because the number of shares to be issued pursuant to the Merger Agreement will not be adjusted to reflect any changes in the market price of the Class A common stock, the market value of Falcon common stock issued in the Merger may be higher or lower than the values of these shares on earlier dates.

In addition, following the Merger, fluctuations in the price of the post-combination company’s securities could contribute to the loss of all or part of your investment. Prior to the Merger, there has not been a public market for the securities of Desert Peak. Accordingly, the valuation ascribed to Desert Peak in the Merger may not be indicative of the price that will prevail in the trading market following the Merger. The trading price of the post-combination company’s securities following the Merger could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment in our securities and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a further decline.

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Factors affecting the trading price of the post-combination company’s securities may include:

Broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general, and Nasdaq, have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of our securities, may not be predictable. A loss of investor confidence in the market for the stocks of other companies that investors perceive to be similar to the post-combination company could depress the post-combination company’s stock price regardless of our business, prospects, financial conditions, or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

None.

Our executive offices are located at 609 Main Street, Suite 3950, Houston, TX 77002. We have additional leased office space in New York, NY and Philadelphia, PA.  We believe that these facilities are adequate for our current operations.

Additional information regarding our properties is contained in “Item––Business” and is incorporated by reference herein.  

To the knowledge of our management, there is no material litigation, arbitration or governmental proceeding currently pending against us or any members of our management team in their capacity as such.

Not applicable.

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PART II

Market Information

Our units commenced public trading on July 21, 2017, and our Class A common stock and warrants commenced separate trading on August 15, 2017.  Prior to the separation of our units on August 15, 2017, there was no public market for our Class A common stock.  Prior to the Closing of the deSPAC Transactions on August 23, 2018, our Class A common stock, warrants, and units were each listed on the NASDAQ Capital Market under the symbols OSPR, OSPRW and OSPRU, respectively.

Our Class A common stock and warrants are currently listed on the Nasdaq Capital Market under the symbols “FLMN” and “FLMNW,” respectively.  

We had approximately 13 registered stockholders of record of our Class A common stock and eight registered holders of our warrants as of March 3, 2022. This number does not include owners, stockholders or warrant holders who beneficially own our shares through a broker or other entity who may hold shares in “street name”.  There is no public market for our Class C common stock. As of March 3, 2022, we had seven holders of record of our Class C common stock.

Cash Dividends

Cash dividends are made to the common stockholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter’s dividend is determined by the Board of Directors following the end of such quarter. Available cash for each quarter generally equals Adjusted EBITDA reduced for cash needed for debt service, income tax requirements and other contractual obligations and fixed charges that the Board of Directors deems necessary or appropriate, if any.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information as of December 31, 2021 with respect to equity compensation plans under which shares of our common stock are authorized for issuance:

Stockholder Performance Graph

The performance graph below compares the cumulative total returns of our Class A common stock over the period from July 21, 2017 through December 31, 2021 with the cumulative total returns for the same period for the Standard and Poor’s (“S&P”) 500 Index and the SPDR S&P Oil & Gas Exploration & Production ETF (“XOP”).  XOP is a weighted composite of 59 oil and gas exploration and productions companies.  The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our Class A common stock on July 21, 2017, and in the S&P 500 Index and XOP on the same date.  The results shown in the graph below are not necessarily indicative of future performance.  

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[Reserved]

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You should read the following discussion of our historical performance and financial condition together with Part II, Item 6. “Selected Financial Data,” the description of the business appearing in Part I, Item 1. “Business,” and the consolidated financial statements and the related notes in Part II, Item 8. of this Annual Report.

This discussion may contain forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in Part I, Item 1A. “Risk Factors” and under “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We were formed to own and acquire Royalties in oil and natural gas properties in North America, substantially all of which are located in the Eagle Ford Shale. These Royalties entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of any applicable post-production expenses and taxes. The holder of these interests has no obligation to fund exploration and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life, which we believe results in low breakeven costs. As such, we have historically operated with high cash margins, converting a large percentage of revenue to free cash flow, the majority of which can be distributed to our stockholders. 

Recent Developments

On January 11, 2022, Falcon, Merger Sub and Desert Peak entered into the Merger Agreement, pursuant to which, subject to the satisfaction or waiver of certain conditions in the Merger Agreement, Merger Sub will merge with and into Desert Peak, with Desert Peak continuing as the surviving entity in the Merger as a wholly owned subsidiary of OpCo.

Pursuant to the terms of the Merger Agreement and subject to the conditions therein, at the Merger Effective Time, the DPM Membership Units issued and outstanding immediately prior to the Merger Effective Time will be converted into the right to receive an aggregate of (a) 235,000,000 shares of Class C common stock, (b) 235,000,000 OpCo Common Units and (c) additional shares of Falcon Class C common stock (and a corresponding number of OpCo Common Units) equal to (i) the sum of (x) the difference between $140,000,000 and the Sierra Net Debt plus (y) the amount by which the Indebtedness for borrowed money of Falcon and its subsidiaries exceeds $45,000,000 as of immediately prior to the Merger Effective Time divided by (ii) $5.15.

Completion of the Merger is subject to certain customary conditions, including, among others, the following: (a) the affirmative vote of the holders of at least (i) a majority of the votes cast at the Falcon Stockholder Meeting on the approval of the issuance of the Merger Consideration and (ii) a majority of the voting power of the outstanding capital stock of Falcon entitled to vote on the approval of the Falcon Reverse Stock Split; (b) there being no law or injunction prohibiting consummation of the Transactions; (c) approval for listing on the Nasdaq Capital Market of the Class A common stock issuable upon exchange of the Merger Consideration; (d) the expiration or termination of all applicable waiting periods (and any extensions thereof) under the HSR Act, applicable to the Transactions, and any commitment to, or agreement (including any timing agreement) with, any government entity to delay the consummation of, or not to close before a certain date, the Transactions; (e) the effectiveness of the Falcon Reverse Stock Split and the adoption of a reverse unit split of the OpCo Common Units prior to the Merger Effective Time, at a ratio of four to one; (f) subject to specified materiality standards, the accuracy of certain representations and warranties of each party; (g) compliance by each party in all material respects with its covenants included in the Merger Agreement; (h) each of the Registration Rights Agreement and the Director Designation Agreement being in full force and effect; and (i) the Available Liquidity is no less than $65,000,000 and the Sierra Net Debt is not in excess of $140,000,000.

Factors Impacting the Comparability of Our Financial Results

COVID-19 Pandemic.  The outbreak of COVID-19 caused a continuing disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil in 2020. This disruption has somewhat been alleviated in 2021. However, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Given the dynamic nature of these events, the Company cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. The decline in commodity prices adversely affected the revenues we received for our mineral and royalty interests and could impact our ability to access capital markets on terms favorable to us. Market volatility has continued, and we expect it will continue for the foreseeable future. Additionally, many operators of our mineral and royalty interests announced reductions to their capital budgets for 2021 and beyond, which has and will adversely affect the near-term development pace of our properties. However, many operators have resumed or increased drilling and completion activities compared to activity levels in 2020 in connection with the increase in commodity prices in late 2020 and 2021. In connection with the market and commodity price challenges resulting from the COVID-19 pandemic, our acquisition activity saw a significant decline in 2020 as we experienced a meaningful difference in sellers’ pricing expectations and the

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prices we were willing to offer for assets. We cannot predict the extent and potential duration of these and other impacts on our business from the COVID-19 pandemic, efforts to fight the pandemic and other market events.

Sources of Our Revenue

Our revenues were derived from royalty payments we received from our operators based on the sale of crude oil, natural gas, natural gas liquids that are extracted from natural gas during processing, and lease bonuses. As of December 31, 2021, our Royalties represented the right to receive an average of 1.25% from the producing wells on the underlying acreage at the sales price received by our operators net of any applicable post-production expenses and taxes. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.  Oil, NGLs and natural gas prices have historically been volatile therefore, from time to time, we have entered into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. Such instruments may include variable-to-fixed-price swaps, fixed price contracts, costless collars, and other contractual agreements.  The impact of these derivative instruments could affect the amount of revenue we ultimately realize.  We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges in the future.  We do not enter into derivative instruments for speculative purposes.  Our open commodity derivative contracts as of December 31, 2021 are detailed in “Note 4—Commodity Derivative Financial Instruments” to our audited consolidated financial statements included elsewhere in this Annual Report.

During the year ended December 31, 2021, the West Texas Intermediate average monthly posted prices ranged from $52.10 to $81.22 per Bbl for crude oil and the average monthly Henry Hub settlement price of natural gas ranged from $2.47 to $6.20 per MMBtu for natural gas. During the year ended December 31, 2020, West Texas Intermediate average monthly posted prices ranged from $16.70 to $57.86 per Bbl for crude oil and the average monthly Henry Hub settlement price of natural gas ranged from $1.50 to $3.00 per MMBtu.  During the year ended December 31, 2019, West Texas Intermediate average monthly posted prices ranged from $51.55 to $63.87 per Bbl for crude oil and the average monthly Henry Hub settlement price of natural gas ranged from $2.14 to $3.64 per MMBtu.

The following table presents the breakdown of our revenue for the following periods:

Commodity prices are inherently volatile, and changes in such prices have historically had an impact on our revenue.  Lower prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that our operators can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.

The following table sets forth the average realized prices for oil, natural gas and natural gas liquids for the years ended December 31, 2021, 2020 and 2019:

Principal Components of Our Cost Structure

Production and Ad Valorem Taxes 

Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state, and local taxing authorities. Where available, we have historically benefited from tax credits and exemptions in our various taxing jurisdictions. We also directly paid ad valorem taxes in the counties where our production was located. Ad valorem taxes were generally based on the state government’s appraisal of our oil and natural gas properties.

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Marketing and Transportation

Marketing and transportation expenses include the costs to process and transport our production to applicable sales points.  Generally, the terms of the lease governing the development of our properties permit the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.

Amortization

Our Royalties are recorded at cost and capitalized as tangible assets. Acquisition costs related to proved properties are amortized on a units of production basis over the life of the proved reserves.

General and Administrative

General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits (including stock-based compensation expenses), office expenses and fees for professional services.  In addition, we incur incremental G&A expenses relating to expenses associated with SEC reporting requirements, including annual and quarterly reports to shareholders, tax return preparation and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our securities, independent auditor fees, legal expenses, and investor relations expenses.

Interest Expense

We finance a portion of our working capital requirements and acquisitions with borrowings under our credit facility.  As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.  We reflect interest paid to the lenders under our credit facility in interest expense on our statement of operations.  Please read “—Liquidity and Capital Resources—Indebtedness” for further details of our credit facility.    

Income Tax Expense

Income taxes reflect the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying current tax rates to the differences between financial statement and income tax reporting. In assessing the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income based on proved and risk adjusted unproved oil and gas reserves and forecasted commodity pricing, and tax planning strategies in making this assessment. We will continue to evaluate whether the valuation allowance is needed in future reporting periods. We are subject to taxation in many jurisdictions, and the calculation of our income tax liabilities involves dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. We recognize certain income tax positions that meet a more-likely-than not recognition threshold. If we ultimately determine that the payment of these liabilities will be unnecessary, we will reverse the liability and recognize an income tax benefit during the period in which we determine the liability no longer applies.

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Overview of Our Results of Operations

The following table summarizes our revenue and expenses and production data for the periods indicated (in thousands, except production data).

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Comparison of Year Ended December 31, 2021 to Year Ended December 31, 2020

Oil and Gas Revenues

Oil and gas revenues increased $32.8 million, or 82%, to $72.8 million for the year ended December 31, 2021, from $40.1 million for the year ended December 31, 2020. The increase in oil and gas revenues was attributable to an 85% increase in realized oil prices and a 79% increase in realized natural gas prices partially offset by a 3% decrease in production.   We received an average price of $66.39 per Bbl of oil and $3.59 per Mcf of gas sold during the year ended December 31, 2021 compared to $35.84 per Bbl of oil and $2.01 per Mcf of gas sold during the year ended December 31, 2020.  The Company also had an increase of $2.0 million in lease bonus revenue during the year ended December 31, 2021 compared to same period during 2020. In addition, the Company recognized a $3.6 million increase in its loss from our commodity derivative instruments as compared to our realized loss during 2020.  

Production and Ad Valorem Taxes

Production and ad valorem taxes increased $1.1 million, or 40%, to $4.0 million for the year ended December 31, 2021, from $2.8 million for the year ended December 31, 2020. As a percentage of oil and gas revenues, production and ad valorem taxes were 5% for the year ended December 31, 2021 compared to 7% for the year ended December 31, 2020.  This decrease, as a percentage of revenues, was partially due to the approximately 85% and 79% increase, respectively, in the average realized price of oil and natural gas as compared to 2020.  

Marketing and Transportation Expense

Marketing and transportation expense decreased $0.2 million or 12%, to $1.8 million for the year ended December 31, 2021, from $2.0 million for the year ended December 31, 2020. As a percentage of revenues, marketing and transportation expense was 2% during the year ended December 31, 2021 as compared to 5% for the prior year.  The decrease in marketing and transportation expense as a percentage of revenues during 2021 was attributable to fixed transportation costs incurred under our leases that do not increase along with the realized price on the sale of oil and natural gas.    

Amortization of Royalty Interests in Oil and Natural Gas Properties Expense

Amortization of royalty interests in oil and natural gas properties expense increased $1.1 million, or 8%, to $15.2 million for the year ended December 31, 2021, from $14.1 million for the year ended December 31, 2020. The increase in amortization of royalty interests in oil and gas properties expense was primarily attributable to the impact of higher depletion rates which was partially offset by lower production.  The higher depletion rates were primarily driven by decreases in estimated proved developed producing reserve quantities in the Eagle Ford as adjusted in our 2021 year-end reserve reports.  

General, Administrative, and Other Expense

General, administrative, and other expense increased by $2.1 million, or 18%, to $14.1 million for the year ended December 31, 2021, from $12.0 million for the year ended December 31, 2020. The increase in general, administrative, and other expense was

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attributable to an increase of $2.2 million of transaction expenses related to the Desert Peak Minerals transaction, an increase of $2.5 million of payroll expense and other expenses associated with the departure of the Company’s former CEO and $0.2 million attributable to the restatement of the Company’s financial statements included in its 2020 Annual Report on Form 10-K.  This increase was partially offset by a $3.2 million decrease in stock based compensation expense associated with forfeitures.

Change in Fair Value of Warrant Liability

The change in the fair value of warrant liability decreased by $4.7 million, or 91% to a $0.5 million gain for the year ended December 31, 2021, from a $5.1 million gain for the year ended December 31, 2020.  The change in the fair value of the warrant liability was primarily attributable to the increase in the Company’s stock price and the decrease in the remaining term used as inputs in determining the fair value of the Private Placement Warrant liability.

Interest Expense

Interest expense decreased by $0.3 million, or 12%, to $1.9 million for the year ended December 31, 2021, from $2.2 million for the year ended December 31, 2020.  The decrease in interest expense was attributable to lower average outstanding borrowings under our Credit Facility as well as lower average interest rates.

Income Taxes

Income tax expense increased to $4.1 million for the year ended December 31, 2021, compared to $0.6 million for the year ended December 31, 2020.  The increase in income taxes was attributed to an increase in taxable income during the year ended December 31, 2021 as compared to the same period during 2020 attributable to higher average realized prices during 2021.    

Comparison of Year Ended December 31, 2020 to Year Ended December 31, 2019

Oil and Gas Revenues

Oil and gas revenues decreased $28.4 million, or 41%, to $40.1 million for the year ended December 31, 2020, from $68.5 million for the year ended December 31, 2019. The decrease in oil and gas revenues was attributable to a decrease in oil and natural gas production in addition to a 40% decrease in realized oil and a 23% decrease in realized natural gas prices.  We received an average price of $35.84 per Bbl of oil and $2.01 per Mcf of gas sold during the year ended December 31, 2020 compared to $59.85 per Bbl of oil and $2.62 per Mcf of gas sold during the year ended December 31, 2019.  The Company also had a decrease of $1.9 million in lease bonus revenue during the year ended December 31, 2020 compared to the same period in 2020.  In addition, during 2020, we recognized a $1.2 million loss from our commodity derivative instruments.  We did not enter into any commodity derivative instruments during 2019.  

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased $1.5 million, or 34%, to $2.8 million for the year ended December 31, 2020, from $4.3 million for the year ended December 31, 2019. The decrease in production and ad valorem taxes was attributable to the decrease in production.  As a percentage of oil and gas revenues, production and ad valorem taxes were 7% for the year ended December 31, 2020 compared to 6% for the year ended December 31, 2019.  This increase, as a percentage of revenues, was partially due to the approximately 40% and 23% decrease, respectively, in the average realized price of oil and natural gas as compared to 2019.  

Marketing and Transportation Expense

Marketing and transportation expense decreased $0.4 million or 17%, to $2.0 million for the year ended December 31, 2020, from $2.4 million for the year ended December 31, 2019. As a percentage of revenues, marketing and transportation expense was 5% during the year ended December 31, 2020 as compared to 4% for the prior year.  The increase in marketing and transportation expense as a percentage of revenues during 2020 was attributable to fixed transportation costs incurred under our leases that do not decrease along with the realized price on the sale of oil and natural gas.    

Amortization of Royalty Interests in Oil and Natural Gas Properties Expense

Amortization of royalty interests in oil and natural gas properties expense increased $1.4 million, or 11%, to $14.1 million for the year ended December 31, 2020, from $12.7 million for the year ended December 31, 2019. The increase in amortization of royalty interests in oil and gas properties expense was primarily attributable to the impact of higher depletion rates which was partially offset by lower production.  The higher depletion rates were primarily driven by decreases in estimated proved developed producing reserve quantities in the Eagle Ford as adjusted in our 2020 year-end reserve reports.  

General, Administrative, and Other Expense

General, administrative, and other expense increased by $0.1 million, or 1%, to $12.0 million for the year ended December 31, 2020, from $11.9 million for the year ended December 31, 2019. The increase in general, administrative, and other expense was attributable to $0.8 million of expenses incurred as a part of the strategic review process which management had begun during the third

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quarter of 2020 and an increase of $0.9 million in stock-based compensation.  These increases were partially offset by cost cutting measures implemented by management during the first quarter of 2020 due to the effects of the pandemic.  

Change in Fair Value of Warrant Liability

The change in the fair value of warrant liability decreased by $0.9 million, or 16% to $5.1 million for the year ended December 31, 2020, from $6.1 million for the year ended December 31, 2019.  The decrease in the fair value of the warrant liability is attributable to the decrease in the Company’s stock price that was used in determining the fair value of the warrant liability.  

Interest Expense

Interest expense decreased by $0.3 million, or 12%, to $2.2 million for the year ended December 31, 2020, from $2.5 million for the year ended December 31, 2019.  The decrease in interest expense was attributable to lower average outstanding borrowings under our Credit Facility as well as lower average interest rates.

Income Taxes

Income tax expense decreased to $0.6 million for the year ended December 31, 2020, compared to $3.9 million for the year ended December 31, 2019.  The decrease in income taxes was attributed to a decrease in taxable income during the year ended December 31, 2020 as compared to the same period during 2019 attributable to lower production and lower average realized prices during 2020.

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders, and rating agencies. We believe Adjusted EBITDA is useful because it allows us to evaluate our performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay dividends to our common stockholders.

We define Adjusted EBITDA as net income before interest expense, net, depletion expense, provision for income taxes, depreciation, unrealized gains and losses on commodity derivative instruments, non-cash gains and losses on revaluation of warrant liability, and non-cash equity-based compensation. Adjusted EBITDA is not a measure of net income as determined by GAAP. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, royalty income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of net income to Adjusted EBITDA, our most directly comparable GAAP financial measure for the periods indicated (in thousands).

Liquidity and Capital Resources

Overview

Our primary sources of liquidity have historically been cash flows from operations and equity and debt financings, and our primary uses of cash are for dividends and for the acquisition of additional Royalties.  We intend to finance potential future acquisitions through a combination of cash on hand, borrowings under our Credit Facility and, subject to market conditions and other factors, proceeds from one or more capital market transactions, which may include debt or equity offerings. Our ability to generate cash is subject to a number

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of factors, some of which are beyond our control, including commodity prices and general economic, financial, competitive, legislative, regulatory, and other factors, including weather.

Our shareholders agreement does not require us to distribute any of the cash we generate from operations. Cash dividends are made to the common stockholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter’s dividend is determined by the Board of Directors following the end of such quarter. Available cash for each quarter generally equals Adjusted EBITDA reduced for cash needed for debt service, income tax requirements and other contractual obligations and fixed charges that the Board of Directors deems necessary or appropriate, if any.

The effects of the COVID-19 outbreak and recent oil price volatility could have significant adverse consequences for general economic, financial and business conditions, as well as for our business and financial position and the business and financial position of the operators of our mineral interests and may, among other things, impact our ability to generate cash flows from operations, access the capital markets on acceptable terms or at all, and affect our future need or ability to borrow under our Credit Facility.  In addition to our potential sources of funding, the effects of such global events may impact our liquidity or need to alter our allocation or sources of capital, implement further cost reduction measures, and change our financial strategy.  Although the COVID-19 outbreak and recent oil price volatility could have a broad range of effects on our sources and uses of liquidity, the ultimate effect thereon, if any, will depend on future developments, which cannot be predicted at this time.

The following table presents cash distributions approved by the Board of Directors of our general partner for the periods presented.

Indebtedness

Falcon Credit Facility

On the Closing Date, OpCo entered into a credit facility with Citibank, N.A., as administrative agent and collateral agent for the lenders from time-to-time party thereto (the “Credit Facility”). The Credit Facility provides for a maximum credit amount of $500.0 million and a borrowing base based on our oil and natural gas reserves and other factors of $70.0 million, subject to scheduled semi-annual and other borrowing base redeterminations and matures on the fifth anniversary of the Closing Date. As of December 31, 2021, OpCo had borrowings of $40.0 million under the Credit Facility at an interest rate of 2.60% and $30.0 million available for future borrowings under the Credit Facility.

Principal amounts borrowed are payable on the maturity date. OpCo has a choice of borrowing at the base rate or LIBOR, with such borrowings bearing interest, payable quarterly in arrears for base rate loans and one month, two-month, three month or six-month periods for LIBOR loans. LIBOR loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 or LIBOR02 page as the LIBOR, for deposits in dollars at 12:00 noon (London, England time) for one, two, three, or six months plus an applicable margin ranging from 200 to 300 basis points. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one-month LIBOR loans plus 1%, plus an applicable margin ranging from 100 to 200 basis points. The scheduled redeterminations of OpCo’s borrowing base take place on April 1^st and October 1^st of each year. 

Obligations under the Credit Facility are guaranteed by OpCo and each of our existing and future, direct and indirect domestic subsidiaries (the “Credit Parties”) and are secured by all of the present and future assets of the Credit Parties, subject to customary carve-outs.

The Credit Facility contains certain customary representations and warranties, affirmative covenants, negative covenants, and events of default. As of December 31, 2021, OpCo was in compliance with such covenants. The negative covenants include restrictions

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on the Company’s ability to incur additional indebtedness, acquire and sell assets, create liens, enter into certain lease agreements, make investments, and make distributions.

Cash Flows

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020   

A summary of the changes in cash flow data for the years ended December 31, 2021 and 2020 are set forth in the following table (in thousands, except percentages):