UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, ~~2022~~2023

[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to .

Commission File No. 001-35343

Chesapeake Granite Wash Trust

(Exact name of registrant as specified in its charter)


Delaware						45-6355635
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A., Trustee Global Corporate Trust
601 Travis Street, Floor 16
Houston, Texas						77002
(Address of principal executive offices)						(Zip Code)

(512) 236-6555


(Registrant’s telephone number, including area code)

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

Title of Each Class

Trading Symbol

Name on each exchange on which registered

None

Not applicable

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 [X]

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 [ X] No [X ]

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 [X ] No [ X]

~~Indicate~~The byregistrant ~~check~~is ~~mark~~a ~~whether~~voluntary ~~the~~filer ~~registrant~~of ~~has~~reports ~~submitted~~required ~~electronically,~~to ~~every~~be ~~Interactive~~filed ~~Data~~by ~~File~~certain ~~required~~companies tounder beSection ~~submitted~~13 ~~pursuant~~or to15(d) ~~Rule~~of ~~405~~the Securities Exchange Act of ~~Regulation~~1934 ~~S-T~~and ~~(§232.405~~has offiled ~~this~~all ~~chapter)~~reports that would have been required to have been filed by the registrant during the preceding 12 months ~~(or~~had ~~for~~it ~~such~~been ~~shorter~~subject ~~period~~to ~~that~~such ~~the~~filing ~~registrant~~requirements ~~was~~during ~~required~~the toentirety ~~submit~~of such ~~files)~~period. ~~Yes [X] 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 [X]

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

Large accelerated filer [ ]

Accelerated filer [ ]

Non-accelerated filer
[X]

Smaller reporting company [ ]

Emerging growth company [ ]

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

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements

of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

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

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

The aggregate market value of the 23,000,000 Common Units representing beneficial interests in Chesapeake Granite Wash Trust held by non-affiliates of the registrant, computed using the closing sale price of $1.2118 on June 30, ~~2022~~2023, was approximately $27.8314 million.

As of March 2228, ~~2023~~2024, 46,750,000 Common Units representing beneficial interests in Chesapeake Granite Wash Trust were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Listed below is the only document parts of which are incorporated herein by reference and the parts of this Annual Report into which the document is incorporated:

None

CHESAPEAKE GRANITE WASH TRUST

~~2020~~2023 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

	PART I	Page
Item 1.	Business	1
Item 1A.	Risk Factors	1918
Item 1B.	Unresolved Staff Comments	3936
Item 2.	Properties	39
Item 1C.	Cybersecurity	36
Item 3.	Legal Proceedings	39
Item 2.	Properties	38
Item 4.	Mine Safety Disclosures	39
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	38
	PART II
Item 5.	Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units	4039
Item 6.	[RESERVED]	4039
Item 7.	Trustee's Discussion and Analysis of Financial Condition and Results of Operations	4039
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4544
Item 8.	Financial Statements and Supplementary Data	45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	63
Item 9A.	Controls and Procedures	63
Item 9B.	Other Information	64
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	64
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	65
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	65
Item 13.	Certain Relationships and Related Transactions and Director Independence	66
Item 14.	Principal Accountant Fees and Services	67
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	68
Item 16.	Form 10-K Summary	70
Signatures		75

All references to “we,” “us,” “our,” or the “Trust” refer to Chesapeake Granite Wash Trust. The royalty interests conveyed on November 16, 2011 by Chesapeake Energy Corporation from its interests in certain properties in the Colony Granite Wash formation in Oklahoma and held by the Trust are referred to as the “Royalty Interests.” References to "Chesapeake" refer to Chesapeake Energy Corporation and, where the context requires, its subsidiaries. References to "Tapstone" refer to Tapstone Energy Holdings, LLC or its wholly owned subsidiary Tapstone Energy LLC, as applicable. References to "Diversified" refer to Diversified Energy Company PLC and, where the context requires, its subsidiaries. References to "Operator" refer to (i) Diversified Energy Company PLC and, where the context requires, its subsidiaries at all times after consummation of the Merger (as defined below), (ii) Tapstone Energy, LLC at all times from December 11, 2020 and prior to the consummation of the Merger, and (iii) Chesapeake at all times prior to December 11, 2020. AsCommencing as of December 7, 2021, Diversified, through Tapstone, its wholly owned subsidiary, owns and operates all Underlying Properties (as defined below) held by the ~~Trust.~~

Trust. Additional information about Diversified, including its presentation of the Merger is available on Diversified's website at www.div.energy.

RISK FACTOR SUMMARY

Our business involves certain risks and uncertainties. The following is a description of significant risks that might cause our future financial condition or results of operations to differ materially from those expected. In addition to the risks and uncertainties described below, we may face other risks and uncertainties, some of which may be unknown to us and some of which we may deem immaterial. A summary of our risk factors is as follows (capitalized terms being defined in the Glossary below):

•Producing oil, natural gas, and NGL on the Underlying Properties is a high-risk activity with many uncertainties.

•Oil, natural gas, and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on proceeds to the Trust and cash distributions to unitholders.

•Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.

•The sale of the Underlying Properties of the Trust may result in the ownership and management of the Trust by a party that is unfamiliar with the operation of the Trust or the Underlying Properties.

•Due to the Trust's lack of industry and geographic diversification, adverse developments in the Trust's existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.

•The generation of proceeds for distribution by the Trust depends in part on access to and the operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil, natural gas and NGL production from the Underlying Properties.

•The Trust units may lose value and cash available for distribution may be reduced as a result of title deficiencies with respect to the Underlying Properties.

•The oil, natural gas and NGL reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time.

•An increase in the differential between the prices realized by the Operator for oil, natural gas and NGL produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions by the Trust and the value of Trust units.

•Oil and natural gas producing operations can be hazardous and may expose the Operator to liabilities.

•Climate change and the effects of energy transition could result in significant operational changes and expenditures, reduce demand for our services and adversely affect business.

•Negative public perception regarding the Operator or the oil and gas industry could have an adverse effect on the Operator's operations.

•Increases in interest rates may cause the value of the Trust units to decline.

•The amount of cash available for distribution by the Trust will be reduced by post-production expenses and applicable taxes associated with the Royalty Interests and Trust expenses.

•The Trust is passive in nature and will have no voting rights in the Operator managerial, contractual or other ability to influence the Operator, or control over the field operations of, sales of oil, natural gas and NGL from, or development of, the Underlying Properties.

•Financial information of the Trust is not prepared in accordance with U.S. GAAP.

•The Trust is precluded from acquiring other oil and natural gas properties or royalty interests to replace the depleting assets and production.

•The Trustee may, under certain circumstances, sell the Royalty Interests and dissolve the Trust.

•The Trust is administered by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.

•Trust unitholders have limited ability to enforce provisions of the Royalty Interest conveyances, and the Operator's liability to the Trust is limited.

•Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.

•Diversified may sell Trust units in the public or private markets and such sales could have an adverse impact on the trading price of the common units.

•Conflicts of interest could arise between the Operator and the Trust.

•The Operator may sell all or a portion of its retained interest in the Underlying Properties, subject to and burdened by the Royalty Interests.

•The Trust units are listed quoted for trading on the OTC Pink marketplace.

•The Operator is subject to extensive governmental regulation, including environmental, which can change and could adversely impact the Operator's business.

•The Trust could be negatively affected by cybersecurity threats.

•The Trust's tax treatment depends on its status as a partnership for U.S. federal income tax purposes.

•The U.S. federal income tax treatment of the Development Royalty Interest is not entirely free from doubt.

•The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

•If the IRS contests the tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce the Trust's cash available for distribution to Trust unitholders.

•Trust unitholders will be required to pay taxes on their share of the Trust's income even if they do not receive any cash distributions from the Trust.

•Tax gain or loss on the disposition of the Trust units could be more or less than expected.

•Tax-exempt entities and non-U.S. persons face unique tax issues from owning the Trust units that may result in adverse tax consequences to them.

•The Trust will treat each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased.

•The Trust prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly record date in such quarter, instead of on the basis of the date a particular Trust unit is transferred.

•A Trust unitholder whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed of those Trust units.

•The Trust has adopted certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders.

•Trust unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in Trust units.

GLOSSARY OF CERTAIN TERMS

In this Annual Report, the following terms have the meanings specified below. Other terms are defined in the text of this Annual Report.

Administrative Servicer. The company providing the Trust with certain accounting, tax preparation, bookkeeping and information services related to the Royalty Interests and the Registration Rights Agreement in accordance with the Administrative Services Agreement (defined below). Pursuant to an agreement between Tapstone and Chesapeake following the divestiture of the Underlying Properties, (i) Chesapeake served as the Administrative Servicer through the filing of the 2020 Annual Report with the SEC and (ii) Tapstone is the Administrative Servicer for all periods subsequent to the filing of the 2020 Annual Report with the SEC. Following consummation of the Merger (as defined in Part I Item 1. Business), all duties previously performed by Tapstone and its subsidiaries with respect to the Trust are now performed by Diversified.

Administrative Services Agreement. An administrative services agreement the Trust entered into on November 16, 2011 with the Administrative Servicer, effective July 1, 2011, pursuant to which the Administrative Servicer provides the Trust with certain accounting, tax preparation, bookkeeping and information services related to the Royalty Interests and the Registration Rights Agreement.

AMI. The area of mutual interest, or AMI, lies within Washita County in western Oklahoma and is limited to the Colony Granite Wash formation in the area identified below, consisting of approximately 40,500 gross acres (26,400 net acres) held by Tapstone as of December 31, ~~2022~~2023.

Assignment Agreement. Assignment and Assumption Agreement, dated as of December 11, 2020, by and among Chesapeake, Chesapeake Exploration, L.L.C., Chesapeake E&P Holding, L.L.C., and Tapstone, pursuant to which Tapstone agreed to assume all duties and obligations of Chesapeake and its subsidiaries under each of the Trust Agreement, the Administrative Services Agreement, the royalty conveyances and the Registration Rights Agreement following the divestiture by Chesapeake of the Underlying Properties and 23,750,000 common units.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Boe. Barrel of oil equivalent. Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Despite holding this ratio constant at six mcf to one bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

Btu. British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or natural gas liquids, or in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at the original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (b) drill and equip Development Wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (c) acquire, construct and install production facilities such as leases, flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (d) provide improved recovery systems.

Development Well. As defined by the SEC, a development well is a well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. For the purposes of the Trust and as used herein, references to “Development Wells” refer to the 118 horizontal development wells that, since July 1, 2011, have been drilled on properties held by the Operator in the AMI and in which the Trust has received an interest.

Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically Producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue is determined at the terminal point of oil and ~~natural~~ gas producing activities as defined in Rule 4-10(a)(16) of Regulation S-X under the Securities Act.

Estimated Future Net Revenues. The result of applying current prices of oil, natural gas and NGL to estimated future production from oil, natural gas and NGL proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays or areas of interest.

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 a working interest is owned.

IRS. The Internal Revenue Service of the United States federal government.

Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.

Mboe. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

Mmcf. One million cubic feet.

Net Acres or Net Wells. The sum of the fractional working interest owned in gross acres or gross wells, respectively.

Net Revenue Interest. A share of production after all burdens, such as royalty and overriding royalty interests, have been deducted from the working interest.

Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.

NYMEX. New York Mercantile Exchange.

Operator. The company that holds the AMI, owns the Underlying Properties and is bound by the terms of the Trust Agreement. Following the consummation of the Merger (as defined below), Diversified Energy Company PLC and, where the context requires, its subsidiaries, became the Operator.

Participation Agreement. Participation Agreement, dated October 2, 2020, by and between Operator and OCM Denali Holdings, LLC, which agreement was not in existence as of the date of the Conveyances and is a permitted encumbrance under the Conveyances. The agreement relates to the Underlying Properties.

Plugging and Abandoning. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Oklahoma regulations require plugging of abandoned wells.

Present Value of Estimated Future Net Revenues or PV-10 (non-GAAP). When used with respect to oil, natural gas and NGL reserves, present value of estimated future net revenues, or PV-10, means the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted net cash flows, or Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Because the Trust will not bear income tax expense, the PV-10 and Standardized Measure attributable to the Royalty Interests are the same.

Price Differential. The difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.

Producing Well. As defined by the SEC, a producing well is a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. For the purposes of the Trust and as used herein, references to “Producing Wells” refer to the 69 existing horizontal wells in which Chesapeake conveyed an interest to the Trust effective as of July 1, 2011.

Production Expenses. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil, natural gas and NGL produced. Examples of production expenses (sometimes called lifting expenses) are:

•costs of labor to operate the wells and related equipment and facilities;

•repairs and maintenance;

•materials, supplies and fuel consumed as well as supplies utilized in operating the wells and related equipment and facilities;

•property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

facilities; and

•production taxes.

Some support equipment or facilities may serve two or more oil and natural gas producing activities and may also serve transportation, refining and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production expenses, as appropriate. Depreciation, depletion and amortization of capitalized acquisition, exploration, and development costs are not production expenses but also become part of the cost of oil and natural gas produced along with production (lifting) costs identified above.

Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.

Prospectus. The Trust Prospectus dated November 10, 2011 and filed with the SEC on November 14, 2011, in connection with the initial public offering of the Trust's common units.

Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved Reserves. As used in this report, proved reserves has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved oil and natural gas 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.

Proved Undeveloped Reserves (PUDs). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively high expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Registration Rights Agreement. ~~Dated~~Registration Rights Agreement dated as of November 16, 2011, by and among Tapstone (as successor to Chesapeake and Chesapeake Exploration, L.L.C.) and the Trust.

Reserves. 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 market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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

SEC. The United States Securities and Exchange Commission.

Standardized Measure. The discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.

Underlying Properties. Interests in specified oil and natural gas properties located in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma.

Undeveloped Acreage. 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.

Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (“Annual Report” or "Form 10-K") includes “forward-looking statements” about the Trust and the Operator and other matters discussed herein that are subject to risks and uncertainties that are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical fact included in this document, ~~including,~~are ~~without~~forward-looking ~~limitation,~~ statements ~~relating to actions by~~, ~~or disputes among or between~~including, ~~members~~without ~~of the Organization of the Petroleum Exporting Countries and its allies ("OPEC+")~~limitation, ~~market factors, market prices,~~ statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I and elsewhere herein regarding market factors, market prices, the proved oil, natural gas and NGL reserves associated with the properties underlying the Royalty Interests, the Trust’s or the Operator's future financial position, business strategy, budgets, projected costs and plans and objectives for future operations, information regarding target distributions, statements pertaining to future development activities and costs and information regarding production and reserve growth, statements regarding the continued trading of the Trust's ~~continued~~common ~~listing~~units on the Pink Open Market operated by OTC Markets Group, Inc. (the "OTC Pink"), statements regarding the expected impact of geopolitical events, including the ongoing ~~conflict~~conflicts in Ukraine and Israel, and actions by, or disputes among or between, members of the ~~impact~~Organization ~~thereof~~of the Petroleum Exporting Countries and its allies, in each case on our and the Operator's business, financial condition, results of operations and cash flows ~~are forward-looking statements~~. ~~Actual outcomes and results may differ materially from those projected.~~ Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “seek,” “plan,” “goal,” “assume,” “target,” “should,” “intend," "ability," "will," "would," "forecast" or other words that convey the uncertainty of future events or outcomes. Actual outcomes and results may differ materially from those projected. These forward-looking statements are based on certain assumptions made by the Trust, and by the Operator in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with such expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part I of this Annual Report, which could affect the future results of the energy industry in general, and the Trust and the Operator in particular, and could cause those results to differ materially from those expressed in such forward-looking statements. These factors should not be construed as exhaustive, and there may also be other risks that we are unable to predict at this time. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on the Operator's business and the Trust. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trustee relies on the Operator for information regarding the Royalty Interests, the Underlying Properties and the Operator itself. The Trust undertakes no obligation to publicly update or revise any forward-looking statements and expressly disclaims any obligation to do so, except as required by applicable law.

PART I

ITEM 1.Business

Introduction

The Trust is a statutory trust formed in June 2011 under the Delaware Statutory Trust Act pursuant to an initial trust agreement by and among the Operator, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust maintains its offices at the office of the Trustee, which is located at 601 Travis Street, Floor 16, Houston, Texas 77002, and the telephone number of the Trustee is (512) 235-6555.

The Trustee maintains a website for filings by the Trust with the SEC. Electronic filings by the Trust with the SEC are available free of charge through the Trust's website at www.chkgranitewashtrust.com and through the SEC's website at www.sec.gov. The Trust will also provide electronic and paper copies of its recent filings free of charge upon request to the Trustee. Documents and information on the Trust's website are not incorporated by reference herein.

General

The Trust was created to own the Royalty Interests for the benefit of Trust unitholders pursuant to a trust agreement dated as of June 29, 2011 and subsequently amended and restated as of November 16, 2011 by and among Tapstone (as successor to Chesapeake and Chesapeake Exploration, L.L.C., a wholly owned subsidiary of Chesapeake), the Trustee and the Delaware Trustee (the “Trust Agreement”). The Royalty Interests are derived from the Underlying Properties. Chesapeake conveyed the Royalty Interests to the Trust from Chesapeake's interests in the Producing Wells and the Development Wells.

The business and affairs of the Trust are managed by the Trustee. The Trust Agreement limits the Trust's business activities generally to owning the Royalty Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances applicable to the Royalty Interests. The royalty interests in the Producing Wells (the “PDP Royalty Interest”) entitle the Trust to receive 90% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to the Operator's net revenue interest in the Producing Wells. The royalty interests in the Development Wells (the “Development Royalty Interest”) entitle the Trust to receive 50% of the proceeds (exclusive of any production or development costs but after deducting certain post-production expenses and any applicable taxes) from the sales of oil, natural gas and NGL production attributable to the Operator's net revenue interest in the Development Wells.

Through an initial public offering in November 2011, the Trust sold to the public 23,000,000 common units, representing beneficial interests in the Trust, for cash proceeds of approximately $409.7 million, net of offering costs. The Trust delivered the net proceeds of the initial public offering, along with 12,062,500 common units and 11,687,500 subordinated units, to certain wholly owned subsidiaries of Chesapeake in exchange for the conveyance of the Royalty Interests to the Trust. Upon completion of these transactions, there were 46,750,000 Trust units issued and outstanding, consisting of 35,062,500 common units and 11,687,500 subordinated units, which were converted into common units on a one-for-one basis as of June 30, 2017. On December 11, 2020, Chesapeake sold its 23,750,000 common units to Tapstone in a sale that included the Underlying Properties of the Trust.

On October 6, 2021, Tapstone Energy Holdings, LLC, a Delaware limited liability company, and the parent of Tapstone, ("Tapstone Holdings"), entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Diversified, the parent of Diversified Production LLC (“Diversified Production”), and certain of its affiliates, including Diversified Production. Upon the terms and subject to the conditions set forth in the Merger Agreement, a wholly owned subsidiary of Diversified merged with and into Tapstone Holdings with Tapstone Holdings as the surviving entity, resulting in Tapstone Holdings and Tapstone becoming wholly owned subsidiaries of Diversified. The ~~terms~~transactions ~~and~~provided ~~conditions~~for ofunder the Merger Agreement were ~~fulfilled~~consummated on December 7, 2021, and Tapstone Holdings became a wholly owned subsidiary of Diversified on such date (the “Merger”). Following the Merger, the 23,750,000 common units previously held by Tapstone Energy LLC were transferred to Diversified Production, another indirect, wholly-owned subsidiary of Diversified. Subsequently, on September 22, 2023, the 23,750,000

Following consummation of the Merger, duties previously performed by Tapstone and its subsidiaries with respect to the Trust are now performed by Diversified.

~~Tapstone’s~~common ~~right,~~units ~~title~~were ~~and~~transferred ~~interest in and~~ to, ~~and~~DP ~~all~~Bluegrass ofLLC ~~their duties and obligations under all documents related to the Trust~~ (~~including~~"DP ~~the Amended and Restated Trust Agreement (dated as of November 16, 2011~~Bluegrass"), ~~the~~an ~~Administrative Services Agreement (dated as of November 16~~indirect, ~~2011)~~wholly-owned ~~and~~subsidiary ~~the related royalty interest conveyances) remain unchanged as a result~~ of ~~the Merger, although there have been certain changes in the management of the Underlying Properties. However, as a result of the Merger,~~ Diversified ~~may be deemed the beneficial owner of the 23,750,000 common units of the Trust, held by Tapstone, representing all of Tapstone’s 50~~Production.~~8% beneficial ownership interest in the Trust immediately prior to the effective time of the Merger.~~

Following consummation of the Merger, duties previously performed by Tapstone and its subsidiaries with respect to the Trust are now performed by Diversified.

Tapstone’s right, title and interest in and to, and all of their duties and obligations under all documents related to the Trust (including the Amended and Restated Trust Agreement (dated as of November 16, 2011), the Administrative Services Agreement (dated as of November 16, 2011) and the related royalty interest conveyances) remain unchanged as a result of the Merger, although there have been certain changes in the management of the Underlying Properties. However, as a result of the Merger, Diversified may be deemed the beneficial owner of the 23,750,000 common units of the Trust, now held by DP Bluegrass, representing the entire 50.8% beneficial ownership interest in the Trust held by Tapstone immediately prior to the effective time of the Merger.

Neither the Trust nor the Trustee is responsible for, or has any control over, any operating or capital costs of the Underlying Properties. The Trust's cash receipts with respect to the Royalty Interests in the Underlying Properties are determined after deducting certain post-production expenses and any applicable taxes associated with the Royalty Interests. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas and NGL produced. However, the Trust is not responsible for costs of marketing services provided by affiliates of the Operator. Cash distributions to unitholders will continue to be reduced by the Trust's general and administrative expenses.

The Trust will dissolve and begin to liquidate on June 30, 2031 (the “Termination Date”), or earlier upon certain events, and will soon thereafter wind up its affairs and terminate. At the Termination Date, (a) 50% of the total Royalty Interests conveyed by the Operator (the “Term Royalties”) will revert automatically to the Operator and (b) 50% of the total Royalty Interests conveyed by the Operator (the “Perpetual Royalties”) will be retained by the Trust and thereafter sold. The net proceeds of the sale of the Perpetual Royalties, as well as any remaining Trust cash reserves, will be distributed to the unitholders on a pro rata basis. The Operator will have a right of first refusal to purchase the Perpetual Royalties retained by the Trust at the Termination Date.

The Trust is required to make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the Trust's administrative expenses and any cash reserves, on or about 60 days following the completion of each quarter through (and including) the quarter ending June 30, 2031. Quarterly distributions to Trust unitholders will generally include royalty income attributable to sales of oil, natural gas and NGL for three months, including the first two months of the quarter just ended and the last month of the quarter prior to that one. The first quarterly distribution was made on December 28, 2011 to record unitholders as of December 15, 2011.

Actual cash distributions to the Trust unitholders will fluctuate quarterly based on the quantity of oil, natural gas, and NGL sold from the Underlying Properties, the prices received for such sales, the timing of the Operator's receipt of payment for such sales, the Trust's expenses and other factors. Target distributions will decline over time as a result of the depletion of the reserves in the Underlying Properties.

For the year ended December 31, ~~2022~~2023, the Trust declared and paid the following cash distributions:

Production Period	Distribution Date	Cash Distribution per Common Unit
June 2022 – August 2022	December 1, 2022	$	0.0722
June 2023 – August 2023	November 30, 2023	$	0.0336
March 2022 - May 2022	August 29, 2022	$	0.0849
March 2023 - May 2023	August 31, 2023	$	0.0178
December 2021 - February 2022	May 31, 2022	$	0.0540
December 2022 - February 2023	June 1, 2023	$	0.0487
September 2021 - November 2021	March 3, 2022	$	0.0667
September 2022 - November 2022	March 1, 2023	$	0.0757

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Subsequent Distribution. The Trust's quarterly income available for distribution was $0.0757 per common unit for the production period from September 1, 2022 to November 30, 2022. On February 3, 2022, the Trust declared a cash distribution of $0.0757 per common unit attributable to such production period. The distribution was paid on March 1, 2023 to record unitholders as of February 20, 2023. All Trust unitholders share on a pro rata basis in the Trust's distributable income.

As of March 22, 2023, Tapstone owned 23,750,000 common units, which represent 50.8% of the outstanding Trust units. Diversified is the ultimate parent company of Tapstone, and therefore is deemed to beneficially own the common units held by Tapstone.

Subsequent Distribution. The Trust's quarterly income available for distribution was $0.0214 per common unit for the production period from September 1, 2023 to November 30, 2023. On February 5, 2024, the Trust declared a cash distribution of $0.0214 per common unit attributable to such production period. The distribution was paid on February 29, 2024 to record unitholders as of February 19, 2024. All Trust unitholders share on a pro rata basis in the Trust's distributable income.

As of March 28, 2024, DP Bluegrass held 23,750,000 common units, which represent 50.8% of the outstanding Trust units. Diversified is the ultimate parent company of DP Bluegrass, and therefore is deemed to beneficially own the common units held by DP Bluegrass.

Administrative Services Agreement

In return for the services provided by the Administrative Servicer under the Administrative Services Agreement, the Trust pays the Administrative Servicer an annual fee of $200,000, which is paid in equal quarterly installments and remains fixed for the life of the Trust. The Administrative Servicer is also entitled to receive reimbursement for its actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement.

The Administrative Services Agreement will terminate upon the earliest to occur of (a) the date the Trust shall have been wound up in accordance with the Trust Agreement, (b) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (c) with respect to services to be provided with respect to any Underlying Properties being transferred by the Operator, the date that either the Administrative Servicer or the Trustee may designate by delivering 90-days prior written notice, provided that the transferee of such Underlying Properties assumes responsibility to perform the services in place of the Administrative Servicer or (d) a date mutually agreed by the Administrative Servicer and the Trustee.

Description of the Trust

Common Units. Each Trust unit is a unit of the beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. The Trust has 46,750,000 Trust units issued and outstanding, all of which are common units.

Distributions and Income Computations. The Trust is required to make quarterly cash distributions to unitholders from its available funds for such calendar quarter. Royalty Interest payments due to the Trust with respect to any calendar quarter are based on actual sales volumes attributable to the Trust's interests in the Underlying Properties (as measured at the Operator's metering systems) for the first two months of the quarter just ended as well as the last month of the immediately preceding quarter and actual revenues, net of post-production expenses received for such volumes. The Operator makes the Royalty Interest payments to the Trust within 35 days of the end of each calendar quarter. Taking into account the receipt and disbursement of all such amounts, the Trustee determines for such calendar quarter the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust over the Trust's expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.

The Trustee distributes cash approximately 60 days (or the next succeeding business day following such day if such day is not a business day) following each calendar quarter to each person who is a Trust unitholder of record on the quarterly record date together with interest expected to be earned on the amount of such quarterly distribution from the date of receipt thereof by the Trustee to the payment date.

Unless otherwise advised by counsel or the IRS, the Trustee treats the income and expenses of the Trust for each quarter as belonging to the Trust unitholders of record on the quarterly record date that occurs in such quarter. Trust unitholders recognize income and expenses for tax purposes in the quarter the Trust receives or pays those amounts, rather than in the quarter the Trust distributes them. Minor variances may occur. For example, the Trustee could establish a reserve in one quarter that would not result in a tax deduction until a later quarter. The Trustee could also make a payment in one quarter that would be amortized for tax purposes over several months.

Transfer of Trust Units. Trust unitholders may transfer their Trust units in accordance with the Trust Agreement. The Trustee does not require either the transferor or transferee to pay a service charge for any transfer of a Trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Trust unit as shown by its records as the owner of the Trust unit. The Trustee will not be considered to know about any claim or demand on a Trust unit by any party except the record owner. A person who acquires a Trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of Trust units.

Periodic Reports. The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders a Schedule K-1 and also causes to be prepared and filed reports required to be filed under the Exchange Act, and by the rules any securities exchange or quotation system on which the Trust units are listed or admitted to trading.

considered to know about any claim or demand on a Trust unit by any party except the record owner. A person who acquires a Trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of Trust units.

Each Trust unitholder and his representatives have the right, at his own expense and during reasonable business hours upon reasonable prior notice, to examine and inspect the records of the Trust and the Trustee in reference thereto for any purpose reasonably related to the Trust unitholder's interest as a Trust unitholder.

Liability of Trust Unitholders. Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

Voting Rights of Trust Unitholders. The Trustee or Trust unitholders owning at least 10% of the outstanding Trust units may call meetings of Trust unitholders. The Trust does not intend to hold annual meetings of the Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders unless such meeting is called by the Trust unitholders, in which case the Trust unitholders are responsible for all costs associated with calling such meeting of Trust unitholders. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.

Unless otherwise required by the Trust Agreement, a matter may be approved or disapproved by the vote of a majority of the Trust units held by the Trust unitholders voting in person or by proxy at a meeting where there is a quorum. Accordingly, a matter may be approved even if a majority of the total outstanding Trust units does not approve it.

Until such time as Diversified and its affiliates own less than 10% of the outstanding Trust units, the affirmative vote of the holders of a majority of common units (excluding common units owned by Diversified and its affiliates) and a majority of Trust units voting in person or by proxy at a meeting of such holders at which a quorum is present is required to:

•dissolve the Trust (except in accordance with its terms);

•remove the Trustee or the Delaware Trustee;

•amend the Trust Agreement, the royalty conveyances, the Administrative Services Agreement and the development agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect);

•merge, consolidate or convert the Trust with or into another entity; or

•approve the sale of all or any material part of the assets of the Trust.

At any time when Diversified and its affiliates own less than 10% of the outstanding Trust units, the vote of the holders of a majority of Trust units, including units owned by Diversified, voting in person or by proxy at a meeting of such holders at which a quorum is present will be required to take the actions described above. Notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.

Certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders. The Trustee must consent before all or any part of the Trust assets can be sold except in connection with the dissolution of the Trust or limited sales directed by Diversified in conjunction with its sale of Underlying Properties.

Description of the Trust Agreement. The Trust was created under Delaware law as a separate legal entity to acquire and hold the Royalty Interests for the benefit of the Trust unitholders pursuant to the Trust Agreement among the Operator, the Trustee and the Delaware Trustee. The Royalty Interests are passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. Neither the Operator nor other operators of the Underlying Properties have any contractual commitments to the Trust to provide additional funding for, to conduct further drilling on or to maintain their ownership interest in any of these properties.

The Trust Agreement provides that the Trust's business activities are generally limited to owning the Royalty Interests and any activities reasonably related thereto, including activities required or permitted by the terms of the conveyances related to the Royalty Interests. As a result, the Trust is not generally permitted to acquire other oil, natural gas and NGL properties or royalty interests. The Trust is not able to issue any additional Trust units.

Contractual Rights and Assets of the Trust. Contractual rights of the Trust include those contained in the development agreement and the Administrative Services Agreement. The assets of the Trust consist of the Royalty Interests and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the Trust unitholders.

Duties and Powers of the Trustee. The duties and powers of the Trustee are specified in the Trust Agreement and by the laws of the State of Delaware, except as modified by the Trust Agreement. The Trust Agreement provides that the Trustee shall not have any duties or liabilities, including fiduciary duties, except as expressly set forth in the Trust Agreement and the duties and liabilities of the Trustee as set forth in the Trust Agreement replace any other duties and liabilities, including fiduciary duties, to which the Trustee might otherwise be subject.

The Trustee's principal duties consist of:

•collecting cash proceeds attributable to the Royalty Interests;

•paying expenses, charges and obligations of the Trust from the Trust's assets;

•making cash distributions to the unitholders and the Operator (with respect to incentive distributions) in accordance with the Trust Agreement;

•causing to be prepared and distributed a Schedule K-1 for each Trust unitholder and preparing and filing tax returns on behalf of the Trust; and

•causing to be prepared and filed reports required to be filed under the Exchange Act, and by the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading.

The Administrative Servicer will provide administrative and other services to the Trust in fulfillment of certain of the foregoing duties pursuant to the Administrative Services Agreement.

The Trustee may create a cash reserve to pay for future expenses of the Trust. If the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust's expenses, the Trustee may cause the Trust to borrow funds required to pay the expenses. The Trust may borrow the funds from any person, including the Trustee or its affiliates or, as described below, the Operator. The terms of such indebtedness, if funds were loaned by the entity serving as Trustee or Delaware Trustee, must be similar to the terms which such entity would grant to a similarly situated, unaffiliated commercial customer, and such entity shall be entitled to enforce its rights with respect to any such indebtedness as if it were not then serving as Trustee or Delaware Trustee. If the Trust borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid (except in certain circumstances where the Trust borrows funds from the Operator).

Each quarter, the Trustee will pay Trust obligations and expenses and distribute to the Trust unitholders the remaining proceeds received from the Royalty Interests. The cash held by the Trustee as a reserve against future liabilities must be invested in:

•interest-bearing obligations of the U.S. government;

•money market funds that invest only in U.S. government securities;

•repurchase agreements secured by interest-bearing obligations of the U.S. government; or

•bank certificates of deposit.

Alternatively, cash held for distribution at the next distribution date may be held in a non-interest bearing account.

The Trustee withheld approximately $1.0 million from the first distribution to establish an initial cash reserve available for Trust expenses. If the Trustee uses its cash reserve (or any portion thereof) to pay or reimburse Trust liabilities or expenses, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until the cash reserve is replenished. Additional cash reserves may also be established from time to time as determined by the Trustee to pay for future expenses of the Trust. This cash reserve will be part of the Trust estate and will bear interest at the same rate as other cash on hand in the Trust estate. Upon the dissolution of the Trust, after payment of Trust liabilities, the balance of the cash reserve (including accrued interest thereon) will be distributed to Trust unitholders on a pro rata basis.

also be established from time to time as determined by the Trustee to pay for future expenses of the Trust. This cash reserve will be part of the Trust estate and will bear interest at the same rate as other cash on hand in the Trust estate. Upon the dissolution of the Trust, after payment of Trust liabilities, the balance of the cash reserve (including accrued interest thereon) will be distributed to Trust unitholders on a pro rata basis.

The Trust may not acquire any asset except the Royalty Interests, the other assets described above under Contractual Rights and Assets of the Trust and cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.

The Trust Agreement provides that the Trustee will not make business decisions affecting the assets of the Trust. However, the Trustee may:

•prosecute or defend, and settle, claims of or against the Trust or its agents;

•retain professionals and other third parties to provide services to the Trust;

•charge for its services as Trustee;

•retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law);

•lend funds at commercial rates to the Trust to pay the Trust's expenses; and

•seek reimbursement from the Trust for its out-of-pocket expenses.

In discharging its duty to Trust unitholders, the Trustee may act in its discretion and will be liable to the Trust unitholders only for willful misconduct, bad faith or gross negligence, and certain taxes, fees and other charges based on fees, commissions or compensation received by the Trustee in connection with the transactions contemplated by the Trust Agreement. The Trustee is not liable for any act or omission of its agents or employees unless the Trustee acts with willful misconduct, bad faith or gross negligence in its selection and retention. The Trustee will be indemnified individually or as the Trustee for any liability or cost that it incurs in the administration of the Trust, except in cases of willful misconduct, bad faith or gross negligence. The Trustee has a lien on the assets of the Trust as security for this indemnification and its compensation earned as Trustee. Trust unitholders are not liable to the Trustee for any indemnification. The Trustee is obligated to ensure that all contractual liabilities of the Trust are limited to the assets of the Trust.

The Trust may merge or consolidate with or into, or convert into, one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the Trustee and approved by the vote of the holders of a majority of the Trust units and a majority of the common units (excluding common units owned by Diversified and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law. At any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, however, the standard for approval will be the vote of a majority of the Trust units, including units owned by Diversified voting in person or by proxy at a meeting of such holders at which a quorum is present. Notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.

the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.

Trustee's Power to Sell Trust Assets. The Trustee may sell Trust assets, including the Royalty Interests, under any of the following circumstances:

•the sale is requested by Diversified, in accordance with the provisions of the Trust Agreement; or

•the sale is approved by the vote of holders representing a majority of the Trust units and a majority of the common units (excluding common units owned by Diversified and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Diversified voting in person or by proxy at a meeting of such holders at which a quorum is present. Notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.

vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units.

Upon dissolution of the Trust, the Trustee must sell the remaining Royalty Interests. No Trust unitholder approval is required in this event.

The Trustee will distribute the net proceeds from any sale of the Royalty Interests and other assets to the Trust unitholders after payment or reasonable provision for payment of the liabilities of the Trust.

Dispute Resolution. To the fullest extent permitted by law, any dispute, controversy or claim that may arise between the Operator and the Trustee relating to the Trust will be submitted to binding arbitration before a panel of three arbitrators.

Trust Fees and Expenses. It is expected that the Trust will only incur liabilities for routine administrative expenses, such as legal, accounting, audit, tax advisory, engineering, printing and other administrative and out-of-pocket fees and expenses incurred by or at the direction of the Trustee or the Delaware Trustee, including tax return and Schedule K-1 preparation and mailing costs; independent auditor fees; and registrar and transfer agent fees. The Trust is also responsible for paying costs associated with annual and quarterly reports to unitholders. Moreover, the Trustee's and the Delaware Trustee's compensation, and the fee payable to the Administrative Servicer pursuant to the Administrative Services Agreement, are paid out of the Trust's assets.

The Operator's Obligation to Fund Trust Expenses in Certain Circumstances. The Operator has agreed that, if at any time the Trust's cash on hand (including available cash reserves) is not sufficient to pay the Trust's ordinary course expenses as they become due, the Operator will lend funds to the Trust necessary to pay such expenses. Any funds loaned by the Operator pursuant to this commitment will be limited to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services or the payment of other accrued current liabilities arising in the ordinary course of the Trust's business, and may not be used to satisfy Trust indebtedness for borrowed money. If the Operator lends funds pursuant to this commitment, unless the Operator agrees otherwise, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid. Any such loan will be on an unsecured basis. There were no loans outstanding as of December 31, ~~2022~~2023 or December 31, ~~2021~~2022.

Duration of the Trust; Sale of Royalty Interests. The Trust will dissolve and begin to liquidate on the Termination Date, or earlier upon the occurrence of certain events, and will soon thereafter wind up its affairs and terminate. At the Termination Date, the Term Royalties will revert automatically to the Operator. Following the Termination Date, the Perpetual Royalties will be sold by the Trust and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be distributed to the unitholders pro rata. The Operator will have a right of first refusal to purchase the Perpetual Royalties from the Trust following the Termination Date.

The Trust will not dissolve until the Termination Date, unless:

•the Trust sells all of the Royalty Interests;

•the aggregate quarterly cash distribution amounts for any four consecutive quarters is less than $1.0 million;

•the holders of a majority of the Trust units and a majority of the common units (excluding common units owned by Diversified and its affiliates) in each case voting in person or by proxy at a meeting of such holders at which a quorum is present vote in favor of dissolution; except that at any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be a majority of the Trust units, including units owned by Diversified, voting in person or by proxy at a meeting of such holders at which a quorum is present; notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units; or

•the Trust is judicially dissolved.

In the case of any of the foregoing, the Trustee would sell all of the Trust's assets, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities.

Federal Income Tax Considerations

The Trust's federal income tax reporting position is that it is classified as a partnership for federal and applicable state income tax purposes. This position relies on the opinion of Bracewell LLP, former counsel to the Operator and the Trust, rendered in connection with the initial public offering of the Trust units in 2011, in which counsel opined that at least 90% of the Trust's gross income is qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended. The Trust's federal income tax reporting positions are consistent with the Federal Income Tax Considerations section in the ~~prospectus~~Prospectus filed by the Trust with the SEC on November 14, 2011, in connection with the initial public offering of its common units (the “Federal Income Tax Considerations Section in the Prospectus”). However, as discussed in detail below under Item 1A. Risk Factors – Tax Risks Related to the Units, the Trust has not requested a ruling from the IRS regarding its U.S. federal income tax reporting positions and its positions may not be sustained by a court or if contested by the IRS.

Additional information regarding the opinion and material tax matters is discussed in the Federal Income Tax Considerations Section in the Prospectus.

Competition and Markets

The oil and natural gas industry is highly competitive. The Operator competes with both major integrated and other independent oil and natural gas companies in all aspects of its business to explore, develop and operate its properties and market its production. Some of the Operator's competitors may have larger financial and other resources than the Operator. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of the Operator's competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities, and overall economic conditions. The Operator also faces indirect competition from alternative energy sources, including wind, solar and electric power. The Operator believes that its technological expertise, combined with its exploration, land, drilling and production capabilities and the experience of its management team enable it to compete effectively.

Recent volatility in oil, natural gas and NGL prices has impacted, and will continue to directly impact, Trust distributions, estimates of reserves attributable to the Trust's interest, and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply and demand for oil, natural gas and NGL, neither the Trust nor the Operator can make reliable predictions of future supply and demand for oil, natural gas and NGL, future oil, natural gas and NGL prices or the effect of future oil, natural gas and NGL prices on the Trust.

Public Policy and Government Regulation

All of the Operator's operations are conducted onshore in the United States. The U.S. oil and natural gas industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. The Operator has advised the Trustee that the Operator actively monitors regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting our operations.

Public Policy and Government Regulation

Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations

The Operator's operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:

•reporting of workplace injuries and illnesses;

•industrial hygiene monitoring;

•worker protection and workplace safety;

•approval or permits to drill and to conduct operations;

•provision of financial assurances (such as bonds) covering drilling and well operations;

•calculation and disbursement of royalty payments and production taxes;

•seismic operations and data;

•hydraulic fracturing;

•location, drilling, cementing and casing of wells;

•well design and construction of pad and equipment;

•construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;

•method of completing wells and hydraulic fracturing;

•water withdrawal;

•well production and operations, including processing and gathering systems;

•emergency response, contingency plans and spill prevention plans;

•emissions and discharges permitting;

•climate change;

•use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

•surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;

•plugging and abandoning of wells; and

•transportation of production.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines or penalties or injunctions limiting the Operator's operations in affected areas. Moreover, multiple environmental laws provide for citizen suits that allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. The Operator considers the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of its business. The Operator has been able to plan for and comply with environmental, safety and health initiatives without materially altering its operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, the Operator's capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and may continue to increase. The Operator cannot predict with any reasonable degree of certainty its future exposure concerning such matters.

The Operator's operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas the Operator can produce from its wells and the number of wells or the locations at which it can drill. For further discussion, see Item 1A. Risk Factors - The Operator is subject to extensive governmental regulation, which can

~~change~~environment and ~~could~~safety ~~adversely~~and ~~impact~~health compliance have increased over the years and may continue to increase. The Operator's ~~business~~cannot predict with any reasonable degree of certainty its future exposure concerning such matters.

Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it prohibitive to conduct operations, and also reduce the amount of oil, natural gas and NGL that the Operator is ultimately able to produce in commercial quantities from its properties.

Certain of the Operator's U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays.

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit the Operator's ability to execute its drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of the Operator's permits, inability to obtain new permits and the imposition of fines and penalties. For further discussion, see Item 1A. Risk Factors - Oil and natural gas drilling and producing operations can be hazardous and may expose the Operator to liabilities.

Human Capital

The Trust does not have any employees, directors, or executive officers.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, the Operator could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. The Operator's horizontal operations involve greater risk of mechanical problems than vertical wells.

As a passive entity, the Trust does not maintain insurance policies for the Underlying Properties. The Operator maintains a control of well insurance policy with a $3 million limit on producing wells with a true vertical depth of less than or equal to 5,000 feet, a $20 million limit on producing wells with a true vertical depth of more than 5,000 feet, and a $20 million to $30 million limit on drilling, workover, and re-entry activities depending on the level of the authorization for expenditure that insure against certain sudden and accidental risks associated with drilling, completing, and operating its wells. There is no assurance that this insurance will be adequate to cover all losses or exposure to liability. The Operator also carries in excess of $20 million in commercial general liability and/or umbrella insurance that is inclusive of sudden and accidental pollution liability. The Operator provides workers’ compensation insurance coverage to employees in all states in which it operates. While the Operator has informed us that it believes these policies are customary in the industry, they do not provide complete coverage against all operating risks and policy limits scale to the Operator's working interest percentage in certain situations. In addition, the Operator's insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect to the Operator's financial position, results of operations and cash flows. The Operator’s insurance coverage may not be sufficient to cover every claim made against the Operator or may not be commercially available for purchase in the future.

The Underlying Properties and the Royalty Interests

Overview. The Underlying Properties consist of working interests owned by the Operator located in the Colony Granite Wash play in Washita County in western Oklahoma arising from leases and farmout agreements related to properties from which the Royalty Interests were conveyed. The AMI consists of approximately 40,500 gross acres (26,400 net acres). As of December 31, 2022 and 2021, the total reserves estimated to be attributable to the Trust were 3,846 mboe (57% natural gas by volume) and 3,867 mboe (55% natural gas by volume), respectively. These amounts include 3,846 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2022 and 3,867 mboe of proved developed reserves and no proved undeveloped reserves as of

~~December 31,~~us ~~2021.~~that ~~The~~it ~~decrease~~believes inthese ~~estimated~~policies ~~total~~are ~~reserves~~customary ~~attributable~~in to the ~~Trust~~industry, ofthey 21do ~~mboe~~not isprovide ~~primarily~~complete ~~attributable~~coverage toagainst ~~2022~~all ~~production~~operating ~~offset~~risks byand ~~the~~policy ~~economic~~limits ~~well~~scale ~~life~~to ~~increasing~~the asOperator's aworking ~~result~~interest ofpercentage ~~the increase~~ in ~~commodity~~certain ~~pricing~~situations. In ~~See~~addition, ~~Item~~the ~~1A.~~Operator's ~~Risk~~insurance ~~Factors~~does –not ~~Actual~~cover ~~reserves~~penalties ~~and~~or ~~future~~fines ~~production~~that may be ~~less~~assessed ~~than current estimates, which could reduce cash distributions~~ by ~~the~~a ~~Trust~~governmental ~~and~~authority. ~~the~~A ~~value~~loss ofnot ~~the~~fully ~~Trust~~covered ~~units~~by ~~and~~insurance ~~Risks~~could ~~and~~have ~~Uncertainties~~a inmaterial ~~Note~~adverse 2effect to the Operator's financial ~~statements contained in Part II~~position, ~~Item~~results 8 of ~~this~~operations ~~Annual~~and ~~Report~~cash ~~for further discussion of the decrease in reserves~~flows. ~~For~~The ~~clarity,~~Operator’s ~~the~~insurance ~~Trust~~coverage ~~does~~may not ~~own~~be orsufficient ~~have~~to ~~rights~~cover toevery ~~undeveloped~~claim ~~lands,~~made ~~undeveloped~~against ~~formations,~~the Operator or ~~undeveloped~~may ~~reserves,~~not ~~nor~~be ~~the~~commercially ~~right~~available orfor ~~ability~~purchase toin ~~drill~~the future ~~wells~~.

The ~~Colony~~Underlying ~~Granite~~Properties Wash is a subset of the greater granite wash plays of the Anadarko Basin. The Colony Granite Wash is located at the eastern end of a series of Des Moines-age granite wash fields that extend along the southern flank of the Anadarko Basin, approximately 60 miles into the Texas Panhandle. These granite wash fields were generally deposited as deep-water turbidites that result in relatively low risk, laterally extensive reservoirs. The productive members of the Colony Granite Wash are encountered between approximately 11,500 and ~~13,000 feet and lie stratigraphically between~~ the ~~top~~Royalty of the Des Moines formation (or top of Colony Granite Wash 'A') and the top of the Prue formation (or base of Colony Granite Wash 'C'). The individual productive members within the Colony Granite Wash may reach 200 feet or more in gross interval thickness and the targeted porosity zones within these individual members are generally 20 to 75 feet thick. The Colony Granite Wash is primarily a natural gas and natural gas condensate reservoir based on reserve volumes. However, in the Colony Granite Wash, oil and NGL production currently generate more revenue than natural gas production due to higher relative prices for oil and NGL than for natural gas. No development costs were incurred in the years ended December 31, 2022 and 2021 due to no new wells being drilled by the Operator in the Colony Granite Wash after fulfillment of its drilling obligation to the Trust.Interests

~~Royalty Interests~~Overview. The ~~Royalty~~Underlying ~~Interests~~Properties ~~were~~consist ~~conveyed~~of ~~from~~working ~~Chesapeake's~~interests ~~interest~~owned by the Operator located in the ~~Underlying~~Colony ~~Properties~~Granite ~~effective~~Wash asplay in Washita County in western Oklahoma arising from leases and farmout agreements related to properties from which the Royalty Interests were conveyed. The AMI consists of ~~July~~approximately 140,500 ~~2011~~gross acres (26,400 net acres). As of December 31, 2023 and 2022, the total reserves estimated to be attributable to the Trust onwere ~~average~~3,593 ~~owns~~mboe a(60% ~~47.8~~natural gas by volume) and 3,846 mboe (57% ~~net~~natural ~~revenue~~gas ~~interest~~by involume), ~~the~~respectively. ~~Producing~~These ~~Wells~~amounts include 3,593 mboe of proved developed reserves and ano ~~28.6%~~proved ~~net~~undeveloped ~~revenue~~reserves ~~interest~~as inof ~~the~~December 31, ~~completed~~2023 ~~Development~~and ~~Wells~~3,846 mboe of proved developed reserves and no proved undeveloped reserves as of December 31, 2022. The ~~Operator~~decrease ~~retains~~in ~~10%~~estimated oftotal ~~the~~reserves ~~proceeds~~attributable ~~from~~to the ~~sales~~Trust of ~~oil,~~253 ~~natural~~mboe ~~gas~~is primarily due to 2023 production and ~~NGL~~decreases in commodity pricing. See Item 1A. Risk Factors – Actual reserves and future production ~~attributable~~may tobe ~~its~~less ~~net~~than ~~revenue~~current ~~interest~~estimates, which could reduce cash distributions by the Trust and the value of the Trust units and Risks and Uncertainties in Note 2 to the ~~Producing~~financial ~~Wells~~statements contained in Part II, ~~and~~Item ~~50%~~8 of this Annual Report for further discussion of the ~~proceeds~~decrease ~~from~~in reserves. For clarity, the ~~sales~~Trust ofdoes ~~production~~not ~~attributable~~own or have rights to ~~its~~undeveloped ~~net~~lands, ~~revenue~~undeveloped ~~interest~~formations, inor undeveloped reserves, nor the ~~Development~~right ~~Wells.~~or ability to drill future wells.

The Colony Granite Wash is a subset of the greater granite wash plays of the Anadarko Basin. The Colony Granite Wash is located at the eastern end of a series of Des Moines-age granite wash fields that extend along the southern flank of the Anadarko Basin, approximately 60 miles into the Texas Panhandle. These granite wash fields were generally deposited as deep-water turbidites that result in relatively low risk, laterally extensive reservoirs. The productive members of the Colony Granite Wash are encountered between approximately 11,500 and 13,000 feet and lie stratigraphically between the top of the Des Moines formation (or top of Colony Granite Wash 'A') and the top of the Prue formation (or base of Colony Granite Wash 'C'). The individual productive members within the Colony Granite Wash may reach 200 feet or more in gross interval thickness and the targeted porosity zones within these individual members are generally 20 to 75 feet thick. The Colony Granite Wash is primarily a natural gas and natural gas condensate reservoir based on reserve volumes. No development costs were incurred in the years ended December 31, 2023 and 2022 due to no new wells being drilled by the Operator in the Colony Granite Wash after fulfillment of its drilling obligation to the Trust.

Royalty Interests. The Royalty Interests were conveyed from Chesapeake's interest in the Underlying Properties effective as of July 1, 2011. As of December 31, 2023, the Trust on average owns a 47.8% net revenue interest in the Producing Wells and a 28.6% net revenue interest in the completed Development Wells. The Operator retains 10% of the proceeds from the sales of oil, natural gas and NGL production attributable to its net revenue interest in the Producing Wells, and 50% of the proceeds from the sales of production attributable to its net revenue interest in the Development Wells.

The Royalty Interests were conveyed to the Trust by Chesapeake by means of conveyance instruments that were recorded in the appropriate real property records in Washita County, Oklahoma. The conveyance instruments obligate the Operator to act diligently and as a reasonably prudent oil and gas operator would act under the same or similar circumstances as if it were acting with respect to its own properties, disregarding the existence of the Royalty Interests as burdens affecting such properties. We refer to this standard as the "Reasonably Prudent Operator Standard." The Trustee has no ability to manage or influence the operation of the Underlying Properties.

Oil, Natural Gas and NGL Reserves. Proved reserve quantities attributable to the Royalty Interests are calculated by multiplying the gross reserves for each property attributable to the Operator's interest by the net revenue interest assigned to the Trust in each property. The reserves related to the Underlying Properties include all proved reserves expected to be economically produced during the life of the properties. The reserves attributable to the Trust's interests include only the reserves attributable to the Underlying Properties that are expected to be produced within the 20-year period prior to the Termination Date as well as the residual 50% interest in the Royalty Interests that the Trust will own on the Termination Date and subsequently sell.

All of the Trust's estimated oil, natural gas and NGL reserves are located within the U.S. The table below sets forth information as of December 31, ~~2022~~2023 with respect to the estimated proved reserves of the Underlying Properties and Royalty Interests and the associated PV-10. Because the Trust will not bear income tax expense, PV-10 and the standardized measure of estimated future net revenue of the Royalty Interests are the same. PV-10 is not intended to represent the current market value of the estimated oil, natural gas and NGL reserves attributable to the Royalty Interests. The reserve estimates were prepared by third party engineering firm, Netherland, Sewell & Associates, Inc., in accordance with the criteria established by the SEC. Management uses PV-10, a non-GAAP measure, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.

Proved Reserves

Oil(mbbl)

Natural Gas(mmcf)

NGL(mbbl)

Total(mboe)

PV-10 ($ in thousands)

Underlying Properties:

Developed

~~461~~418

1612,~~669~~882

~~1,635~~989

43,~~874~~553

8317,~~043~~345

Undeveloped

—

Total

~~461~~418

1612,~~669~~882

~~1,635~~989

43,~~874~~553

8317,~~043~~345

Royalty Interests:

Developed(1)

~~367~~419

13,~~165~~035

1,~~285~~001

3,~~846~~593

6635,~~648~~081

Undeveloped(1)

—

Total

~~367~~419

13,~~165~~035

1,~~285~~001

3,~~846~~593

6635,~~648~~081

_________________________________________________

(1)PV-10 for the Royalty Interests was calculated exclusive of any production or development costs.

Proved Developed

Proved Undeveloped

Total Proved

($ in thousands)

Royalty Interests:

Estimated future net revenue (1)

~~125~~71,~~909~~120

—

~~125~~71,~~909~~120

Present value of estimated future net revenue (PV-10)(1)

6635,~~648~~081

—

6635,~~648~~081

Standardized measure(1)

6635,~~648~~081

_________________________________________________

(1)Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and costs, using prices and costs under existing economic conditions as of December 31, ~~2022~~2023. PV-10 is the present value of estimated future net revenue to be generated from the production of proved reserves, discounted at 10% per annum to reflect timing of future cash flows and calculated without deducting future income taxes. PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted net cash flows, or the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, as the Trust is not subject to income tax expense, the two measures are the same as of December 31, ~~2022~~2023.

A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of the proved oil and gas reserves.

The proved reserves were determined using a 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas and NGL for the period from January 1, ~~2022~~2023 through December 1 31, ~~2022~~2023, and were held constant for the life of the properties. The prices used in the reserve reports, as well as the Operator's internal reports, yield weighted average prices at the wellhead, which are based on first-day-of-the-month reference prices and before basis differential adjustments. For the Royalty Interests, costs of marketing services provided by the Operator's affiliates will not be charged to the Trust. The reference prices and the equivalent weighted average wellhead prices are presented in the table below.

	Oil		Natural Gas
	(per bbl)		(per mcf)
Trailing 12-month average (SEC) pricing	$	9478.1421	$	62.3664
Weighted average wellhead prices (Underlying Properties)	$	9674.6357	$	51.3468
Weighted average wellhead prices (Royalty Interests)	$	9274.2557	$	41.4568

As of December 31, ~~2022~~2023, no Royalty Interests or proved reserves attributable to the Underlying Properties were classified as PUDs.

As of December 31, ~~2022~~2023, of the total proved reserves, 43,~~874~~553 mboe and 3,~~846~~593 mboe attributable to the Underlying Properties and the Royalty Interests, respectively, were classified as proved developed reserves.

The Operator's ownership interest used for calculating proved reserves and the associated estimated future net revenue assumed maximum participation by other parties to the Operator's farmout and participation agreements. SEC pricing used for calculating the estimated future net revenues attributable to proved reserves does not reflect actual market prices for oil, natural gas and NGL production sold subsequent to December 31, ~~2022~~2023.

The Trust's estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021, respectively, along with the changes in quantities and standardized measure of such reserves for the three years ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021, respectively, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this Annual Report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Operator's control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions to such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures about Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this ~~report~~Annual Report for further discussion of our reserve quantities.

Development Wells. Pursuant to the development agreement with the Trust, the Operator was obligated to drill, cause to be drilled or participate as a non-operator in the drilling of 118 Development Wells by June 30, 2016. The Operator had fulfilled its drilling obligation under the development agreement as of June 30, 2016. The Operator retained an interest in each of the Producing Wells and Development Wells and Diversified currently operates approximately 96% of the Producing Wells and the completed Development Wells. Prior to fulfilling its commitment to drill the Development Wells, the Operator was not allowed to drill or complete, or permit any other person within ~~its control to drill or complete any well in the Colony Granite Wash formation or lease acreage included within the~~

its control to drill or complete any well in the Colony Granite Wash formation or lease acreage included within the AMI for its own account. For the life of the Trust, the Operator will not be permitted to drill or complete any well that will have a perforated segment within 600 feet of any perforated interval of any Development Well or Producing Well. The Operator's average net revenue interest in the oil and gas properties underlying the Development Royalty Interest is approximately 60%. The Development Royalty Interest entitles the Trust to receive 50% of the proceeds attributable to the Operator's net revenue interest in future production of oil, natural gas and NGL from the Development Wells.

The Trust was not responsible for any costs related to the drilling of the Development Wells and is not responsible for any other operating or capital costs of the Underlying Properties.

Due to the Operator's completion of its drilling obligation under the development agreement, it may now sell all or any part of its retained interest in the Underlying Properties, without the consent or approval of the Trust unitholders. In any such sale by the Operator, the Underlying Properties must be sold subject to and burdened by the Royalty Interests, except that the Operator may require the Trust to release the Royalty Interests on such Underlying Properties with an aggregate value of up to $5.0 million during any 12-month period. In such event, the Trust must receive an amount equal to the fair value to the Trust of any ~~royalty~~Royalty ~~interests~~Interests it sells.

Drilling Activity. Due to the Operator's completion of its drilling obligation under the development agreement as of June 30, 2016, the Operator did not drill any wells in ~~2022~~2023, ~~2021~~2022 or ~~2020~~2021 and has no obligation to do so in the future.

Developed and Undeveloped Acreage. The following table sets forth information regarding developed and undeveloped acreage held by the Operator within the AMI as of December 31, ~~2022~~2023. All of the leases associated with the Underlying Properties are held by production and not subject to expiration so long as production continues in paying quantities.

Developed

Acreage(1)

Undeveloped
Acreage

Gross

Net

Gross

Net

Acreage Held by the Operator within the AMI

40,236

26,195

—

_________________________________________________

(1)Gross and net developed acres are acres spaced or assignable to productive wells. The drilling unit for each Colony Granite Wash horizontal well comprises 640 acres. As such, developed acreage may include up to 640 acres assigned to each Colony Granite Wash horizontal well.

Marketing and Post-Production Services. Pursuant to the terms of the conveyances creating the Royalty Interests, the Operator has the responsibility to market, or cause to be marketed, the oil, natural gas and NGL production related to the Underlying Properties. Marketing costs are deducted from the proceeds upon which the royalty payments are calculated.

Post-production expenses are also deducted from proceeds paid to the Trust. Williams Partners, L.P. ("WMB"), provides gathering, treating, compression and other post-production services, and an affiliate of Energy Transfer LP ("Energy Transfer") provides gathering, processing, transportation and other post-production services. The proceeds paid to the Trust are reduced by deductions for these post-production expenses.

Post-production expenses may be deducted by the ultimate purchaser of the oil, natural gas and NGL prior to payment being made to the Operator for such production. At other times, the Operator makes payments directly to the applicable provider of such post-production services. In either instance, the Trust's cash available for distribution is reduced by the expenses incurred for such post-production services. If the post-production expenses are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the Royalty Interest are reduced accordingly.

The post-production expenses are negotiated based on market conditions at the time or pursuant to a state or federal regulatory proceeding. The Operator is permitted to deduct from the proceeds available to the Trust other post-production expenses necessary to enhance the value of the oil, natural gas and NGL from the Underlying Properties and to transport such production to market.

Natural gas and NGL produced from the Underlying Properties are gathered by gathering pipelines owned by WMB under a contract that expires in approximately 65 years. NGL and natural gas are gathered and processed at facilities owned by Energy Transfer under a contract that ~~expires~~is inmonth-to-month ~~2023~~ and then sold to a number of primary purchasers in the area. The contract with Energy Transfer requires a 30 day written notice for termination and can be assigned to any third party by mutual agreement. Oil produced from the Underlying Properties is gathered by gathering pipelines and equipment owned by WMB or transported by trucks owned by third parties and sold to various counterparties. In the event of a loss of its contracts with WMB or Energy Transfer, the Operator believes that the availability of other customers and service providers in the area is sufficient to accommodate such loss.

Any new oil, natural gas and NGL supply arrangements or those entered into for providing post-production services will be utilized in determining the proceeds for the Underlying Properties.

Discussion and Analysis of Results from the Underlying Properties

Historical Results. The Underlying Properties consist of the working interests owned by the Operator in the Colony Granite Wash play in Washita County in western Oklahoma arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the Development Royalty Interest were conveyed.

The following table provides revenues and direct operating expenses for the years ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021 as derived from the Underlying Properties' statements of revenues and direct operating expenses.

	Years Ended December 31,
	2022		2021		2020
	2023		2022		2021
	($ in thousands)
Oil, natural gas and NGL revenues(1)	$	1811,~~349~~240	$	2018,~~718~~349	$	420,~~821~~718
Direct operating expenses:
Production expenses excluding taxes	23,~~732~~419		42,~~459~~732		4,~~690~~459
Production taxes	~~1,395~~780		1,~~525~~395		~~316~~1,525
Ad valorem taxes	—		—		8
Total direct operating expenses	4,199		4,127		5,984
Total direct operating expenses	4,127		5,984		5,014
Revenues in excess of direct operating expenses	$	7,041	$	14,222	$	14,734
Revenues in excess (deficit) of direct operating expenses(2)	$	14,222	$	14,734	$	(193)

_________________________________________________

(1)Oil, natural gas and NGL revenues are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.

(2)Net deficit in 2020 is attributable to significant decreases in commodity prices throughout 2020.

The following table sets forth the production, average sales prices, and average cost per boe for production expenses and production taxes for the Underlying Properties for the years ended December 31, ~~2022~~2023, ~~2021~~2022 and ~~2020~~2021.

	Years Ended December 31,
	2022		2021		2020
	2023		2022		2021
Production:
Oil (mbbls)	6968		9969		9299
Natural gas (mmcf)	1,~~588~~830		21,~~271~~588		2,~~700~~271
NGL (mbbls)	~~148~~151		~~286~~148		~~244~~286
Total production (mboe)	~~482~~525		~~764~~482		~~786~~764
Average sales prices:(1)
Oil (per bbl)	$	9674.6852	$	6496.7168	$	3264.8271
Natural gas (per mcf)(2)	$	6.62	$	3.12	$	(0.09)
Natural gas (per mcf)	$	2.62	$	6.62	$	3.12
NGL (per bbl)	$	4328.1644	$	2543.2916	$	825.4929
Average (per boe)	$	3821.0743	$	2738.1207	$	627.1312
Direct operating expenses:
Production expenses (per boe)	$	56.6752	$	5.8467	$	5.9784
Production taxes (per boe)(3)	$	2.90	$	2.00	$	0.40
Production taxes (per boe)(2)	$	1.49	$	2.90	$	2.00

___________________________________________________

(1)Average sales prices are net of post-production expenses, including gathering, storage, compression, transportation, processing, treating, dehydrating and non-affiliate marketing expenses.

(2)~~Negative~~Production ~~sales~~taxes ~~price~~are ~~for~~generally ~~natural~~based ~~gas~~upon involume ~~2020~~produced isand ~~a result of gross sales~~ prices ~~being~~received ~~less~~for ~~than post-~~production ~~expenses~~and ~~needed~~include toad ~~produce~~valorem ~~natural gas~~taxes.

( Oil, Natural Gas and NGL Revenues. For the year ended December 31, 2023, oil, natural gas and NGL revenues were $11.2 million compared to $18.3~~)Production~~ ~~taxes~~million ~~are~~and ~~generally~~$20.7 ~~based~~million ~~upon~~for ~~volume~~the ~~produced~~years ended 2022 and 2021, respectively. The $7.1 million decrease in revenues from 2022 to 2023 was due to a decrease in average sales prices received ~~for~~offset by an increase in production from Diversified's acquisition of additional working interests in certain of the Underlying Properties in October 2022, which did not affect the corresponding revenue attributable to the Trust. The overall decrease in the price received per boe in 2023 compared to 2022 resulted in a $8.7 million decrease in oil, natural gas and ~~include~~NGL adrevenues. ~~valorem~~Increased ~~taxes~~sales volumes resulted in a $1.6 million increase in oil, natural gas and NGL revenues. The Participation Agreement was effective throughout 2023, and did not affect the corresponding revenue attributable to the Trust.

Oil, Natural Gas and NGL Revenues. For the year ended December 31, 2022, oil, natural gas and NGL revenues were $18.3 million compared to $20.7 million and $4.8 million for the years ended 2021 and 2020, respectively. The $2.4 million decrease in revenues from 2021 to 2022 was due to a decrease in production offset by an increase in average sales prices received. The overall increase in the price received per boe in 2022 compared to 2021 resulted in a $5.3 million increase in oil, natural gas and NGL revenues. Decreased sales volumes in 2022 resulted in a $7.7 million decrease in oil, natural gas and NGL revenues. This decrease iswas a result of ~~Oaktree Capital Partners, L.P. ("Oaktree") participating in~~ the ~~Underlying~~Participation ~~Properties~~Agreement, which did not affect the corresponding revenue attributable to the Trust.

~~The~~Production ~~$15~~Expenses.9 ~~million~~For ~~increase~~the inyear ~~revenues~~ended ~~from~~December 31, ~~2020~~2023, toproduction ~~2021~~expenses ~~was~~were ~~due~~$3.4 million compared to an$2.7 ~~increase~~million inand ~~average~~$4.5 ~~sales~~million ~~prices~~for ~~received,~~the ~~offset~~years byended a2022 ~~decrease~~and in2021, ~~production~~respectively. ~~The~~On ~~overall~~a ~~increase~~unit-of-production inbasis, ~~the~~production ~~price~~expenses ~~received~~were $6.52 per boe in ~~2021~~2023 compared to ~~2020 resulted in a~~ $165.067 ~~million~~per ~~increase~~boe in ~~oil,~~2022 ~~natural gas~~ and ~~NGL revenues. Decreased sales volumes resulted in a~~ $05.184 ~~million~~per ~~decrease~~boe in ~~oil, natural gas and NGL revenues~~2021.

Production ~~Expenses~~Taxes. For the year ended December 31, ~~2022~~2023, production ~~expenses~~taxes were $20.78 million, compared to $41.54 million and $41.75 million for the years ended ~~2021~~2022 and ~~2020~~2021, respectively. On a unit-of-production basis, production ~~expenses~~taxes were $51.6749 per boe in ~~2022~~2023 compared to $52.8490 per boe in ~~2021~~2022 and $52.9700 per boe in ~~2020~~2021. The decrease in per unit-of-production taxes from 2022 to 2023 was primarily due to the decrease in commodity prices. The increase in per unit-of-production taxes from 2021 to 2022 was primarily due to the increase in commodity prices.

Production Taxes. For the year ended December 31, 2022, production taxes were $1.4 million, compared to $1.5 million and $0.3 million for the years ended 2021 and 2020, respectively. On a unit-of-production basis, production taxes were $2.90 per boe in 2022 compared to $2.00 per boe in 2021 and $0.40 per boe in 2020. The increase in per unit-of-production taxes from 2021 to 2022 was primarily due to the increase in commodity prices.

The increase in per unit-of-production taxes from 2020 to 2021 was primarily due to the increase in commodity prices.

The Reserve Report for the Underlying Properties and the Royalty Interests

The oil, natural gas and NGL reserves in this Annual Report were estimated by Netherland, Sewell & Associates, Inc. ("NSAI"). The process to review and estimate the reserves begins with Diversified's Corporate Reserves Department collecting and verifying all pertinent data, including but not limited to well test data, production data, historical pricing, cost information, property ownership interests, reservoir data, and geosciences data. This data is reviewed by various levels of Diversified management for accuracy before consultation with NSAI. NSAI was consulted with regularity during the reserve estimation process to review properties, assumptions, and any new data available. Internal reserve estimates and methodologies are compared to NSAI's estimates and methodologies to test the reserve estimates and conclusions before the reserve estimates are included in this Annual Report. Additionally, Diversified's senior management reviews and approves the reserve report contained herein.

Internal Controls. Diversified's Vice President of Engineering, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. His qualifications include the following:

•over 2425 years of practical experience in the oil and gas industry, with over 20 years in reservoir engineering;

•Bachelor of Science degree in Petroleum Engineering; and

•member in good standing of the Society of Petroleum Engineers.

Diversified ensures that the key members of Diversified's Reservoir Engineering Department have appropriate technical qualifications to oversee the preparation of reserves estimates. Each of Diversified's Corporate Reserves Engineers has significant experience in reserve estimation.

Diversified maintains internal controls such as the following to ensure the reliability of reserves estimations:

•Diversified follows comprehensive SEC-compliant internal policies to estimate and report proved reserves for the Trust. Reserves estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Diversified's Vice President of Engineering.

•Diversified's Reservoir Engineering Department reviews all of Diversified's reserves bi-annually and the Trust's proved reserves at the close of each quarter.

Technologies. The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells, as defined by the SEC. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field. The continuity of the play across the AMI area was established by reviewing electronic well logs from wells, geologically mapping the analogous reservoir and reviewing extensive production data from horizontal wells within the larger Colony Granite Wash area.

Netherland, Sewell & Associates, Inc. Diversified engaged Netherland, Sewell & Associates, Inc., a third-party engineering firm, to prepare all of the Trust's estimated proved reserves as of December 31, ~~2022~~2023. A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical person at the firm primarily responsible for overseeing the preparation of our reserve estimates are set forth below.

•over 30 years of practical experience in the estimation and evaluation of reserves;

•licensed professional engineer in the State of Texas; and

•Bachelor of Science in Mechanical Engineering, Bachelor of Science in Geology and Master of Science in Geology.

Miscellaneous

The Trustee may consult with counsel (which may include counsel to the Operator), accountants, tax advisors, geologists and engineers and other parties the Trustee believes to be qualified as experts on the matters for which advice is sought. The Trustee is protected for any action it takes in good faith reliance upon the opinion of the expert.

advice is sought. The Trustee is protected for any action it takes in good faith reliance upon the opinion of the expert.

The Delaware Trustee and the Trustee may resign at any time or be removed with or without cause at any time by the vote of a majority of the outstanding Trust units (excluding common units owned by Diversified and its affiliates) voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Diversified and its affiliates collectively own less than 10% of the outstanding Trust units, the standard for approval will be the vote of a majority of the Trust units, including units owned by Diversified, voting in person or by proxy at a meeting of such holders at which a quorum is present. Notwithstanding the foregoing, there are conflicting interpretations that the Trust Agreement requires the exclusion of the common units owned by Diversified and its affiliates in a vote following Tapstone's acquisition of the Underlying Properties from Chesapeake even if Diversified and its affiliates own over 10% of the outstanding Trust units. Abstentions and broker non-votes shall not be deemed to be votes cast. Any successor must be a bank or trust company meeting certain requirements, including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware Trustee, and $100 million, in the case of the Trustee.

ITEM 1A. Risk Factors

~~Summary~~Geopolitical ofEvents ~~Risk~~May ~~Factors~~Adversely Impact the Trust's Business, Cash Flows, Liquidity, or Financial Condition

~~Our~~We ~~business~~are ~~involves~~actively ~~certain~~monitoring ~~risks~~the military conflicts in Ukraine and ~~uncertainties.~~in ~~The~~Israel ~~following~~and issurrounding acountries, ~~description~~and ofassessing ~~significant~~their ~~risks~~impact ~~that~~on ~~might~~the ~~cause~~Trust’s ~~our~~business. ~~future~~To ~~financial~~date, ~~condition~~we orhave ~~results~~not ofexperienced ~~operations~~any material interruptions to ~~differ~~our ~~materially~~business ~~from~~given ~~those~~that ~~expected~~the Underlying Properties are exclusively located within the United States. InThe ~~addition~~extent toand duration of the ~~risks~~military action, sanctions and ~~uncertainties~~resulting ~~described~~market ~~below~~disruptions could be significant, weincluding ~~may~~significant ~~face~~volatility ~~other~~in ~~risks~~commodity prices, supply of energy resources, instability in financial markets, including inflation, supply chain interruptions, political and ~~uncertainties~~social instability, ~~some~~changes in consumer or purchaser preferences as well as increases in cyberattacks and espionage, each of which ~~may~~could behave ~~unknown~~a tosubstantial usimpact on the global economy and ~~some~~consequently our business for an unknown period of ~~which~~time. We currently do not expect any material impact on the Trust’s business, cash flows, liquidity or financial condition; however, we ~~may~~have ~~deem~~no ~~immaterial.~~way Ato ~~summary~~predict the progress or outcome of ~~our~~the ~~risk~~military ~~factors~~conflict isin Ukraine and Israel as ~~follows:~~the conflict, and any resulting government reactions, are rapidly developing and beyond our control.

•Producing oil, natural gas and NGL on the Underlying Properties is a high-risk activity with many uncertainties.

•Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on proceeds to the Trust and cash distributions to unitholders.

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