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Item 2. Properties

2024-02-29 compared with 2023-03-01 · 434 added, 419 removed, 128 unchanged (87% of the section changed)

The net overriding royalties conveyed to the Trust (the Royalties) include:

(1) a 75% net overriding royalty carved out of Southland

Royaltys fee mineral interests in the Waddell Ranch in Crane County, Texas (the Waddell Ranch properties);

and (2) a 95% net overriding royalty carved out of Southland Royaltys major producing royalty interests in Texas

(the Texas Royalty properties).

(1) a 75% net overriding royalty carved out of

Southland Royaltys fee mineral interests in the Waddell Ranch in Crane County, Texas (the Waddell Ranch properties);

and (2) a 95% net overriding royalty carved out of Southland Royaltys major producing royalty interests

in Texas (the Texas Royalty properties).

The interests out of which the Trusts net overriding royalty interests were carved were in all cases less than 100%.

The Trusts net overriding royalty interests represent burdens against the

properties in favor of the Trust without regard to ownership of the properties from which the overriding royalty interests were carved.

The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease agreements

under which such royalties were created.

The Trusts net overriding royalty interests represent burdens

against the properties in favor of the Trust without regard to ownership of the properties from which the overriding royalty interests were carved.

The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease

agreements under which such royalties were created.

References below to net wells and acres are to the interests of the owner of the Underlying Properties (from which the Royalties were carved) in the gross wells and acres.

A production index for oil and gas properties is the number of years derived by dividing remaining reserves by current production.

The production index

for the Trust properties based on the reserve report prepared by independent petroleum engineers as of December 31, 2022, is approximately 15 years.

The following information under this Item 2 is based upon data and information, including audited computation statements, furnished to the Trustee by

Blackbeard, the owner of the Waddell Ranch properties and BROG, the former owner of the Waddell Ranch properties, and Riverhill Energy, the owner of the Texas Royalty properties.

production index for the Trust properties based on the reserve report prepared by independent petroleum engineers as of December 31, 2023, is approximately 15 years.

The following information under this Item 2 is based upon data and information, including audited computation statements, furnished to the

Trustee by Blackbeard, the owner of the Waddell Ranch properties, and Riverhill Energy, the owner of the Texas Royalty properties.

PRODUCING ACREAGE, WELLS AND DRILLING

Waddell Ranch Properties .

The net profits/overriding royalty interest in the Waddell Ranch properties is the largest asset

of the Trust.

The mineral interests in the Waddell Ranch, from which such net royalty interests are carved, vary from

37.5% (Trust net interest) to 50% (Trust net interest) in 78,715 gross (34,205 net) producing acres.

A majority of the proved reserves are attributable to six fields:

Dune, Sand Hills (Judkins),

Sand Hills (McKnight), Sand Hills (Tubb), University-Waddell (Devonian) and Waddell.

At December 31, 2022, the Waddell Ranch properties contained 918 (net) productive oil wells and 111 (net) productive gas wells.

As of April 1, 2020, Blackbeard Operating, LLC (Blackbeard) became operator of record of the Waddell Ranch properties.

technical and accounting operations have been contracted by agreements between the working interest owners and Schlumberger Integrated Project Management (IPM) and Riverhill Capital Corporation (Riverhill Capital), but remain

under the direction of Blackbeard, as of December 31, 2022.

Six major fields on the Waddell Ranch properties account for more than 80% of the

total production.

The net profits/overriding royalty interest in the Waddell Ranch properties is the largest asset of the

The mineral interests in the Waddell Ranch, from which such net royalty interests are carved, vary from 37.5% (Trust net interest) to 50% (Trust net interest) in 78,715 gross (34,205 net) producing acres.

A majority of the proved reserves are

attributable to six fields:

Dune, Sand Hills (Judkins), Sand Hills (McKnight), Sand Hills (Tubb), University-Waddell (Devonian) and Waddell.

At December 31, 2023, the Waddell Ranch properties contained 1,067 gross (499 net) productive oil wells

and 108 gross (51 net) productive gas wells.

As of April 1, 2020, Blackbeard Operating, LLC (Blackbeard) became operator

of record of the Waddell Ranch properties.

All field, technical and accounting operations have been contracted by agreements between the working interest owners and Schlumberger Integrated Project Management (IPM) and Riverhill Capital

Corporation (Riverhill Capital), but remain under the direction of Blackbeard, as of December 31, 2023.

Six major fields

on the Waddell Ranch properties account for more than 80% of the total production.

In the six fields, there are 12 producing zones ranging in depth from 2,800 to 10,600 feet.

Most prolific of these zones are the Grayburg and San Andres, which produce from depths between 2,800 and 3,400 feet.

Also productive from

the San Andres are the Sand Hills (Judkins) gas field and the Sand Hills (McKnight) oil field, the Dune (Grayburg/San Andres) oil field, and the Waddell (Grayburg/San Andres) oil field.

Most prolific of these zones are the Grayburg and San Andres, which

produce from depths between 2,800 and 3,400 feet.

Also productive from the San Andres are the Sand Hills (Judkins) gas field and the Sand Hills (McKnight) oil field, the Dune (Grayburg/San Andres) oil field, and the Waddell (Grayburg/San Andres) oil

The Dune and Waddell oil fields are productive from both the Grayburg and San Andres formations.

The Sand Hills (Tubb) oil fields produce from the Tubb

formation at depths averaging 4,300 feet, and the University Waddell (Devonian) oil field is productive from the Devonian formation between 8,400 and 9,200 feet.

The Waddell Ranch properties are mature producing properties, and all of the major oil fields are currently being waterflooded for the purpose of

facilitating enhanced recovery.

The Sand Hills (Tubb) oil fields

produce from the Tubb formation at depths averaging 4,300 feet, and the University Waddell (Devonian) oil field is productive from the Devonian formation between 8,400 and 9,200 feet.

The Waddell Ranch properties are mature producing properties, and all of the major oil

fields are currently being waterflooded for the purpose of facilitating enhanced recovery.

Proved reserves and estimated future net revenues attributable to the properties are included in the reserve reports summarized below.

The owner of the Underlying Properties for Waddell Ranch does not own the full

working interest in any of the tracts constituting the Waddell Ranch properties and, therefore, implementation of any development programs will require approvals of other working interest holders as well as the owner of the Underlying Properties.

addition, implementation of any development programs will be dependent upon oil and gas prices currently being received and anticipated to be received in the future.

There were 46.1 net drill wells completed on the Waddell Ranch properties during

The owner of the

Underlying Properties for Waddell Ranch does not own the full working interest in any of the tracts constituting the Waddell Ranch properties and, therefore, implementation of any development programs will require approvals of other working interest

holders as well as the owner of the Underlying Properties.

In addition, implementation of any development programs will be dependent upon oil and gas prices currently being received and anticipated to be received in the future.

There were 28.9 new

drill wells (net) completed on the Waddell Ranch properties during 2023.

At December 31, 2023, there were 3 gross (1.1 net) drill wells and 5 gross (1.9 net) workover in progress on the Waddell Ranch properties.

There were 46.1 net drill wells

completed on the Waddell Ranch properties during 2022.

At December 31, 2022, there were 46.9 drill wells and 38.7 workover in progress on the Waddell Ranch properties.

There were 79 gross (30 net) drill wells completed on the Waddell Ranch properties during 2021.

At December 31, 2021,

there were 11 drill wells and 11 workover in progress on the Waddell Ranch properties.

There were 16 gross (6 net) drill wells completed on the Waddell Ranch properties during 2020.

At December 31, 2020, there were 4 drill wells and 3 workover

in progress on the Waddell Ranch properties.

Blackbeard has advised the Trustee that the total amount of capital expenditures for 2022 with regard

to the Waddell Ranch properties totaled $124 million (gross).

There were 79 gross (30 net) drill wells completed on the Waddell Ranch

properties during 2021.

At December 31, 2021, there were 11 drill wells and 11 workover in progress on the Waddell Ranch properties.

Blackbeard has advised the Trustee that the total amount of capital expenditures for 2023 with regard to the Waddell Ranch properties totaled

$135 million (gross).

Capital expenditures include the cost of remedial and maintenance activities.

The amount spent on remedial and maintenance activities is approximately $89 million of the amount

expended by Blackbeard in 2022.

Blackbeard has advised the Trustee that the capital expenditures budget for 2023 totals approximately

$122 million net to the Trust, of which approximately $8.1 million (gross) is attributable to facilities.

Accordingly, there is a 32% increase in capital expenditures for 2023 as compared with the 2022 capital expenditures.

are expected to be 48.75 new drill wells and 45 recompletions in 2023 as compared to 46.88 new drill wells and 45.06 recompletion in 2022.

Trustee has been advised that, effective November 1, 2019, BROG sold its interests in the Waddell Ranch properties to Blackbeard.

In conjunction with the transfer and assignment of the Waddell Ranch properties, BROG also assigned to Blackbeard

all of its rights, title and interest in and to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust - Waddell Ranch) dated November 1, 1980.

BROG handled all operations and accounting on

behalf of Blackbeard until March 31, 2020.

The amount spent on remedial and maintenance activities is approximately $19 million of the amount expended by Blackbeard in 2023.

Blackbeard has advised the Trustee that the capital expenditures budget for 2024 has not been finalized;

however, Blackbeard provided the

Trustee with a preliminary capital expenditures budget of approximately $301 million (gross) and development plan reflecting the number of wells it expects to drill in 2024.

Blackbeard has advised the Trustee there are expected to be 95 new drill

wells and 24 recompletions in 2024 as compared to 77 new drill wells (gross) and 142 recompletion (gross) in 2023

The Trustee has been

advised that, effective November 1, 2019, BROG sold its interests in the Waddell Ranch properties to Blackbeard.

In conjunction with the transfer and assignment of the Waddell Ranch properties, BROG also assigned to Blackbeard all of its

rights, title and interest in and to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust - Waddell Ranch) dated November 1, 1980.

BROG handled all operations and accounting on behalf of

Blackbeard until March 31, 2020.

Texas Royalty Properties .

The Texas Royalty properties consist of

royalty interests in mature producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N.

The Texas Royalty properties consist of royalty interests in

mature producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N.

Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole and others located in 33 counties across Texas.

The Texas Royalty properties consist

of approximately 125 separate royalty interests containing approximately 303,000 gross (approximately 51,000 net) producing acres.

Approximately 39% of the future net revenues discounted at 10%

attributable to Texas Royalty properties are located in the Wasson and Yates fields.

The Texas Royalty

properties consist of approximately 125 separate royalty interests containing approximately 303,000 gross (approximately 51,000 net) producing acres.

Approximately 39% of the future net revenues discounted at 10% attributable to Texas Royalty

properties are located in the Wasson and Yates fields.

Detailed information concerning the number of wells on royalty properties is not generally available to the owners of royalty interests.

Consequently, an accurate

count of the number of wells located on the Texas Royalty properties cannot readily be obtained.

In February 1997, BROG sold its interests in the

Texas Royalty properties that are subject to the Net Overriding Royalty Conveyance to the Trust dated effective November 1, 1980 (Texas Royalty Conveyance) to Riverhill Energy Corporation (Riverhill Energy), which was

then a wholly-owned subsidiary of Riverhill Capital and an affiliate of Coastal Management Corporation (CMC).

At the time of such sale, Riverhill Capital was a privately owned Texas corporation with offices in Bryan and Midland, Texas.

The Trustee was informed by BROG that, as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all of the requirements upon, and the responsibilities of BROG under, the Texas Royalty Conveyance with regard to the Texas Royalty

BROG and Riverhill Energy further advised the Trustee that all accounting operations pertaining to the Texas Royalty properties were being performed by Riverhill Energy.

The Trustee has been advised that, effective April 1, 1998, Schlumberger Technology Corporation (STC) acquired all of the shares of

stock of Riverhill Capital.

Consequently, an accurate count of the number of wells

located on the Texas Royalty properties cannot readily be obtained.

In February 1997, BROG sold its interests in the Texas Royalty

properties that are subject to the Net Overriding Royalty Conveyance to the Trust dated effective November 1, 1980 (Texas Royalty Conveyance) to Riverhill Energy Corporation (Riverhill Energy), which was then a

wholly-owned subsidiary of Riverhill Capital and an affiliate of Coastal Management Corporation (CMC).

The Trustee was informed by BROG that, as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all of the

requirements upon, and the responsibilities of BROG under, the Texas Royalty Conveyance with regard to the Texas Royalty properties.

BROG and Riverhill Energy further advised the Trustee that all accounting operations pertaining to the Texas Royalty

properties were being performed by Riverhill Energy.

The Trustee has been advised that, effective April 1, 1998, Schlumberger

Technology Corporation (STC) acquired all of the shares of stock of Riverhill Capital.

Prior to the acquisition by STC, CMC and Riverhill Energy were wholly-owned subsidiaries of Riverhill Capital.

The Trustee has further been advised, in accordance with the STC acquisition of Riverhill Capital, the

shareholders of Riverhill Capital acquired ownership of all shares of stock of Riverhill Energy.

The Trustee has further been advised,

in accordance with the STC acquisition of Riverhill Capital, the shareholders of Riverhill Capital acquired ownership of all shares of stock of Riverhill Energy.

Effective January 1, 2001 CMC merged into STC.

Thus, the ownership in the Texas Royalty properties remained in Riverhill Energy.

The Trustee has been advised that as of May 1, 2000, the accounting operations pertaining to the Texas Royalty properties were transferred from STC

to Riverhill Energy.

As of January 1, 2012, ConocoPhillips assumed all field, technical and accounting operations, on behalf of BROG, with regard to the Waddell Ranch properties.

ConocoPhillips currently provides summary reporting of monthly

results for the Waddell Ranch properties.

The Trustee has been advised that as of May 1, 2000, the accounting operations pertaining to the Texas Royalty properties were

transferred from STC to Riverhill Energy.

Well Count and Acreage Summary .

The following table shows as of

December 31, 2022, the gross and net producing wells and acres for the Blackbeard interests on the Waddell Ranch.

The net wells and acres are determined by multiplying the gross wells or acres by the Blackbeard interests owners working

interest in the wells or acres as of December 31, 2022.

The following table shows as of December 31, 2023,

the gross and net producing wells and acres for the Blackbeard interests on the Waddell Ranch.

The net wells and acres are determined by multiplying the gross wells or acres by the Blackbeard interests owners working interest in the wells or

acres as of December 31, 2023.

Similar information is not available for the Riverhill Energy interests.

There is no undeveloped acreage on the Waddell Ranch properties.

NUMBER OF WELLS

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The Trust recognizes production during the month in which the related distribution is received.

Production of oil and gas attributable to the Royalties

and the Underlying Properties, the related average sales prices and the average production cost per unit of production attributable to the Underlying Properties for the three years ended December 31, 2022, excluding portions attributable to the

adjustments discussed below, were as follows:

Waddell Ranch Properties

Production of oil and gas attributable to the

Royalties and the Underlying Properties, the related average sales prices and the average production cost per unit of production attributable to the Underlying Properties for the three years ended December 31, 2023, excluding portions

attributable to the adjustments discussed below, were as follows:

Waddell Ranch

Texas Royalty

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Average Production Cost Oil/Gas BOE

Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such

factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison.

Waddell Ranch

properties lease operating expense for 2022 was $44 million (gross).

The lease operating expense increased from $23 million in 2021 primarily because of increasing activity and facilities maintenance.

Waddell Ranch lifting cost on a barrel

of oil equivalent (BOE) basis was $17.58 bbl as compared to $17.71 in 2021 and $32.92 in 2020.

Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent

on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison.

Waddell Ranch properties lease operating expense for 2023 was $80 million (gross).

The lease operating expense increased from

$44 million (gross) in 2022 primarily because of increasing activity and facilities maintenance.

Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis was $20.59 bbl as compared to $17.58 in 2022 and $17.71 in 2021.

PRICING INFORMATION

Reference is made to the caption entitled Regulation for information as to federal regulation of prices of natural gas.

The following

paragraphs provide information regarding sales of oil and gas from the Waddell Ranch properties.

following paragraphs provide information regarding sales of oil and gas from the Waddell Ranch properties.

As a royalty owner, Riverhill Energy is not furnished detailed information regarding sales of oil and gas from the Texas Royalty properties.

The Trustee has been advised by the operator that since June 2006, the oil from the Waddell Ranch has been marketed

by the operator by soliciting bids from third parties on an outright sale basis of production listed in bid packages.

The gas produced from the Waddell Ranch properties is processed through a natural gas processing plant and sold at

the tailgate of the plant.

Plant products are marketed by Burlington Resources Trading Inc., an indirect subsidiary of BRI.

The processor of the gas (Warren Petroleum Company, L.P.) receives 15% of the liquids and residue gas as a fee for gathering,

compression, treating and processing the gas.

The Trustee has been advised by the operator that the majority of oil from the Waddell Ranch is now pipeline connected

and sold under long term crude purchase agreements.

The trustee has been advised by the operator that the majority of

gas produced from Waddell Ranch properties is processed through Targa Resources Corporation Midway processing plant.

Both residue gas and plant products are purchased by Targa who receives fees (gathering, compression, treating, processing) and a

percentage of the gas and liquids as compensation.

OIL AND GAS RESERVES

The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Item:

Proved oil and gas reserves are those quantities of oil and 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.

The project to extract the hydrocarbons must have

commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir

considered as proved includes:

The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data,

can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulationsprior to the time at which

contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

The project to extract the hydrocarbons must

have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the

reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain

economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved

quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an

associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection)

are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with

properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering

analysis on which the project or program was based;

(B) The project has been approved for development by all necessary parties

and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a

reservoir is to be determined.

The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of

the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements,

excluding escalations based upon future conditions.

Developed oil and gas reserves are reserves of any category that can be expected to

be recovered (i) 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;

and (ii) through installed extraction equipment

and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Estimated future net

revenues are computed by applying average prices during the 12-month period prior to fiscal year-end determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it

and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data

on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact

with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO)

elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher

contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques

(including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing

by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology

establishes the reasonable certainty of the engineering analysis on which the project or program was based;

project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic

conditions include prices and costs at which economic producibility from a reservoir is to be determined.

The price shall be the average price during the 12-month period prior to the ending date of the period

covered by the report, determined as an unweighted arithmetic average of the

first-day-of-the-month price for each month within such period, unless prices are defined

by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves are reserves

of any category that can be expected to be recovered (i) 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;

(ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Estimated future net revenues are computed by applying average prices during the 12-month

period prior to fiscal year-end determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month

within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions to estimated future production of proved oil and gas reserves as of

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future net revenues are sometimes referred to herein as estimated future net cash flows.

Present value of estimated future net

revenues is computed using the estimated future net revenues and a discount factor of 10%.

Reserves are estimated remaining

quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from

existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be 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.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled

to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for

undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an

analogous reservoir, as defined in 17 CFR 210.4-10(a)(2), or by other evidence using reliable technology establishing reasonable certainty.

Present value of estimated future

net revenues is computed using the estimated future net revenues and a discount factor of 10%.

Reserves are estimated

remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled

acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage

shall be 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.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted

indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual

projects in the same reservoir or an analogous reservoir, as defined in 17 CFR 210.4-10(a)(2), or by other evidence using reliable technology establishing reasonable certainty.

The process of estimating oil and gas reserves is complex and requires significant judgment.

As a result, the Trustee has developed internal policies

and controls for estimating reserves.

As described above, the Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests.

The Trustee gathers production information (which information is net to the Trusts interests in the Underlying Properties) and provides such information to Cawley, Gillespie & Associates, Inc., who extrapolates from such information

estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information.

The Trusts policies regarding reserve

estimates require proved reserves to be in compliance with the SEC definitions and guidance.

The independent petroleum engineers reports as

to the proved oil and gas reserves attributable to the Royalties conveyed to the Trust were prepared by Cawley, Gillespie & Associates, Inc.(CG&A).

CG&A, whose firm registration number is

F-693, was founded in 1961 and is nationally recognized in the evaluation of oil and natural gas properties.

The technical person at CG&A primarily responsible for overseeing the reserves estimates with

respect to the Trust is Zane Meekins.

Meekins has been a practicing petroleum engineering consultant since 1989 with over 35 years of practice experience in petroleum engineering, and is a registered professional engineer in the State of

Texas (License No.

As a result, the Trustee has developed internal

policies and controls for estimating reserves.

As described above, the Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty

information estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information.

The Trusts policies

regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance.

The independent petroleum

engineers reports as to the proved oil and gas reserves attributable to the Royalties conveyed to the Trust were prepared by Cawley, Gillespie & Associates, Inc.

CG&A, whose firm registration number is F-693, was founded in 1961 and is nationally recognized in the evaluation of oil and natural gas properties.

The technical person at CG&A primarily responsible for overseeing the reserves estimates with respect

to the Trust is Zane Meekins.

Meekins has been a practicing petroleum engineering consultant since 1989 with over 36 years of practice experience in petroleum engineering, and is a registered professional engineer in the State of Texas

Meekins graduated from Texas A&M University in 1987, S umma Cum Laude , with a B.S.

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requirements set forth in Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Cawley, Gillespie & Associates, Inc.s reports are attached as exhibits to this Form 10-K.

Cawley, Gillespie & Associates, Inc.s reports are attached as exhibits to

this Form 10-K.

The following table presents a reconciliation of proved reserve quantities from January 1, 2021 through December 31, 2023 (in thousands):

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Proved Undeveloped

Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as

follows (in thousands):

Totals do not add due to rounding.

Estimated quantities of proved undeveloped reserves of oil and gas on the Waddell Ranch

properties as of December 31, 2023 were calculated based on a preliminary development plan and budget provided by Blackbeard.

Any change in the budget or development plan by Blackbeard could result in a change in the estimated quantities of

proved undeveloped reserves.

Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows

(in thousands):

Proved Developed Reserves:

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December 31, 2023

The SEC requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future

net cash flows relating to proved oil and gas reserve quantities.

Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the

The SEC requires supplemental disclosures for oil and gas producers based on a standardized measure of

discounted future net cash flows relating to proved oil and gas reserve quantities.

Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to

fiscal year-end, determined as an unweighted arithmetic average of the

first-day-of-the-month benchmark price for each month within such period, unless prices

4 unchanged sentences

Estimates of proved oil and gas reserves are by their very nature imprecise.

Estimates of future net revenue attributable to proved reserves are

sensitive to the unpredictable prices of oil and gas and other variables.

The 2022, 2021 and 2020 change in the standardized measure of discounted

future net cash revenues related to future royalty income from proved reserves attributable to the Royalties discounted at 10% is as follows (in thousands):

Estimates of future net revenue attributable to proved reserves

are sensitive to the unpredictable prices of oil and gas and other variables.

The 2023, 2022 and 2021 change in the standardized measure

of discounted future net cash revenues related to future royalty income from proved reserves attributable to the Royalties discounted at 10% is as follows (in thousands):

Waddell Ranch

4 unchanged sentences

Royalty income

Average oil and gas prices of $93.67 per barrel and $6.36 per Mcf were used to determine the estimated future net

revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2022.

The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due to

stronger pricing for oil and by stronger gas pricing.

The Texas Royalty properties are revised upward due to stronger pricing for oil.

Average oil and gas prices of $78.22 per barrel and $2.64 per Mcf were used to determine the estimated future

net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2023.

The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due

to weaker pricing for oil and gas pricing.

The Texas Royalty properties are revised downward due to weaker pricing for oil.

and gas prices of $93.67 per barrel and $6.36 per Mcf were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2022.

2 unchanged sentences

The Texas Royalty properties are revised upward due to stronger pricing for oil.

Average oil and gas prices of $39.57 per barrel and $2.00 per Mcf were used to determine the estimated future net revenues from the Waddell Ranch

properties and the Texas Royalty properties, respectively, at December 31, 2020.

The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due to weaker pricing for oil and by

weaker gas pricing.

The Texas Royalty properties are revised downward due to weaker pricing for oil.

The following presents estimated future net revenue and the present value of estimated future net

revenue attributable to the Royalties, for each of the years ended December 31, 2022, 2021 and 2020 (in thousands):

Average oil and gas prices of $66.56 per barrel and $3.65 per Mcf were used to determine the

estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2021.

The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties

are primarily due to stronger pricing for oil and by stronger gas pricing.

The Texas Royalty properties are revised upward due to stronger pricing for oil.

The following presents estimated future net revenue and the present value of estimated future net revenue attributable to the Royalties, for

each of the years ended December 31, 2023, 2022 and 2021 (in thousands):

Estimated Future

Waddell Ranch properties

Texas Royalty properties

Reserve quantities and revenues shown in the preceding tables for the Royalties were estimated from projections of

reserves and revenue attributable to the combined Blackbeard, River Hill Energy and Trust interests in the Waddell Ranch properties and Texas Royalty properties.

Reserve quantities attributable to the Royalties were estimated by allocating to the

Royalties a portion of the total estimated net reserve quantities of the interests, based upon gross revenue less production taxes.

Because the reserve quantities attributable to the Royalties are estimated using an allocation of the reserves, any

changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalties.

Reserve quantities and revenues shown in the preceding tables for the Royalties were estimated from

projections of reserves and revenue attributable to the combined Blackbeard, River Hill Energy and Trust interests in the Waddell Ranch properties and Texas Royalty properties.

Reserve quantities attributable to the Royalties were estimated by

allocating to the Royalties a portion of the total estimated net reserve quantities of the interests, based upon gross revenue less production taxes.

Because the reserve quantities attributable to the Royalties are estimated using an allocation of

the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalties.

Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur.

Proved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as additional

information becomes available.

Proved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as

additional information becomes available.

The reserves actually recovered and the timing of production of those reserves may be substantially different from the original estimate.

Moreover, the present values shown above should not be considered as the market

values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves.

Moreover, the present values shown above should not be considered as

the market values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves.

A market value determination would include many additional factors.

Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests.

Consequently,

the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on the above royalty properties, the number of exploratory or development wells

drilled on the above royalty properties during the periods presented by this report, or the number of wells in process or other present activities on the above royalty properties, and the Registrant cannot readily obtain such information.

Many aspects of the production,

pricing, transportation and marketing of crude oil and natural gas are regulated by federal and state agencies.

Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory

burden on affected members of the industry.

Exploration and production operations are subject to various types of regulation at the federal,

tribal, state and local levels.

Such regulation includes requiring permits for the drilling and production of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling

and casing wells, controlling and remediating pollution from exploration and production activities, proper handling and disposal of waste generated from exploration and production operations, the surface use and restoration of properties upon which

wells are drilled and the plugging and abandonment of wells.

Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of

wells which may be drilled and unitization or pooling of oil and gas properties.

In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and

impose certain requirements regarding the ratability of production.

The effect of these regulations is to limit the amounts of natural gas and oil that can be produced, potentially to raise prices, and to limit the number of wells or the locations

which can be drilled.

Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on the above royalty properties, the number of exploratory or

development wells drilled on the above royalty properties during the periods presented by this report, or the number of wells in process or other present activities on the above royalty properties, and the Registrant cannot readily obtain such

Many aspects of the production, pricing, transportation and marketing of crude oil and natural gas are regulated by federal and state

Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry.

Exploration and production operations are subject to various types of regulation at the federal, tribal, state and local levels.

regulation includes requiring permits for the drilling and production of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing

wells, controlling and remediating pollution from exploration and production activities, proper handling and disposal of waste generated from exploration and production operations, the surface

use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells.

Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing

units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties.

In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally

prohibit the venting and regulate the flaring of natural gas and impose certain requirements regarding the ratability of production.

The effect of these regulations is to limit the amounts of natural gas and oil that can be produced, potentially to

raise prices, and to limit the number of wells or the locations which can be drilled.

Federal Natural Gas Regulation

9 unchanged sentences

Consequently, sales of natural gas may be made at market prices, subject to applicable contract provisions.

natural gas are affected by the availability, terms and cost of transportation.

The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation.

Several major regulatory changes have been

implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales.

In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations

affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERCs jurisdiction.

These initiatives may also affect the intrastate transportation of gas under

certain circumstances.

The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas

Sales of natural gas are affected by the availability, terms and cost of transportation.

The price and terms for access to pipeline

transportation remain subject to extensive federal and state regulation.

Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation,

In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject

to the FERCs jurisdiction.

These initiatives may also affect the intrastate transportation of gas under certain circumstances.

The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the

natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry.

The ultimate impact of the rules and regulations issued by the FERC since 1985 cannot be predicted.

In addition, many aspects of these regulatory developments have not become final but are still pending judicial decisions and final

decisions by the FERC.

New proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the

FERC, state regulatory bodies and the courts.

The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust.

In addition, many aspects of

these regulatory developments have not become final but are still pending judicial decisions and final decisions by the FERC.

proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts.

The Trust cannot predict when or if any such proposals might become effective, or

their effect, if any, on the Trust.

The natural gas industry historically has been very heavily regulated;

there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Sales of crude oil,

condensate and natural gas liquids are not currently regulated and are made at market prices.

Crude oil prices are affected by a variety of factors.

Since domestic crude price controls were lifted in 1981, the principal factors influencing the

prices received by producers of domestic crude oil have been the pricing and production of the members of the Organization of Petroleum Export Countries (OPEC).

On December 19, 2007, President Bush signed into law the Energy Independence & Security Act of 2007 (PL 110 140).

The EISA, among other

things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe,

directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder.

therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices.

Crude oil prices are

affected by a variety of factors.

Since domestic crude price controls were lifted in 1981, the principal factors influencing the prices received by producers of domestic crude oil have been the pricing and production of the members of the

Organization of Petroleum Export Countries (OPEC).

On December 19, 2007, President Bush signed into law the Energy

Independence & Security Act of 2007 (PL 110 140).

The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in

contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder.

State Regulation

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of

developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources.

The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a

market demand or conservation basis, or both.

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the

method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources.

The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be

established on a market demand or conservation basis, or both.

Local Regulation

Drilling for and production and transportation of crude oil and natural gas are also regulated by local authorities.

Local laws may include land use

regulations, permitting requirements, and noise and traffic ordinances.

Local laws may include

land use regulations, permitting requirements, and noise and traffic ordinances.

Such regulation could increase drilling and production costs or create delays in development and production of the Underlying Properties.

Environmental Regulation

Companies in the oil and gas industry are subject to stringent and complex federal, tribal, state and local laws and regulations governing the health and

safety aspects of oil and gas operations, the management and discharge of materials into the environment, or otherwise relating to environmental protection.

Those laws and regulations may impose numerous obligations that are applicable to the

operations of the Underlying Properties, including the acquisition of a permit before conducting drilling, production or underground injection activities;

the restriction on the types, quantities and concentrations of materials that can be emitted

or released into the environment;

the limitation or prohibition of drilling or other construction or operational activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat, and other protected areas;

installation of emission monitoring and/or pollution control equipment;

the reporting of the types and quantities of various substances that are stored, processed, released, or disposed of in connection with operation of the Underlying Properties;

the remediation of pollution from current or former operations, such as cleanup of releases, pit closure, removal of surface equipment and plugging of abandoned wells;

the sourcing and disposal of water used in the drilling, fracturing and

completion processes;

the planning and preparedness for spill and emergency response activities;

the oil and gas industry are subject to stringent and complex federal, tribal, state and local laws and regulations governing the health and safety aspects of oil and gas operations, the management and discharge of materials into the environment, or

otherwise relating to environmental protection.

Those laws and regulations may impose numerous obligations that are applicable to the operations of the Underlying Properties, including the acquisition of a permit before conducting drilling,

production or underground injection activities;

the restriction on the types, quantities and concentrations of materials that can be emitted or released into the environment;

the limitation or prohibition of drilling or other construction or

operational activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat, and other sensitive environments or protected areas;

the installation of emission monitoring and/or pollution control equipment;

reporting of the types and quantities of various substances that are generated, stored, processed, released, or disposed of in connection with operation of the Underlying Properties;

the remediation of pollution from current or former operations,

such as cleanup of releases, pit closure, removal of surface equipment and plugging of abandoned wells;

the sourcing and disposal of water used in the drilling, fracturing and completion processes;

the planning and preparedness for spill and

emergency response activities;

the application of specific health and safety criteria addressing worker protection;

and the imposition of substantial liabilities for pollution

resulting from operations including waste generation, air emissions, water discharges and current and historical waste disposal practices.

Failure to comply with these laws and regulations may result in the suspension or revocation of necessary

permits, licenses and authorizations;

the requirement that additional pollution controls be installed;

and the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions,

water discharges and current and historical waste disposal practices.

Failure to comply with these laws and regulations may result in the adverse modification, suspension or revocation of necessary permits, licenses and authorizations;

requirement that additional pollution controls be installed;

the assessment of administrative, civil or criminal penalties;

the imposition of investigatory or remedial obligations;

and the issuance of

injunctions limiting or preventing some or all of the operations.

Under certain environmental laws and regulations, the operators of the Underlying Properties could also be subject to joint and several, strict liability for the removal or

remediation of previously released materials or property contamination, in either case, whether at a drilling or other operations site or a waste disposal facility, regardless of whether the operators were responsible for the release or

contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.

In addition, climate change is

the subject of an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states.

President Biden has set ambitious goals related to mitigating climate change, including at least a

50 per cent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030.

and the issuance of injunctions limiting or preventing some or all

of the operations.

Under certain environmental laws and regulations, the operators of the Underlying Properties could also be subject to joint and several, strict liability for the removal or remediation of previously released materials or property

contamination, in either case, whether at a drilling or other operations site or a waste disposal facility, regardless of whether the operators were responsible for the release or contamination or if the operations were in compliance with all

applicable laws at the time those actions were taken.

In addition, climate change is the subject of an important public policy debate and

the basis for new legislation proposed by the United States Congress and certain states.

President Biden has set ambitious goals related to mitigating climate change, including at least a 50 per cent reduction from 2005 levels in economy-wide

net greenhouse gas pollution by 2030.

Some states have also adopted climate change statutes and regulations.

In response to the April 2007 U.S.

Supreme Court decision in Massachusetts

EPA finding that greenhouse gases (GHGs) are air pollutants under the Clean Air Act (CAA), the United States Environmental Protection Agency (the EPA) issued an Endangerment Finding under

Section 202(a) of the CAA, concluding that GHG pollution threatens the public health and welfare of future generations.

Thereafter, EPA promulgated GHG monitoring and reporting regulations that, since 2011, have required annual reporting of

carbon dioxide, methane and nitrous oxide emissions from certain sources in the oil and natural gas industry sector, including in the onshore oil and natural gas production segment.

The EPA indicated that it will use data collected through the

reporting rules to decide whether to promulgate future GHG emission limits.

More recently, in August 2022, Congress passed the Inflation Reduction Act, which includes requirements to impose fees beginning in 2025 on methane emissions from oil and

gas operations that are required to report their GHG emissions under the EPAs GHG Reporting Rule.

Pursuant to the CAA and state laws

concerning the permitting of air emissions, certain new and modified sources of air emissions are subject to air permitting authorizations for construction and operation, and sources of air emissions at the Underlying Properties are no exception to

these requirements.

In addition to air permitting requirements, certain sources of emissions involved in oil and gas operations are subject to source-specific emission standards pursuant to CAA New Source Performance Standards (NSPS) and

National Emissions Standards for Hazardous Air Pollutants (NESHAPS).

For example, on August 16, 2012, the EPA issued a final rule, known as NSPS Subpart OOOO, that established new source performance standards for volatile organic

compounds (VOCs) and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage.

The rule applied to certain oil and

natural gas sources that were constructed, modified, or reconstructed after August 23, 2011, and required that all hydraulically fractured or refractured natural gas wells be completed using reduced emission (green) completion

technology, which significantly reduces VOC emissions.

Limiting emissions of VOCs will have the co-benefit of also limiting methane, a GHG.

These regulations also include requirements applicable to storage

tanks and other equipment in the affected oil and natural gas industry segments.

On June 3, 2016, EPA promulgated NSPS Subpart OOOOa,

establishing additional standards for the reduction of methane, VOCs, and other emissions from new and existing sources in the oil and gas sector.

Among other requirements, these new standards

extended green completion requirements to new hydraulically fractured or refractured oil wells.

Furthermore, EPA has also recently proposed to revise and add to the NSPS OOOO program rules, which, if adopted, could have a significant impact on the

upstream and midstream oil and gas sectors.

The proposed rules would formally instate methane emissions limitations from new, modified, and reconstructed sources;

and would regulate existing sources for the first time under the NSPS OOOO program by

requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities.

Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation

and the ultimate scope of the VOC and methane emissions standards for the oil and gas production, transmission, and storage industry segments are uncertain at this time as a result of ongoing rulemakings and ongoing and expected legal challenges.

Congress and various states, including Texas, have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the

hydraulic fracturing fluid that is used in the drilling operation.

Texas requires oil and gas operators to disclose the chemicals on the Frac Focus website.

Hydraulic fracturing has historically been regulated by state oil and natural gas

The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (the SDWA).

The EPA has issued permitting guidance for oil and

natural gas hydraulic fracturing activities using diesel fuels.

Under the guidance, EPA defined the term diesel to include five categories of oils, including some such as kerosene, that are not traditionally considered to be diesel.

The Federal Water Pollution Control Act, also known as the Clean Water Act (CWA), and analogous state laws impose restrictions and strict

controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States.

The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a

permit issued by EPA or the relevant state agency.

The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S.

Army Corps of Engineers

Whether CWA permitting is required depends upon whether and the extent to which Waters of the United States (WOTUS) may be impacted by the planned activity for example, construction of drilling

pads, access roads, or pipelines.

Rulemaking by EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect at times in some states but not others.

Most recently, EPA and USACEs WOTUS definition rulemaking

on December 30, 2022, incorporated relatively permanent and significant nexus standards for determining jurisdiction over adjacent wetlands and additional waters.

This WOTUS definition will become effective

March 20, 2023.

Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations, such as spill prevention, control, and countermeasure (SPCC) planning, may be triggered during development and

operation of the Underlying Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of the Underlying Properties.

SPCC regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 impose obligations and liabilities related to the

prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines.

For example, operators of certain oil and natural gas facilities that store oil in more than threshold

quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain SPCC Plans.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the superfund law, imposes

liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment.

These persons include the current or previous owner and

operator of a site where a hazardous substance has been disposed and persons who disposed or arranged for the disposal of a hazardous substance at a site, or transported a hazardous substance to a site for disposal.

CERCLA also authorizes the EPA

and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action.

From time to time, EPA may designate

additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or reopener of Superfund sites that previously received

Supreme Court decision in Massachusetts vs.

EPA finding that greenhouse gases (GHGs)

are air pollutants under the Clean Air Act (CAA), the United States Environmental Protection Agency (the EPA) issued an Endangerment Finding under Section 202(a) of the CAA, concluding that GHG pollution

threatens the public health and welfare of future generations.

Thereafter, EPA promulgated GHG monitoring and reporting regulations that, since 2011, have required annual reporting of carbon dioxide, methane and nitrous oxide emissions from certain

sources in the oil and natural gas industry sector, including in the onshore oil and natural gas production segment.

The EPA indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG emission

More recently, in August 2022, Congress passed the Inflation Reduction Act, which includes requirements to impose fees beginning in 2025 on methane emissions from oil and gas operations that are required to report their GHG emissions

under the EPAs GHG Reporting Rule.

EPAs proposed rule to implement the fee requirements, Waste Emissions Charge for Petroleum and Natural Gas Systems was published on

January 26, 2024, with comments due by March 11, 2024.

Pursuant to the CAA and state laws concerning the permitting of air

emissions, certain new and modified sources of air emissions are subject to air permitting authorizations for construction and operation, and sources of air emissions at the Underlying Properties are no exception to these requirements.

to air permitting requirements, certain sources of emissions involved in oil and gas operations are subject to source-specific emission standards pursuant to CAA New Source Performance Standards (NSPS) and National Emissions Standards

for Hazardous Air Pollutants (NESHAPS).

For example, on August 16, 2012, the EPA issued a final rule, known as NSPS Subpart OOOO, that established new source performance standards for volatile organic compounds (VOCs)

and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage.

The rule applied to certain oil and natural gas sources that were

constructed, modified, or reconstructed after August 23, 2011, and required that all hydraulically fractured or refractured natural gas wells be completed using reduced emission (green) completion technology, which significantly

reduces VOC emissions.

Limiting emissions of VOCs also has the co-benefit of limiting methane, a GHG.

In addition, these regulations also include requirements applicable to storage tanks and other equipment in

the affected oil and natural gas industry segments.

On June 3, 2016, EPA promulgated NSPS Subpart OOOOa, establishing additional standards for the reduction of methane, VOCs, and other emissions from new and existing sources in the oil and gas

Among other requirements, these new standards extended green completion requirements to new hydraulically fractured or refractured oil wells.

Furthermore, in December 2023, EPA announced additional final NSPS OOOO program rules, referred to

as Subparts OOOOb and OOOOc, which once effective upon publication in the Federal Register, are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective.

The rules formally instate

methane emissions limitations from new, modified, and reconstructed sources;

and will regulate existing sources for the first time under the NSPS Subpart OOOOc program by requiring states to implement plans that meet or exceed federally established

emission reduction guidelines for existing oil and natural gas facilities.

Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of the VOC and methane emissions standards for the oil

and gas production, transmission, and storage industry segments are uncertain at this time as a result of ongoing rulemakings and ongoing and expected legal challenges.

Changes in the U.S.

presidential administration following the 2024 presidential

election could also affect the implementation of the NSPS Subpart OOOOb and OOOOc rules.

Congress and various states, including Texas,

have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in the drilling operation.

Texas requires oil and gas operators to disclose the chemicals on the Frac Focus

Hydraulic fracturing has historically been regulated by state oil and natural gas commissions.

The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking

Water Act (the SDWA).

The EPA has issued permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuels.

Under the guidance, EPA defined the term diesel to include five categories of oils,

including some such as kerosene, that are not traditionally considered to be diesel.

The Federal Water Pollution Control Act, also known

as the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States.

discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state agency.

The CWA also prohibits the discharge of dredge and fill material into regulated waters,

including wetlands, unless authorized by a permit issued by the U.S.

Army Corps of Engineers (USACE).

Whether CWA permitting is required depends upon whether and the extent to which Waters of the United States

(WOTUS) may be impacted by the planned activityfor example, construction of drilling pads, access roads, or pipelines.

Rulemaking by EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect

at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states.

EPA and USACEs WOTUS definition rulemaking

published in the Federal Register on January 18, 2023 (the January 2023 Rule) incorporated relatively permanent and significant nexus standards for determining jurisdiction over adjacent

wetlands and additional waters, expanding the types of waters that could be considered WOTUS;

however, this WOTUS definition was litigated and eventually amended on August 29, 2023, when EPA

and USACE issued a final rule to conform the WOTUS definition to the U.S.

Supreme Courts May 25, 2023 decision in Sackett v.

Environmental Protection Agency , which invalidated parts of the January 2023 Rule.

With the August 2023

rulemaking, EPA and USACE implemented a narrower definition of WOTUS by, for example, removing interstate wetlands;

redefining adjacent to mean having a continuous surface connection;

and removing the

significant nexus standard from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds.

Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations, such as

spill prevention, control, and countermeasure (SPCC) planning, may be triggered during development and operation of the Underlying Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost

of development and operation of the Underlying Properties.

SPCC regulations promulgated under the CWA and later amended by the Oil

Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines.

For example, operators of certain oil

and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain SPCC Plans.

Federal and state regulatory agencies

can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the superfund law,

imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment.

These persons include the current or previous

owner and operator of a site where a hazardous substance has been disposed and persons who disposed or arranged for the disposal of a hazardous substance at a site, or transported or arranged for transport of a hazardous substance to a site for

CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action.

From time to time, EPA may designate additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or reopener of Superfund sites that previously received

regulatory closure.

For example, on August 26, 2022, EPA announced a proposal to designate as hazardous substances perfluorooctanoic acid (PFOA) and perfluorooctanesulfonic acid

(PFOS), which have been commonly used in a variety of industrial and consumer products.

In the course of operations, the working interest owner and/or the operator of the Underlying Properties may have generated and may generate wastes

that may fall within CERCLAs definition of hazardous substances. The operator of the Underlying Properties or the working interest owners may be responsible under CERCLA for all or part of the costs to clean up sites at which such

substances have been disposed.

Although the Trust is not the operator of any of the Underlying Properties, or the owner of any working interest, its ownership of royalty interests could cause it to be responsible for all or part of such costs to the

extent CERCLA imposes responsibility on such parties as owners.

The Underlying Properties have produced oil and/or gas for many years

and, in connection with that production, managed waste, such as drilling fluids and produced water, that is subject to regulation under environmental laws.

Although the Trust has no knowledge of the procedures followed by the operators of the

Underlying Properties in this regard, hydrocarbons or other solid or hazardous wastes may have been or may be disposed or released on, under, or from the Underlying Properties by the current or previous operators or may have been disposed offsite of

the Underlying Properties.

For example, on August 26, 2022, EPA announced a proposal to designate as hazardous substances under CERCLA perfluorooctanoic acid (PFOA) and perfluorooctanesulfonic acid (PFOS), which have been

commonly used in a variety of industrial and consumer products.

In the course of operations, the working interest owner and/or the operator of the Underlying Properties may have generated and may generate wastes that may fall within CERCLAs

definition of hazardous substances. The operator of the Underlying Properties or the working interest owners may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed.

responsibility on such parties as owners.

The Underlying Properties have produced oil and/or gas for many years and, in

connection with that production, managed waste, such as drilling fluids and produced water, that is subject to regulation under environmental laws.

Although the Trust has no knowledge of the procedures followed by the operators of the Underlying

Properties in this regard, hydrocarbons or other solid or hazardous wastes may have been or may be disposed or released on, under, or from the Underlying Properties by the current or previous operators or may have been disposed offsite of the

Underlying Properties.

Federal, state and local laws and regulations applicable to oil and gas-related wastes and properties have become increasingly more stringent.

3 unchanged sentences

regardless of whether the operators of the Underlying Properties were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.

The federal Safe Drinking Water Act (SDWA) and the Underground Injection Control (UIC) program promulgated under the SDWA and

analogous state programs regulate the drilling and operation of salt water disposal wells.

EPA directly administers the UIC program in some states and in others administration is delegated to the state.

Permits must be obtained before drilling salt

water disposal wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater.

In addition, because some states have become concerned that the injection or disposal of

produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding such disposal methods.

Changes in regulations or the inability to obtain permits for new

disposal wells in the future may affect the ability of the operators of the Underlying Properties to dispose of produced water and ultimately increase the cost of operation of the Underlying Properties or delay production schedules.

For example, in

2014, the Railroad Commission of Texas (RRC) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on

seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question.

If the permittee or an applicant of a disposal well permit fails

to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate

the permit application or existing operating permit for that well.

Furthermore, in response to a number of earthquakes in recent years in the Midland Basin, in September 2021 the RRC announced that it will not issue any new saltwater disposal

(SWD) well permits in an area known as the Gardendale Seismic Response Area (SRA), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well..

2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits.

And in October 2021 and January 2022, respectively, the RRC identified two additional SRAs:

Culberson-Reeves SRA and the Stanton SRA.

Operators in the Northern Culberson-Reeves and Stanton SRAs were required to develop and implement seismic response plans, which include expanded data collection efforts, contingency responses for future

seismicity, and scheduled checkpoint updates with RRC staff.

Both the Gardendale and Northern Culberson-Reeves SRAs were expanded in December 2022 in response to additional earthquakes in the area.

Such restrictions and requirements could limit the

Underlying Properties oil and gas well exploration and production activities or increase the cost of those activities if wastewater disposal options become limited.

In addition, several cases have in recent years put a spotlight on the issue of whether injection

wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established.

The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari

to the United States Supreme Court in August 2018, one of which was granted in February 2019.

EPA has also brought attention to the reach of the CWAs jurisdiction in such instances by issuing a request for comment in February 2018 regarding

the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered direct, and whether such discharges

would be better addressed through other federal or state programs.

In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via

The federal Safe Drinking Water Act (SDWA) and the Underground Injection Control

(UIC) program promulgated under the SDWA and analogous state programs regulate the drilling and operation of salt water disposal and injection wells.

EPA directly administers the UIC program in some states and in others administration is

delegated to the state.

Permits must be obtained before drilling salt water disposal and injection wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater.

addition, because some states have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding such

disposal methods.

Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Underlying Properties to dispose of produced water and ultimately increase the cost of

operation of the Underlying Properties or delay production schedules.

For example, in 2014, the Railroad Commission of Texas (RRC) published a final rule governing permitting or re-permitting of

disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the

disposal area in question.

If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined

to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

Furthermore, in response to a number of earthquakes in recent years in the Midland Basin,

in September 2021 the RRC announced that it will not issue any new saltwater disposal (SWD) well permits in an area known as the Gardendale Seismic Response Area (SRA), and will require existing SWD wells in that area to

reduce their maximum daily injection rate to 10,000 barrels per day per well.

In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits.

In October 2021

and January 2022, respectively, the RRC identified two additional SRAs:

the Northern Culberson-Reeves (NCR) SRA and the Stanton SRA.

Operators in the NCR and Stanton SRAs were required to develop and implement seismic response plans,

which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff.

Both the Gardendale and NCR SRAs were expanded in December 2022 in response to additional earthquakes in

the area and effective January 12, 2014, the RRC suspended all (totaling 23) deep disposal well permits in the NCR SRA.

Such restrictions and requirements could limit the Underlying Properties oil and gas well exploration and production

activities or increase the cost of those activities if wastewater disposal options become limited.

In addition, several cases have in

recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established.

The split among federal circuit courts of appeals that

decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019.

EPA has also brought attention to the reach of the CWAs jurisdiction in such

instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological

connections should be considered direct, and whether such discharges would be better addressed through other federal or state programs.

In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be

interpreted to require permits for discharges of pollutants that reach surface waters via groundwater.

However, in April 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v.

Hawaii Wildlife Fund , holding that discharges into groundwater may be regulated under the CWA if the discharge is the

functional equivalent of a direct discharge into navigable waters.

On January 14, 2021, EPA issued guidance on the ruling that emphasized discharges to groundwater are not necessarily the functional equivalent of a

direct discharge based solely on proximity to jurisdictional waters, although EPA rescinded that guidance on September 16, 2021.

If in the future CWA permitting is required for saltwater injection wells, as a result of the Supreme Courts

ruling in County of Maui, Hawaii v.

Hawaii Wildlife Fund , the costs of permitting and compliance for injection well operations by the companies that operate the Underlying Properties could increase.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds

and their habitat, wetlands, and natural resources.

These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act, the CWA, and CERCLA.

The United States Fish and Wildlife Service

(USFWS) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species.

A critical habitat or suitable habitat designation could result in further material

restrictions to federal land use and private land use and could delay or prohibit land access or development.

Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at

times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for

example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.

The Underlying Properties and operation thereof are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and

comparable state statutes.

In addition to the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty

clause and Risk Management Planning regulations promulgated under section 112(r) of the Clean Air Act, and similar state statutes may also require disclosure of information about hazardous materials used, produced or otherwise managed during

operation of the Underlying Properties.

Some of these laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants.

The Trustee is unable to predict the total impact of the current and potential regulations upon the operators of the Underlying Properties, but it is

possible that the operators of the Underlying Properties could face operational delays, increases in the operating costs to comply with climate change or any other environmental legislation or regulation, or decreases in the completion of new oil

and natural gas wells, each of which could reduce net proceeds payable to the Trust and Trust distributions.

Hawaii Wildlife Fund , holding that

discharges into groundwater may be regulated under the CWA if the discharge is the functional equivalent of a direct discharge into navigable waters.

On November 20, 2023, EPA issued draft guidance outlining the factors that may be

considered when evaluating whether discharges through groundwater may be the functional equivalent of a direct discharge and subject to regulation under the CWA National Pollutant Discharge Elimination System permitting program and

describing the types of information that should be used in the determination.

Comments on the draft guidance were due to the agency by December 27, 2023, and to date EPA has not yet finalized the guidance.

If in the future CWA permitting is

required for saltwater injection wells as a result of the Supreme Courts ruling in County of Maui, Hawaii v.

Hawaii Wildlife Fund , the costs of permitting and compliance for injection well operations by the companies that operate

the Underlying Properties could increase.

Various state and federal statutes prohibit certain actions that adversely affect endangered or

threatened species and their habitat, migratory birds and their habitat, wetlands, and natural resources.

These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act, the CWA, and

The United States Fish and Wildlife Service (USFWS) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or

endangered species.

A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development.

Where takings of, or harm to,

species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species,

habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in

some cases, criminal penalties.

The Underlying Properties and operation thereof are subject to the requirements of the federal

Occupational Safety and Health Act (OSHA) and comparable state statutes.

In addition to the OSHA hazard communication standard, the EPA community

right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the Clean Air

Act, and similar state statutes may also require disclosure of information about hazardous materials used, produced or otherwise managed during operation of the Underlying Properties.

Some of these laws also require the development of risk

management plans for certain facilities to prevent accidental releases of pollutants.

The Trustee is unable to predict the total impact

of the current and potential regulations upon the operators of the Underlying Properties, but it is possible that the operators of the Underlying Properties could face operational delays, increases in the operating costs to comply with climate

change or any other environmental legislation or regulation, or decreases in the completion of new oil and natural gas wells, each of which could reduce net proceeds payable to the Trust and Trust distributions.

Other Regulation

The petroleum industry is also subject to compliance with various other federal, tribal, state, and local regulations and laws, including, but not

limited to, occupational safety, resource conservation and equal employment opportunity.

The Trustee does not believe that compliance with these laws by the operating parties will have any material adverse effect on Unit holders.

Legal Proceedings

There are no material pending legal proceedings to which the Trust is a party or of which any of its property is the subject.

Mine Safety Disclosures

This Item is not applicable to the Trust.

The petroleum industry

is also subject to compliance with various other federal, tribal, state, and local regulations and laws, including, but not limited to, occupational safety, resource conservation and equal employment opportunity.

The Trustee does not believe that

compliance with these laws by the operating parties will have any material adverse effect on Unit holders.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 2. Properties