What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2026-03-23 compared with 2025-03-19 · 409 added, 338 removed, 672 unchanged (53% of the section changed)

72 unchanged sentences

behalf of the Trust, reconveyed, terminated and released to the Sponsor the Net Profits Interest with respect to the 2023 Divestiture

For additional information regarding this transaction, see “Trustee’s Discussion and Analysis of Financial Condition

and Results of Operations—Sale of 2023 Divestiture Properties”

in Part II, Item 7 of this Form 10-K.

The Net Profits Interest is passive in nature and

7 unchanged sentences

interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interest.

Trust has no employees.

Administrative functions are performed by the Trustee pursuant to the Trust Agreement.

The Trustee has no authority

over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties.

The duties of the Trustee are specified in the Trust Agreement and by the laws of the state of Delaware, except as modified by

the Trust Agreement.

The Trustee’s principal duties consist of:

The Trust has no employees.

Administrative functions

are performed by the Trustee pursuant to the Trust Agreement.

The Trustee has no authority over or responsibility for, and no involvement

with, any aspect of the oil and gas operations or other activities on the Underlying Properties.

The duties of the Trustee are specified

in the Trust Agreement and by the laws of the state of Delaware, except as modified by the Trust Agreement.

The Trustee’s principal

duties consist of:

collecting cash attributable to the Net Profits Interest;

· paying expenses, charges and obligations of the Trust from the Trust’s assets;

paying expenses, charges and obligations of the Trust from the Trust’s

distributing distributable cash to the Trust unitholders;

· causing to be prepared and distributed a tax information report for each Trust unitholder and preparing and filing tax returns on

behalf of the Trust;

· causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended (the “Exchange

Act”), and by the rules of any securities exchange or quotation system on which the Trust Units are listed or admitted to trading;

· causing to be prepared and filed a reserve report by or for the Trust by independent reserve engineers as of December 31 of each

year in accordance with criteria established by the Securities and Exchange Commission (the “SEC”);

· establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements

of the Sarbanes-Oxley Act of 2002;

causing to be prepared and distributed a tax information report for each

Trust unitholder and preparing and filing tax returns on behalf of the Trust;

causing to be prepared and filed reports required to be filed under the Securities

Exchange Act of 1934, as amended (the “Exchange Act”), and by the rules of any securities exchange or quotation system

on which the Trust Units are listed or admitted to trading;

causing to be prepared and filed a reserve report by or for the Trust by

independent reserve engineers as of December 31 of each year in accordance with criteria established by the Securities and Exchange

Commission (the “SEC”);

establishing, evaluating and maintaining a system of internal control over

financial reporting in compliance with the requirements of the Sarbanes-Oxley Act of 2002;

enforcing the Trust’s rights under certain agreements;

· taking any action it deems necessary or advisable to best achieve the purposes of the Trust.

taking any action it deems necessary or advisable to best achieve the purposes

of the Trust.

In connection with the formation of the Trust,

47 unchanged sentences

money market funds that invest only in United States government securities;

· repurchase agreements secured by interest-bearing obligations of the United States government;

repurchase agreements secured by interest-bearing obligations of the United

States government;

bank certificates of deposit.

3 unchanged sentences

dissolve upon the earliest to occur of the following:

· the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells the Net Profits Interest;

· the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of

any two consecutive years;

· the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution;

the Trust, upon approval of the holders of at least 75% of the outstanding

Trust Units, sells the Net Profits Interest;

the annual cash proceeds received by the Trust attributable to the Net Profits

Interest are less than $2 million for each of any two consecutive years;

the holders of at least 75% of the outstanding Trust Units vote in favor

of dissolution;

the Trust is judicially dissolved.

39 unchanged sentences

Pioneer Natural Resources USA

Holly Frontier

BPX Operating Company

Competition and Markets

105 unchanged sentences

dissolve the Trust;

· amend the Trust Agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in

any material respect);

· approve the sale of all the assets of the Trust (including the sale of the Net Profits Interest).

amend the Trust Agreement (except with respect to certain matters that do

not adversely affect the rights of Trust unitholders in any material respect);

approve the sale of all the assets of the Trust (including the sale of the

Net Profits Interest).

In September 2017, following a special meeting

42 unchanged sentences

to a production month that occurs prior to July 1, 2011 (as such items are reduced by any offset amounts, as described in the Conveyance):

· with the exception of certain costs and expenses related to 20 wells located in the Haynesville Shale identified in the Conveyance,

all costs for (i) drilling, development, production and abandonment operations, (ii) all direct labor and other services necessary

for drilling, operating, producing and maintaining the Underlying Properties and workovers of any wells located on the Underlying Properties,

(iii) treatment, dehydration, compression, separation and transportation, (iv) all materials purchased for use on, or in connection

with, any of the Underlying Properties and (v) any other operations with respect to the exploration, development or operation of

hydrocarbons from the Underlying Properties;

· all losses, costs, expenses, liabilities and damages with respect to the operation or maintenance of the Underlying Properties for

(i) defending, prosecuting, handling, investigating or settling litigation, administrative proceedings, claims, damages, judgments,

fines, penalties and other liabilities, (ii) the payment of certain judgments, penalties and other liabilities, (iii) the payment

or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying with applicable local, state and federal

statutes, ordinance, rules and regulations, (v) tax or royalty audits and (vi) any other loss, cost, expense, liability

or damage with respect to the Underlying Properties not paid or reimbursed under insurance;

· all taxes, charges and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate, franchise and like

taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying Properties;

· all insurance premiums attributable to the ownership or operation of the Underlying Properties for insurance actually carried with

respect to the Underlying Properties, or any equipment located on any of the Underlying Properties, or incident to the operation or maintenance

of the Underlying Properties;

· all amounts and other consideration for (i) rent and the use of or damage to the surface, (ii) delay rentals, shut-in well

payments, minimum royalties and similar payments and (iii) fees for renewal, extension, modification, amendment, replacement or supplementation

of the leases included in the Underlying Properties;

· all amounts charged by the relevant operator as overhead, administrative or indirect charges specified in the applicable operating

agreements or other arrangements covering the Underlying Properties or operations with respect thereto;

· to the extent that the Sponsor is the operator of certain of the Underlying Properties and there is no operating agreement covering

such portion of the Underlying Properties, those overhead, administrative or indirect charges that are allocated by the Sponsor to such

portion of the Underlying Properties;

· if, as a result of the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of hydrocarbons produced

from the Underlying Properties, any amounts previously credited to the determination of the net profits are reclaimed from the Sponsor,

then the amounts reclaimed;

· all costs and expenses for recording the Conveyance and, at the applicable times, terminations and/or releases thereof;

· amounts previously included in gross profits but subsequently paid as a refund, interest or penalty;

· at the option of the Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure

projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $2.0 million in the aggregate,

and will be subject to the limitations described below (provided that such costs shall not be debited from gross profits when actually

with the exception of certain costs and expenses related to 20 wells located

in the Haynesville Shale identified in the Conveyance, all costs for (i) drilling, development, production and abandonment operations,

(ii) all direct labor and other services necessary for drilling, operating, producing and maintaining the Underlying Properties and

workovers of any wells located on the Underlying Properties, (iii) treatment, dehydration, compression, separation and transportation,

(iv) all materials purchased for use on, or in connection with, any of the Underlying Properties and (v) any other operations

with respect to the exploration, development or operation of hydrocarbons from the Underlying Properties;

all losses, costs, expenses, liabilities and damages with respect to the

operation or maintenance of the Underlying Properties for (i) defending, prosecuting, handling, investigating or settling litigation,

administrative proceedings, claims, damages, judgments, fines, penalties and other liabilities, (ii) the payment of certain judgments,

penalties and other liabilities, (iii) the payment or restitution of any proceeds of hydrocarbons from the Underlying Properties,

(iv) complying with applicable local, state and federal statutes, ordinance, rules and regulations, (v) tax or royalty

audits and (vi) any other loss, cost, expense, liability or damage with respect to the Underlying Properties not paid or reimbursed

under insurance;

all taxes, charges and assessments (excluding federal and state income, transfer,

mortgage, inheritance, estate, franchise and like taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying

all insurance premiums attributable to the ownership or operation of the

Underlying Properties for insurance actually carried with respect to the Underlying Properties, or any equipment located on any of the

Underlying Properties, or incident to the operation or maintenance of the Underlying Properties;

all amounts and other consideration for (i) rent and the use of or damage

to the surface, (ii) delay rentals, shut-in well payments, minimum royalties and similar payments and (iii) fees for renewal,

extension, modification, amendment, replacement or supplementation of the leases included in the Underlying Properties;

all amounts charged by the relevant operator as overhead, administrative

or indirect charges specified in the applicable operating agreements or other arrangements covering the Underlying Properties or operations

with respect thereto;

to the extent that the Sponsor is the operator of certain of the Underlying

Properties and there is no operating agreement covering such portion of the Underlying Properties, those overhead, administrative or indirect

charges that are allocated by the Sponsor to such portion of the Underlying Properties;

if, as a result of the occurrence of the bankruptcy or insolvency or similar

occurrence of any purchaser of hydrocarbons produced from the Underlying Properties, any amounts previously credited to the determination

of the net profits are reclaimed from the Sponsor, then the amounts reclaimed;

all costs and expenses for recording the Conveyance and, at the applicable

times, terminations and/or releases thereof;

amounts previously included in gross profits but subsequently paid as a refund,

interest or penalty;

at the option of the Sponsor (or any subsequent owner of the Underlying Properties),

amounts reserved for approved development expenditure projects, including well drilling, recompletion and workover costs, which amounts

will at no time exceed $2.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs

shall not be debited from gross profits when actually incurred).

As mentioned above, the costs deducted in the net

25 unchanged sentences

any production, then for purposes of determining gross profits:

· any proceeds that are withheld for any reason (other than at the request of the Sponsor) are not considered received until such time

that the proceeds are actually collected;

· amounts received and promptly deposited with a non-affiliated escrow agent will not be considered to have been received until disbursed

to the Sponsor by the escrow agent;

· amounts received and not deposited with an escrow agent will be considered to have been received.

any proceeds that are withheld for any reason (other than at the request

of the Sponsor) are not considered received until such time that the proceeds are actually collected;

amounts received and promptly deposited with a non-affiliated escrow agent

will not be considered to have been received until disbursed to the Sponsor by the escrow agent;

amounts received and not deposited with an escrow agent will be considered

to have been received.

The Trustee is not obligated to return any cash

19 unchanged sentences

an amount equal to the fair value to the Trust of such Net Profits Interest being treated as an offset amount against costs and expenses.

In May 2023, the Sponsor sold approximately $0.3 million in non-producing, non-cash flowing acreage to a private oil company, free

and clear of the Net Profits Interest, as permitted under the Trust Agreement.

In September 2025, the Sponsor sold approximately $0.4 million in non-producing, non-cash flowing acreage to a private oil company,

free and clear of the Net Profits Interest, as permitted under the Trust Agreement.

The proceeds from this sale attributable to the Trust’s

Net Profits Interest were included in the distribution that was paid to Trust unitholders on August 14, 2023.

Net Profits Interest were included in the distribution that was paid to Trust unitholders on December 15, 2025.

As the designated operator of a property included

88 unchanged sentences

result in an increase in the administrative expense of the Trust in subsequent periods.

current law, the highest marginal U.S.

federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal

federal income tax rate applicable to long-term capital gai ns (generally, gains from the sale or exchange of certain investment

assets held for more than one year) and qualified dividends of individuals is generally 20%.

Such marginal tax rates may be effectively

increased due to the phaseout of personal exemptions and certain limitations and prohibitions on itemized deductions.

The highest marginal

federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.

Under current law, the highest marginal U.S.

income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S.

federal income tax rate applicable

to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified

dividends of individuals is generally 20%.

Such marginal tax rates may be effectively increased due to the phaseout of personal exemptions

and certain limitations and prohibitions on itemized deductions.

The highest marginal U.S.

federal income tax rate applicable to

corporations is 21%, and such rate applies to both ordinary income and capital gains.

Section 1411 of the Code imposes a 3.8% Medicare

51 unchanged sentences

Available Trust Tax Information

compliance with the Treasury regulations reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the

Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation

of their federal and state income tax returns.

In compliance with the Treasury regulations reporting

requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting

booklet which is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.

This tax information booklet can be obtained at www.permianvilleroyaltytrust.com.

Environmental Matters and Regulation

For purposes of the discussion in this section, the oil and natural gas production operations conducted on the properties that are subject

to the Net Profits Interest are referred to as the “Sponsor’s operations.”

The Sponsor’s oil and natural gas exploration

and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing

the discharge of materials into the environment or otherwise relating to environmental protection.

These laws and regulations may impose

significant obligations on the Sponsor’s operations, including requirements to:

For purposes of the discussion

in this section, the oil and natural gas production operations conducted on the properties that are subject to the Net Profits Interest

are referred to as the “Sponsor’s operations.”

The Sponsor’s oil and natural gas exploration and production operations

are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials

into the environment or otherwise relating to environmental protection.

These laws and regulations may impose significant obligations

on the Sponsor’s operations, including requirements to:

obtain permits to conduct regulated activities;

· limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

· restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling,

completion and production activities;

· initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling

pits and plugging of abandoned wells;

limit or prohibit drilling activities on certain lands lying within wilderness,

wetlands and other protected areas;

restrict the types, quantities and concentration of materials that can be

released into the environment in the performance of drilling, completion and production activities;

initiate investigatory and remedial measures to mitigate pollution from former

or current operations, such as restoration of drilling pits and plugging of abandoned wells;

apply specific health and safety criteria addressing worker protection.

22 unchanged sentences

environmental, health and safety laws and regulations to which the Sponsor’s business operations are subject.

substance and wastes.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”),

also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct

on certain classes of persons who are considered to be jointly and severally responsible for the release of a “hazardous substance”

Hazardous substance and wastes.

The Comprehensive

Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the Superfund law, and comparable

state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered

to be jointly and severally responsible for the release of a “hazardous substance”

into the environment.

These persons include current and prior owners or operators of the site where the release occurred and entities

that disposed or arranged for the disposal of the hazardous substances found at the site.

These persons include

current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of

the hazardous substances found at the site.

Under CERCLA, these “responsible persons”

may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural

resources, and for the costs of certain health studies.

may be liable for the costs of cleaning

up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain

health studies.

CERCLA also authorizes the U.S.

Environmental Protection Agency (“EPA”)

and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from

the responsible classes of persons the costs they incur.

It is not uncommon for neighboring landowners and other third parties to file

claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Although petroleum,

natural gas, and natural gas liquids are excluded from the definition of “hazardous substance”

under CERCLA, the Sponsor handles

materials in the course of its operations that may be regulated as CERCLA hazardous substances, despite the so-called “petroleum

exclusion.”

Environmental Protection Agency (“EPA”) and, in some instances, third parties

to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the

costs they incur.

It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property

damage allegedly caused by the hazardous substances released into the environment.

Although petroleum, natural gas, and natural gas liquids

are excluded from the definition of “hazardous substance”

under CERCLA, the Sponsor handles materials in the course of its

operations that may be regulated as CERCLA hazardous substances, despite the so-called “petroleum exclusion.”

The Sponsor also generates solid and hazardous

10 unchanged sentences

and production wastes, including the wastes associated with hydraulic fracturing activities.

properties upon which the Sponsor conducts its operations have been used for oil and natural gas exploration and production for many years.

Although the Sponsor and, as applicable, the Sponsor’s predecessor, Enduro, may have utilized operating and disposal practices that

were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released at or from the real properties

upon which the Sponsor conducts its operations, or at or from other, offsite locations, where these petroleum hydrocarbons and wastes

have been taken for treatment or disposal.

In addition, the properties upon which the Sponsor conducts its operations may have been operated

by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not

under the Sponsor’s control.

These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.

Under these laws, the Sponsor could be required to investigate, remove or remediate previously disposed wastes, to clean up contaminated

property and to perform response actions to prevent future contamination.

The federal Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls

on the discharge of pollutants into “waters of the United States”

The properties upon which the Sponsor conducts

its operations have been used for oil and natural gas exploration and production for many years.

Although the Sponsor and, as applicable,

the Sponsor’s predecessor, Enduro, may have utilized operating and disposal practices that were standard in the industry at the

time, hydrocarbons and wastes may have been disposed of or released at or from the real properties upon which the Sponsor conducts its

operations, or at or from other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for treatment or disposal.

In addition, the properties upon which the Sponsor conducts its operations may have been operated by third parties or by previous owners

or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under the Sponsor’s control.

properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.

Under these laws, the Sponsor could be

required to investigate, remove or remediate previously disposed wastes, to clean up contaminated property and to perform response actions

to prevent future contamination.

Water discharges.

The federal Clean Water

Act (“CWA”) and analogous state laws impose restrictions and strict controls on the discharge of pollutants into “waters

of the United States”

and waters within the scope of the state law, respectively.

Pursuant to the CWA and applicable state laws, permits must be obtained to discharge pollutants into regulated waters.

Any such discharge

of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the applicable state

agency or both.

The discharge of wastewater from most onshore oil and gas exploration and production activities is currently prohibited

east of the 98 th meridian.

Additionally, in June 2016, the EPA issued a final rule implementing wastewater pretreatment

standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending certain wastewater directly to publicly

owned treatment works (“POTW”).

Unconventional extraction facilities are allowed by 40 CFR Part 437 to send wastewater

to an off-site private centralized wastewater treatment (“CWT”) facility in most circumstances.

CWT facilities can either

discharge treated water directly to surface waters or send it to a POTW.

In 2018, the EPA concluded a study of the treatment and discharge

of oil and gas wastewater that could lead to changes in requirements for discharge of produced water under Part 437, including more

stringent requirements or a prohibition on discharge of produced water from CWT facilities.

Any restriction of disposal options for hydraulic

fracturing waste and other changes to CWA discharge requirements may result in increased costs.

Pursuant to the CWA and applicable state laws,

permits must be obtained to discharge pollutants into regulated waters.

Any such discharge of pollutants into regulated waters must be

performed in accordance with the terms of the permit issued by the EPA or the applicable state agency or both.

The discharge of wastewater

from most onshore oil and gas exploration and production activities is currently prohibited east of the 98 th meridian.

Additionally,

in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional

oil and natural gas extraction facilities from sending certain wastewater directly to publicly owned treatment works (“POTW”).

Unconventional extraction facilities are allowed by 40 CFR Part 437 to send wastewater to an off-site private centralized wastewater

treatment (“CWT”) facility in most circumstances.

CWT facilities can either discharge treated water directly to surface waters

or send it to a POTW.

In 2018, the EPA concluded a study of the treatment and discharge of oil and gas wastewater that could lead to changes

in requirements for discharge of produced water under Part 437, including more stringent requirements or a prohibition on discharge

of produced water from CWT facilities.

Any restriction of disposal options for hydraulic fracturing waste and other changes to CWA discharge

requirements may result in increased costs.

The discharge of dredge and fill material in waters

7 unchanged sentences

of the United States”

(“WOTUS”), which defines the extent of geographic jurisdiction under the CWA, can impact the Sponsor’s

regulatory and permitting obligations under the CWA.

In 2023, the EPA and the USACE issued a final rule (the “2023 rule”)

that is described by the EPA and the USACE as following the 1986 regulations as modified by subsequent U.S.

Supreme Court decisions and

guidance issued by the EPA and USACE interpreting the decisions.

Shortly thereafter, the Supreme Court issued its decision in Sackett

II which overturned a substantial portion of the basis for the 2023 rule.

The USACE and the EPA subsequently amended the 2023 rule and

excluded a number of types of wetlands and streams from CWA jurisdiction, but the rule is subject to litigation regarding the sufficiency

of the agencies’

interpretation of the Sackett II decision.

The 2023 rule is presently in effect in about half of the states

while it is enjoined in the other half.

In those states where the rule is enjoined, the EPA and the USACE define WOTUS in accordance

with an earlier regulatory definition adjusted in light of the Supreme Court’s Sackett II decision.

The Sponsor’s regulatory

obligations and permitting costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of

CWA regulation, given the ongoing litigation.

(“WOTUS”), which defines the extent of geographic jurisdiction under the CWA, has been the subject

of controversy and litigation for decades and can impact the Sponsor’s regulatory and permitting obligations under the CWA.

in Sackett v.

EPA , the Supreme Court issued a landmark decision interpreting WOTUS more narrowly than the then-current definition

contemplated, resulting in diminished jurisdiction over wetlands and streams that lacked certain connections to other waters or consistent

Following Sackett , because of ongoing litigation, the regulatory landscape currently remains unsettled.

The regulations

currently in effect in 24 states define WOTUS using a 2023 regulation modified after the Sackett decision.

In the rest of the country,

the agencies base jurisdiction on an earlier WOTUS definition as implemented in light of a number of Supreme Court decisions, including

Despite the two approaches, jurisdiction over WOTUS is essentially consistent across the United States.

In November 2025, the USACE released a proposed

rule revising the regulatory definition of WOTUS.

That new definition is expected to go into effect in early 2026 without substantial

changes from the proposed definition.

Regardless of the ultimate details, the revised definition likely will further reduce CWA jurisdiction,

especially over wetlands and streams, leading to fewer permitting requirements.

Once the new WOTUS definition is final, litigation will

likely continue challenging the legality of the definition.

This litigation could have the effect of delaying or precluding implementation

of the new rule.

The Sponsor’s regulatory obligations and permitting costs will continue to be subject to remaining uncertainty

around the definition of WOTUS and the scope of CWA regulation, given the ongoing litigation.

USACE Nationwide Permits (“NWPs”) are

a streamlined form of permitting used to authorize development activities with minimal individual or cumulative adverse effects in wetlands

or other waters of the United States under the CWA.

Some NWPs are also used to authorize activities that impact traditional navigable

waters under the Rivers and Harbors Act.

NWP 12 will expire in March 2026 and be replaced with a new version.

a federal court in Washington, D.C.

is currently hearing a challenge to NWP 12.

An adverse decision in the litigation may restrict

or remove the ability to use NWP 12 to permit regulated impacts, resulting in the need to apply for a more time-consuming individual permit.

This could result in additional cost and time for permitting projects.

a streamlined form of permitting used to authorize activities related to development activities with minimal individual or cumulative

adverse effects in wetlands or other waters of the United States under the CWA.

Some NWPs are also used to authorize activities that impact

traditional navigable waters under the Rivers and Harbors Act.

The NWPs expire in March 2026 and will be replaced, simultaneously,

with new versions that are largely unchanged from the previous set.

Litigation challenging the NWPs, if filed, could result in additional

cost and time for permitting projects.

In February 2025, the USACE began implementing

emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency.

result in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects subject to the Executive

the Oil Pollution Act of 1990, as amended (“OPA”), which amends the CWA, establishes standards for prevention, containment

and cleanup of oil spills into waters of the United States.

The OPA requires measures to be taken to prevent the accidental discharge

of oil into waters of the United States from onshore production facilities.

Measures under the OPA and/or the CWA include inspection and

maintenance programs to minimize spills from oil storage and conveyance systems;

the use of secondary containment systems to prevent spills

from reaching nearby waterbodies;

proof of financial responsibility to cover environmental cleanup and restoration costs that could be

incurred in connection with an oil spill;

and the development and implementation of spill prevention, control and countermeasure (“SPCC”)

plans to prevent and respond to oil spills.

The OPA also subjects owners and operators of facilities in certain instances to strict, joint

and several liability for all containment and cleanup costs and certain other damages arising from a spill.

The Sponsor has developed

and implemented SPCC plans for the Underlying Properties as required under the CWA.

Various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts

of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formation

to stimulate production of oil and natural gas.

Congress has considered legislation to amend the federal Safe Drinking Water

Act (“SDWA”) to subject hydraulic fracturing operations to regulation under the SDWA’s Underground Injection Control

Program and to require the disclosure of chemicals used in the hydraulic fracturing process.

Any such legislation could make it easier

for third parties opposed to hydraulic fracturing to initiate legal proceedings against companies.

In December 2016, the EPA issued

a final report on the potential impacts of hydraulic fracturing on drinking water resources.

The report did not find widespread, systematic

impacts to drinking water from hydraulic fracturing;

at the same time, the report acknowledged information gaps that limited EPA’s

ability to fully assess the potential impacts to drinking water resources.

To date, the EPA has taken no further action in response to

the December 2016 report.

However, in April 2024, the BLM issued a final rule to reduce the waste of natural gas from venting,

flaring, and leaks during oil and gas production activities on federal and American Indian leases.

resulted, in many instances, in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects

subject to the Executive Order.

Finally, the Oil Pollution Act of 1990, as amended

(“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of

the United States.

The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from

onshore production facilities.

Measures under the OPA and/or the CWA include inspection and maintenance programs to minimize spills from

oil storage and conveyance systems;

the use of secondary containment systems to prevent spills from reaching nearby waterbodies;

of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill;

and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond

to oil spills.

The OPA also subjects owners and operators of facilities in certain instances to strict, joint and several liability for

all containment and cleanup costs and certain other damages arising from a spill.

The Sponsor has developed and implemented SPCC plans

for the Underlying Properties as required under the CWA.

Hydraulic fracturing.

Various federal and

state initiatives are underway to regulate, or further investigate, the environmental impacts of hydraulic fracturing, a practice that

involves the pressurized injection of water, chemicals and other substances into rock formation to stimulate production of oil and natural

Congress has considered legislation to amend the federal Safe Drinking Water Act (“SDWA”) to subject hydraulic

fracturing operations to regulation under the SDWA’s Underground Injection Control Program and to require the disclosure of chemicals

used in the hydraulic fracturing process.

Any such legislation could make it easier for third parties opposed to hydraulic fracturing

to initiate legal proceedings against companies.

In December 2016, the EPA issued a final report on the potential impacts of hydraulic

fracturing on drinking water resources.

The report did not find widespread, systematic impacts to drinking water from hydraulic fracturing;

at the same time, the report acknowledged information gaps that limited the EPA’s ability to fully assess the potential impacts

to drinking water resources.

To date, the EPA has taken no further action in response to the December 2016 report.

However, in April 2024,

the BLM issued a final rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities

on federal and American Indian leases.

On August 16, 2012 the EPA published final

15 unchanged sentences

impact on its operations or financial results.

states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating

to hydraulic fracturing in certain circumstances, including the disclosure of information regarding the substances used in the hydraulic

fracturing process.

Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process

to state or federal regulatory authorities who could then make such information publicly available.

Disclosure of chemicals used in the

fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers

and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

In addition, if hydraulic fracturing is regulated at the federal level, the Sponsor’s and the third-party operators’

fracturing activities could become subject to additional permit requirements or operational restrictions, to associated permitting delays

and potential increases in costs.

In December 2014, the Governor of New York announced that the state would maintain its moratorium

on hydraulic fracturing in the state.

Further, some local governments have imposed moratoria on drilling permits within city limits so

that local ordinances may be reviewed to assess their adequacy to address such activities.

Similar measures could be considered or implemented

in the jurisdictions in which the Underlying Properties are located.

However, in May 2015, the Texas legislature enacted a bill preempting

local bans on hydraulic fracturing.

Meanwhile, in Texas, specific oil and natural gas regulations apply to oil and gas operations,

including the drilling, completion and operations of wells, and the disposal of waste oil and salt water.

In October 2023, the Texas

Railroad Commission (“RRC”) announced draft amendments to its water protection rules to, among other things, encourage

waste recycling.

There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as

governed by the applicable governing state agency.

As an example, the RRC adopted rules in 2014 requiring companies seeking permits

for disposal wells to provide seismic activity data in permit applications.

The rules also allow the RRC to modify, suspend, or terminate

permits if a disposal well is determined to be causing seismic activity.

Determinations by the RRC under these rules may adversely

affect our operations.

The federal Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the

emission of air pollutants from many sources and also impose various monitoring and reporting requirements.

These laws and regulations

may require the Sponsor to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce

or significantly increase air emissions, and to comply with stringent air emissions permit or regulatory requirements or utilize specific

equipment or technologies to control emissions.

Some states have adopted, and other states are

considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances,

including the disclosure of information regarding the substances used in the hydraulic fracturing process.

Such federal or state legislation

could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could

then make such information publicly available.

Disclosure of chemicals used in the fracturing process could make it easier for third parties

opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific

chemicals used in the fracturing process could adversely affect groundwater.

In addition, if hydraulic fracturing is regulated at the

federal level, the Sponsor’s and the third-party operators’

fracturing activities could become subject to additional permit

requirements or operational restrictions, to associated permitting delays and potential increases in costs.

In December 2014, the

Governor of New York announced that the state would maintain its moratorium on hydraulic fracturing in the state.

Further, some local

governments have imposed moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy

to address such activities.

Similar measures could be considered or implemented in the jurisdictions in which the Underlying Properties

However, in May 2015, the Texas legislature enacted a bill preempting local bans on hydraulic fracturing.

in Texas, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations

of wells, and the disposal of waste oil and salt water.

In October 2023, the Texas Railroad Commission (“RRC”) announced

draft amendments to its water protection rules to, among other things, encourage waste recycling.

There are also procedures incident

to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

As an example, the RRC adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data

in permit applications.

The rules also allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to

be causing seismic activity.

Determinations by the RRC under these rules may adversely affect our operations.

Air emissions.

The federal Clean Air Act,

as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources and

also impose various monitoring and reporting requirements.

These laws and regulations may require the Sponsor to obtain pre-approval for

the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, and to

comply with stringent air emissions permit or regulatory requirements or utilize specific equipment or technologies to control emissions.

Obtaining permits has the potential to delay the development of the Sponsor’s properties.

19 unchanged sentences

state plans, with expected compliance dates for existing sources arriving in 2029.

The results of the 2024 presidential election and

President Trump’s energy agenda prioritizing domestic oil and gas production likely will impact the air quality-related requirements

that apply to the Sponsor.

In March 2025, the EPA announced it was reconsidering the 2024 rules that established new volatile

organic compound and methane emissions standards for both new and existing sources.

Following that announcement, the EPA adopted amendments

to the NSPS and existing source performance standards that extended the compliance deadlines for many of the new source requirements adopted

in 2024 and extended the state plan submittal deadlines, which will effectively extend the dates by which existing sources must come into

compliance with the existing source emissions guidelines.

It is currently unknown whether EPA’s reconsideration of the 2024 rules will

result in further changes.

Similar to prior changes to the air pollution control standards for oil and gas sources, the most recent changes

will be subject to judicial review, as well as the potential for future presidential administrations to take a different approach.

The EPA is also charged with establishing National

4 unchanged sentences

In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone

More recently, however, in February 2024, the EPA announced a final rule that will lower the annual standard for fine

particulate matter from 12 micrograms per cubic meter to 9 micrograms per cubic meter.

State or federal implementation of the NAAQS

could result in stricter permitting or regulatory requirements, delay or prohibit the Sponsor’s ability to obtain such permits,

and result in increased expenditures for pollution control equipment.

The 2024 presidential election in the United States

may impact the air quality-related requirements that apply to the Sponsor.

The Trump Administration may adopt a different approach to

many actions taken under the prior presidential administration, including the 2024 revisions to the emissions standards and guidelines

for new and existing sources in the oil and gas industry, as well as the 2024 changes to the NAAQS for fine particulate matter.

of the Trump Administration’s evaluation of the prior administration’s regulatory approach is not certain at this time, but

President Trump has made it clear that his energy agenda prioritizes an increase in domestic oil and gas production.

Likewise, in March 2024, the EPA issued a final rule that lowered the annual standard for fine particulate matter

from 12 to 9 micrograms per cubic meter.

In March 2025, however, the EPA announced that it would reconsider the rule lowering

the fine particulate matter standard, and the EPA has filed a request that the U.S.

Court of Appeals vacate the 2024 rule.

EPA also has delayed taking certain actions necessary to implement air quality requirements under the lower 2024 standard.

No regulatory

action or court decision has changed the 2024 rule lowering the fine particulate matter standard, and the EPA’s delayed implementation

of the 2024 standard likely will be subject to judicial review.

State or federal implementation of the NAAQS could result in stricter

permitting or regulatory requirements, delay or prohibit the Sponsor’s ability to obtain such permits, and result in increased expenditures

for pollution control equipment.

The Sponsor may be required to incur certain capital

expenditures for air pollution control equipment or other air emissions-related issues, The Sponsor currently does not expect that such

expenditures for air pollution control equipment or other air emissions-related issues.

The Sponsor currently does not expect that such

requirements will have a material adverse effect on its operations.

In response to its 2009 finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”)

may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases

under existing provisions of the CAA.

These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and

operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed

oil and gas sources—as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in

The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources

in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis.

On January 20, 2025,

President Trump announced the withdrawal of the United States from the Paris Climate Agreement.

President Trump also issued an executive

order directing the EPA to review the legality and continuing applicability of its 2009 GHG endangerment finding.

The outcome of that

review is not currently known;

however, it has the potential to eliminate the basis for the EPA’s regulation of GHGs under the CAA.

The EPA has established GHG standards for oil and

gas sources based on the GHG endangerment finding.

In 2024, the EPA adopted a final rule that will directly regulate volatile organic

compound and methane emissions from new oil and gas sources and will require reductions in GHG and volatile organic compound emissions

through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and

equipment leaks.

At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require

reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources.

source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in

Climate change.

The Trump Administration’s

efforts to roll back federal regulation of greenhouse gases (“GHGs”) represent a significant shift in federal climate policy,

though the ultimate impact of those efforts on the Sponsor is unclear.

In 2009, the EPA found that emissions of carbon dioxide, methane

and GHGs may present an endangerment to public health and the environment and subsequently issued regulations to restrict emissions of

greenhouse gases under existing provisions of the CAA.

These regulations include limits on tailpipe emissions from motor vehicles, preconstruction

and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and

reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and gas

sources that were adopted in 2024.

The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse

gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis.

after President Trump took office in January 2025, the federal government embarked on a series of changes relating to climate policy

and regulation.

On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement.

In July 2025, the EPA issued a proposed rule to rescind the 2009 GHG endangerment finding that provided a basis for GHG regulation

under the CAA.

In September 2025, the EPA proposed to rescind the GHG reporting program for sectors other than the oil and gas sector,

while proposing to suspend GHG reporting requirements for the oil and gas sector until 2034.

In February 2026, the EPA adopted a

final rule repealing its prior endangerment finding, which opens the door for the EPA to repeal its GHG rules for the oil and

The EPA has established methane standards for oil

and gas sources based on the now-repealed GHG endangerment finding.

In 2024, the EPA adopted a final rule that will directly regulate

volatile organic compound and methane emissions from new oil and gas sources and will require reductions in methane and volatile organic

compound emissions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids

unloading, and equipment leaks.

At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources

and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new

The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates arriving in

In 2025, however, the EPA extended certain compliance deadlines for both new and existing sources, and the 2026 endangerment finding

repeal provides a basis for undoing the oil and gas methane standards –

though the fact that the oil and gas standards address both

methane and volatile organic compounds, which are regulated independently of the EPA’s authority to regulate GHGs, may limit the

impact of future changes to the methane standards that currently apply to oil and gas sources.

The Inflation Reduction Act of 2002 (the “IRA”)

10 unchanged sentences

key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject

to and in complete compliance with EPA’s new or existing source methane requirements.

to and in complete compliance with the EPA’s new or existing source methane requirements.

The EPA adopted new rules to implement

1 unchanged sentence

however, the fate of the WEC and the EPA rules implementing the WEC is unclear.

In February 2025,

the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the

Congressional Review Act (“CRA”), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA.

the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including

the statutory provisions establishing the WEC.

In addition to the federal actions, more than one-third

of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission

inventories and/or regional GHG cap and trade programs.

Although most of the state-level initiatives to date have focused on large sources

of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission

limitations or allowance purchase requirements in the future.

In March 2025,

President Trump signed legislation repealing the EPA’s 2024 WEC rules under the Congressional Review Act.

The repeal of the

EPA’s WEC rules did not eliminate the statutory requirement to pay the WEC, but it eliminated the rules established by

the EPA to determine the WEC due, the payment mechanism, and any payment deadlines.

Congress may be considering amendment or

repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

Meanwhile, more than one-third of the states have

begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories

and/or regional GHG cap and trade programs.

Although most of the state-level initiatives to date have focused on large sources of GHG

emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations

or allowance purchase requirements in the future.

For example, the states of Colorado and New Mexico have adopted rules regulating

24 unchanged sentences

duration and magnitude of those conditions.

Environmental Policy Act.

The National Environmental Policy Act (“NEPA”) requires the federal government to undertake

an environmental review prior to making a decision on most proposed federal actions –

National Environmental Policy Act.

Environmental Policy Act (“NEPA”) requires the federal government to undertake an environmental review prior to making a decision

on most proposed federal actions —

such as permits, leases, and rights-of-way.

2025, agencies undertook NEPA reviews pursuant to binding regulations issued by the White House Council on Environmental Quality (“CEQ”)

as well as pursuant to the federal agency’s own NEPA procedures.

CEQ issued its rules after being directed to do so by an Executive

Order issued in the Carter Administration.

After two federal courts held that CEQ did not have authority to issue binding regulations,

the Trump Administration revoked the Carter Administration Executive Order and directed CEQ to withdraw the regulations.

In their place,

agencies are directed to develop procedures that hew to the statutory text over the course of 2025 with the goal of having them finalized

in early 2026.

In the meantime, agencies will continue to use their own NEPA procedures and may continue to follow the CEQ regulations,

using them as guidance.

This may result in delays and uncertainty in permitting reviews as agencies adjust to a new NEPA approach.

The federal Endangered Species Act, as amended (“ESA”), prohibits take of listed endangered, and in

some cases threatened, species.

Under the ESA, federal agencies are obligated to consult with the U.S.

Fish and Wildlife Service

or National Marine Fisheries Service if an agency’s actions, including permit actions, may affect listed species or designated critical

If endangered species are located in areas of the Underlying Properties where seismic surveys, development activities or abandonment

operations may be conducted, the work could be prohibited or delayed or expensive mitigation may be required, depending on the implications

for protected species and designated critical habitat.

On August 27, 2019, the U.S.

Fish and Wildlife Service published a final rule adopting

several changes to the federal regulations that implement the ESA, including changes to the procedures and criteria for listing or removing

species from the Lists of Endangered and Threatened Wildlife and Plants and for designating critical habitat.

The Biden Administration

rescinded one of the rules adopted by the prior administration, dealing with critical habitat, and issued a revised rule making

changes to the federal consultation process.

These changes could make a federal review process occasioned by the application for permits,

rights of way, or leases more complex in certain circumstances.

In addition, designation of new species as threatened or endangered could

cause the Sponsor to incur additional costs arising from species protection measures, could result in limitations on activities, and could

require a more complex regulatory compliance process.

In January 2025, the Trump Administration directed the use of the emergency

consultation procedures for permitting for energy projects in the Declaring a National Energy Emergency Executive Order.

health and safety.

The operations of the Sponsor are subject to a number of federal and state laws and regulations, including

the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect

the health and safety of workers.

In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under

Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained

concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government

authorities and citizens.

Driven by court decisions and Administration

policy, NEPA implementation and resulting litigation changed dramatically in 2025.

Key changes are driving agencies to narrow their NEPA

reviews and complete them faster and are driving courts to show more deference to agencies when reviewing the adequacy of an agency’s

analysis under NEPA, benefitting private projects that may require federal permits and reviews.

In particular, until 2025, agencies undertook NEPA

reviews pursuant to binding regulations issued by the White House Council on Environmental Quality (“CEQ”) as well as pursuant

to the federal agency’s own NEPA procedures.

After two federal courts found that CEQ did not have authority to issue binding regulations,

CEQ withdrew their regulations.

In their place, agencies each issued their own NEPA procedures and, for the most part, put those procedures

in agency guidance rather than binding regulations, although the UUSACE (which issues permits that can be critical to construction) regulatory

program is a notable exception, keeping its NEPA procedures in regulations.

While the agency procedures were based on a CEQ template,

there are inconsistencies among the agencies on various topics, including the requirement for public comment and consideration of various

types of impacts.

These procedures make changes that are intended to streamline reviews.

Also, on May 29, 2025, the Supreme Court decided

Seven County Infrastructure Coalition v.

Eagle County , Colorado , in which the Court expressed clear intention that NEPA

should be brought “back in line with the statutory text and common sense.”

Significantly for permits that may be needed for

private projects, the Court clarified that agencies need only evaluate the effects of the specific “proposed action”

them, not the impacts of “other future or geographically separate projects that may be built (or extended) as a result of or in

the wake of the immediate project under consideration.”

The Court also emphasized that courts must afford agencies substantial deference

in reviewing agency actions under NEPA and that agencies “must have broad latitude to draw a ‘manageable line’”

when determining the appropriate scope of analysis.

The Court’s decision may reduce litigation risk and help streamline federal

Endangered Species Act.

The federal Endangered

Species Act, as amended (“ESA”), prohibits taking of listed endangered, and in some cases threatened, species.

Under the ESA,

federal agencies are obligated to consult with the U.S.

Fish and Wildlife Service or National Marine Fisheries Service (the “Services”)

if an agency’s actions, including permit actions, may affect listed species or designated critical habitat.

If endangered species

are located in areas of the Underlying Properties where seismic surveys, development activities or abandonment operations may be conducted,

the work could be prohibited or delayed or expensive mitigation may be required, depending on the implications for protected species and

designated critical habitat.

Changes to implementing rules in the Biden Administration may, in some instances, make a federal review

process occasioned by the application for permits, rights of way, or leases more complex in certain circumstances.

In addition, designation

of new species as threatened or endangered could cause the Sponsor to incur additional costs arising from species protection measures,

could result in limitations on activities, and could require a more complex regulatory compliance process.

However, in 2025, the Services

issued proposed revisions to the regulations implementing the ESA Section 7 consultation process and the scope of the definition

of the term “take.”

These regulations, if finalized, generally would be deregulatory in nature, modestly reducing the coverage

of the ESA and streamlining the ESA section 7 consultation process.

Nevertheless, these rules are expected to be immediately challenged

in litigation, which will create uncertainty as to if and when these rules will go into effect.

In January 2025, the Trump Administration

directed the use of the emergency consultation procedures for permitting for energy projects in the Declaring a National Energy Emergency

Executive Order.

Employee health and safety.

The operations

of the Sponsor are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health

Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers.

addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund

Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials

used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Where You Can Find Other Information

5 unchanged sentences

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 1. Business