NYSE: MVO

On January 24, 2007, MV Partners and the Trust completed an initial public offering of units of beneficial interest in the Trust (the “Trust Units”). In connection with the completion of the initial public offering of Trust Units, on January 24, 2007, MV Partners conveyed a term net profits interest to the Trust that represents the right to receive 80% of the net proceeds (calculated as described below) from all of MV Partners’ interests in oil and natural gas properties as of January 24, 2007 (the “net profits interest”), pursuant to the Conveyance of net profits interest dated as of January 24, 2007 (the “Conveyance”). These properties are located in the Mid-Continent region in the States of Kansas and Colorado. MV Partners’ net interests in such properties, after deduction of all royalties and other burdens on production thereon as of January 24, 2007, are referred to in this Form 10-K as the “underlying properties.” As of December 31, 2025, the underlying properties produced predominantly oil from approximately 830 wells, and the projected reserve life of the underlying properties was over 28 years. Based on the summary prepared by Cawley, Gillespie & Associates, Inc., independent petroleum and geological engineers (“CG&A”), of its reserve report as of December 31, 2025 for the Trust, which is summarized herein under “— Description of the Underlying Properties — Reserves” and is referred to herein as the “reserve report,” the net profits interest would entitle the Trust to receive net proceeds from the sale of production of not less than 11.5 MMBoe of proved reserves during the term of the Trust, calculated as 80% of the proved reserves attributable to the underlying properties expected to be produced during the term of the Trust. Of these reserves, 100% were classified as proved developed producing reserves as of December 31, 2025. Production volumes from the underlying properties for the year ended December 31, 2025 were approximately 99% oil and approximately 1% natural gas and natural gas liquids. The underlying properties are all located in mature fields that are characterized by long production histories and numerous additional development opportunities to help reduce the natural decline in production from the underlying properties.

As of December 31, 2025, cumulatively, since inception, the Trust has received payment for 80% of the net proceeds attributable to MV Partners’ interest from the sale of 15.3 MMBoe of production from the underlying properties (which amount is the equivalent of 12.2 MMBoe with respect to the Trust’s net profits interest). Consequently, pursuant to the terms of the Conveyance, the net profits interest will terminate on June 30, 2026 (the “Termination Date”), because the minimum amount of production (14.4 MMBoe) applicable to the net profits interest has been produced and sold (which amount is the equivalent of 11.5 MMBoe with respect to the Trust’s net profits interest). The Trustee will make a final quarterly cash distribution, if any, on or about July 24, 2026 to the Trust unitholders of record on the 15th day following June 30, 2026, and the Trust Units are expected to be cancelled shortly thereafter. The Trust will not be entitled to any net proceeds that MV Partners receives after the Termination Date from the sale of production from

the underlying properties. The Trust will dissolve and commence winding up its business and affairs after the Termination Date, and once the Trust winds up and terminates, it will pay no further distributions.

The gross proceeds used to calculate the net proceeds payable to the Trust are based on prices realized for oil, natural gas and natural gas liquids attributable to the underlying properties for each calendar quarter during the term of the net profits interest. In calculating the net proceeds, MV Partners deducts from the gross proceeds from the underlying properties all lease operating expenses, maintenance expenses and capital expenditures (including the cost of workovers and recompletions, drilling costs and development costs), amounts that may be reserved for future expenditures (which reserve amounts may not exceed $1.0 million in the aggregate at any given time), post-production costs and production and property taxes paid by MV Partners.

Net proceeds payable to the Trust depend upon production quantities, sales prices of oil, natural gas and natural gas liquids, and costs to develop and produce the oil, natural gas and natural gas liquids. If at any time costs should exceed gross proceeds, neither the Trust nor the Trust unitholders would be liable for the excess costs; the Trust, however, would not receive any net proceeds until future net proceeds exceed the total amount of those excess costs, plus interest at the prime rate.

The Trust will make quarterly cash distributions of substantially all of its quarterly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash the Trustee decides to hold as a reserve against future expenses, to holders of its Trust Units during the term of the Trust. Because payments to the Trust will be generated by depleting assets and the Trust has a finite life with the production from the underlying properties diminishing over time, a portion of each distribution will represent a return of the original investment in the Trust Units.

The Trust was created to acquire and hold the net profits interest for the benefit of the Trust unitholders. The net profits interest is passive in nature and neither the Trust nor the Trustee has any control over or responsibility for costs relating to the operation of the underlying properties. The business and affairs of the Trust are managed by the Trustee, and MV Partners and its affiliates have no ability to manage or influence the operations of the Trust. The underlying properties, for which MV Partners is designated as the operator, are currently operated on a contract operator basis by Vess Oil Corporation (“Vess Oil”) and Murfin Drilling Company, Inc. (“Murfin Drilling”), each of which is an affiliate of MV Energy, LLC (“MV Energy”), the sole manager of MV Partners. MV Partners does not, as a matter of course, make public projections as to future sales, earnings or other results relating to the underlying properties.

Description of the Trust Units

Each Trust Unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. Each Trust unitholder has the same rights regarding each of his or her Trust Units as every other Trust unitholder has regarding his or her Trust Units. The Trust Units are in book-entry form only and are not represented by certificates. The Trust had 11,500,000 Trust Units outstanding as of March 24, 2026.

Distributions and Income Computations

Each quarter, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the net profits interest and other sources (such as interest earned on any amounts reserved by the Trustee) in that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future expenses. Quarterly cash distributions during the term of the Trust are made by the Trustee on or before the 25th day of the month following the end of each quarter to the Trust unitholders of record on the 15th day of the month following the end of each quarter (or the next succeeding business day).

Unless otherwise advised by counsel or the Internal Revenue Service (the “IRS”), the Trustee will treat the income and expenses of the Trust for each quarter as belonging to the Trust unitholders of record on the quarterly record date. For federal income tax purposes, Trust unitholders must take into account items of income, gain, loss, deduction and credit consistent with their methods of accounting and without regard to

the taxable year or accounting method employed by the Trust and without regard to the quarter in which the Trust makes distributions related to those items to the Trust unitholders. Variances between taxable income and cash distributions may occur. For example, the Trustee could establish a reserve in one quarter using funds that would be included in income in the quarter in which the reserve is created but may not result in a tax deduction or a distribution until a later quarter or possibly in a later taxable year. Similarly, the Trustee could also make a payment in one quarter that would be amortized for income tax purposes over several quarters. See “— Federal Income Tax Matters.”

Periodic Reports

The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and provides the tax information that Trust unitholders need to correctly report their share of the income and deductions of the Trust. The Trustee also causes to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust Units are listed or admitted to trading, and also causes the Trust to comply with the provisions of the Sarbanes-Oxley Act of 2002, including but not limited to, by establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.

Each Trust unitholder and his or her representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.

Voting Rights of Trust Unitholders

The Trustee or Trust unitholders owning at least 10% of the outstanding Trust Units may call meetings of Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders unless such meeting is called by Trust unitholders, in which case the Trust unitholders calling the meeting are responsible for all such costs. Meetings must be held in such location as is the Trustee designates in the notice of such meeting. The Trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust Units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust Unit owned.

Unless otherwise required by the Trust Agreement, a matter may be approved or disapproved by the vote of a majority of the Trust Units held by the Trust unitholders at a meeting where there is a quorum. This is true even if a majority of the total Trust Units did not approve it. The affirmative vote of the holders of a majority of the outstanding Trust Units is required to:

•

dissolve the Trust;

•

remove the Trustee or the Delaware Trustee;

•

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

•

merge or consolidate the Trust with or into another entity; or

•

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

In addition, the Trustee may make certain amendments to the Trust Agreement without approval of the Trust unitholders. The Trustee must consent before all or any part of the Trust assets can be sold except in connection with the dissolution of the Trust or limited sales directed by MV Partners in conjunction with its sale of underlying properties.

Duration of the Trust; Sale of the Net Profits Interest

The Trust will remain in existence until shortly after the Termination Date, which is June 30, 2026, since 14.4 MMBoe have been produced from the underlying properties and sold (which amount is the equivalent of 11.5 MMBoe in respect of the Trust’s right to receive 80% of the net proceeds from the underlying properties pursuant to the net profits interest). The net profits interest will terminate on the Termination Date, at which point the Trust will dissolve and commence winding up its business and affairs. It is anticipated that the Trustee will make a final quarterly cash distribution, if any, shortly after the Termination Date to the Trust unitholders of record on the 15th day following June 30, 2026, and the Trust Units are expected to be cancelled shortly thereafter.

The Trust will dissolve and commence winding up its business and affairs prior to the Termination Date if:

•

the Trust sells the net profits interest;

•

the holders of a majority of the outstanding Trust Units vote in favor of dissolution; or

•

there is a judicial dissolution of the Trust.

Upon dissolution, the Trustee would then sell all of the Trust’s assets, which are limited to the net profits interest, and do not include the underlying properties, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders. As the net profits interest will terminate as of the Termination Date, there will be no sale of the net profits interest following June 30, 2026.

Computation of Net Proceeds

The provisions of the Conveyance governing the computation of the net proceeds are detailed and extensive. The following information summarizes the material information contained in the Conveyance related to the computation of the net proceeds. For more detailed provisions concerning the net profits interest, please see the Conveyance, which is included as an exhibit to this Form 10-K.

Net Profits Interest

The term net profits interest was conveyed to the Trust by MV Partners on January 24, 2007 by means of a conveyance instrument that has been recorded in the appropriate real property records in each county in Kansas and Colorado where the oil and natural gas properties to which the underlying properties relate are located. The net profits interest burdens the net interests owned by MV Partners in the underlying properties in existence as of January 24, 2007.

The amounts paid to the Trust for the net profits interest are based on the definitions of “gross proceeds” and “net proceeds” contained in the Conveyance and described below. Under the Conveyance, net proceeds are computed quarterly, and 80% of the aggregate net proceeds attributable to a computation period will be paid to the Trust on or before the 25th day of the month following the computation period. MV Partners will not pay to the Trust any interest on the net proceeds held by MV Partners prior to payment to the Trust. The Trustee will make distributions to Trust unitholders quarterly, if sufficient funds are available. See “— Description of the Trust Units — Distributions and Income Computations.”

“Gross proceeds” mean the aggregate amount received by MV Partners from sales of oil, natural gas and natural gas liquids produced from the underlying properties (other than amounts received for certain future non-consent operations).

Gross proceeds does not include consideration for the transfer or sale of any underlying property by MV Partners or any subsequent owner to any new owner unless the net profits interest is released (as is permitted in certain circumstances). Gross proceeds also does not include any amount for oil, natural gas or natural gas liquids lost in production or marketing or used by the owner of the underlying properties in drilling, production and plant operations. Gross proceeds includes payments for future production if they are not subject to repayment in the event of insufficient subsequent production.

“Net proceeds” means gross proceeds less the following:

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all payments to mineral owners or landowners, such as royalties or other burdens against production, delay rentals, shut-in oil and natural gas payments, minimum royalty or other payments for drilling or deferring drilling;

•

any taxes paid by the owner of an underlying property to the extent not deducted in calculating gross proceeds, including estimated and accrued general property (ad valorem), production, severance, sales, gathering, excise and other taxes;

•

any extraordinary taxes or windfall profits taxes that may be assessed in the future that are based on profits realized or prices received for production from the underlying properties;

•

costs paid by an owner of a property comprising the underlying properties under any joint operating agreement;

•

all other costs and expenses, capital costs and liabilities of exploring for, drilling, recompleting, workovers, operating and producing oil, natural gas and natural gas liquids, including allocated expenses such as labor, vehicle and travel costs and materials and any plugging and abandonment liabilities (net of any capital costs for which a reserve had already been made to the extent such capital costs are incurred during the computation period) other than costs and expenses for certain future non-consent operations;

•

costs or charges associated with gathering, treating and processing oil, natural gas and natural gas liquids;

•

any overhead charge incurred pursuant to any operating agreement relating to an underlying property, including the overhead fee payable by MV Partners to Vess Oil and Murfin Drilling as described below;

•

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

•

costs and expenses for renewals or extensions of leases; and

•

at the option of MV Partners (or any subsequent owner of the underlying properties), amounts reserved for approved exploration, development, maintenance or operating expenditures, including well drilling, recompletion and workover costs, which amounts will at no time exceed $1.0 million in the aggregate, and will be subject to the limitations described below.

During each twelve-month period beginning on June 30, 2023 (the “Capital Expenditure Limitation Date”), the sum of the capital expenditures and amounts reserved for approved capital expenditure projects for such twelve-month period may not exceed the Average Annual Capital Expenditure Amount. The “Average Annual Capital Expenditure Amount” means the quotient of (x) the sum of the capital expenditures and amounts reserved for approved capital expenditure projects with respect to the three twelve-month periods ending on the Capital Expenditure Limitation Date, divided by (y) three. Commencing on the Capital Expenditure Limitation Date, and each anniversary of the Capital Expenditure Limitation Date thereafter, the Average Annual Capital Expenditure Amount will be increased by 2.5% to account for expected increased costs due to inflation. The Average Annual Capital Expenditure Amount for the twelve-month period ending June 30, 2026 is $2,336,477.

As is customary in the oil and natural gas industry, MV Partners pays an overhead fee to Vess Oil and Murfin Drilling to operate the underlying properties on behalf of MV Partners. The operating activities include various engineering, accounting and administrative functions. The fee is based on a monthly charge per active operated well, which totaled $3.4 million in 2023, $3.6 million in 2024 and $3.8 million in 2025 for all of the underlying properties for which MV Partners was designated as the operator. The fee is adjusted annually and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.

If the net proceeds for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest at the prime rate will be deducted from gross proceeds in the following computation period for purposes of determining the net proceeds for that following computation period. Gross proceeds and net proceeds are calculated on a cash receipts and cash disbursements basis.

Additional Provisions

If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:

•

amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected;

•

amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and

•

amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received.

The Trustee is not obligated to return any cash received from the net profits interest. Any overpayments that MV Partners makes to the Trust due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the Trust until MV Partners recovers the overpayments plus interest at the prime rate.

The Conveyance generally permits MV Partners to transfer without the consent or approval of the Trust unitholders all or any part of its interest in the underlying properties, subject to the net profits interest. The Trust unitholders are not entitled to any proceeds of a sale or transfer of MV Partners’ interest unless the Trust is required to sell the net profits interest as to such interest. Following a sale or transfer, the underlying properties will continue to be subject to the net profits interest, and the net proceeds attributable to the transferred property will be calculated as part of the computation of net proceeds described in this Form 10-K.

In addition, MV Partners may, without the consent of the Trust unitholders, require the Trust to release the net profits interest associated with any lease that accounts for less no more than 0.25% of the total production from the underlying properties in the prior 12 months and provided that the net profits interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by MV Partners to a non-affiliate of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair market value to the Trust of such net profits interest. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received.

As the designated operator of the properties comprising the underlying properties, MV Partners may enter into farm-out, operating, participation and other similar agreements to develop the property. MV Partners may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.

MV Partners and any transferee of an underlying property will have the right to abandon its interest in any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, MV Partners or any transferee of an underlying property is required under the applicable conveyance to act as a reasonably prudent operator in the State of Kansas under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the net profits interest as a burden on such property. Upon termination of the lease, the portion of the net profits interest relating to the abandoned property will be extinguished.

MV Partners must maintain books and records sufficient to determine the amounts payable for the net profits interest to the Trust. Quarterly and annually, MV Partners must deliver to the Trustee a statement of the computation of the net proceeds for each computation period. The Trustee has the right to inspect and copy the books and records maintained by MV Partners during normal business hours and upon reasonable notice.

Federal Income Tax Matters

The following is a summary of certain federal income tax matters that may be relevant to Trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as

amended (the “Code”), existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes or different interpretation at any time, possibly with retroactive effect. No attempt has been made in the following summary to comment on all federal income tax matters affecting the Trust or the Trust unitholders.

The summary is limited to Trust unitholders who are individual citizens or residents of the United States. Accordingly, the following summary has limited application to domestic corporations and persons subject to specialized federal income tax treatment. Each Trust unitholder should consult his or her own tax advisor with respect to his or her particular circumstances.

Classification and Taxation of the Trust

Tax counsel to the Trust advised the Trust at the time of formation that, for federal income tax purposes, in its opinion the Trust will be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the IRS with respect to the federal income tax treatment of the Trust, including as to the status of the Trust as a grantor trust for such purposes. Thus, no assurance can be provided that the tax treatment of the Trust would be sustained by a court if contested by the IRS or another taxing authority. The remainder of the discussion below is based on tax counsel’s opinion, at the time of formation, that the Trust will be classified as a grantor trust for federal income tax purposes. As a grantor trust, the Trust will not be subject to federal income tax at the Trust level. Rather, each Trust unitholder will be considered for federal income tax purposes to own its proportionate share of the Trust’s assets directly as though no trust were in existence. The income of the Trust is deemed to be received or accrued by the Trust unitholder at the time such income is received or accrued by the Trust, rather than when distributed by the Trust. Each Trust unitholder will be subject to tax on its proportionate share of the income and gain attributable to the assets of the Trust and will be entitled to claim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholder’s taxable year and tax method of accounting and without regard to the taxable year or accounting method employed by the Trust.

The Trust will allocate items of income, gain, loss, deductions and credits to Trust unitholders based on record ownership at each quarterly record date. It is possible that the IRS or another taxing authority could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily, prorated or other basis, which could require adjustments to the tax returns of the Trust unitholders affected by this issue and result in an increase in the administrative expense of the Trust in subsequent periods.

Classification of the Net Profits Interest

Tax counsel to the Trust also advised the Trust at the time of formation that, for federal income tax purposes, based upon representations made by MV Partners regarding the expected economic life of the underlying properties and the expected duration of the net profits interest, in its opinion the net profits interest should be treated as a “production payment” under Section 636 of the Code or otherwise as a debt instrument. On the basis of that advice, the Trust will treat the net profits interest as indebtedness subject to Treasury regulations applicable to contingent payment debt instruments, and by purchasing Trust Units, a Trust unitholder agrees to be bound by the Trust’s application of those regulations, including the Trust’s determination of the rate at which interest is deemed to accrue on the net profits interest. No assurance can be given that the IRS or another taxing authority will not assert that the net profits interest should be treated differently. Any such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in Trust Units and could require a Trust unitholder to accrue income at a rate different than that determined by the Trust.

Widely Held Fixed Investment Trust Reporting Information

The Trustee assumes that some Trust Units are held by middlemen, as such term is broadly defined in Treasury regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, Texas 77002, telephone number 1-855-802-1094,

is the representative of the Trust that will provide tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Trust unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Trust unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units. Any generic tax information provided by the Trustee of the Trust is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.

Available Trust Tax Information

In compliance with the reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting booklet that is intended to be used only to assist Trust unitholders in the preparation of their 2025 federal and state income tax returns. The projected payment schedule for the net profits interest is included with the tax information booklet. This tax information booklet, when available, can be obtained at http://mvo.q4web.com/home/default.aspx.

Description of the Underlying Properties

The underlying properties consist of MV Partners’ net interests in all of its oil and natural gas properties as of January 24, 2007, which properties are located in the Mid-Continent region in the States of Kansas and Colorado. Affiliates of MV Partners are the contract operators of substantially all of the underlying properties.

MV Partners’ interests in the underlying properties require MV Partners to bear its proportionate share, along with the other working interest owners, of the costs of development and operation of such properties. The underlying properties are burdened by non-working interests owned by third parties, consisting primarily of royalty interests retained by the owners of the land subject to the working interests. These landowners’ royalty interests typically entitle the landowner to receive 12.5% of the revenue derived from oil and natural gas production resulting from wells drilled on their land, without any deduction for drilling costs or other costs related to production of oil and natural gas. A working interest percentage represents a working interest owner’s proportionate ownership interest in a property in relation to all other working interest owners in that property, whereas a net revenue interest percentage is a working interest owner’s percentage of production after reducing such percentage by the percentage of burdens on such production such as royalties and overriding royalties.

Based on the reserve report, the net profits interest would entitle the Trust to receive net proceeds from the sale of production of not less than 11.5 MMBoe of proved reserves attributable to the underlying properties expected to be produced during the term of the net profits interest, calculated as 80% of the proved reserves attributable to the underlying properties expected to be produced during the term of the net profits interest. The reserves attributable to the underlying properties include all reserves expected to be economically produced during the life of the properties, whereas the Trust is entitled to only receive 80% of the net proceeds from the sale of production of oil, natural gas and natural gas liquids attributable to the underlying properties during the term of the net profits interest.

The Mid-Continent region is a mature producing region with well-known geologic characteristics. Most of the production from the underlying properties consists of desirable crude oil of a quality level between sweet and sour with 33 to 34 gravity averages. Most of the producing wells to which the underlying properties relate are relatively shallow, ranging from 600 to 4,500 feet, and many are completed to multiple producing zones. In general, the producing wells to which the underlying properties relate have stable production profiles and their production is generally long-lived, often with total projected economic lives over 50 years.

Reserves

The engineering departments of each of Vess Oil and Murfin Drilling, which together manage MV Partners and operate the underlying properties on behalf of MV Partners, maintain oversight and

compliance responsibility for the internal reserve estimate process and, in accordance with internal policies and procedures, provide appropriate data to independent third party engineers for the annual estimation of year-end reserves. These engineering departments accumulate historical production data for the underlying properties, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, and obtain logs, 3-D seismic and other geological and geophysical information. This data is forwarded to CG&A, thereby allowing CG&A to prepare estimated proved reserves in their entirety based on such data.

Estimates of the proved oil and gas reserves attributable to the Trust as of December 31, 2023, 2024 and 2025 are based on reports prepared by CG&A. CG&A has been in business since 1961 and serves many organizations and individuals in the petroleum industry, including owners and operators of oil and gas properties, exploration groups, planners, and professionals in investment and finance. One of the principal businesses of CG&A is providing detailed assessment of producing reservoirs. CG&A is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists and does not own an interest in the underlying properties and is not employed on a contingent basis. Mr. W. Todd Brooker, President, is the technical person at CG&A who is primarily responsible for overseeing CG&A’s preparation of the reserve estimates. Mr. Brooker is a graduate of the University of Texas at Austin with a Bachelor of Science degree in Petroleum Engineering and has 34 years of experience in petroleum engineering. He is a licensed professional engineer in the State of Texas (License #83462).

Oil and gas proved reserves are disclosed by significant geographic area, using the 12-month average beginning-of-month price for the year, based on the use of reliable technologies to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Reserve and related information for 2023, 2024 and 2025 is presented consistent with these requirements.

Proved Reserves of MV Oil Trust. The following table sets forth, as of December 31, 2025, estimated proved reserves attributable to the Trust derived from the reserve report. A summary of the reserve report is included below.

Oil

(MBbls)

Natural gas

(MMcf)

Natural gas

liquids

(MBbls)

Oil

equivalents

(MBoe)

Proved Developed

—

Proved Undeveloped

—
—
—
—

Total Proved

  —

Information concerning historical changes in net proved reserves attributable to the Trust, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in Note J to the financial statements of the Trust included in this Form 10-K. MV Partners has not filed reserve estimates covering the underlying properties with any other federal authority or agency.

The following table summarizes the changes in estimated proved reserves attributable to the Trust for the periods indicated. Amounts reflect sales volumes produced during the applicable year regardless of whether royalty payments thereon have been remitted to the Trust by MV Partners.

Oil

(MBbls)

Natural Gas

(MMcf)

Natural Gas

Liquids

(MBbls)

Oil

Equivalents

(MBoe)

Proved Reserves:

Balance, December 31, 2022

1,549
  —
1,561

Revisions of previous estimates

(14)
—

Production

(484)
(24)
—
(488)

Balance, December 31, 2023

1,083
—
1,089

Revisions of previous estimates

(7)
—

Production

(469)
(22)
—
(473)

Oil

(MBbls)

Natural Gas

(MMcf)

Natural Gas

Liquids

(MBbls)

Oil

Equivalents

(MBoe)

Balance, December 31, 2024

—

Revisions of previous estimates

—

Production

(454)
(18)
—
(457)

Balance, December 31, 2025

—

Proved Developed Reserves:

Balance, December 31, 2022

1,493
—
1,505

Balance, December 31, 2023

1,069
—
1,075

Balance, December 31, 2024

—

Balance, December 31, 2025

—

Proved Undeveloped Reserves:

Balance, December 31, 2022

—
—

Proved undeveloped reserves converted to proved developed reserves by drilling

(18)
—
—
(18)

Additional proved undeveloped reserves added during 2023

—
—
—
—

Proved undeveloped reserves removed from drilling plan

(22)
—
—
(22)

Revisions of previous estimates

(3)
—
—
(3)

Balance, December 31, 2023

—
—

Proved undeveloped reserves converted to proved developed reserves by drilling

(3)
—
—
(3)

Additional proved undeveloped reserves added during 2024

—
—
—
—

Proved undeveloped reserves removed from drilling plan

—
—
—
—

Revisions of previous estimates

(10)
—
—
(10)

Balance, December 31, 2024

—
—

Proved undeveloped reserves converted to proved developed reserves by drilling

—
—
—
—

Additional proved undeveloped reserves added during 2025

—
—
—
—

Proved undeveloped reserves removed from drilling plan

—
—
—
—

Revisions of previous estimates

(1)
—
—
(1)

Balance, December 31, 2025

—
—
—
—

None of the proved undeveloped reserves have remained undeveloped for five years or more after they were initially disclosed as proved undeveloped reserves.

The reserves above represent the Trust’s 80% net profits interest in the underlying properties for the remainder of the term of the Trust.

The following table sets forth the estimates of total proved reserves and forecasts of economics attributable to the Trust’s 80% net profits interest in the underlying properties as of December 31, 2025 for the remainder of the term of the Trust, as presented in the summary prepared by CG&A of its reserve report as of December 31, 2025 for the Trust. The estimates of proved reserves have not been filed with or included in reports to any federal authority or agency. The discounted cash flow value shown in the table is not intended to represent the current market value of the estimated oil and natural gas reserves attributable to the Trust’s interests.

Proved

Developed

Producing

Net Reserves

Oil (MBbl)

262.2

Gas (MMcf)

6.3

NGL (MBbl)

0.1

Revenue

Oil

$
15,951.0

Gas

18.5

NGL

1.0

Severance Taxes

92.4

Ad Valorem Taxes

366.9

Operating Expenses

9,155.4

Future Development Costs

0.0

80% NPI Net Operating Income(1)

$
5,084.7

80% Net Profits Interest (NPI)(2)

$
4,968.0

(1)

Before interest and taxes.

(2)

Discounted at 10%.

The net profits interest entitles the Trust to receive 80% of the net proceeds attributable to MV Partners’ interest from the sale of production from the underlying properties. The net profits interest will terminate on June 30, 2026 because the minimum amount of production (14.4 MMBoe) applicable to the net profits interest has been produced and sold (which amount is the equivalent of 11.5 MMBoe with respect to the Trust’s net profits interest), and the Trust will soon thereafter wind up its affairs and terminate. See “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations — Termination of the Trust.” The reserve report reflects the termination of the net profits interest on June 30, 2026.

Oil and gas prices were adjusted to a WTI Cushing oil price of $65.34 per Bbl and a Henry Hub natural gas price of $3.387 per MMbtu. As specified by the SEC, these prices are 12-month averages based upon the price on the first day of each month during 2025. The price adjustments were based on oil price differentials forecast at -$4.50 per Bbl for all properties. Oil price differentials were not escalated. Gas and NGL price differentials were forecast on a per property basis as provided by MV Partners and were also not escalated. Price differentials include adjustments for transportation and basis differential. Gas prices were further adjusted with a heating value (Btu content) applied on a per-property basis. Operating expenses, workover expenses, COPAS overhead charges and investments were forecast on a per property basis as furnished by MV Partners. Expenses and investments were held constant in accordance with SEC rules and guidelines. Severance tax rates were applied at normal state percentages of oil and gas revenue, except for those Kansas producing properties that are severance tax exempt. Ad valorem taxes of 2.0% of total revenue were applied to each property as provided by MV Partners. Oil and gas conservation tax rates were applied to all Kansas properties at the applicable rates.

The estimates of proved oil and natural gas reserves attributable to the underlying properties are based on estimates prepared by CG&A. Rules and guidelines established by the SEC regarding the present value of future net revenues were used to prepare these reserve estimates. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and estimates of other engineers might differ materially from those included in the report. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are inherently imprecise and should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

Producing Acreage and Well Counts

For the following data, “gross” refers to the total wells or acres in which MV Partners owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by MV Partners. Although many of MV Partners’ wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.

The underlying properties are interests in developed properties located in oil and natural gas producing regions of Kansas and eastern Colorado. The following is a summary of the approximate acreage of the underlying properties at December 31, 2025.

Gross

Net

(acres)

Developed Acreage:

El Dorado Area

15,145
15,133

Northwest Kansas Area

11,165
11,120

Other

20,030
16,382

Total

46,340
42,635

Undeveloped Acreage:

—
—

The following is a summary of the producing wells on the underlying properties as of December 31, 2025:

Operated

Wells

Non-Operated

Wells

Total

Gross

Net

Gross

Net

Gross

Net

Oil

Natural gas

—

Total

MV Partners did not drill any developmental wells or exploratory wells on the underlying properties during the years ended December 31, 2023, 2024 and 2025.

MV Partners did not drill, complete or commence production with respect to any wells on the underlying properties during the years ended December 31, 2023, 2024 and 2025. As of December 31, 2025, no wells were being drilled. There were no capital expenditures associated with converting proved undeveloped reserves to proved developed reserves for the year ended December 31, 2025. MV Partners continues to develop further proved undeveloped reserves pursuant to its planned development and workover program. See “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations — Planned Development and Workover Program.”

The following table shows the average sales prices per Bbl of oil and Mcf of natural gas produced and the production costs and production and property taxes per Boe for the underlying properties. Sales volumes for natural gas liquids during the periods presented were not significant.

Year Ended December 31,

Sales prices:

Oil (per Bbl)

$
73.85
$
72.09
$
61.85

Natural gas (per Mcf)

$
3.09
$
2.08
$
2.57

Lease operating expense (per Boe)

$
24.02
$
24.22
$
26.12

Lease maintenance (per Boe)

$
3.95
$
5.18
$
4.59

Lease overhead (per Boe)

$
5.80
$
6.30
$
6.81

Production and property taxes (per Boe)

$
1.88
$
2.07
$
1.79

Major Producing Areas

Approximately 62% of the net acres included in the underlying properties are located in the El Dorado Area, which is located in southeastern Kansas, and in the Northwest Kansas Area. The underlying properties are all located in mature fields that are characterized by long production histories. The properties provide continual workover and developmental opportunities which MV Partners has pursued to reduce the natural decline in production from the underlying properties.

El Dorado Area

The underlying properties located in the El Dorado Area are operated on behalf of MV Partners by Vess Oil and are located in the El Dorado, Augusta and Valley Center Fields. Vess Oil has actively pursued infill drilling, well re-entries, plugback and deepening recompletion operations, various types of restimulation work and equipment optimization programs to reduce the natural decline in production from these fields.

El Dorado Field. The El Dorado Field is located atop the Nemaha Ridge in Central Butler County, Kansas and was first discovered in 1915. Up to 15 horizons have been reported to contain hydrocarbons, ranging from the Admire Sands, at a depth of 650 feet, to the Arbuckle Dolomite, at a depth of 2,500 feet. The primary producing intervals are the Admire, Lansing-Kansas City, Viola, Simpson and Arbuckle. Cumulative production of all producers from the El Dorado Field has exceeded 300 MMBbls of oil with production peaking between 1916 and 1918, reaching 116,000 Bbls per day in 1918.

Augusta Field. The Augusta Field is on a trend similar to the nearby El Dorado Field and strikes northeast parallel to the Nemaha Ridge. The field was discovered in 1914 and covers approximately 10 square miles of Butler County, Kansas. The primary producing interval has been the Arbuckle with additional production coming from the Simpson and Lansing-Kansas City intervals. Cumulative production of all producers from the Augusta Field has exceeded 48 MMBbls of oil. The Augusta Field is largely an extension of the El Dorado Field and has very similar geological characteristics.

Vess Oil has maintained constant activity in these fields to increase production. Vess Oil plans to maintain its annual recompletion and workover program over the next five years. Vess Oil has commenced a waterflood program to enhance production from the Whitecloud formation. Vess Oil plans to convert wells as the infill developmental drilling program proceeds.

Valley Center Field. The Valley Center Field was discovered in 1928 and covers approximately 60 square miles of Sedgwick County, Kansas. Production is primarily from the Viola interval, which is located at an average depth of 2,500 feet. Cumulative production of all producers from the Valley Center Field has exceeded 25 MMBbls of oil. The Valley Center Field has similar geological characteristics as the El Dorado Field.

Northwest Kansas Area

Each of Vess Oil and Murfin Drilling operate leases on behalf of MV Partners included in the underlying properties that are located in the Northwest Kansas Area. The primary fields in this area are the Bemis-Shutts, Trapp, Ray and Hansen Fields. Vess Oil and Murfin Drilling have actively pursued polymer treatments, stimulation workovers and recompletion operations to reduce the natural decline in production from these fields.

Bemis-Shutts Field. The Bemis-Shutts Field is located on the Fairport Anticline within the Central Kansas Uplift and was discovered in 1928. The field consists of 17,080 acres in northeastern Ellis and southeastern Rooks Counties, Kansas. Production has been from multiple pay zones with the primary formation being the Arbuckle interval at a depth of 3,300 feet and the Lansing-Kansas City interval at a depth of 2,800 feet. Cumulative production of all producers from the Bemis-Shutts Field has exceeded 248 MMBbls of oil.

Both Vess Oil and Murfin Drilling have pursued polymer treatment programs with success in the Bemis-Shutts Field and plan to continue these workovers. MV Partners has continued to acquire 3-D seismic surveys over portions of the field to further define the boundaries of the Arbuckle structure in the field and to evaluate undrilled infill locations.

Trapp Field. The Trapp Field consists of 35,900 acres in Russell and Barton Counties, Kansas and was discovered in 1929. Production has primarily been from the Lansing-Kansas City and Shawnee limestones and the Arbuckle dolomite. Cumulative production of all producers from the Trapp Field has exceeded 239 MMBbls of oil.

Hansen and Ray Fields. The Hansen Field is located along the crest of the Stuttgart-Huffstutor Anticline and was discovered in 1943. Production from this field has primarily come from the Lansing- Kansas City limestone. Cumulative production of all producers from the Hansen Field has exceeded 9.2 MMBbls of oil.

The Ray Field is located on the eastern flank of the Central Kansas Uplift and was discovered in 1940. Production has primarily been from the Arbuckle dolomite and the Gorham sands with additional production from the Lansing-Kansas City interval along the eastern flank of the field. Cumulative production of all producers from the Ray Field has exceeded 18 MMBbls of oil.

The Hansen and Ray Fields consist of over 7,000 acres in Philips and Norton Counties, Kansas.

Murfin Drilling operates the leases held by MV Partners in the Trapp, Hansen and Ray Fields. Murfin Drilling has informed the Trustee that it plans to workover and recomplete additional wells, including acid stimulations, over the next five years.

Marketing and Post-Production Services

Pursuant to the terms of the Conveyance, MV Partners has the responsibility to market, or cause to be marketed, the oil, natural gas and natural gas liquid production attributable to the underlying properties. The terms of the Conveyance do not permit MV Partners to charge any marketing fee when determining the net proceeds upon which the net profits interest is calculated. As a result, the net proceeds to the Trust from the sales of oil, natural gas and natural gas liquid production from the underlying properties are determined based on the same price that MV Partners receives for oil, natural gas and natural gas liquid production attributable to MV Partners’ remaining interest in the underlying properties.

Vess Oil and Murfin Drilling, as contract operators, generally sell production from the underlying properties to several purchasers, including MV Purchasing, LLC (“MV Purchasing”), under short-term arrangements using market-sensitive pricing. MV Purchasing is majority-owned by the indirect equity owners of MV Partners. These sales to purchasers are under terms ranging from one month to six months, using market sensitive pricing. Two purchasers, including MV Purchasing, have been purchasing substantially all of the crude oil production, and a substantial portion of the crude oil production may continue be acquired by one or more single purchasers. For the years ended December 31, 2023, 2024 and 2025, MV Purchasing purchased 73%, 74% and 74%, respectively, of the production sold from the underlying properties. MV Partners does not believe that loss of any of these parties as a purchaser would have a material adverse impact on the business of MV Partners, as substitute purchasers are generally available; however, a purchaser’s failure to pay for purchased crude oil could have a significant adverse impact on MV Partners’ business.

Oil production is typically transported by truck from the field to the closest gathering facility or refinery. MV Partners sells the majority of the oil production from the underlying properties under short-term arrangements using market sensitive pricing. The price received by MV Partners for the oil production from the underlying properties is usually based on the NYMEX price applied to equal daily quantities on the month of delivery, which price is then reduced for differentials based upon delivery location and oil quality. The average differential for oil production during the years ended December 31, 2023, 2024 and 2025 was $4.13, $3.91 and $3.89 per barrel, respectively.

All natural gas produced by MV Partners is marketed and sold to third-party purchasers. The natural gas is sold on a contract basis and, in all but one case, the contracts are in their secondary terms and are on a month-to-month basis. In all cases, the contract price is based on a percentage of a published regional index price, after adjustments for Btu content, transportation and related charges.

Sale and Abandonment of Underlying Properties

MV Partners and any transferee of any of the underlying properties will have the right to abandon its interest in any well or property comprising a portion of the underlying properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between MV Partners and the Trust in determining whether a well is capable of producing in commercially paying quantities, MV Partners is required under the Conveyance to act as a reasonably prudent operator in the State of Kansas under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the net profits interest as a burden on such property. For the years ended December 31, 2023, 2024 and 2025, MV Partners plugged and abandoned 4, 7 and 27 wells, respectively, based on its determination that such wells were no longer economical to operate or restore to production.

MV Partners generally may sell all or a portion of its interests in the underlying properties, subject to and burdened by the net profits interest, without the consent of the Trust unitholders. In addition, MV Partners may, without the consent of the Trust unitholders, require the Trust to release the net profits interest associated with any lease that accounts for no more than 0.25% of the total production from the underlying properties in the prior 12 months and provided that the net profits interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by MV Partners to a non-affiliate of the relevant underlying properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such net profits interest. Any net sales proceeds paid to the Trust are distributable to Trust unitholders for the quarter in which they are received.

Title to Properties

The underlying properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect MV Partners’ rights to production and the value of production from the underlying properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and the value of the reserves attributable to the underlying properties.

MV Partners’ interests in the underlying properties are typically subject, in one degree or another, to one or more of the following:

•

royalties, overriding royalties and other burdens, express and implied, under oil and natural gas leases;

•

overriding royalties, production payments and similar interests and other burdens created by MV Partners or its predecessors in title;

•

a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the underlying properties or their title;

•

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

•

pooling, unitization and communitization agreements, declarations and orders;

•

easements, restrictions, rights-of-way and other matters that commonly affect property;

•

conventional rights of reassignment that obligate MV Partners to reassign all or part of a property to a third party if MV Partners intends to release or abandon such property; and

•

rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the underlying properties and the net profits interest therein.

MV Partners has informed the Trustee that MV Partners believes that the burdens and obligations affecting the underlying properties are conventional in the industry for similar properties. MV Partners also has informed the Trustee that MV Partners believes that the existing burdens and obligations do not, in

the aggregate, materially interfere with the use of the underlying properties and do not materially adversely affect the value of the net profits interest.

MV Partners acquired the underlying properties in two transactions, the first of which was in 1998 when it acquired a substantial portion of the underlying properties from a major oil and gas company and the second of which was in 1999 when it acquired the remaining portion of the underlying properties from a large independent oil and gas company. At the time of its acquisition of the underlying properties, MV Partners believes that it undertook a thorough title examination of the underlying properties.

MV Partners has recorded the Conveyance in the real property records in each Kansas County where the properties are located. MV Partners has informed the Trustee that MV Partners believes that the delivery and recording of the Conveyance constituted fully conveyed and vested property interests in the Trust under Kansas law. Although no assurance can be given, MV Partners has informed the Trustee that MV Partners believes that, if, during the term of the Trust, MV Partners becomes involved as a debtor in a bankruptcy proceeding, the Conveyance, as vested and recorded property interests, cannot be avoided by a bankruptcy Trustee. If in such a proceeding a determination were made that the Conveyance constitutes an executory contract and the net profits interest is not a fully conveyed property interest under the laws of Kansas, and if such contract were not to be assumed in a bankruptcy proceeding involving MV Partners, the Trust would be treated as an unsecured creditor of MV Partners with respect to such net profits interest in the pending bankruptcy proceeding.

Oil and gas leases are real property interests under Colorado law. Net profits interests are non-operating, non-possessory interests carved out of the oil and gas leasehold estate. MV Partners has informed the Trustee that MV Partners believes that it is possible that the net profits interest for the underlying properties located in Colorado may not be treated as a real property interest under the laws of Colorado. MV Partners has recorded the Conveyance in the real property records of Colorado in accordance with local recording acts. MV Partners has informed the Trustee that MV Partners believes that if, during the term of the Trust, MV Partners becomes involved as a debtor in a bankruptcy proceeding, the net profits interest relating to the underlying properties located in Colorado should be treated as a fully conveyed personal property interest under the laws of Colorado. In such a proceeding, however, a determination could be made that the Conveyance constitutes an executory contract and the net profits interest is not a fully conveyed personal property interest under the laws of Colorado, and if such contract were not to be assumed in a bankruptcy proceeding involving MV Partners, the Trust would be treated as an unsecured creditor of MV Partners with respect to such net profits interest in the pending bankruptcy proceeding. Although no assurance can be given, MV Partners does not believe that the conveyance of the net profits interest relating to the underlying properties located in Colorado should be subject to rejection in a bankruptcy proceeding as an executory contract.

Competition and Markets

The oil and natural gas industry is highly competitive. MV Partners competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than MV Partners, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. The Trust is subject to the same competitive conditions as MV Partners and other companies in the oil and natural gas industry.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Future price fluctuations for oil, natural gas and natural gas liquids will directly impact Trust distributions, estimates of reserves attributable to the Trust’s interests and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the Trust nor MV Partners can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on the Trust.

Regulation

The production of oil and gas from the underlying properties is affected by many state and federal regulations with respect to allowable rates of production, drilling permits, well spacing, marketing, environmental matters and pricing. Future regulations could change allowable rates of production or the manner in which oil and gas operations may be lawfully conducted.

FERC Regulation

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the Federal Energy Regulatory Commission, or the “FERC,” under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or “NGPA,” and regulations issued under those statutes. Over the last two decades, the FERC has issued orders and adopted regulations resulting in a restructuring of the natural gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or “unbundle,” into individual components the various services offered on their systems, with all transportation services to be provided on a non-discriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these and other regulations to determine whether further changes are needed. In addition to rulemaking proceedings, the FERC establishes new policies and regulations through policy statements and adjudications of individual pipeline matters. Further, additional changes to regulations may occur based on actions taken by the United States Congress and/or the courts.

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be just and reasonable and may not be unduly discriminatory or confer any undue preference upon any shipper. Rates generally are cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

Although the price at which MV Partners sells oil, natural gas and natural gas liquids is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation, with regard to physical sales of natural gas and oil, MV Partners is required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission and the Federal Trade Commission. If MV Partners were to violate the anti-market manipulation laws and regulations, MV Partners could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

As to these various developments, MV Partners has advised the Trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.

State and Other Regulation

In general, the jurisdictions in which royalty properties are located have statutory provisions regulating the production and sale of crude oil and natural gas. The regulations often require permits for the drilling of wells but extend also to the spacing of wells, the prevention of waste of oil and gas resources, the rate of production, prevention and clean-up of pollution and other matters.

Environmental Matters and Regulation

General. The operations of the underlying properties are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

•

restrict the types, quantities and concentration of various substances that can be released or emitted into the environment in connection with oil and natural gas drilling and production activities;

•

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

•

require investigatory and remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on the operating costs of the underlying properties.

The following is a summary of the existing laws, rules and regulations to which the operations of the underlying properties are subject that are material to the operation of the underlying properties.

Hazardous Substances 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. 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. 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 then 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 release of hazardous substances or other pollutants into the environment. Although petroleum, natural gas, and natural gas liquids are excluded from the definition of “hazardous substance” under CERCLA, MV Partners handles materials in the course of its operations that may be regulated as CERCLA hazardous substances, despite the so-called “petroleum exclusion.”

MV Partners also generates solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of its operations, MV Partners generates petroleum hydrocarbon wastes and ordinary industrial wastes that may be classified as hazardous wastes under RCRA and comparable state laws. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, production, and development of crude oil or natural gas are currently regulated under RCRA as non-hazardous wastes. While many exploration and production wastes are exempt from regulation as hazardous waste, these wastes are generally subject to non-hazardous waste regulation under RCRA and applicable state regulations. Many state governments have specific regulations and guidance for exploration and production wastes, including the wastes associated with hydraulic fracturing activities.

MV Partners currently owns or leases, and in the past may have owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although MV Partners 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 properties owned or leased by MV Partners or at or from the other locations where these hydrocarbons and wastes have been taken for treatment or disposal.

In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under MV Partners’ control. These properties and wastes disposed thereon may give rise to liability under CERCLA, RCRA and analogous state laws. Under these laws, MV Partners 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 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 activities exploration and production activities is currently prohibited east of the 98th 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 wastewater directly to publicly owned treatment works (“POTW”). Unconventional extraction facilities are in certain circumstances allowed by federal regulations 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 federal regulations, 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 of the United States, including wetlands, is also prohibited unless authorized by a permit issued under CWA Section 404 by the U.S. Army Corps of Engineers (“USACE”). CWA Section 401 provides that the applicant for a Section 404 USACE permit for the discharge of dredge and fill material must seek a Section 401 water quality certification by applying to the state in which the discharge will occur for the state to determine if the discharge will comply with the state’s approved water quality program. In some instances, this process could result in a delay in issuance of the permit, more stringent permit requirements, or denial of the permit.

How the EPA and the USACE define “waters of the United States” ​(“WOTUS”), which defines the extent of geographic jurisdiction under the CWA, has been the subject of controversy and litigation for decades and can impact MV Partners’ regulatory and permitting obligations under the CWA. In 2023, 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 water flow. 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 Sackett. 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. MV Partners’ 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 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. This has resulted, in many instances, in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects subject to the Executive Order.

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 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 to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. MV Partners has developed and implemented SPCC plans for the underlying properties as required under the CWA.

Air Emissions. The 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 MV Partners 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 permit or regulatory requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of MV Partners’ properties.

The EPA has established pollution control standards for oil and gas sources under the CAA. In 2012 and 2016, the EPA adopted federal New Source Performance Standards (“NSPS”) that require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels, and for equipment leaks. These NSPS apply to sources that are newly constructed or modified after the rules’ applicability dates. More recently, the EPA adopted a final rule in 2024 that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed or modified after December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. Additionally, the EPA for the first time 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. The existing source emissions guidelines are to be implemented through 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 MV Partners. 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 the 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 Ambient Air Quality Standards (“NAAQS”), the implementation of which can indirectly impact MV Partners’ operations. The CAA directs the EPA to review each NAAQS every five years to ensure that the standards are protective of public health and welfare. This process routinely results in the tightening of those standards, and in October 2015, the EPA lowered the ozone NAAQS from 75 to 70 parts per billion. In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone standard. 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. In 2026, the 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 MV Partners’ ability to obtain such permits, and result in increased expenditures for pollution control equipment.

MV Partners may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. MV Partners currently does not expect that such requirements will have a material adverse effect on its operations.

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 MV Partners 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. Shortly 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 gas sector.

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 sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates arriving in 2029. 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 (the “IRA”) included new Clean Air Act section 136(c) directing the EPA to collect the Waste Emissions Charge (“WEC”) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to

methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes 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. The EPA adopted new rules to implement the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In March 2025, President Trump signed legislation repealing the EPA’s 2024 WEC rules under the Congressional Review Act. The repeal of 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. The U.S. 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 GHGs from the oil and gas industry that are based on the federal standards. Congress may in the future consider adopting other legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on MV Partners’ business, capital expenditures, financial condition and results of operations.

The adoption and implementation of regulations imposing reporting obligations on, or limiting emissions of GHGs from, MV Partners’ equipment and operations could require MV Partners to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas it produces. Legislation or regulations that may be adopted to address climate change could also affect the markets for MV Partners’ products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with higher GHG-emitting energy sources, MV Partners’ products may become more desirable in the market with more stringent limitations on GHG emissions. To the extent that its products are competing with lower GHG-emitting energy, MV Partners’ products may become less desirable in the market with more stringent limitations on greenhouse gas emissions. MV Partners cannot predict with any certainty at this time how these possibilities may affect its operations.

The operations of the underlying properties are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact the operations of the properties.

Finally, some scientists have theorized that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such significant physical effects were to occur, they could have an adverse effect on MV Partners’ assets and operations and cause MV Partners to incur costs in preparing for and responding to them. Additionally, energy needs could increase or decrease as a result of extreme weather conditions, depending on the duration and magnitude of those conditions.

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 MV Partners 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.

National 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 — such as permits, leases, and rights-of-way. Driven by court decisions and Administration policy, NEPA implementation and resulting litigation changed dramatically in 2025. Key changes are driving agencies 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 USACE (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” before 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 reviews.

OSHA and Other Laws and Regulation. MV Partners is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and comparable state statutes require in certain circumstances that information be maintained concerning hazardous materials used or produced in MV Partners’ operations and that this information be provided to employees, state and local government authorities and citizens. MV Partners believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

MV Partners believes that it is in substantial compliance with all existing environmental laws and regulations applicable to the current operations of the underlying properties and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. For instance, MV Partners did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2023, 2024 and 2025.

Additionally, MV Partners has informed the Trust that MV Partners is not aware of any environmental issues or claims that will require material capital expenditures during 2026. Nevertheless, the passage of more

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stringent laws or regulations in the future could have a negative impact on the operations of the underlying properties and cash distributions to Trust unitholders.