Form 10-K - Annual report [Section 13 and 15(d), not S-K Item 405]

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

☒

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2024
or

☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-33219

MV OIL TRUST

(Exact name of registrant as specified in its charter)

	Delaware (State or other jurisdiction of incorporation or organization)			06-6554331 (I.R.S. Employer Identification No.)
	The Bank of New York Mellon Trust Company, N.A., Trustee Global Corporate Trust 601 Travis Street, Floor 16 Houston, Texas (Address of principal executive offices)			77002 (Zip Code)

Registrant’s telephone number, including area code: (713) 483-6020

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

	Title of each class			Trading Symbol(s)			Name of each exchange on which registered
	Units of Beneficial Interest			MVO			New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by checkmark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☐ No ☐

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

Large accelerated filer ☐

Accelerated filer ☐

Non-accelerated filer ☒

Smaller reporting company ☒
Emerging growth company ☐

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

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

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

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

The aggregate market value of the 8,625,000 Units of Beneficial Interest in MV Oil Trust held by non-affiliates of the registrant, computed using the closing sales price of $9.42 on June 28, 2024, was approximately $81,247,500.

As of March 20, 2025, 11,500,000 Units of Beneficial Interest in MV Oil Trust were outstanding.

Documents Incorporated By Reference: None

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	Page
Forward-Looking Statements		1
Glossary of Certain Oil and Natural Gas Terms		2
PART I
Item 1. Business		6
Item 1A. Risk Factors		28
Item 1B. Unresolved Staff Comments		41
Item 1C. Cybersecurity		41
Item 2. Properties		43
Item 3. Legal Proceedings		43
Item 4. Mine Safety Disclosures		43
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		44
Item 6. [Reserved]		44
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		44
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		48
Item 8. Financial Statements and Supplementary Data		49
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		59
Item 9A. Controls and Procedures		59
Item 9B. Other Information		60
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections		60
PART III
Item 10. Directors, Executive Officers and Corporate Governance		61
Item 11. Executive Compensation		61
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		61
Item 13. Certain Relationships and Related Transactions, and Director Independence		62
Item 14. Principal Accountant Fees and Services		63
PART IV
Item 15. Exhibit and Financial Statement Schedules		64
Item 16. Form 10-K Summary		65
SIGNATURES		66

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Form 10-K”) contains forward-looking statements about MV Partners, LLC (“MV Partners”) and MV Oil Trust (the “Trust”) that are subject to risks and uncertainties and that are intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included in this document, including, without limitation, statements under “Business” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth, and other plans and objectives for the future operations of MV Partners and the Trust, are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward- looking statements are subject to risks and uncertainties and include statements pertaining to future development activities and costs and other statements in this Form 10-K that are prospective and constitute forward-looking statements.

When used in this Form 10-K, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-K, could affect the future results of the energy industry in general, and MV Partners and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

•

risks incident to the drilling and operation of oil and natural gas wells;

•

future production and development costs and plans;

•

the occurrence or threat of epidemic or pandemic diseases or other public health events or any government response to such occurrence or threat;

•

the effects of actions by, or disputes among or between members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil-exporting nations, such as Russia, with respect to production levels or other matters related to the prices of oil and natural gas;

•

the impact of geopolitical developments and tensions, war and uncertainty involving or in the geographical region of oil-producing countries (including the ongoing armed conflicts between Russia and Ukraine and between Israel and Iran and its proxies and any related political or economic responses and counter-responses or otherwise by various global actors or the general effect on the global economy);

•

global economic conditions, such as a general slowdown in the global economy, trade barriers and tariffs, supply chain disruptions, inflationary pressures, currency fluctuations, changes in interest rates, and instability of financial institutions;

•

the effect of existing and future laws and regulatory actions;

•

the effect of changes in commodity prices and conditions in the capital markets;

•

competition from others in the energy industry;

•

ability of commodity purchasers to make payment;

•

weather conditions or force majeure events;

•

uncertainty of estimates of oil and natural gas reserves and production;

•

potential impacts on MV Partners’ business resulting from climate change, greenhouse gas regulations, and the impact of climate change related changes in the frequency and severity of weather patterns; and

•

other risks described under the caption “Risk Factors” in this Form 10-K.

This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of MV Partners and the Trust, including under the heading “Risk Factors” in Item 1A. All written and oral forward-looking statements attributable to MV Partners or the Trust or persons acting on behalf of MV Partners or the Trust are expressly qualified in their entirety by such factors.

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this Form 10-K the following terms have the meanings specified below.

Bbl — One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Boe — One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas and one Bbl of crude oil equals 1.54 Bbls of natural gas liquids.

Btu or British Thermal Unit — The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit.

Developed Acreage — The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development Well — A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

DUCs — Drilled but uncompleted. A well that has been drilled but has not undergone the final steps of perforating/acidizing or hydraulic fracturing and procedures necessary to place the well on production.

Estimated Future Net Revenues — Also referred to as “estimated future net cash flows.” The result of applying current prices of oil, natural gas and natural gas liquids to estimated future production from oil, natural gas and natural gas liquids proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves.

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

Gross Acres or Gross Wells — The total acres or wells, as the case may be, in which a working interest is owned.

Henry Hub — A distribution hub on the natural gas pipeline system in Erath, Louisiana. It is the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange and the over the counter swaps traded on Intercontinental Exchange. Spot and future natural gas prices set at Henry Hub are denominated in USD per MMBtu.

Mba — One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe — One thousand barrels of oil equivalent.

Mcf — One thousand standard cubic feet of natural gas.

MMBbls — One million barrels of crude oil or other liquid hydrocarbons.

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British Thermal Units.

MMcf — One million standard cubic feet of natural gas.

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

Net Profits Interest — A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

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Net Revenue Interest — An interest in all oil, natural gas and natural gas liquids produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

NGLs — Natural gas liquids.

NYMEX — New York Mercantile Exchange.

Plugging and Abandonment — Activities to remove production equipment and seal off a well at the end of a well’s economic life.

Proved Developed Non-Producing Reserves — Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved Developed Oil and Gas Reserves — Proved Oil and Gas Reserves that can be expected to be recovered:

(A)

through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(B)

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

Proved Developed Producing Reserves — Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved Oil and Gas Reserves — Those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(A)

The area of a reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(B)

In the absence of data on fluid contacts, proved quantities in the reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(C)

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(D)

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

(E)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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Proved Undeveloped Oil and Gas Reserves — Proved Oil and Gas Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(A)

Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(B)

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(C)

Under no circumstances are estimates for undeveloped reserves to be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Recompletion — The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

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

Standardized Measure of Discounted Future Net Cash Flows — Also referred to herein as “standardized measure.” It is the present value of estimated future net revenues computed by discounting estimated future net revenues at a rate of 10% annually.

The Financial Accounting Standards Board requires disclosure of standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities per accounting literature for extractive activities — oil and gas, as follows: A standardized measure of discounted future net cash flows relating to an enterprise’s interests in (a) proved oil and gas reserves and (b) oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the enterprise participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves shall be disclosed as of the end of the year. The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. The following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed:

Future cash inflows. These shall be computed by the average of the first-day-of-the-month prices during the 12-month period preceding the end of the year for 2022, 2023 and 2024 of oil and gas relating to the enterprise’s proved reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the enterprise’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions, tax credits and allowances relating to the enterprise’s proved oil and gas reserves.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

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Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

Working Interest — Also called an operating interest. The right granted to the lessee of a property to explore for and to produce and own oil, gas or other minerals. The working interest owner bears the exploration, development and operating costs on either a cash, penalty or carried basis.

Workover — Operations on a producing well to restore or increase production.

WTI Cushing — West Texas Intermediate, a type of crude oil used as a benchmark in oil pricing and the underlying commodity of NYMEX oil futures contracts for delivery at Cushing, Oklahoma.

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PART I

Item 1.

Business.

General

MV Oil Trust (the “Trust”) was formed in August 2006 by MV Partners, LLC (“MV Partners”). Much of the information disclosed in this Form 10-K has been provided to the Trust by MV Partners, including information associated with the underlying properties (as defined below) such as production and well counts, major producing areas, customer relationships, competition, marketing and post-production services, and certain information on which reserve data is based.

The Trust is a statutory trust created under the Delaware Statutory Trust Act pursuant to a Trust Agreement (as subsequently amended and restated, the “Trust Agreement”) among MV Partners, as trustor, The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”), and Wilmington Trust Company, as Delaware trustee (the “Delaware Trustee”). The Trust does not have any employees, and the business and affairs of the Trust are managed by the Trustee. The Trust maintains its offices at the office of the Trustee, at 601 Travis Street, Floor 16, Houston, Texas 77002. The telephone number of the Trustee is 1-855-802-1094. The Delaware Trustee has only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act.

The Trustee does not maintain a website for filings by the Trust with the Securities and Exchange Commission (the “SEC”). Electronic filings by the Trust with the SEC are available free of charge through the SEC’s website at www.sec.gov and at http://mvo.q4web.com/home/default.aspx.

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, 2024, the underlying properties produced predominantly oil from approximately 840 wells, and the projected reserve life of the underlying properties was over 35 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, 2024 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, approximately 98% were classified as proved developed producing reserves as of December 31, 2024. Production volumes from the underlying properties for the year ended December 31, 2024 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, 2024, cumulatively, since inception, the Trust has received payment for 80% of the net proceeds attributable to MV Partners’ interest from the sale of 14.7 MMBoe of production from the underlying properties (which amount is the equivalent of 11.8 MMBoe with respect to the Trust’s net profits interest). Consequently, 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). It is anticipated that the Trustee will make a final quarterly cash distribution, if any, 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

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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 20, 2025.

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

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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

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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

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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:

•

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, 2025 is $2,279,490.

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 $3.3 million in 2022, $3.4 million in 2023 and $3.6 million in 2024 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

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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.

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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

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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 2024 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.

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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, 2022, 2023 and 2024 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 33 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 2022, 2023 and 2024 is presented consistent with these requirements.

Proved Reserves of MV Oil Trust. The following table sets forth, as of December 31, 2024, 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		617		6		—		618
Proved Undeveloped		1		—		—		1
Total Proved		618		6		—		619

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, 2021		1948		87		—		1,962
Revisions of previous estimates		95		11		—		97
Production		(494)		(25)		—		(498)

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	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Oil Equivalents (MBoe)
Balance, December 31, 2022		1,549		73		—		1,561
Revisions of previous estimates		18		(14)		—		16
Production		(484)		(24)		—		(488)
Balance, December 31, 2023		1,083		35		—		1,089
Revisions of previous estimates		4		(7)		—		3
Production		(469)		(22)		—		(473)
Balance, December 31, 2024		618		6		—		619
Proved Developed Reserves:
Balance, December 31, 2021		1,861		87		—		1,875
Balance, December 31, 2022		1,493		73		—		1,505
Balance, December 31, 2023		1,069		35		—		1,075
Balance, December 31, 2024		617		6		—		618
Proved Undeveloped Reserves:
Balance, December 31, 2021		87		—		—		87
Proved undeveloped reserves converted to proved developed reserves by drilling		(31)		—		—		(31)
Additional proved undeveloped reserves added during 2022		27		—		—		27
Proved undeveloped reserves removed from drilling plan		(25)		—		—		(25)
Revisions of previous estimates		(1)		—		—		(1)
Balance, December 31, 2022		57		—		—		57
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		14		—		—		14
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		1		—		—		1

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.

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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, 2024 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, 2024 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			Proved Developed Non-Producing			Proved Undeveloped			Total Proved
	(dollars in thousands)
Net Reserves
Oil (MBbl)			767.7			3.0			1.3			772.1
Gas (MMcf)			7.2			0.0			0.0			7.2
NGL (MBbl)			0.1			0.0			0.0			0.1
Revenue
Oil		$	54,494.9		$	214.8		$	94.0		$	54,803.7
Gas			14.3			0.0			0.0			14.3
NGL			3.8			0.0			0.0			3.8
Severance Taxes			324.8			9.7			4.3			338.8
Ad Valorem Taxes			1,280.5			12.9			5.6			1,299.1
Operating Expenses			27,543.6			6.8			5.6			27,556.0
Future Development Costs			0.0			120.0			250.0			370.0
80% NPI Net Operating Income(1)		$	20,291.3		$	52.3		$	(137.2)		$	20,206.5
80% Net Profits Interest (NPI)(2)		$	18,966.6		$	44.3		$	(121.5)		$	18,889.4

(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. 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 $75.48 per Bbl and a Henry Hub natural gas price of $2.13 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 2024. 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

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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, 2024.

	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, 2024:

	Operated Wells				Non-Operated Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Oil		775		762		64		9		839		771
Natural gas		3		2		1		—		4		2
Total		778		764		65		9		843		773

The following is a summary of the number of developmental wells drilled by MV Partners on the underlying properties during the last three years. MV Partners did not drill any exploratory wells during the periods presented.

	Year Ended December 31,
	2022				2023				2024
	Gross		Net		Gross		Net		Gross		Net
Completed:
Oil wells		1		1		—		—		—		—
Natural gas wells		—		—		—		—		—		—
Non-productive		—		—		—		—		—		—
Total		1		1		—		—		—		—

During the years ended December 31, 2022, 2023 and 2024, MV Partners drilled, completed and commenced production with respect to 1, 0 and 0 wells, respectively, on the underlying properties. As of

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December 31, 2024, no wells were being drilled. Capital expenditures associated with converting proved undeveloped reserves to proved developed reserves for the year ended December 31, 2024, were approximately $62,454. 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,
	2022			2023			2024
Sales prices:
Oil (per Bbl)		$	89.97		$	73.85		$	72.09
Natural gas (per Mcf)		$	5.98		$	3.09		$	2.08
Lease operating expense (per Boe)		$	22.67		$	24.02		$	24.22
Lease maintenance (per Boe)		$	4.95		$	3.95		$	5.18
Lease overhead (per Boe)		$	5.41		$	5.80		$	6.30
Production and property taxes (per Boe)		$	1.64		$	1.88		$	2.07

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

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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

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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, 2022, 2023 and 2024, MV Purchasing purchased 74%, 73% 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, 2022, 2023 and 2024 was $4.17, $4.13 and $3.91 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, 2022, 2023 and 2024, MV Partners plugged and abandoned 6, 4 and 7 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:

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

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

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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;

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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;

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pooling, unitization and communitization agreements, declarations and orders;

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

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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

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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.

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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

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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:

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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;

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

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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

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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, can impact MV Partners’ regulatory and permitting obligations under the CWA. In 2023, the EPA and the USACE issued a final rule (the “2023 rule”) that is described by the EPA and the USACE as following the 1986 regulations as modified by subsequent U.S. Supreme Court decisions and guidance issued by the EPA and USACE interpreting the decisions. Shortly

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thereafter, the Supreme Court issued its decision in Sackett II which overturned a substantial portion of the basis for the 2023 rule. The USACE and the EPA subsequently amended the 2023 rule and excluded a number of types of wetlands and streams from CWA jurisdiction, but the rule is subject to litigation regarding the sufficiency of the agencies’ interpretation of the Sackett II decision. The 2023 rule is presently in effect in about half of the states while it is enjoined in the other half. In those states where the rule is enjoined, the EPA and the USACE define WOTUS in accordance with an earlier regulatory definition adjusted in light of the Supreme Court’s Sackett II decision. 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. NWP 12 will expire in March 2026 and be replaced with a new version. In addition, a federal court in Washington, D.C. is currently hearing a challenge to NWP 12. An adverse decision in the litigation may restrict or remove the ability to use NWP 12 to permit regulated impacts, resulting in the need to apply for a more time-consuming individual permit. This could result in additional cost and time for permitting projects.

In February 2025, the USACE began implementing emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency. This may result 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

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existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

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. More recently, however, in February 2024, the EPA announced a final rule that will lower the annual standard for fine particulate matter from 12 micrograms per cubic meter to 9 micrograms per cubic meter. State or federal implementation of the NAAQS could result in stricter permitting or regulatory requirements, delay or prohibit MV Partners’ ability to obtain such permits, and result in increased expenditures for pollution control equipment.

The 2024 presidential election in the United States may impact the air quality-related requirements that apply to MV Partners. The Trump Administration may adopt a different approach to many actions taken under the prior presidential administration, including the 2024 revisions to the emissions standards and guidelines for new and existing sources in the oil and gas industry, as well as the 2024 changes to the NAAQS for fine particulate matter. The outcome of the Trump Administration’s evaluation of the prior administration’s regulatory approach is not certain at this time, but President Trump has made it clear that his energy agenda prioritizes an increase in domestic oil and gas production.

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. In response to its 2009 finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in 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. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. President Trump also issued an executive order directing the EPA to review the legality and continuing applicability of its 2009 GHG endangerment finding. The outcome of that review is not currently known; however, it has the potential to eliminate the basis for the EPA’s regulation of GHGs under the CAA.

The EPA has established GHG standards for oil and gas sources based on the GHG endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require reductions in GHG and volatile organic compound emissions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

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

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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 February 2025, the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the Congressional Review Act (“CRA”), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA. In addition, the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

In addition to the federal actions, more than one third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state level initiatives to date have focused on large sources of GHG emissions, such as coal fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. 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 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. On August 27, 2019, the U.S. Fish and Wildlife Service published a final rule adopting several changes to the federal regulations that implement the ESA, including changes to the procedures and criteria for listing or removing species from the Lists of Endangered and Threatened Wildlife and Plants and for designating critical habitat. The Biden Administration rescinded one of the rules adopted by the prior administration, dealing with critical habitat, and issued a revised rule making changes to the federal consultation process. These changes could make a federal review process occasioned by the application for permits, rights of way, or leases more complex in certain circumstances. In addition, designation of new species as threatened

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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. 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. 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. CEQ issued its rules after being directed to do so by an Executive Order issued in the Carter Administration. After two federal courts held that CEQ did not have authority to issue binding regulations, the Trump Administration revoked the Carter Administration Executive Order and directed CEQ to withdraw the regulations. In their place, agencies are directed to develop procedures that hew to the statutory text over the course of 2025 with the goal of having them finalized in early 2026. In the meantime, agencies will continue to use their own NEPA procedures and may continue to follow the CEQ regulations, using them as guidance. This may result in delays and uncertainty in permitting reviews as agencies adjust to a new NEPA approach.

OSHA and Other Laws and Regulation. MV Partners is subject to the requirements of the federal Occupational Safety and Health Act, or “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, 2022, 2023 and 2024. 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 2024. Nevertheless, the passage of more 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.

Item 1A. Risk Factors

Operating Risks

Prices of oil, natural gas and natural gas liquids fluctuate, and lower prices could reduce proceeds to the Trust and cash distributions to Trust unitholders.

The reserves attributable to the underlying properties and the quarterly cash distributions of the Trust are highly dependent upon the prices realized from the sale of oil, natural gas and natural gas liquids. Prices of oil, natural gas and natural gas liquids can fluctuate widely on a quarter-to-quarter basis in response to a variety of factors that are beyond the control of the Trust and MV Partners. These factors include, among others:

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regional, domestic and foreign supply and perceptions of supply of oil, natural gas and natural gas liquids;

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the level of demand and perceptions of demand for oil, natural gas and natural gas liquids;

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political conditions or hostilities in oil and natural gas producing regions, including the Middle East, North Africa and South America;

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the armed conflicts between Russia and Ukraine and between Israel and Iran and its proxies and the potential destabilizing effects such conflicts may pose for the global oil and gas markets;

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the occurrence or threat of epidemic or pandemic diseases or other public health events or any government response to such occurrence or threat;

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the actions of OPEC, its members and other oil-producing nations, such as Russia, relating to oil price and production levels, including announcements of potential changes to such levels;

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the levels of production of oil and natural gas of non-OPEC countries;

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anticipated future prices of oil and natural gas and other commodities;

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weather conditions and seasonal trends;

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technological advances affecting energy consumption and energy supply;

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U.S. and worldwide economic conditions;

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trade barriers and tariffs;

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the price and availability of alternative fuels;

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the proximity, capacity, cost and availability of refineries and gathering and transportation facilities;

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the volatility and uncertainty of regional pricing differentials;

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governmental regulations and taxation;

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energy conservation and environmental measures; and

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acts of force majeure.

Crude oil prices have been volatile during the last several years, and in 2024 ranged from a high of $86.91 to a low of $65.75. The NYMEX crude oil prices per Bbl were $80.26, $71.65 and $71.72 as of December 31, 2022, 2023 and 2024, respectively. Neither MV Partners nor the Trust can predict the timing or the duration of any economic cycle and, depending on the prices realized, the operating results of MV Partners and the financial condition of the Trust could be materially and adversely affected.

The terms of the Conveyance prohibit MV Partners from entering into hedging arrangements for the benefit of the Trust. As a result, the amounts of cash distributions by the Trust may fluctuate significantly as a result of changes in commodity prices because there will be no hedge contracts in place to reduce the effects of any changes in commodity prices.

Low prices of oil, natural gas and natural gas liquids will reduce the amount of the net proceeds to which the Trust is entitled and may ultimately reduce the amount of oil, natural gas and natural gas liquids that is economic to produce from the underlying properties. As a result, the operator of any of the underlying properties could determine during periods of low commodity prices to shut in or curtail production from wells on the underlying properties, or to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices.

Because the underlying properties are mature, with many of them being in production since the early 1900s, decreases in commodity prices could have a more significant effect on the economic viability of these properties compared to more recently discovered properties. The commodity price sensitivity of these mature wells is due to a culmination of factors that vary from well-to-well, including the additional costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the amount of future cash distributions to Trust unitholders to fluctuate, and a substantial decline in the price of oil, natural gas or natural gas liquids will reduce the amount of cash available for distribution to the Trust unitholders.

Sustained lower prices of oil and natural gas also could negatively affect the price of the Trust Units and the qualification of the Trust Units to remain listed on the New York Stock Exchange.

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

The value of the Trust Units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the production and reserves estimated to be attributable

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to the underlying properties and the net profits interest. Estimating production and reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties could vary both positively and negatively from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating production and reserves. Those factors and assumptions include:

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historical production from the area compared with production rates from other producing areas;

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the assumed effect of governmental regulation; and

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assumptions about future prices of oil, natural gas and natural gas liquids, production and development expenses, gathering and transportation costs, severance and excise taxes and capital expenditures.

Changes in these assumptions could materially decrease production and reserve estimates.

The estimated reserves attributable to the net profits interest and the estimated future net revenues attributable to the net profits interest are based on estimates of reserve quantities and revenues for the underlying properties. See “Item 1. Business — Description of the Underlying Properties — Reserves” for a discussion of the method of allocating proved reserves to the underlying properties and the net profits interest. The quantities of reserves attributable to the underlying properties and the net profits interest may decrease in the future as a result of future decreases in the prices of oil, natural gas or natural gas liquids.

Risks associated with the production, gathering, transportation and sale of oil, natural gas and natural gas liquids could adversely affect cash distributions by the Trust.

The net proceeds payable to the Trust, the value of the Trust Units and the amount of cash distributions to the Trust unitholders depend upon, among other things, the costs incurred by MV Partners to develop and exploit oil and natural gas reserves attributable to the underlying properties. Drilling, production, or transportation accidents that temporarily or permanently halt the production and sale of oil, natural gas, and natural gas liquids at any of the underlying properties will reduce Trust distributions by reducing the amount of net proceeds available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. Any costs incurred by MV Partners in connection with any such accidents that are not insured against will have the effect of reducing the net proceeds payable to the Trust and available for distribution to Trust unitholders.

In addition, curtailments or damage to pipelines used by MV Partners to transport oil, natural gas and natural gas liquid production to markets for sale could reduce the amount of net proceeds available for distribution. Any such curtailment or damage to the gathering systems used by MV Partners could also require MV Partners to find alternative means to transport the oil, natural gas and natural gas liquid production from the underlying properties, which alternative means could require MV Partners to incur additional costs that will have the effect of reducing net proceeds available for distribution by the Trust. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production activities.

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices, which could reduce the amount of cash available for distribution to Trust unitholders.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, such as Russia, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices OPEC members and other oil exporting nations might not agree to future production cuts or other actions to support and stabilize oil prices, and they may not reduce oil prices or increase production in the future. Uncertainty regarding future actions that OPEC members or other oil exporting countries may take could lead to continued volatility in the price of oil, which could adversely affect the financial condition and economic performance of the operators of the underlying properties and may

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reduce the net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders.

Production of oil, natural gas and natural gas liquids on the underlying properties could be materially and adversely affected by severe or unseasonable weather.

Production of oil, natural gas and natural gas liquids on the underlying properties could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:

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evacuation of personnel and curtailment of operations;

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weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;

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inability to deliver materials to worksites; and

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weather-related damage to pipelines and other transportation facilities.

Interruptions in production could have a material adverse effect on the Trust’s financial condition, results of operations and cash flows, and could reduce the amount of cash distributions to Trust unitholders.

Shortages or increases in costs of oil field equipment, services and qualified personnel available to MV Partners could reduce the amount of cash available for distribution to Trust unitholders.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment, and services. Shortages of field personnel and equipment or price increases could significantly decrease the amount of cash available for distribution to the Trust unitholders or restrict the ability of MV Partners to drill the wells and conduct the operations which it currently has planned for the underlying properties.

Financial Risks

The reserves attributable to the underlying properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production.

The net proceeds payable to the Trust from the net profits interest are derived from the sale of oil, natural gas and natural gas liquids produced from the underlying properties. The reserves attributable to the underlying properties are depleting assets, which means that those reserves will decline over time. As a result, the quantity of oil and natural gas produced from the underlying properties is expected to decline over time. Based on the estimated production volumes in the reserve report, the oil and natural gas production from proved reserves attributable to the underlying properties is projected to decline at an average annual rate of approximately 9.72% over the next 20 years assuming no additional developmental drilling or other capital expenditures are made after 2026 on the underlying properties. The anticipated rate of decline is an estimate and actual decline rates may vary from those estimated. The net profits interest will terminate on 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 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 net profits interest will terminate on the Termination Date, at which point the Trust will dissolve and commence winding up its business and affairs. Once the Trust winds up and terminates, it will pay no further distributions to Trust unitholders.

Future maintenance projects on the underlying properties beyond those which are currently estimated may affect the quantity of proved reserves that can be economically produced from the underlying properties. The timing and size of these projects will depend on, among other factors, the market prices of oil, natural

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gas, and natural gas liquids. In addition, because MV Partners has agreed to limit the amount of capital expenditures that may be taken into account in calculating net proceeds attributable to the net profits interest during a specified period preceding the termination of the net profits interest, MV Partners may choose to delay certain capital projects that may otherwise benefit the Trust unitholders until the termination of the net profits interest. If operators of the wells to which the underlying properties relate do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by MV Partners or estimated in the reserve report.

The Trust Agreement provides that the Trust’s business activities are limited to owning the net profits interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the Conveyance related to the net profits interest. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the net profits interest.

Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of the distributions to Trust unitholders attributable to depletion may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the underlying properties burdened by the net profits interest may cease to produce in commercially paying quantities and the Trust may, therefore, cease to receive any distributions of net proceeds therefrom.

The amount of cash available for distribution by the Trust will be reduced by the amount of any production and development costs, taxes, capital expenditures and post-production costs.

Production and development costs on the underlying properties are deducted in the calculation of the net proceeds payable to the Trust. In addition, production and property taxes, capital expenditures or post- production costs are deducted in the calculation of the net proceeds payable to the Trust. Accordingly, higher production and development expenses, taxes, capital expenditures and post-production costs will directly decrease the amount of cash received by the Trust in respect of its net profits interest. For a summary of these costs for the last three years, see “Item 1. Business — Description of the Underlying Properties — Producing Acreage and Well Counts.” Historical costs may not be indicative of future costs. In addition, cash available for distribution by the Trust will be further reduced by the Trust’s general and administrative expenses.

If development and production costs of the underlying properties exceed the proceeds of production from the underlying properties, the Trust will not receive net proceeds from those properties until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. If annual cash proceeds received by the Trust are less than $1.0 million for each of two consecutive years, then under the terms of the Trust Agreement, the Trust would be required to dissolve.

The Trust has established a cash reserve for contingent liabilities and to pay expenses in accordance with the Trust Agreement, which would reduce net profits payable to the Trust and distributions to Trust unitholders.

The Trust’s source of capital is the cash flows from the net profits interest. Pursuant to the Trust Agreement, the Trust may establish a cash reserve through the withholding of cash for contingent liabilities and to pay expenses, which will reduce the amount of cash otherwise available for distribution to Trust unitholders.

A purchaser’s failure to pay MV Partners for purchased production could have a significant adverse impact on MV Partners, which in turn could result in MV Partners not having sufficient net proceeds attributable to the net profits interest for MV Partners to distribute cash to the Trust.

A purchaser’s failure to pay for purchased production could have a significant adverse impact on MV Partners’ business, which in turn could adversely affect the Trust. A tightening of credit in the financial

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markets may make it more difficult for purchasers to obtain financing, and depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by such purchasers, which may reduce the net proceeds payable to the Trust and the amount of cash available for distribution to Trust unitholders.

If the financial position of MV Partners degrades in the future, MV Partners may not be able to satisfy its obligations to the Trust.

MV Partners is a privately held limited liability company engaged in the exploration, development, production, gathering and aggregation and sale of oil and natural gas, primarily in the Mid-Continent region in the United States, and it is responsible for operating substantially all of the underlying properties. The operating agreement of MV Partners provides that Vess Oil and Murfin Drilling will operate the underlying properties on behalf of MV Partners for which MV Partners is designated as the operator. The Conveyance provides that MV Partners is obligated to market, or cause to be marketed, the production related to the underlying properties.

The ability of MV Partners to perform its obligations related to the operation of the underlying properties will depend on MV Partners’ future financial condition and economic performance, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions, collections of payments due from third parties, and upon financial, business, and other factors, many of which are beyond the control of MV Partners. If MV Partners were to be unable to perform its obligations to the Trust, it could have a material adverse effect on the net proceeds payable to the Trust and the amount of cash available for distribution to Trust unitholders.

Risks Related to the Structure of the Trust

The Trust and the public Trust unitholders have no voting or managerial rights with respect to MV Partners, the operator of the underlying properties. As a result, public Trust unitholders have no ability to influence the operation of the underlying properties.

Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property.

MV Partners is currently designated as the operator of substantially all of the underlying properties. MV Partners has contracted with two of its affiliates, Vess Oil and Murfin Drilling, to operate these properties on its behalf. Neither the Trustee nor the public Trust unitholders has any contractual ability to influence or control the field operations of, sale of oil and natural gas from, or future development of, these properties. The public Trust unitholders also have no voting rights with respect to MV Partners and, therefore, have no managerial, contractual, or other ability to influence MV Partners’ or its affiliates’ activities as operator of the oil and natural gas properties to which substantially all of the underlying properties relate.

MV Partners may transfer all or a portion of the underlying properties at any time, subject to specified limitations, and MV Partners may abandon individual wells or properties that it reasonably believes to be uneconomic. Under these circumstances, Trust unitholders have no ability to prevent MV Partners from transferring the underlying properties to another operator, even if the Trust unitholders do not believe that operator would operate the underlying properties in the same manner as MV Partners.

MV Partners may at any time transfer all or part of the underlying properties. Trust unitholders are not entitled to vote on any transfer of the underlying properties, and the Trust will not receive any proceeds from any such transfer, except in the limited circumstances when the net profits interest is released in connection with such transfer, in which case the Trust will receive an amount equal to the fair market value of the net profits interest released. See “Item 1. Business — Description of the Underlying Properties — Sale and Abandonment of Underlying Properties.” Following any material sale or transfer of any of the underlying properties, such underlying properties will continue to be subject to the net profits interest of the

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Trust, 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. MV Partners may delegate to the transferee responsibility for all of MV Partners’ obligations relating to the net profits interest on the portion of the underlying properties transferred.

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’s 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 will be distributable to Trust unitholders for the quarter in which they are received.

MV Partners or any transferee of the underlying properties may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially economic quantities. This could result in termination of the net profits interest relating to the abandoned well or property. In making such decisions, MV Partners and any such transferee will be 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.

The Trustee may, under certain circumstances, sell the net profits interest and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.

The Trustee must sell the net profits interest if the holders of a majority of the Trust Units approve the sale or vote to dissolve the Trust. The sale of the net profits interest will result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders; however, Trust unitholders may not recover their investment in the Trust Units.

The Trust will dissolve and commence winding up its business and affairs upon the Termination Date, which is June 30, 2026, the date on which the net profits interest will terminate. After the Termination Date, it is anticipated that the Trustee will make a final quarterly cash distribution, if any, to the Trust unitholders of record on the 15th day following June 30, 2026. Other than such potential payment, the Trust unitholders will not be entitled to receive any net proceeds from the sale of production from the underlying properties following the Termination Date. Therefore, the market price of the Trust Units will approach and eventually reach zero shortly after the end of the net profits interest term because cash distributions from the Trust will cease following the termination of the net profits interest, and the Trust will have no right to any additional production from the underlying properties after the term of the net profits interest.

Conflicts of interest could arise between MV Partners and the Trust unitholders.

As a working interest owner in the underlying properties, MV Partners could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:

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MV Partners’ interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the underlying properties. MV Partners may make decisions with respect to development expenditures that adversely affect the underlying properties. These decisions include reducing development expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future, or increasing development expenditures on the underlying properties during the final years of the term of the Trust, which expenditures will benefit the Trust unitholders only to the extent that they reduce the natural decline in oil and natural gas production during the term of the Trust by an amount that more than offsets the cost of these development expenditures.

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MV Partners may sell some or all of the underlying properties and such sale may not be in the best interests of the Trust unitholders. If MV Partners sells all or any portion of the underlying properties, the purchaser of such underlying properties will acquire such underlying properties subject to the

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net profits interest relating thereto and, in connection therewith, such purchaser will be subject to the same standards of conduct with respect to development, operation and abandonment of such underlying properties as are currently imposed on MV Partners. MV Partners also has the right, subject to significant limitations as described herein, to cause the Trust to release all or a portion of the net profits interest in connection with a sale of a portion of the underlying properties to which such net profits interest relates. In such an event, the Trust is entitled to receive its proportionate share of the proceeds from the sale attributable to the net profits interest released. See “Item 1. Business — Description of the Underlying Properties — Sale and Abandonment of Underlying Properties.”

In addition, affiliates of MV Partners may engage in activities whereby such affiliates could have interests that conflict with the interests of MV Partners, which could, depending on the circumstances, negatively impact MV Partners’ business.

In making decisions with respect to the development, operation, abandonment or sale of the underlying properties, MV Partners and any successor operator will be 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. Except for specified matters that require approval of the Trust unitholders, the documents governing the Trust do not provide a mechanism for resolving these conflicting interests.

The Trust is managed by a Trustee who cannot be replaced except by a majority vote of Trust unitholders holding a majority of the Trust Units at a special meeting, which may make it difficult for Trust unitholders to remove or replace the Trustee.

The business and affairs of the Trust are managed by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Trust Units at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust Units. MV Energy and VAP-I, LLC (“VAP-I”) collectively own 25% of the outstanding Trust Units. As a result, it will be difficult to remove or replace the Trustee, particularly without the approval of the members of MV Partners.

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

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted which could not be accrued in GAAP financial statements.

The Trust is a smaller reporting company and benefits from certain reduced governance and disclosure requirements, including that the Trust’s independent registered public accounting firm is not required to attest to the effectiveness of the Trust’s internal control over financial reporting. The Trust cannot be certain if the omission of reduced disclosure requirements applicable to smaller reporting companies will make the Trust Units less attractive to investors.

Currently, the Trust is a “smaller reporting company,” meaning that the outstanding Trust Units held by nonaffiliates had a value of less than $250 million at the end of the Trust’s most recently completed second fiscal quarter. As a smaller reporting company, the Trust is not required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, meaning the Trust’s auditors are not required to attest to the effectiveness of the Trust’s internal control over financial reporting. As a result, investors and others may be less comfortable with the effectiveness of the Trust’s internal controls and the risk that material weaknesses or other deficiencies in internal controls go undetected may increase. In addition, as a smaller reporting company, the Trust takes advantage of its ability to provide certain other less comprehensive disclosures in its SEC filings, including, among other things, providing only two years of audited financial statements in annual reports. Consequently, it may be more challenging for investors to

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analyze the Trust’s results of operations and financial prospects, as the information the Trust provides to Trust unitholders may be different from what one might receive from other public companies in which one holds shares. As a smaller reporting company, the Trust is not required to provide this information.

Risks Related to Ownership of the Trust Units

The market price for the Trust Units may not reflect the value of the net profits interest held by the Trust and, in addition, over time will decline to zero around or shortly after the termination date of the net profits interest, June 30, 2026.

The trading price for publicly traded securities similar to the Trust Units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing sales prices of oil, natural gas and natural gas liquids production attributable to the underlying properties. Further, the market price of Trust Units may be affected by factors other than the anticipated future Trust distributions. Consequently, the market price for the Trust Units may not necessarily be indicative of the value that the Trust would realize if it sold the net profits interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid, if any, on the Trust Units should be considered by investors as a return of capital, with the remainder, if any, being considered as a return on investment. As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the unitholder, and over time the market price of the Trust Units will decline to zero around or shortly after the Termination Date, which is June 30, 2026, the date on which the net profits interest will terminate. After the Termination Date, it is anticipated that the Trustee will make a final quarterly cash distribution, if any, to the Trust unitholders of record on the 15th day following June 30, 2026. If the Trust Units are trading at a price substantially in excess of the aggregate distributions that may reasonably be expected to be made prior to the termination of the Trust, the price decline is likely to include one or more abrupt substantial decreases.

The disposal by the two members of MV Partners of their remaining Trust Units may reduce the market price of the Trust Units.

As of the date of this Form 10-K, the two members of MV Partners, MV Energy and VAP-I, owned 25% of the outstanding Trust Units. The two members of MV Partners may use some or all of the remaining Trust Units they own for a number of corporate purposes, including:

•

selling them for cash; and

•

exchanging them for interests in oil and natural gas properties or securities of oil and natural gas companies.

If they sell additional Trust Units or exchange Trust Units in connection with acquisitions, then additional Trust Units will be available for sale in the market. The sale of additional Trust Units may reduce the market price of the Trust Units. MV Partners and the Trust have entered into a registration rights agreement pursuant to which the Trust has agreed to file a registration statement or a shelf registration statement to register the resale of the remaining Trust Units held by MV Partners and any transferee of the Trust Units upon request by such holders. See “Item 13. Certain Relationships and Related Transactions, and Director Independence — Registration Rights.”

The market price for the Trust Units may not reflect the value of the net profits interest held by the Trust.

The market price for publicly traded securities similar to the Trust Units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing prices for sales of oil, natural gas and natural gas liquid production from the underlying properties. Consequently, the market price for the Trust Units may not necessarily be indicative of the value that the Trust would realize if it sold the net profits interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust Units should be considered by investors as a return of capital, with the remainder being considered as a return

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on investment. As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the Trust unitholder.

Trust unitholders have limited ability to enforce provisions of the net profits interest.

The Trust Agreement permits the Trustee to sue MV Partners or any other future owner of the underlying properties on behalf of the Trust to enforce the terms of the Conveyance creating the net profits interest. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, recourse of the Trust unitholders would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust Agreement expressly limits the Trust unitholders’ ability to directly sue MV Partners or any other third party other than the Trustee. As a result, the unitholders will not be able to sue MV Partners or any future owner of the underlying properties to enforce these rights. Furthermore, the Conveyance provides that, except as set forth in the Conveyance, MV Partners will not be liable to the Trust for the manner in which it performs its duties in operating the underlying properties as long as it acts without gross negligence or willful misconduct.

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

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

Legal, Environmental and Regulatory Risks

The Trust’s net profits interest may be characterized as an executory contract in bankruptcy, which could be rejected in bankruptcy, thus relieving MV Partners from its obligations to make payments to the Trust with respect to the net profits interest.

MV Partners has recorded the Conveyance in Kansas 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 constitute fully conveyed and vested property interests in the Trust under Kansas law. If in a bankruptcy proceeding in which MV Partners becomes involved as a debtor 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. The net profits interest is a non- operating, non-possessory interest 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.

The operations of the underlying properties are subject to environmental laws and regulations and operational safety matters that may result in significant costs and liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.

Significant costs and liabilities can be incurred as a result of environmental and safety requirements applicable to the oil and natural gas exploration, development and production activities of the underlying

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properties. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of the operations of the underlying properties.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause liability for the conduct of others or for the consequences of one’s own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If it were not possible to recover the resulting costs through insurance or increased revenues, this could have a material adverse effect on the cash distributions to the Trust unitholders. Please read “Item 1. Business — Description of the Underlying Properties — Regulation — Environmental Matters and Regulation” for more information.

Governmental authorities may enact climate change regulations that could increase MV Partners’ costs to operate and, therefore, adversely affect distributions to the Trust unitholders.

From time to time, the U.S. Congress has considered legislation directed at reducing greenhouse gas emissions. The EPA has proposed rules to regulate greenhouse gases and regional initiatives have formed to control greenhouse gases. Additionally, the states in which MV Partners operates may implement air pollution control regulations that are more stringent than existing and proposed federal regulations, in particular the regulation of emissions of greenhouse gases. The adoption of laws and regulations to implement controls of greenhouse gases, including the imposition of fees or taxes, could adversely affect MV Partners’ operations and, therefore, distributions to the Trust unitholders.

Regulation of greenhouse gases and climate change could adversely affect Trust distributions.

In response to its 2009 finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in 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. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. President Trump also issued an executive order directing the EPA to review the legality and continuing applicability of its 2009 GHG endangerment finding. The outcome of that review is not currently known; however, it has the potential to eliminate the basis for the EPA’s regulation of GHGs under the CAA.

The EPA has established GHG standards for oil and gas sources based on its 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 further emissions reductions 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 for existing sources arriving in 2029.

The Inflation Reduction Act of 2022 (“IRA”) included new CAA 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

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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 the 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 February 2025, the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the Congressional Review Act (“CRA”), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA. In addition, the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

Additionally, 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 have to date 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. In addition, Congress may consider adopting 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 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 less desirable than competing sources of energy. 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.

In addition, new and emerging regulatory initiatives in the U.S. related to climate change could adversely affect the Trust. In 2024, the SEC issued a final rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The final rule mandates extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy and greenhouse gas emissions, for certain public companies. Compliance with the final rule may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on the personnel, systems and resources of MV Partners or the Trust or both. The SEC’s climate disclosure requirements may change under the Trump Administration. In February 2025, the acting SEC Chair issued a statement that the SEC would not defend the 2024 disclosure rule in court and that the SEC would revisit the 2024 rule. The outcome of the SEC’s review may result in changes to SEC climate-related disclosure requirements, but the outcome of that review is uncertain. Even in the absence of federal requirements, however, some states have adopted climate disclosure laws or rules that are not affected by the SEC’s review.

The operations of the underlying properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cash distributions to the Trust unitholders.

The exploration, development and production operations of the underlying properties are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these

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laws and regulations, MV Partners must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. MV Partners may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, and the net profits interest will bear its share of these costs. In addition, the costs of compliance may increase or the operations of the underlying properties may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to such operations. Such costs could have a material adverse effect on the cash distributions to the Trust unitholders.

Laws and regulations governing exploration and production may also affect production levels. MV Partners is required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. These and other laws and regulations can limit the amount of oil and natural gas MV Partners can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.

New laws or regulations, or changes to existing laws or regulations, may unfavorably impact MV Partners, could result in increased operating costs or have a material adverse effect on MV Partners’ financial condition and results of operations and reduce the amount of cash received by the Trust. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations could increase the operating costs of the underlying properties, reduce MV Partners’ liquidity, delay MV Partners’ operations or otherwise alter the way MV Partners conducts its business, any of which could have a material adverse effect on the net profits interest and the Trust’s cash flows.

Tax Risks Related to the Trust Units

The Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust Units or the tax treatment of the net profits interest. If the IRS were to determine (and be sustained in that determination) that the Trust is not a grantor Trust for federal income tax purposes, or that the net profits interest is not a debt instrument for federal income tax purposes, the Trust unitholders may receive different and less advantageous tax treatment than that described in this Form 10-K.

Tax counsel to MV Partners advised the Trust at the time of formation that, for federal income tax purposes, in its opinion MV Partners will be treated as a grantor Trust and not as an unincorporated business entity. Tax counsel to MV Partners 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.

If the net profits interest were not treated as a debt instrument, or if the Trust were not treated as a grantor Trust, for federal income tax purposes, the tax treatment of tax items in respect of an investment in Trust Units may be affected. The effects of this different tax treatment may be less advantageous to Trust unitholders.

Neither MV Partners nor the Trustee has requested a ruling from the IRS regarding these tax questions. Such a ruling may not be granted if requested; moreover, the IRS could challenge these positions on audit. See “Item 1. Business — Federal Income Tax Matters” for more information about the various matters described under this risk factor.

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Cybersecurity Risks

Cyber-attacks or other failures in telecommunications or information technology systems could result in information theft, data corruption and significant disruption of MV Partners’ business operations.

MV Partners relies on information technology (“IT”) systems and networks in connection with its business activities, including exploration, development and production activities. MV Partners relies on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. These threats pose a risk to the security of MV Partners’ systems and networks, the confidentiality, availability and integrity of its data and the physical security of its employees and assets. MV Partners has experienced, and expects to continue to experience, attempts from hackers and other third parties to gain unauthorized access to its IT systems and networks. Although prior cyber-attacks have not had a material adverse effect on MV Partners’ operations or financial performance, MV Partners may not be successful in preventing cyber-attacks or mitigating their effect. Any cyber-attack could have a material adverse effect on MV Partners’ reputation, competitive position, business, financial condition and results of operations, and could have a material adverse effect on the Trust. Cyber-attacks or security breaches also could result in litigation or regulatory action, as well as significant additional expense to MV Partners to implement further data protection measures.

In addition to the risks presented to MV Partners’ systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack of this nature would be outside MV Partners’ ability to control but could have a material adverse effect on MV Partners’ business, financial condition and results of operations, and could have a material adverse effect on the Trust.

Cyber-attacks or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of the Trustee’s operations.

The Trustee depends heavily upon IT systems and networks in connection with its business activities. Despite a variety of security measures implemented by the Trustee, events such as the loss or theft of back-up tapes or other data storage media could occur, and the Trustee’s computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within the respective companies.

If a cyber-attack were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the Trustee’s computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust, which could result in litigation, increased costs and regulatory penalties. Although steps are taken to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.

Item 1B. Unresolved Staff Comments.

None.

Item 1C. Cybersecurity.

The Trust has no directors or executive officers. The affairs of the Trust are managed by the Trustee. The Trust falls under the cybersecurity program of The Bank of New York Mellon Corporation (“BNY Mellon”), the parent corporation of The Bank of New York Mellon Trust Company, N.A. As further described in its 2024 Annual Report, BNY Mellon maintains a broad range of defenses aimed at remaining

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abreast of and responding to evolving cybersecurity threats impacting it, its operations, its clients, its third-party service providers and the broader financial services sector.

Risk Management Strategy and Procedures

BNY Mellon has implemented policies and procedures designed to detect, prevent and respond to malicious and accidental disruptions to the delivery of critical technology services. BNY Mellon’s cybersecurity risk management program is embedded in its three lines of defense model.

As part of its first line of defense, BNY Mellon maintains a dedicated Information Security Division (“ISD”), led by the Chief Information Security Officer (the “CISO”), that is responsible for the day-to-day management of risks from cybersecurity threats. ISD’s responsibilities include cybersecurity threat intelligence, incident response and other cybersecurity operations aimed at enabling BNY Mellon to identify, assess and manage existing and emerging cybersecurity threats. ISD monitors for potential threats and communicates relevant risks to the CISO and other members of executive management. Additionally, ISD maintains a cybersecurity incident response and reporting process pursuant to which cybersecurity incidents are classified according to their severity based upon an assessment of multiple factors. Certain cybersecurity incidents may activate enterprise-wide resiliency processes, which include, among other things, escalation through the management and Board committee structures described below. In addition, BNY Mellon maintains a preparedness program designed to reinforce cybersecurity risk management practices and compliance with BNY Mellon’s policies and procedures. The preparedness program includes mandatory training for all employees, contractors and consultants, enhanced training for those in roles presenting higher risk, calibrated phishing email simulations, distribution of information security awareness materials and cybersecurity event simulation exercises. In addition, BNY Mellon leverages both internal and external assessments and engages with third-party assessors, consultants and auditors to evaluate and test its cybersecurity controls and provide guidance on potential improvements, including design and operating effectiveness. BNY Mellon has standing arrangements with third parties to assist BNY Mellon in identifying, assessing and managing cybersecurity threats, including in connection with risk assessments, penetration testing, legal advice and other aspects of BNY Mellon’s cybersecurity risk management and incident response processes.

BNY Mellon has a defined third-party governance framework to help manage the risk posed to it by the use of third-party service providers. BNY Mellon evaluates the risk posed by third-party service engagements based on multiple factors. BNY Mellon has protocols that seek to mitigate cybersecurity risks associated with third-party service providers based on the risk level assigned to such third party, which may include mandatory contractual obligations or the implementation of additional controls by BNY Mellon and/or the applicable service provider.

ISD is subject to ongoing review and challenge from Technology Risk Management, which is a part of the independent second line of defense risk function. Technology Risk Management, together with the broader Risk & Compliance group, is responsible for and manages BNY Mellon’s risk management framework and establishes guidance for ISD and management designed to help identify, assess and manage cybersecurity risk.

BNY Mellon’s Internal Audit function serves as the third line of defense and provides an independent view on how effectively the organization as a whole manages cybersecurity risk.

Risk Management Oversight and Governance

BNY Mellon’s management is responsible for assessing and managing BNY Mellon’s material risks from cybersecurity threats with oversight provided by its Board of Directors (the “Board”) and the Board committees. The Risk Committee of the Board has primary responsibility for oversight of the overall operation of BNY Mellon’s risk management framework, including policies and practices addressing cybersecurity risk, and is responsible for the oversight of the second line of defense with respect to its cybersecurity risk management responsibilities. The Technology Committee of the Board and the full Board regularly receive reports and briefings from management concerning cybersecurity matters, including any significant changes to BNY Mellon’s cybersecurity program. BNY Mellon also has protocols for escalating cybersecurity threats and incidents to the Technology Committee of the Board and the full Board. In addition, the Audit

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Committee of the Board monitors and oversees the performance of Internal Audit, including with respect to its cybersecurity risk management responsibilities.

At the management level, BNY Mellon’s Technology Oversight Committee, which is the senior management committee responsible for the governance and oversight of BNY Mellon’s significant technology projects and initiatives, reviews reports from management concerning ISD and is responsible for, among other things, escalating issues, including significant cybersecurity threats and incidents, to the Technology Committee of the Board. The Technology Oversight Committee is chaired by the Chief Information Officer (the “CIO”) and its members include the CISO.

BNY Mellon’s Technology Risk Committee is the most senior governance committee primarily focused on cybersecurity and technology risk issues and is a part of the second line of defense risk function. It is responsible for, among other things, overseeing and reviewing emerging cybersecurity risks, significant cybersecurity incidents and remediation plans. The Technology Risk Committee receives reports from management and has protocols for escalating certain issues and risks to the Senior Risk and Control Committee and the Risk Committee of the Board. The Technology Risk Committee is chaired by the interim Chief Technology Risk Officer. Members include key leaders from the first line of defense, including the CISO.

BNY Mellon’s CIO, CISO and interim Chief Technology Risk Officer each have extensive experience in assessing and managing risks from cybersecurity threats. BNY Mellon’s CISO joined BNY Mellon in 2022 and previously served as head of information security at a Fortune 500 biopharmaceutical company and an information technology company, as well as the Global Chief Technology Officer at a large cybersecurity company. BNY Mellon’s CIO joined BNY Mellon in September 2024 from a large multinational company, where she was responsible for overseeing information technology and cybersecurity operations. BNY Mellon’s interim Chief Technology Risk Officer joined BNY Mellon in November 2024 and has previous experience as Global Head of Cyber, Technology and Information Security Risk Management at a global systemically important financial institution and over a decade of experience serving the U.S. intelligence community in a variety of cybersecurity-related positions.

Item 2.

Properties.

Reference is made to “Item 1. Business — Description of the Underlying Properties” and “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations — Planned Development and Workover Program,” which are incorporated herein by reference.

Item 3.

Legal Proceedings.

Currently, there are no legal proceedings pending to which the Trust is a party or of which any of its property is the subject.

Item 4.

Mine Safety Disclosures.

None.

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PART II

Item 5.

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

The Trust Units commenced trading on the New York Stock Exchange on January 19, 2007 under the symbol “MVO.” As of March 20, 2025, the 11,500,000 Trust Units outstanding were held by 11 Trust unitholders of record.

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) that quarter, less the Trust’s expenses for that quarter. Available funds are reduced by any cash that 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).

Equity Compensation Plans

The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.

Recent Sales of Unregistered Securities

There were no equity securities sold by the Trust during the year ended December 31, 2023 that were not registered under the Securities Act of 1933, as amended (the “Securities Act”).

Purchases of Equity Securities

There were no purchases of Trust Units by the Trust or any affiliated purchaser during the fourth quarter of the year ended December 31, 2024.

Item 6.

[Reserved]

Item 7.

Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The Trust’s purpose is, in general, to hold the net profits interest, to distribute to the Trust unitholders cash that the Trust receives in respect of the net profits interest, and to perform certain administrative functions in respect of the net profits interest and the Trust Units. The Trust derives substantially all of its income and cash flows from the net profits interest.

Critical Accounting Policies and Estimates

The Trust uses the modified cash basis of accounting to report receipts by the Trust of the net profits interest and payments of expenses incurred. The net profits interest represents the right to receive revenues (oil, gas and natural liquid gas sales) less direct operating expenses (lease operating, maintenance and overhead expenses and production and property taxes) and an adjustment for lease equipment cost and lease development expenses (which are capitalized in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”)) of the underlying properties times 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the Conveyance.

The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, Trust corpus, earnings and distributions as follows:

(a)

Income from the net profits interest is recorded when distributions are received by the Trust;

(b)

Distributions to Trust unitholders are recorded when paid by the Trust;

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(c)

Trust general and administrative expenses (which include the Trustee’s fees as well as accounting, engineering, legal and other professional fees) are recorded when paid;

(d)

Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under U.S. GAAP;

(e)

Amortization of the investment in net profits interest, calculated using the units-of-production method based upon total estimated proved reserves, is charged directly to Trust corpus and does not affect distributable income; and

(f)

The Trust evaluates its investment in the net profits interest periodically to determine whether its aggregate value has been impaired below its total capitalized cost based on the underlying properties. The Trust will provide a write-down to its investment in the net profits interest if and when total capitalized costs, less accumulated amortization, exceed undiscounted future net cash flows attributable to the Trust’s interests in the proved oil and gas reserves of the underlying properties.

While these statements differ from financial statements prepared in accordance with U.S. GAAP, the modified cash basis of reporting revenues and distributions is considered most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts received from MV Partners. This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for royalty Trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Termination of the Trust

Comparison of Results of the Trust for the Years Ended December 31, 2024 and 2023

The following represents a discussion of the Comparison of Results of the Trust for the Years Ended December 31, 2024 and 2023. Refer to “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on March 20, 2024, for a discussion of the Comparison of Results of the Trust for the Years Ended December 31, 2023 and 2022.

Income for the Trust from the net profits interest was $18.6 million for the year ended December 31, 2024 compared to $18.1 million for the year ended December 31, 2023. The Trustee withheld $0.9 million and $1.3 million for future Trust expenses for the years ended December 31, 2024 and 2023, respectively. General and administrative expense for the Trust was $0.9 million for 2024 and $1.1 million for 2023. These factors resulted in distributable income of $17.7 million, or $1.535 per Trust Unit, in 2024 compared to $16.8 million, or $1.460 per Trust Unit, in 2023.

The revenues from oil production are typically received by MV Partners one month after production; thus, the cash received by the Trust during the year ended December 31, 2024 substantially represented the production by MV Partners from September 2023 through August 2024, and the cash received by the Trust during the year ended December 31, 2023 substantially represented the production by MV Partners from September 2022 through August 2023. MV Partners computes net proceeds quarterly on a calendar basis and

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distributes to the Trust 80% of the aggregate of such net proceeds attributable to a computation period on or before the 25th day of the month following the computation period. As a result, for the year ended December 31, 2024, the Trust’s net profits interest represented the cash proceeds received by the Trust, which was based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2023 through September 30, 2024. For the year ended December 31, 2023, the Trust’s net profits interest represented the cash proceeds received by the Trust, which was based upon the cash receipts for the oil and gas production collected by MV Partners from October 1, 2022 through September 30, 2023.

Excess of revenues over direct operating expenses and lease equipment and development costs from the underlying properties was $23.2 million for the period from October 1, 2023 through September 30, 2024. The Trust’s net profits interest (80%) of this total was $18.6 million for the year ended December 31, 2024. During the year ended December 31, 2024, MV Partners did not withhold or release any dollar amounts due to the Trust from previously established cash reserves for future capital expenditures, which resulted in total cash proceeds received by the Trust of $18.6 million for the year ended December 31, 2024.

Excess of revenues over direct operating expenses and lease equipment and development costs from the underlying properties was $22.6 million for the period from October 1, 2022 through September 30, 2023. The Trust’s net profits interest (80%) of this total was $18.1 million for the year ended December 31, 2023. During the year ended December 31, 2023, MV Partners did not withhold or release any dollar amounts due to the Trust from previously established cash reserves for future capital expenditures, which resulted in total cash proceeds received by the Trust of $18.1 million for the year ended December 31, 2023.

The average price received for crude oil sold during 2024 was $75.52 per Bbl, while the average price received for crude oil sold during 2023 was $74.03 per Bbl. The average price received for natural gas sold during 2024 was $2.19 per Mcf, while the average price received for natural gas sold during 2023 was $4.31 per Mcf. The average prices for 2024 related to production by MV Partners from September 2023 through August 2024, and the average prices for 2023 related to production by MV Partners from September 2022 through August 2023.

The overall production volumes sold and delivered to purchasers attributable to the 80% net profits interest that was for the oil and gas production sold and delivered during the period from October 1, 2023 to September 30, 2024 were 477,311 Bbls of oil, 22,203 Mcf of natural gas and 11 Bbls of natural gas liquids, for a total of 481,018 Boe. The overall production volumes sold and delivered to purchasers attributable to the 80% net profits interest that was for the oil and gas production sold and delivered during the period from October 1, 2022 to September 30, 2023 were 486,189 Bbls of oil, 24,587 Mcf of natural gas and 50 Bbls of natural gas liquids, for a total of 490,320 Boe.

As noted above, the amounts reflected in the accompanying financial statements for the Trust’s year ended December 31, 2024 reflect cash received by the Trust during the year. Such cash is primarily derived from production by MV Partners from September 2023 through August 2024. The amounts reflected in the accompanying financial statements for the Trust’s year ended December 31, 2023 reflect cash received by the Trust during the year. Such cash is primarily derived from production by MV Partners from September 2022 through August 2023.

Liquidity and Capital Resources

Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Administrative expenses include payments to the Trustee as well as an annual administrative fee to MV Partners pursuant to an administrative services agreement. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the net profits interest and payments from other sources (such as interest earned on any amounts reserved by the Trustee) in that quarter, over the Trust’s expenses paid for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future expenses.

The Trustee may cause the Trust to borrow funds required to pay expenses if the Trustee determines that the cash on hand and the cash to be received are insufficient to cover the Trust’s expenses. If the Trust borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid. During

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the years ended December 31, 2024 and 2023 there were no such borrowings. MV Partners has provided a letter of credit in the amount of $1.8 million to the Trustee to protect the Trust against the risk that it does not have sufficient cash to pay future expenses.

From the first quarter of 2022 to the second quarter of 2023, the Trustee withheld a portion of the proceeds otherwise available for distribution each quarter to build an approximately $1.265 million cash reserve for the payment of future known, anticipated or contingent expenses or liabilities. This amount is in addition to the $1.8 million letter of credit described above. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to unitholders, together with interest earned on the funds. As of December 31, 2024, $1,281,396 was held by the Trustee.

Income to the Trust from the net profits interest is based on the calculation and definitions of “gross proceeds” and “net proceeds” contained in the Conveyance.

As further discussed below, MV Partners’ development and workover program will require MV Partners to make future capital expenditures in connection with the development, exploration and production of oil and gas. Substantially all of the underlying properties are located in mature fields and MV Partners does not expect future costs for the underlying properties to change significantly as compared to recent historical costs other than increases due to increases in the general cost of oilfield services.

The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

Planned Development and Workover Program

Since acquiring the underlying properties in 1998 and 1999, MV Partners has implemented a development program on the underlying properties to develop further proved undeveloped reserves and to help offset the natural decline in production. These activities included recompletion of certain existing wells into new producing horizons, workovers of existing wells, and the drilling of infill development wells.

The development program that MV Partners currently intends to implement over the three years ending December 31, 2027 with respect to the underlying properties categorized as proved undeveloped reserves consists of recompletion and workover projects, and polymer workovers. The development program that MV Partners currently intends to implement over the next three years with respect to the underlying properties categorized as proved developed non-producing reserves consists of well-reactivation projects, injection well-workover projects, recompletion projects, and well-workover projects.

MV Partners expects total capital expenditures for the underlying properties during the three years ending December 31, 2027 will be approximately $0.4 million for recompletion and workovers of existing wells. MV Partners expects that these capital projects will add production that will partially offset the natural decline in production otherwise expected to occur with respect to the underlying properties. The Trust is not directly obligated to pay any portion of any capital expenditures made with respect to the underlying properties; however, capital expenditures made by MV Partners with respect to the underlying properties will be deducted from the gross proceeds in calculating the net proceeds from which cash will be paid to the Trust. As a result, the Trust will indirectly bear an 80% (subject to certain limitations during the final three years of the Trust, as described above under “Item 1. Business — Computation of Net Proceeds — Net Profits Interest”) share of any capital expenditures made with respect to the underlying properties. Accordingly, higher or lower capital expenditures will, in general, directly decrease or increase, respectively, the cash received by the Trust in respect of its net profits interest, which will have a corresponding effect on cash available for distribution to Trust unitholders. As the cash received by the Trust in respect of the net profits interest will be reduced by the Trust’s pro rata share of these capital expenditures, MV Partners expects that it will incur capital expenditures with respect to the underlying properties throughout the term of the Trust on a basis that balances the impact of the capital expenditures on current cash distributions to the Trust unitholders with the longer term benefits of increased oil and natural gas production expected to result

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from the capital expenditures. In addition, MV Partners may establish a capital reserve of up to $1.0 million in the aggregate at any given time to reduce the impact on distributions of uneven capital expenditure timing.

MV Partners, as the operator of the underlying properties, is entitled to make all determinations related to capital expenditures with respect to the underlying properties, and there are no limitations on the amount of capital expenditures that MV Partners may incur with respect to the underlying properties, except as described above under “Item 1. Business — Computation of Net Proceeds — Net Profits Interest.” As the Trust unitholders would not be expected to fully realize the benefits of capital expenditures made with respect to the underlying properties toward the end of the term of the Trust, during each twelve-month period beginning on June 30, 2023, capital expenditures that may be taken into account in calculating net proceeds attributable to the net profits interest will be limited to the average annual capital expenditures during the preceding three years, as adjusted for inflation. The Average Annual Capital Expenditure Amount for the twelve-month period ending June 30, 2024 is $2,279,490. See “Item 1. Business — Computation of Net Proceeds — Net Profits Interest.”

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

The Trust is a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and is not required to provide the information under this item.

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Item 8.

Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders of MV Oil Trust
and The Bank of New York Mellon Trust Company, N.A., as Trustee

Opinion on the financial statements

We have audited the accompanying statements of assets and trust corpus of MV Oil Trust (the “Trust”) as of December 31, 2024 and 2023, the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets and trust corpus of the Trust as of December 31, 2024 and 2023, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2024, in conformity with the modified cash basis of accounting described in Note B to the financial statements.

Basis of accounting

As described in Note B to the financial statements, these financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matters

Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Trustee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.

/s/ Grant Thornton LLP

We have served as the Trust’s auditor since 2006.

Oklahoma City, Oklahoma
March 20, 2025

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MV OIL TRUST
STATEMENTS OF ASSETS AND TRUST CORPUS

	December 31,
	2023			2024
ASSETS
Cash and cash equivalents		$	1,263,932		$	1,281,396
Investment in net profits interest			50,383,675			50,383,675
Accumulated amortization			(46,191,522)			(47,799,222)
Total assets		$	5,456,085		$	3,865,849
TRUST CORPUS
Trust corpus, 11,500,000 Trust Units issued and outstanding at December 31, 2023 and 2024		$	5,456,085		$	3,865,849

STATEMENTS OF DISTRIBUTABLE INCOME

	Year ended December 31,
	2022			2023			2024
Income from net profits interest		$	27,204,590		$	18,068,559		$	18,575,409
Cash on hand withheld for Trust expenses			(739,068)			(227,718)			(17,464)
General and administrative expense(1)			(935,522)			(1,050,841)			(905,445)
Distributable income		$	25,530,000		$	16,790,000		$	17,652,500
Distributions per Trust Unit (11,500,000 Trust Units issued and outstanding for 2022, 2023 and 2024)		$	2.220		$	1.460		$	1.535

(1)

Includes $112,379, $116,874 and $121,549 paid to MV Partners, LLC and $150,000, $150,000, and $150,000 paid to The Bank of New York Mellon Trust Company, N.A. for the years ended December 31, 2022, 2023 and 2024, respectively.

STATEMENTS OF CHANGES IN TRUST CORPUS

	Year ended December 31,
	2022			2023			2024
Trust corpus, beginning of year		$	7,909,468		$	6,883,554		$	5,456,085
Income from net profits interest			27,204,590			18,068,559			18,575,409
Cash distributions			(25,530,000)			(16,790,000)			(17,652,500)
Trust expenses			(935,522)			(1,050,841)			(905,445)
Amortization of net profits interest			(1,764,982)			(1,655,187)			(1,607,700)
Trust corpus, end of year		$	6,883,554		$	5,456,085		$	3,865,849

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MV OIL TRUST

NOTES TO FINANCIAL STATEMENTS

NOTE A — ORGANIZATION OF THE TRUST

MV Oil Trust (the “Trust”) is a statutory trust formed on August 3, 2006, under the Delaware Statutory Trust Act pursuant to a Trust Agreement (as amended and restated, the “Trust Agreement”) among MV Partners, LLC (“MV Partners”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”).

The Trust was created to acquire and hold a term net profits interest for the benefit of the Trust unitholders pursuant to the Conveyance of Net Profits Interest dated as of January 24, 2007 from MV Partners to the Trust (the “Conveyance”). The term net profits interest is an interest in underlying properties consisting of MV Partners’ net interests in all of its oil and natural gas properties located in the Mid- Continent region in the states of Kansas and Colorado (the “underlying properties”). These oil and gas properties include approximately 840 producing oil and gas wells.

The net profits interest is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the underlying properties. 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 during the term of the Trust. As of December 31, 2024, cumulatively, since inception, the Trust has received payment for 80% of the net proceeds attributable to MV Partners’ interest from the sale of 14.7 MMBoe of production from the underlying properties (which amount is the equivalent of 11.8 MMBoe with respect to the Trust’s net profits interest). Consequently, 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). It is anticipated that the Trustee will make a final quarterly cash distribution, if any, 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 Trust will dissolve prior to the Termination Date if:

(a)

the Trust sells the net profits interest;

(b)

the holders of a majority of the outstanding units of beneficial interest in the Trust (“Trust Units”) vote in favor of dissolution; or

(c)

there is a judicial dissolution of the Trust.

Upon dissolution, the Trustee would 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 on June 30, 2026, there will be no assets for the Trustee to sell following June 30, 2026.

The Trustee can authorize the Trust to borrow money to pay Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee or the Delaware Trustee as a lender provided the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make other short-term investments with the funds distributed to the Trust.

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NOTE B — TRUST ACCOUNTING POLICIES

A summary of the significant accounting policies of the Trust follows.

Basis of accounting

The Trust uses the modified cash basis of accounting to report receipts by the Trust of the net profits interest and payments of expenses incurred. The net profits interest represents the right to receive revenues (oil, gas and natural gas liquid sales) less direct operating expenses (lease operating, maintenance and overhead expenses and production and property taxes) and an adjustment for lease equipment cost and lease development expenses (which are capitalized in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”)) of the underlying properties times 80% (term net profits interest percentage). Actual cash receipts may vary due to timing delays of actual cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices. The actual cash distributions of the Trust will be made based on the terms of the conveyance creating the Trust’s net profits interest.

The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, Trust corpus, and distributable income as follows:

(a)

Income from net profits interest is recorded when distributions are received by the Trust;

(b)

Distributions to Trust unitholders are recorded when paid by the Trust;

(c)

Trust general and administrative expenses (which include the Trustee’s fees as well as accounting, engineering, legal and other professional fees) are recorded when paid;

(d)

Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under U.S. GAAP;

(e)

Amortization of the investment in net profits interest, calculated using the units-of-production method based upon total estimated proved reserves, is charged directly to trust corpus and does not affect distributable income; and

(f)

The Trust evaluates its investment in the net profits interest periodically to determine whether its aggregate value has been impaired below its total capitalized cost based on the underlying properties. The Trust will provide a write-down to its investment in the net profits interest if and when total capitalized costs, less accumulated amortization, exceed undiscounted net future cash flows attributable to the Trust’s interests in the proved oil and gas reserves of the underlying properties.

While these statements differ from financial statements prepared in accordance with U.S. GAAP, the modified cash basis of reporting income and distributions is considered most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts.

This comprehensive basis of accounting other than generally accepted accounting principles corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (the “SEC”) as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, requiring public entities to disclose information about their reportable segments’ significant expenses and other segment items on an interim and annual basis. Public entities with a single reportable segment are required to apply the disclosure requirements in ASU 2023-07, as well as all existing segment disclosures and reconciliation requirements in ASC 280 on an interim and annual basis. The Trust adopted ASU 2023-07 during the year ended December 31, 2024.

Cash equivalents

For purposes of these statements, the Trust considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

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Use of estimates

The preparation of financial statements requires estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates affecting these financial statements include estimates of proved oil and gas reserves, which are used to compute the Trust’s amortization of net profits interest.

Segment reporting

The Trust has one business activity as the owner of an investment in net profits interest, as reported in accompanying the Statements of Assets and Trust Corpus, and operates in a single operating and reportable segment. Operating segments are defined as components of an entity for which separate financial information is evaluated regularly by the chief operating decision maker (the “CODM”), which is the Trustee. The segment participates in activities and derives its income from net profits interest as reported in the accompanying Statements of Distributable Income, and the CODM uses this in making decisions about the allocation of cash reserves for current and future Trust general and administrative expenses and the ultimate distribution to the Trust unitholders.

NOTE C — NET PROFITS INTEREST

The net profits interest was recorded at the historical cost of MV Partners on January 24, 2007, the date of conveyance, and is calculated as follows:

Oil and gas properties	$	96,210,819
Accumulated depreciation and depletion		(40,468,762)
Hedge asset		7,237,537
Net property value to be conveyed		62,979,594
Times 80% net profits interest to Trust	$	50,383,675

NOTE D — INCOME FROM NET PROFITS INTEREST

	Year ended December 31,
	2022			2023			2024
Excess of revenues over direct operating expenses and lease equipment and development costs(1)		$	34,005,736		$	22,585,699		$	23,219,261
Times net profits interest over the term of the Trust			80%			80%			80%
Income from net profits interest before reserve adjustments			27,204,590			18,068,559			18,575,409
MV Partners reserve for future capital expenditures(2)			—			—			—
Income from net profits interest(3)		$	27,204,590		$	18,068,559		$	18,575,409

(1)

Pursuant to the Conveyance, direct operating expenses, lease equipment and development costs are deducted when calculating the distributable income to the Trust.

(2)

Pursuant to the Conveyance, MV Partners can reserve up to $1,000,000 for future exploration, development, maintenance or operating expenditures at any time. The reserve balance was $1,000,000 at December 31, 2022, 2023 and 2024, respectively.

(3)

The income from net profits interest is based upon the cash receipts from MV Partners for the oil and gas production. The revenues from oil production are typically received one month after production; thus, the cash received by the Trust during the year ended December 31, 2022 substantially represents the production by MV Partners from September 2021 through August 2022; the cash received by the Trust during the year ended December 31, 2023 substantially represents the production by MV

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Partners from September 2022 through August 2023; and the cash received by the Trust during the year ended December 31, 2024 substantially represents the production by MV Partners from September 2023 through August 2024.

For the years ended December 31, 2022, 2023 and 2024, MV Purchasing, LLC (“MV Purchasing”) purchased 74%, 73% and 74%, respectively, of the production sold from the underlying properties. MV Purchasing is majority-owned by the indirect equity owners of MV Partners. Sales to MV Purchasing are under short-term arrangements, ranging from one to six months, using market sensitive pricing.

NOTE E — INCOME TAXES

Tax counsel to the Trust advised the Trust at the time of formation that, under then current tax laws, in its opinion the net profits interest should be treated as a debt instrument for federal income tax purposes, and the Trust should be required to treat a portion of each payment it receives with respect to the net profits interest as interest income in accordance with the “noncontingent bond method” under the original issue discount rules contained in the Internal Revenue Code of 1986, as amended, and the corresponding regulations. Tax counsel to the Trust also advised the Trust at the time of formation that in its opinion the Trust will be treated as a grantor trust for federal income tax purposes. On the basis of this advice, Trust unitholders will be considered to own and receive the Trust’s assets and income and will be directly taxable thereon as if no trust were in existence. No provision for federal or state income taxes has been made in the accompanying statements.

NOTE F — DISTRIBUTIONS TO UNITHOLDERS

The Trustee determines for each quarter the amount available for distribution to the Trust unitholders. This distribution is expected to be made 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). Such amounts will be equal to the excess, if any, of the cash received by the Trust relating to such preceding quarter, over the expenses of the Trust for such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for future expenses of the Trust.

From the first quarter of 2022 to the second quarter of 2023, the Trustee withheld a portion of the proceeds otherwise available for distribution each quarter to build an approximately $1.265 million cash reserve for the payment of future known, anticipated or contingent expenses or liabilities of the Trust. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Trust unitholders, together with interest earned on the funds. This cash reserve is included in cash and cash equivalents on the accompanying Statements of Assets and Trust Corpus.

Date paid	Period covered	Distribution per unit			Reserve released (established)(1)
January 25, 2022	October 1, 2021 through December 31, 2021		$	0.410		—
April 25, 2022	January 1, 2022 through March 31, 2022		$	0.425		—
July 25, 2022	April 1, 2022 through June 30, 2022		$	0.700		—
October 25, 2022	July 1, 2022 through September 30, 2022		$	0.685		—
January 25, 2023	October 1, 2022 through December 31, 2022		$	0.410		—
April 25, 2023	January 1, 2023 through March 31, 2023		$	0.345		—
July 25, 2023	April 1, 2023 through June 30, 2023		$	0.325		—
October 25, 2023	July 1, 2023 through September 30, 2023		$	0.380		—
January 25, 2024	October 1, 2023 through December 31, 2023		$	0.465		—

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Date paid	Period covered	Distribution per unit			Reserve released (established)(1)
April 25, 2024	January 1, 2024 through March 31, 2024		$	0.330		—
July 25, 2024	April 1, 2024 through June 30, 2024		$	0.410		—
October 25, 2024	July 1, 2024 through September 30, 2024		$	0.330		—

(1)

Pursuant to the Conveyance, MV Partners can reserve up to $1,000,000 for future exploration, development, maintenance or operating expenditures at any time.

NOTE G — RELATED PARTY TRANSACTIONS

The Trust has entered into an administrative services agreement with MV Partners that obligates the Trust, throughout the term of the Trust, to pay to MV Partners each quarter an administrative services fee for accounting, bookkeeping and informational services performed by MV Partners on behalf of the Trust relating to the net profits interest. The annual fee, which increases by 4% each year, was a total of $112,379, $116,874 and $121,549 for 2022, 2023 and 2024, respectively. The administrative services agreement will terminate upon the termination of the net profits interest unless earlier terminated by mutual agreement of the Trustee and MV Partners.

The Trust has entered into a Trust Agreement with the Trustee that obligates the Trust, throughout the term of the Trust, to pay to the Trustee a quarterly fee. The annual fee was a total of $150,000 for each of 2022, 2023 and 2024. In addition, the Trustee paid an annual fee to the Delaware trustee of $2,760 in each of 2022, 2023 and 2024. The Trust Agreement will terminate upon the termination of the net profits interest unless earlier terminated by mutual agreement of a majority of the Trust unitholders.

NOTE H — ADVANCE FOR TRUST EXPENSES

Under the terms of the Trust Agreement, the Trustee is allowed to borrow money to pay Trust expenses. During 2022, 2023 and 2024, the Trust did not borrow any money, and there were no prior borrowings that had not been repaid. Since the Trust uses the modified cash basis of accounting, a liability has not been recorded for any advances from MV Partners. The net advance is shown as an addition to Trust Corpus when the borrowing is made and is shown as a reduction to Trust Corpus when it is repaid.

MV Partners provided a letter of credit in the amount of $1.8 million to the Trustee to protect the Trust against the risk that it does not have sufficient cash to pay future expenses.

From the first quarter of 2022 to the second quarter of 2023, the Trustee withheld a portion of the proceeds otherwise available for distribution each quarter to build an approximately $1.265 million cash reserve for the payment of future known, anticipated or contingent expenses or liabilities. This amount is in addition to the $1.8 million letter of credit described above. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to unitholders, together with interest earned on the funds. This cash reserve is included in cash and cash equivalents on the accompanying Statements of Assets and Trust Corpus.

NOTE I — OTHER EVENTS

Subsequent event

The first quarterly distribution for 2025 was $2,760,000, or $0.240 per Trust Unit, and was made on January 25, 2025 to Trust unitholders owning Trust Units as of January 16, 2025. Such distribution included the net proceeds of production collected by MV Partners from October 1, 2024 through December 31, 2024.

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NOTE J — DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)

The Trust is required to disclose proved reserves in accordance with the SEC’s reporting rules, which require that the average, first-day-of-the-month price during the 12-month period before the end of the year be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2022, 2023 and 2024 has been presented in accordance with these rules.

Estimates of the proved oil and gas reserves attributable to the Trust as of December 31, 2022, 2023 and 2024 are based on reports of Cawley, Gillespie & Associates, Inc., independent petroleum and geological engineers, and the contract property management engineering staff of the managers of MV Partners who operate the underlying properties, in accordance with the SEC’s rules and definitions. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” and “proved undeveloped” crude oil, natural gas, and natural gas liquids reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

The reserve data below represent estimates only and should not be construed as being exact. Moreover, the discounted values should not be construed as representative of the current market value of the net profits interest. A market value determination would include many additional factors, including: (i) anticipated future oil and gas prices; (ii) the effect of federal income taxes, if any, on the Trust; (iii) an allowance for return on investment; (iv) the effect of governmental legislation; (v) the value of additional potential reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities; and (vi) other business risks.

The following tables set forth (i) the estimated net quantities of proved, proved developed and proved undeveloped oil, natural gas and natural gas liquids reserves attributable to the Trust, and (ii) the standardized measure of the discounted future net profits interest income attributable to the Trust and the nature of changes in such standardized measure between years. These tables are prepared on the accrual basis, which is the basis on which MV Partners maintains its production records and is different from the basis on which the Trust is reporting.

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ESTIMATED QUANTITIES OF OIL AND GAS RESERVES

	Oil (Bbls)		Gas (Mcf)		NGL (Bbls)		Total (Boe)
Proved reserves
Balance at December 31, 2021		1,947,478		86,535		319		1,962,108
Revisions of previous estimates		95,494		11,867		28		97,490
Production		(493,642)		(25,461)		(87)		(497,942)
Balance at December 31, 2022		1,549,330		72,941		260		1,561,656
Revisions of previous estimates		18,556		(13,839)		(49)		16,218
Production		(484,433)		(23,929)		(34)		(488,444)
Balance at December 31, 2023		1,083,453		35,173		177		1,089,430
Revisions of previous estimates		3,318		(7,531)		(65)		2,021
Production		(469,091)		(21,892)		(11)		(472,747)
Balance at December 31, 2024		617,680		5,750		101		618,704
Proved developed reserves
December 31, 2021		1,860,861		86,535		319		1,875,491
December 31, 2022		1,492,741		72,941		260		1,505,067
December 31, 2023		1,069,533		35,173		177		1,075,510
December 31, 2024		616,621		5,750		101		617,645
Proved undeveloped reserves
December 31, 2021		86,617		—		—		86,617
Proved undeveloped reserves converted to proved developed reserves by drilling		(31,444)		—		—		(31,444)
Additional proved undeveloped reserves added during 2022		26,746		—		—		26,746
Proved undeveloped reserves removed from drilling plan		(25,304)		—		—		(25,304)
Revisions of previous estimates		(26)		—		—		(26)
December 31, 2022		56,589		—		—		56,589
Proved undeveloped reserves converted to proved developed reserves by drilling		(17,513)		—		—		(17,513)
Additional proved undeveloped reserves added during 2023		—		—		—		—
Proved undeveloped reserves removed from drilling plan		(21,859)		—		—		(21,859)
Revisions of previous estimates		(3,297)		—		—		(3,297)
December 31, 2023		13,920		—		—		13,920
Proved undeveloped reserves converted to proved developed reserves by drilling		(3,200)		—		—		(3,200)
Additional proved undeveloped reserves added during 2024		—		—		—		—
Proved undeveloped reserves removed from drilling plan		—		—		—		—
Revisions of previous estimates		(9,661)		—		—		(9,661)
December 31, 2024		1,059		—		—		1,059

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The Trust recognized net reductions to reserves for its share of MV Partners’ total during 2022 associated with the production of properties of 497,942 Boe. The Trust recognized net increases to reserves of 1,442 Boe as a result of changes in the development plan. Additional increases to reserves of 96,047 Boe were a result of positive revisions due to higher commodity prices during 2022.

The Trust recognized net reductions to reserves for its share of MV Partners’ total during 2023 associated with the production of properties of 488,444 Boe. The Trust recognized net decreases to reserves of 21,859 Boe as a result of changes in the development plan. Additional increases to reserves of 38,078 Boe were a result of positive revisions due to the effectiveness of workovers and development during 2023.

The Trust recognized net reductions to reserves for its share of MV Partners’ total during 2024 associated with the production of properties of 472,747 Boe. The Trust recognized net decreases to reserves of 9,661 Boe as a result of changes in the development plan. Additional increases to reserves of 11,681 Boe were a result of positive revisions due to the effectiveness of workovers and development during 2024.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED OIL AND GAS RESERVES

Estimates of future net cash flows from proved reserves of crude oil, natural gas, and natural gas liquids are computed using the average, first-day-of-the-month price during the 12-month period for 2022, 2023 and 2024.

	2022			2023			2024
Future cash inflows		$	138,608,602		$	79,962,266		$	43,857,466
Future costs
Production			(56,930,542)			(39,562,496)			(23,354,998)
Development			(1,047,713)			(472,000)			(296,000)
Future net cash flows			80,630,347			39,927,770			20,206,468
Less 10% discount factor			(11,418,520)			(4,176,829)			(1,317,065)
Standardized measure of discounted future net cash flows		$	69,211,827		$	35,750,941		$	18,889,403

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND GAS RESERVES

	2022			2023			2024
Standardized measure at beginning of year		$	45,261,966		$	69,211,827		$	35,750,941
Net proceeds to the Trust			(27,204,589)			(18,068,560)			(18,575,409)
Net changes in price and production costs			39,987,484			(21,474,622)			(4,255,388)
Changes in estimated future development costs			(124,022)			334,663			98,702
Development costs incurred during the year			454,500			188,000			72,000
Revisions of quantity estimates			4,463,154			723,212			387,062
Accretion of discount			4,526,197			6,921,183			3,575,094
Changes in production rates, timing and other(1)			1,847,137			(2,084,762)			1,836,401
Standardized measure at end of year		$	69,211,827		$	35,750,941		$	18,889,403

(1)

The Trust’s changes in standardized measure of discounted future net cash flows attributable to production rates, timing and other primarily represents changes in the Trust’s estimates of when proved reserve quantities will be realized. During the years ended December 31, 2022, 2023 and 2024, the operator changed its development drilling capital plans, which had the effect of altering the estimated timing of development and then the ultimate realization of undeveloped proved reserves.

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The average, first-day-of-the-month price during the 12-month period for 2022, 2023 and 2024 used in determining future net revenues related to the standardized measure calculation are as follows:

	2022			2023			2024
Oil (per Bbl)		$	89.17		$	73.72		$	70.98
Gas (per Mcf)		$	6.10		$	2.41		$	1.99
NGL (per Bbl)		$	37.47		$	31.29		$	30.19

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A.

Controls and Procedures.

Evaluation of disclosure controls and procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information to be disclosed by the Trust in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and regulations promulgated by the SEC. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by MV Partners to The Bank of New York Mellon Trust Company, N.A., as trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trust’s disclosure controls and procedures. Elaina Rodgers, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due to the contractual arrangements of (i) the Trust Agreement and (ii) the Conveyance, the Trustee relies on (A) information provided by MV Partners, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. See “Item 1A. Risk Factors — The Trust and the public Trust unitholders have no voting or managerial rights with respect to MV Partners, the operator of the underlying properties. As a result, public Trust unitholders have no ability to influence the operation of the underlying properties” in this Form 10-K, and “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of certain risks relating to these arrangements and reliance on information when reported by MV Partners to the Trustee and recorded in the Trust’s results of operations.

Changes in Internal Control Over Financial Reporting. During the fourth quarter ended December 31, 2024, there has been no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of MV Partners.

Trustee’s Report on Internal Control Over Financial Reporting. The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), by the Trust. The Trust’s internal control over financial reporting is a process designed under the supervision of the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Trust’s financial statements for external purposes in accordance with the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts, which is a comprehensive basis of accounting other than generally accepted accounting principles.

As of December 31, 2024, the Trustee assessed the effectiveness of the Trust’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Trustee determined that the Trust maintained effective internal control over financial reporting as of December 31, 2024, based on those criteria.

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Item 9B.

Other Information.

Rule 10b5-1 Trading Plans. During the three months ended December 31, 2024, no officer or employee of the Trustee who performs policy-making functions for the Trust adopted, modified, or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, as such terms are defined in Item 408(a) of Regulation S-K, with respect to the Trust Units.

Item 9C.

Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

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PART III

Item 10.

Directors, Executive Officers and Corporate Governance.

The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust Units at a meeting at which a quorum is present.

Audit Committee and Nominating Committee

Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

Code of Ethics

The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the code of ethics of The Bank of New York Mellon Trust Company, N.A.

Insider Trading Policy

Because the Trust has no directors, officers or employees, and because the Trustee does not have the authority under the terms of the Trust Agreement to engage in transactions in the Trust Units on behalf of the Trust, the Trust has not adopted an insider trading policy applicable to such persons or to the Trust itself. It is the policy of the Trustee that any transaction in Trust Units by any officer or employee of the Trustee who performs policy-making functions for the Trust must comply with the insider trading policies of The Bank of New York Mellon Corporation, the parent corporation of The Bank of New York Mellon Trust Company, N.A.

Item 11.

Executive Compensation.

During the years ended December 31, 2024, 2023 and 2022, the Trustee received compensation from the Trust in the amount of $150,000 each year. The Trust does not have any executive officers. Because the Trust does not have a board of directors, it does not have a compensation committee.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

(a) Security Ownership of Certain Beneficial Owners.

The following table sets forth certain information regarding the beneficial ownership of the Trust Units as of March 20, 2025 by each person who, to the Trust’s knowledge, beneficially owns more than 5% of the outstanding Trust Units.

Beneficial Owner	Trust Units Beneficially Owned		Percent of Class(1)
MV Energy, LLC(2)		2,875,000		25.0%
VAP-I, LLC(2)		1,437,500		12.5%
Robert J. Raymond(3)		1,016,114		8.8%

(1)

Based on 11,500,000 Trust Units outstanding as of March 20, 2025.

(2)

The address of each of MV Energy and VAP-I is 1700 Waterfront, Building 500, Wichita, Kansas 67206. MV Energy is the managing member of VAP-I. As a result, MV Energy has sole voting and investment power with respect to the Trust Units held by VAP-I. Each of MV Energy and VAP-I is the record owner of 1,437,500 Trust Units. The information is based on Form 4 filings with the SEC on January 31, 2007.

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(3)

The information is based on a Schedule 13G dated February 8, 2019 filed jointly by Robert J. Raymond (“Raymond”), RR Advisors, LLC (“Advisors”), RCH Black Fund GP, L.P. (“RCH GP”), and RCH Black Fund, L.P. (“RCH LP” and, together with Raymond, Advisors and RCH GP, the “Reporting Persons”). The principal business address of the Reporting Persons is 3953 Maple Avenue, Suite 180, Dallas, Texas 75219. According to the filing, Raymond has sole voting power and dispositive power with respect to 25,096 Trust Units; Raymond and Advisors each has shared voting and dispositive power with respect to 991,018 Trust Units; and RCH GP and RCH LP each has shared voting and dispositive power with respect to 958,555 Trust Units. According to the filing, each Reporting Person expressly disclaims (a) the existence of any group and (b) beneficial ownership with respect to any Trust Units other than the Trust Units owned of record by such Reporting Person.

(b) Security Ownership of Management.

Not applicable.

The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant.

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

Under the terms of the Conveyance governing the net profits interest, MV Partners is obligated to make certain payments to the Trust on a quarterly basis. Please see “Item 1. Business — Computation of Net Proceeds” for more information about these agreements.

Administrative Services Agreement

The Trust has entered into an administrative services agreement with MV Partners that obligates the Trust, throughout the term of the Trust, to pay to MV Partners each quarter an administrative services fee for accounting, bookkeeping and informational services performed by MV Partners on behalf of the Trust relating to the net profits interest. The annual fee, which increases by 4% each year, was a total of $121,549 for 2024. The administrative services agreement will terminate upon the termination of the net profits interest unless earlier terminated by mutual agreement of the Trustee and MV Partners.

Registration Rights

The Trust entered into a registration rights agreement with MV Partners in connection with MV Partners’ conveyance to the Trust of the net profits interest. In the registration rights agreement, the Trust agreed, for the benefit of MV Partners and any transferee of its Trust Units (each, a “holder”), to register the Trust Units it holds. Specifically, the Trust agreed:

•

subject to certain restrictions, to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable Trust Units;

•

to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and

•

to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the Trust Units covered by the registration statement have been sold pursuant to such registration statement or until all registrable Trust Units:

•

have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;”

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•

have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the Trust Units; or

•

become eligible for resale pursuant to Rule 144(k) (or any similar rule then in effect under the Securities Act).

The holders will have the right to require the Trust to file up to three registration statements and will have piggyback registration rights in certain circumstances.

In connection with the preparation and filing of any registration statement, MV Partners will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trustee, and any underwriting discounts and commissions, which will be borne by the seller of the Trust Units.

Item 14.

Principal Accountant Fees and Services.

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.

The following table presents fees for professional audit services rendered by Grant Thornton LLP for the audit of the Trust’s financial statements for 2023 and 2024 and fees billed for other services rendered by Grant Thornton LLP.

	2023			2024
Audit fees		$	256,172		$	264,833
Audit-related fees			—			—
Tax fees			—			—
All other fees			—			—
Total fees		$	256,172		$	264,833

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PART IV

Item 15.

Exhibit and Financial Statement Schedules

(a)(1) Financial Statements

The following financial statements are set forth under Part II, Item 8 of this Form 10-K on the pages indicated:

	Page in this Form 10-K
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)		49
Statements of Assets and Trust Corpus		50
Statements of Distributable Income		50
Statements of Changes in Trust Corpus		50
Notes to Financial Statements		51

(a)(2) Schedules

Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.

(a)(3) Exhibits

Exhibit Number		Description
3.1	—	Certificate of Trust of MV Oil Trust. (Incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-1, filed on August 14, 2006 (Registration No. 333-136609))
3.2	—	Amended and Restated Trust Agreement, dated as of January 24, 2007, among MV Partners, LLC, The Bank of New York Trust Company, N.A. and Wilmington Trust Company. (Incorporated herein by reference to Exhibit 3.1 to the Trust’s Current Report on Form 8-K filed on January 25, 2007 (File No. 1-33219))
4.1	—	Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934. (Incorporated herein by reference to Exhibit 4.1 to the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (File No. 1-33219))
10.1	—	Conveyance of Net Profits Interest, dated as of January 24, 2007, from MV Partners, LLC to The Bank of New York Trust Company, N.A. as Trustee of MV Oil Trust. (Incorporated herein by reference to Exhibit 10.1 to the Trust’s Current Report on Form 8-K filed on January 25, 2007 (File No. 1-33219))
10.2	—	Administrative Services Agreement, dated January 24, 2007, by and between MV Partners, LLC and The Bank of New York Trust Company, N.A. as Trustee of MV Oil Trust. (Incorporated herein by reference to Exhibit 10.2 to the Trust’s Current Report on Form 8-K filed on January 25, 2007 (File No. 1-33219))
10.3	—	Registration Rights Agreement, dated January 24, 2007, by and between MV Partners, LLC and The Bank of New York Trust Company, N.A. as Trustee of MV Oil Trust. (Incorporated herein by reference to Exhibit 4.1 to the Trust’s Current Report on Form 8-K filed on January 25, 2007 (File No. 1-33219))
31.1*	—	Certification filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	—	Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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Exhibit Number		Description
97.1	—	MV Oil Trust Clawback Policy. (Incorporated herein by reference to Exhibit 97.1 to the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023 (File No. 1-33219))
99.1*		Report of Cawley, Gillespie & Associates, Inc., Petroleum Consultants

Filed or furnished herewith.

Item 16. Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MV OIL TRUST

By:

The Bank of New York Mellon Trust
Company, N.A., as Trustee

By:

/s/ Elaina C. Rodgers

Elaina C. Rodgers
Vice President

March 20, 2025

The Registrant, MV Oil Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust Agreement under which it serves.

Exhibit 31.1

CERTIFICATION

I, Elaina C. Rodgers, certify that:

I have reviewed this annual report on Form 10-K of MV Oil Trust, for which The Bank of New York Mellon Trust Company, N.A. acts as Trustee;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report;

I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and I have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared; and

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

(c)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report information; and

(b)

Any fraud, whether or not material, that involves any persons who have a significant role in the registrant’s internal control over financial reporting.

In giving the foregoing certifications in paragraphs 4 and 5, I have relied to the extent I consider reasonable on information provided to me by MV Partners, LLC.

Date: March 20, 2025

	/s/ Elaina C. Rodgers
	Elaina C. Rodgers Vice President The Bank of New York Mellon Trust Company, N.A., Trustee for MV Oil Trust

Exhibit 32.1

March 20, 2025

Via EDGAR

Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549

Re:	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Ladies and Gentlemen:

In connection with the Annual Report of MV Oil Trust (the “Trust”) on Form 10-K for the year ended December 31, 2024 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

The above certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and is not being filed as part of the Report or as a separate disclosure document.

	The Bank Of New York Mellon Trust Company, N.A.

	Trustee for MV Oil Trust

	By:	/s/ Elaina C. Rodgers
		Elaina C. Rodgers Vice President

Exhibit 99.1

Cawley, Gillespie & Associates, INC.

petroleum consultants

6500 RIVER PLACE BLVD, BLDG 3, SUITE 200	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 1900
AUSTIN, TEXAS 78730	FORT WORTH, TEXAS 76102	HOUSTON, TEXAS 77002
512-249-7000	817- 336-2461	713-651-9944

www.cgaus.com

February 18, 2025

Bank of New York Mellon Trust Company, N.A.

   as Trustee of MV Oil Trust

Attn: Elaina C. Rodgers

919 Congress Avenue

Austin, Texas 78701

Re:	Evaluation Summary	Pursuant to the Guidelines of the
*MV Oil Trust Net Profits Interests*		Securities and Exchange Commission for
Total Proved Reserves		Reporting Corporate Reserves and
Certain Oil and Gas Assets – KS & CO		Future Net Revenue
	As of December 31, 2024

Ladies and Gentlemen:

As requested, this report was prepared on February 18, 2025 for MV Oil Trust (“Trust”) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the Trust term net profits interests. We evaluated 100% of the Company’s reserves, which are associated with certain oil and gas properties in Kansas and Colorado. This evaluation, effective December 31, 2024, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the proved reserves is presented below:

		Proved		Proved
		Developed		Developed		Proved			Total
		Producing		Non-Producing		Undeveloped			Proved
Net Reserves
Oil	-MBBL		767.7		3.0		1.3			772.1
Gas	-MMCF		7.2		0.0		0.0			7.2
NGL	-MBBL		0.1		0.0		0.0			0.1
MBOE	-MBBL		769.0		3.0		1.3			773.4
Revenue
Oil	- M$		54,494.9		214.8		94.0			54,803.7
Gas	- M$		14.3		0.0		0.0			14.3
NGL	- M$		3.8		0.0		0.0			3.8
Severance Taxes	- M$		324.8		9.7		4.3			338.8
Ad Valorem Taxes	- M$		1,280.5		12.9		5.6			1,299.1
Future Production Costs	- M$		27,543.6		6.8		5.6			27,556.0
Future Development Costs	- M$		0.0		120.0		250.0			370.0
Future Net Cash Flow	- M$		20,291.3		52.3		(137.2	)		20,206.5
Discounted @ 10%	- M$		18,966.6		44.3		(121.5	)		18,889.4
*(Present Worth)*

Future revenue was calculated prior to deducting state production taxes and ad valorem taxes; however, future net cash flow was calculated after deducting these taxes, future development costs, and future production costs, but before federal income taxes. Future net cash flow has been discounted at an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine net present worth. Present worth indicates the time value of money and should not be construed as being fair market value.

The oil reserves include oil and condensate. Oil and natural gas liquid (“NGL”) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (“MCF”) at contract temperature and pressure base. Barrels of oil equivalent (“BOE”) is expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels. Our estimates include proved reserves only. Neither probable or possible reserves, nor interest in acreage beyond the location of proven reserves have been estimated.

Proved Developed reserves are the summation of the Proved Developed Producing and Proved Developed Non-Producing reserve estimates. Proved Developed reserves were estimated at 770.7 Mbbl oil, 7.2 MMcf gas and 0.1 Mbbl NGLs (or 772.0 MBOE). Of the Proved Developed reserves, 769.0 MBOE were attributed to producing zones in existing wells and 3.0 MBOE were attributed to zones in existing wells not producing.

Net Profits Calculations

The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of hydrocarbon production within the Company underlying properties. The net profits interests will terminate on the later to occur of (1) June 30, 2026, or (2) the time when 14.4 MMBOE have been produced from the underlying properties and sold, and the trust will soon thereafter wind up its affairs and terminate. For this report, it was estimated that the Trust would terminate June 30, 2026 based on the calculation that 14.4 MMBOE has 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) prior to the effective date of this report. The cash flow tables in this report reflect the termination date of June 30, 2026.

Hydrocarbon Pricing

The base SEC oil and gas prices calculated for year end 2024 were $75.48/bbl and $2.130/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot market prices during 2024 and the base gas price is based upon Henry Hub spot market prices during 2024.

Oil price differentials were forecast at -$4.50/BBL of oil for all properties. Gas price and NGL price differentials varied by property. The base price differentials may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $70.98/BBL for oil, $1.994/MMBTU for gas, and $30.19/BBL for NGLs. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Capital expenses (Future Development Costs), lease operating expenses (Future Production Costs) and ad valorem tax values were forecast as provided by your office and were thoroughly reviewed by us for accuracy and completeness. These values appear to be reasonable and appropriate for this evaluation. Lease operating expenses (column 22) and overhead (COPAS, column 26) were determined at the well level using averages determined from historical lease operating statements. Workover Expenses (column 25) were applied to cover the annual costs for recurring well work and wellbore abandonment. All economic parameters, including expenses and future development costs, were held constant (not escalated) throughout the life of these properties.

Severance tax rates were applied at normal state percentages of oil, gas and NGL 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 your office. Oil and gas conservation tax rates were applied to all Kansas properties at current rates of $0.144 per BBL and $0.0205 per MCF, respectively.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page two (2) of the Appendix. We evaluated 844 PDP properties for this report, most with monthly production data typically updated through 09/30/2024, as provided by the Company. Certain PDP properties consist of multiple-well leases. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting PDNP and PUD reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages three (3) and four (4) of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes two (2) PUD locations based in the Bemis-Shutts Field in Kansas targeting the Arbuckle zone. The PUD locations are commercially viable, however, due to the termination date of the Trust, they do not achieve a positive discounted cash flow in this report. Each of the drilling locations proposed as part of the Company development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have intent to complete this development plan within the next five (5) years. Furthermore, the Company has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have been included as part of the workover expenses described previously.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties, MV Partners, LLC, or MV Oil Trust and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. We consent to the filing of this report as an exhibit to the Annual Report on Form 10-K of MV Oil Trust for the year end December 31, 2024.

	Yours very truly,

	W. Todd Brooker, P.E.
	President
	CAWLEY, GILLESPIE & ASSOCIATES, INC.
	Texas Registered Engineering Firm (F-693)

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22)   Proved oil and gas reserves.   Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“(i)   The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii)   In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii)   Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv)   Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v)   Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“(6)   Developed oil and gas reserves.   Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)   Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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

“(31)   Undeveloped oil and gas reserves.   Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i)   Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii)   Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii)   Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

“(18)   Probable reserves.   Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)   When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)   Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii)   Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)   See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17)   Possible reserves.   Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)   When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)   Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)   Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)   The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)   Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)   Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26)   Reserves.   Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26):   Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

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