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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, 2023

☐

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

For the transition period from to

Commission File 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 $12.77 on June 30, 2023, was approximately $110,141,250.

As of March 20, 2024, 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		29
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		60
Item 9A. Controls and Procedures		60
Item 9B. Other Information		60
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections		61
PART III
Item 10. Directors, Executive Officers and Corporate Governance		62
Item 11. Executive Compensation		62
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		62
Item 13. Certain Relationships and Related Transactions, and Director Independence		63
Item 14. Principal Accountant Fees and Services		64
PART IV
Item 15. Exhibit and Financial Statement Schedules		65
Item 16. Form 10-K Summary		66
SIGNATURES		67

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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, such as the COVID-19 pandemic, 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 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 Hamas 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, 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 2021, 2022 and 2023 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, 2023, the underlying properties produced predominantly oil from approximately 850 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, 2023 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, 2023. Production volumes from the underlying properties for the year ended December 31, 2023 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.

The net profits interest 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 (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), and the Trust will soon thereafter wind up its affairs and terminate. As of December 31, 2023, cumulatively, since inception, the Trust has received payment for approximately 11.3 MMBoe of the Trust’s 11.5 MMBoe interest.

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

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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, 2024.

Distributions and Income Computations

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

Unless otherwise advised by counsel or the Internal Revenue Service (the “IRS”), the Trustee will treat the income and expenses of the Trust for each quarter as belonging to the Trust unitholders of record on the quarterly record date. For federal income tax purposes, Trust unitholders must take into account items of income, gain, loss, deduction and credit consistent with their methods of accounting and without regard to the taxable year or accounting method employed by the Trust and without regard to the quarter in which the Trust makes distributions related to those items to the Trust unitholders. Variances between taxable income and cash distributions may occur. For example, the Trustee could establish a reserve in one quarter using funds that would be included in income in the quarter in which the reserve is created but may not result in a tax deduction or a distribution until a later quarter or possibly in a later taxable year. Similarly,

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the Trustee could also make a payment in one quarter that would be amortized for income tax purposes over several quarters. See “— Federal Income Tax Matters.”

Periodic Reports

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

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

Liability of Trust Unitholders

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

Voting Rights of Trust Unitholders

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

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

•

dissolve the Trust;

•

remove the Trustee or the Delaware Trustee;

•

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

•

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

•

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

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

Duration of the Trust; Sale of the Net Profits Interest

The Trust will remain in existence until shortly after the liquidation date, which is 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 (which amount is the equivalent of 11.5 MMBoe in respect of the Trust’s right to receive 80% of the

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net proceeds from the underlying properties pursuant to the net profits interest). The net profits interest will terminate on the liquidation date, at which point the Trust will dissolve and commence winding up its business and affairs.

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

•

the Trust sells the net profits interest;

•

annual cash proceeds received by the Trust attributable to the net profits interest are less than $1 million for each of two consecutive years;

•

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, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders.

Computation of Net Proceeds

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

Net Profits Interest

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

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

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

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

“Net proceeds” means gross proceeds less the following:

•

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;

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•

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, 2024 is $2,223,892.

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 $3.2 million in 2021, $3.3 million in 2022 and $3.4 million in 2023 for all of the underlying properties for which MV Partners was designated as the operator. The fee is adjusted annually and will increase or decrease each year based on changes in the year-end index of average weekly earnings of crude petroleum and natural gas workers.

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

Gross proceeds and net proceeds are calculated on a cash receipts and cash disbursements basis.

Additional Provisions

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

•

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

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•

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

•

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

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

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

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

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

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

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

Federal Income Tax Matters

The following is a summary of certain federal income tax matters that may be relevant to Trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes or different interpretation at any time, possibly with retroactive effect. No attempt has been made in the following summary to comment on all federal income tax matters affecting the Trust or the Trust unitholders.

The summary is limited to Trust unitholders who are individual citizens or residents of the United States. Accordingly, the following summary has limited application to domestic corporations and persons

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subject to specialized federal income tax treatment. Each Trust unitholder should consult his or her own tax advisor with respect to his or her particular circumstances.

Classification and Taxation of the Trust

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

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

Classification of the Net Profits Interest

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

Widely Held Fixed Investment Trust Reporting Information

The Trustee assumes that some Trust Units are held by middlemen, as such term is broadly defined in Treasury regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, Texas 77002, telephone number 1-855-802-1094, is the representative of the Trust that will provide tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Trust unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Trust unitholders whose Trust Units are held by middlemen should consult with

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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 2023 federal and state income tax returns. The projected payment schedule for the net profits interest is included with the tax information booklet. This tax information booklet, when available, can be obtained at http://mvo.q4web.com/home/default.aspx.

Description of the Underlying Properties

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

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

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

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

Reserves

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

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Estimates of the proved oil and gas reserves attributable to the Trust as of December 31, 2021, 2022 and 2023 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 32 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 2021, 2022 and 2023 is presented consistent with these requirements.

Proved Reserves of MV Oil Trust. The following table sets forth, as of December 31, 2023, 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		1,069		35		—		1,075
Proved Undeveloped		14		—		—		14
Total Proved		1,083		35		—		1,089

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, 2020		1,801		18		1		1,805
Revisions of previous estimates		662		102		(1)		677
Production		(515)		(33)		—		(520)
Balance, December 31, 2021		1,948		87		—		1,962
Revisions of previous estimates		95		11		—		97
Production		(494)		(25)		—		(498)
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
Proved Developed Reserves:
Balance, December 31, 2020		1,641		18		1		1,645
Balance, December 31, 2021		1,861		87		—		1,875

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	Oil (MBbls)		Natural Gas (MMcf)		Natural Gas Liquids (MBbls)		Oil Equivalents (MBoe)
Balance, December 31, 2022		1,493		73		—		1,505
Balance, December 31, 2023		1,069		35		—		1,075
Proved Undeveloped Reserves:
Balance, December 31, 2020		160		—		—		160
Proved undeveloped reserves converted to proved developed reserves by drilling		(69)		—		—		(69)
Additional proved undeveloped reserves added during 2021		10		—		—		10
Proved undeveloped reserves removed from drilling plan		(14)		—		—		(14)
Revisions of previous estimates		—		—		—		—
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

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

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

The following table sets forth the estimates of total proved reserves and forecasts of economics attributable to the Trust’s 80% net profits interest in the underlying properties as of December 31, 2023 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, 2023 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)		1,330.0		6.9		17.4		1,354.3
Gas (MMcf)		44.0		0.0		0.0		44.0
NGL (MBbl)		0.2		0.0		0.0		0.2

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	Proved Developed Producing			Proved Developed Non-Producing			Proved Undeveloped			Total Proved
	(dollars in thousands)
Revenue
Oil		$	98,045.9		$	511.6		$	1,282.7		$	99,840.2
Gas			105.8			0.0			0.0			105.8
NGL			6.9			0.0			0.0			6.9
Severance Taxes			580.4			23.1			58.0			661.6
Ad Valorem Taxes			2,300.9			30.7			77.0			2,408.5
Operating Expenses			46,176.9			19.2			187.0			46,383.1
Future Development Costs			0.0			250.0			340.0			590.0
80% NPI Net Operating Income(1)		$	39,280.4		$	150.8		$	496.6		$	39,927.8
80% Net Profits Interest (NPI)(2)		$	35,199.8		$	123.2		$	427.9		$	35,750.9

(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 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. Based on the reserve report, CG&A estimated that the net profits interest would terminate on June 30, 2026 based on the calculation that 14.4 MMBoe would 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) prior to this date.

Oil and gas prices were adjusted to a WTI Cushing oil price of $78.22 per Bbl and a Henry Hub natural gas price of $2.64 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 2023. The price adjustments were based on oil price differentials forecast at -$4.50 per Bbl for all properties. Oil price differentials were not escalated. Gas and NGL price differentials were forecast on a per property basis as provided by MV Partners and were also not escalated. Price differentials include adjustments for transportation and basis differential. Gas prices were further adjusted with a heating value (Btu content) applied on a per-property basis. Operating expenses, workover expenses, COPAS overhead charges and investments were forecast on a per property basis as furnished by MV Partners. Expenses and investments were held constant in accordance with SEC rules and guidelines. Severance tax rates were applied at normal state percentages of oil and gas revenue, except for those Kansas producing properties that are severance tax exempt. Ad valorem taxes of 2.0% of total revenue were applied to each property as provided by MV Partners. Oil and gas conservation tax rates were applied to all Kansas properties at the applicable rates.

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

Producing Acreage and Well Counts

For the following data, “gross” refers to the total wells or acres in which MV Partners owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by MV

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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, 2023.

	Gross		Net
	(acres)
Developed Acreage:
El Dorado Area		15,165		15,153
Northwest Kansas Area		11,165		11,120
Other		20,030		16,382
Total		46,360		42,655
Undeveloped Acreage:		—		—

The following is a summary of the producing wells on the underlying properties as of December 31, 2023:

	Operated Wells				Non-Operated Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Oil		781		765		64		9		845		775
Natural gas		3		2		1		—		4		2
Total		784		767		65		9		849		777

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,
	2021				2022				2023
	Gross		Net		Gross		Net		Gross		Net
Completed:
Oil wells		1		1		1		1		—		—
Natural gas wells		—		—		—		—		—		—
Non-productive		1		1		—		—		—		—
Total		2		2		1		1		—		—

During the years ended December 31, 2021, 2022 and 2023, MV Partners drilled, completed and commenced production with respect to 1, 1 and 0 wells, respectively, on the underlying properties. As of December 31, 2023, no wells were being drilled. Capital expenditures associated with converting proved undeveloped reserves to proved developed reserves for the year ended December 31, 2023, were approximately $102,477. 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.

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	Year Ended December 31,
	2021			2022			2023
Sales prices:
Oil (per Bbl)		$	61.31		$	89.97		$	73.85
Natural gas (per Mcf)		$	2.85		$	5.98		$	3.09
Lease operating expense (per Boe)		$	20.45		$	22.67		$	24.02
Lease maintenance (per Boe)		$	3.57		$	4.95		$	3.95
Lease overhead (per Boe)		$	5.01		$	5.41		$	5.80
Production and property taxes (per Boe)		$	1.38		$	1.64		$	1.88

Major Producing Areas

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

El Dorado Area

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

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

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

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

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

Northwest Kansas Area

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

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

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

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

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

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

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

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

Marketing and Post-Production Services

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

Vess Oil and Murfin Drilling, as contract operators, generally sell production from the underlying properties to several purchasers, including MV Purchasing, LLC (“MV Purchasing”), under short-term arrangements using market-sensitive pricing. MV Purchasing is majority-owned by the indirect equity owners of MV Partners. These sales to purchasers are under terms ranging from one month to six months, using market sensitive pricing. Two purchasers, including MV Purchasing, have been purchasing substantially all of the crude oil production, and a substantial portion of the crude oil production may continue be acquired by one or more single purchasers. For the years ended December 31, 2021, 2022 and 2023, MV Purchasing purchased 73%, 74% and 73%, 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

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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, 2021, 2022 and 2023 was $4.52, $4.17 and $4.13 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, 2021, 2022 and 2023, MV Partners plugged and abandoned 18, 6 and 4 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.

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

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price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

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

Regulation

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

FERC Regulation

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

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

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

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

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

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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 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.

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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 thereafter, the Supreme Court issued its decision in Sackett II which overturned a substantial portion of the basis for the 2023 Rule. 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. MV Partners’ regulatory obligations and permitting costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given the ongoing litigation.

USACE Nationwide Permits (“NWPs”) are a streamlined form of permitting used to authorize activities related to development activities with minimal individual or cumulative adverse effects in wetlands or other waters of the United States under the CWA. Some NWPs are also used to authorize activities that impact traditional navigable waters under the Rivers and Harbors Act. The current administration has stated an intention to re-visit NWP 12, which is used to authorize regulated impacts related to construction of oil and gas pipelines, through notice and comment rulemaking before its current expiration date of February 2026. In addition, a federal court in Washington, D.C. is currently hearing a challenge to NWP 12. Revisions to NWP 12 by USACE or an adverse decision in Washington, D.C. may restrict or remove the

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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.

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, in December 2023 the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed or modified after December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. Additionally, the EPA for the first time adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

The 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. Although MV Partners may be required to incur certain capital expenditures during the next few years for air pollution control equipment or other air emissions-related issues, at this time MV Partners does not expect that such requirements will have a material adverse effect on its operations.

Climate Change. In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) may present an endangerment to public health and the environment, the EPA

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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 recently adopted methane emissions guidelines for existing oil and gas sources. 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. In addition, the EPA has recently proposed rules to implement the mandatory Waste Emissions Charge set forth in the Inflation Reduction Act of 2022 (the “IRA”), which will charge a fee based on the methane emissions from applicable facilities in the oil and gas sector starting in 2024.

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 limiting 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, in December 2023 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 reductions in 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 IRA included new Clean Air Act section 136(c) directing the EPA to collect the Waste Emissions Charge from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with EPA’s new or existing source methane requirements. The EPA proposed new rules to implement the Waste Emissions Charge program in January 2024.

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. In addition, from time to time Congress has considered 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 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

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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. In January 2021, President Biden issued an Executive Order announcing that the new administration would initiate a review of the 2019 amendments to the ESA rules. The Biden Administration has rescinded one of the rules adopted by the prior administration, dealing with critical habitat, and has issued a proposed rule that would make significant changes to the federal consultation process. That rule is expected to be finalized by the Biden Administration. Changes to these rules could make a federal review process occasioned by the application for permits, rights of way, or leases more complex. In addition, designation of new species as threatened or endangered could cause MV Partners to incur additional costs arising from species protection measures, could result in limitations on activities, and could require a more complex regulatory compliance process.

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. The Trump Administration significantly revised the regulations implementing NEPA in 2020 in an effort to make the review process more efficient and more narrowly tailored to the agency’s specific action. The Biden Administration undertook an initial revision to the NEPA regulations which were finalized in 2022, essentially reverting to the pre-2020 rule language for a few elements of the rules. In 2023, the Biden Administration issued a second proposed rule that would make significant changes to the Trump Administration regulations. The proposed rule is expected to be finalized in April 2024. In addition, in early 2023 the White House Council on Environmental Quality issued Guidance to the federal agencies on how agencies should consider greenhouse gas emissions and climate impacts in the course of their reviews under NEPA. Although the Trump Administration regulations were never fully implemented, the Biden Administration changes may have a meaningful impact on federal reviews related to MV Partners, especially as those reviews relate to climate and environmental justice.

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.

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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, 2021, 2022 and 2023. 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. However, there is no assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on the operations of the underlying properties and cash distributions to Trust unitholders.

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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 Hamas 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, such as the COVID-19 pandemic, 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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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 2023 ranged from a high of $93.68 to a low of $66.74. The NYMEX crude oil prices per Bbl were $75.21, $80.26 and $71.65 as of December 31, 2021, 2022 and 2023, respectively. Commodity prices displayed dramatic volatility in 2020, when the COVID-19 pandemic and various governmental actions taken to mitigate the impact of COVID-19 resulted in an unprecedented decline in demand for oil and natural gas. The effects of the economic disruption caused by the governmental responses to the COVID-19 pandemic continued to be felt through 2023, in the form of lingering supply chain disruptions, higher inflation and higher interest rates, which affected supply and demand for oil and natural gas. Meanwhile, as strains or variants of COVID-19 resurge, or if other epidemic or pandemic diseases or other public health event were to occur, the negative impact to global demand for oil and natural gas could be material. 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.

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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, such as the significant and rapid decline that occurred in 2020, 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 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 price 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

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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, 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 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.

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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 9.2% 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 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 (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).

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 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

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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.

SEC Form 10-K filed by MV Oil Trust