VOC Energy Trust 10-K, filed Mar 20, 2025
VOC Energy Trust (VOC)
10-K
2025-03-20
For: 2024-12-31
View Original
Added on
April 06, 2026
About this 10-K
VOC Energy Trust filed this 10-K on March 20, 2025, covering the fiscal year ended December 31, 2024.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024
or
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 001-35160
VOC ENERGY TRUST
(Exact name of registrant as specified in its charter)
(Exact name of registrant as specified in its charter)
| |
Delaware
(State or other jurisdiction of
incorporation or organization) |
| |
80-6183103
(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
|
| |
VOC
|
| |
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 12,747,750 Units of Beneficial Interest in VOC Energy Trust held by non-affiliates of the registrant, computed using the closing sales price of $4.81 on June 28, 2024, was approximately $61,316,678.
As of March 20, 2025, 17,000,000 Units of Beneficial Interest in VOC Energy Trust were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
TABLE OF CONTENTS
| | | |
Page
|
| |||
| | | | | 1 | | | |
| | | | | 2 | | | |
|
PART I
|
| | | | | | |
| | | | | 6 | | | |
| | | | | 30 | | | |
| | | | | 44 | | | |
| | | | | 44 | | | |
| | | | | 45 | | | |
| | | | | 46 | | | |
| | | | | 46 | | | |
|
PART II
|
| | | | | | |
| | | | | 47 | | | |
| | | | | 47 | | | |
| | | | | 47 | | | |
| | | | | 53 | | | |
| | | | | 54 | | | |
| | | | | 66 | | | |
| | | | | 66 | | | |
| | | | | 66 | | | |
| | | | | 66 | | | |
|
PART III
|
| | | | | | |
| | | | | 67 | | | |
| | | | | 67 | | | |
| | | | | 67 | | | |
| | | | | 68 | | | |
| | | | | 69 | | | |
|
PART IV
|
| | | | | | |
| | | | | 70 | | | |
| | | | | 71 | | | |
| | | | | 72 | | | |
i
FORWARD LOOKING STATEMENTS
This Annual Report on Form 10-K (this “Form 10-K”) contains forward looking statements about VOC Brazos Energy Partners, L.P., a Texas limited partnership (“VOC Brazos”), and VOC Energy 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 VOC Brazos 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 VOC Brazos and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward looking statements:
•
risks incident to the drilling and operation of oil and natural gas wells;
•
future production and development costs and plans;
•
the occurrence or threat of epidemic or pandemic diseases, or other public health events or any government response to such occurrence or threat;
•
the effects of actions by, or disputes among or between members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil-exporting nations, such as Russia, with respect to production levels or other matters related to the prices of oil and natural gas;
•
the impact of geopolitical developments and tensions, war and uncertainty involving or in the geographical region of oil-producing countries (including the ongoing armed conflicts between Russia and Ukraine and between Israel and Iran and its proxies and any related political or economic responses and counter-responses or otherwise by various global actors or the general effect on the global economy);
•
global economic conditions, such as a general slowdown in the global economy, trade barriers and tariffs, supply chain disruptions, inflationary pressures, currency fluctuations, changes in interest rates, and instability of financial institutions;
•
the effect of existing and future laws and regulatory actions;
•
the effect of changes in commodity prices and conditions in the capital markets;
•
competition from others in the energy industry;
•
ability of commodity purchasers to make payment;
•
weather conditions or force majeure events;
•
uncertainty of estimates of oil and natural gas reserves and production;
•
potential impacts on VOC Brazos’ 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 VOC Brazos and the Trust, including under the heading “Risk Factors” in Item 1A. All written and oral forward-looking statements attributable to VOC Brazos or the Trust or persons acting on behalf of VOC Brazos or the Trust are expressly qualified in their entirety by such factors.
1
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.
Completion — The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
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 and natural gas to estimated future production from oil and natural gas 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 the Intercontinental Exchange, Spot and future natural gas prices set at Henry Hub are denominated in USD per MMBtu.
MBbl — 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. For purposes of this Form 10-K, references to Mcf include an insignificant amount of natural gas liquid measurement.
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. For purposes of this Form 10-K, references to MMcf include an insignificant amount of natural gas liquid measurement.
2
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.
Net Revenue Interest — An interest in all oil and natural gas 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.
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.
3
(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.
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.
PV-10 — The present value of estimated future net revenues using a discount rate of 10% per annum.
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:
a.
Future cash inflows. These shall be computed by the average of the first-day-of-the-month prices during the 12-month period preceding the end of the year for 2022, 2023 and 2024 of oil and gas relating to the enterprise’s proved reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.
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.
4
c.
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.
d.
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.
e.
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.
f.
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 the New York Mercantile Exchange’s oil future contracts for delivery at Cushing, Oklahoma.
5
PART I
Item 1. Business.
General
VOC Energy Trust (the “Trust”) was formed in November 2010 by VOC Brazos Energy Partners, L.P. (“VOC Brazos”). Much of the information disclosed in this Form 10-K has been provided to the Trust by VOC Brazos, 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 dated November 3, 2010 (as amended and restated on May 10, 2011, the “Trust Agreement”) among VOC Brazos, 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://voc.q4web.com/home/default.aspx.
On May 10, 2011, VOC Brazos and the Trust completed an initial public offering of units of beneficial interest in the Trust (the “Trust Units”). In connection with the closing of the initial public offering, on May 10, 2011, VOC Brazos conveyed a net profits interest to the Trust, which entitles the Trust to receive 80% of the net proceeds (calculated as described below) from the sale and production of substantially all of the interests in oil and natural gas properties in the states of Kansas and Texas held by VOC Brazos as of May 10, 2011 (the “net profits interest”), pursuant to the Conveyance of Net Profits Interest dated as of May 10, 2011 (the “Conveyance”). VOC Brazos’ net interests in such properties, after deduction of all royalties and other burdens on production thereon as of May 10, 2011, is referred to in this Form 10-K as the “Underlying Properties.” As of December 31, 2024, the Underlying Properties included interests in 722 gross (444.7 net) producing wells and included 80,935 gross (50,160.7 net) acres.
The net profits interest will terminate on the later to occur of (1) December 31, 2030, or (2) the time from and after January 1, 2011 when 10.6 MMBoe have been produced from the Underlying Properties and sold (which amount is the equivalent of 8.5 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, 2024, cumulatively, since inception, the Trust has received payment for approximately 7.3 MMBoe of the Trust’s 8.5 MMBoe interest.
The Trust will make quarterly cash distributions of substantially all of its quarterly cash receipts, after deducting the Trust’s administrative expenses, on or about 45 days following the completion of each quarter through (and including) the quarter ending December 31, 2030. 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 amount of Trust revenues and cash distributions to Trust unitholders will depend on, among other things:
•
oil sales prices and, to a lesser extent, natural gas sales prices;
•
volumes of oil and natural gas produced and sold attributable to the Underlying Properties;
•
property and production taxes;
•
development expenses;
6
•
lease operating expenses; and
•
administrative expenses of the Trust.
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 neither VOC Brazos nor any of its affiliates has the ability to manage or influence the operations of the Trust. Vess Oil Corporation (“Vess Oil”), L.D. Drilling, Inc. and Davis Petroleum, Inc. (collectively, the “VOC Operators”) are currently the operator or contract operator of substantially all of the Underlying Properties. Effective September 1, 2022, Vess Oil took over, from Davis Petroleum, Inc., operations of the Underlying Properties in which VOC Brazos had an ownership interest; and effective July 1, 2023, Vess Oil took over, from L.D. Drilling, Inc., operations of the Underlying Properties in which VOC Brazos had an ownership interest. VOC Brazos 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 units. The Trust Units are in book-entry form only and are not represented by certificates. The Trust had 17,000,000 Trust Units outstanding as of March 20, 2025.
Distributions and Income Computations
Each quarter, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the net profits interest and other sources (such as interest earned on any amounts reserved by the Trustee) in that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future expenses. Quarterly cash distributions during the term of the Trust are made by the Trustee on or before the 45th day following the end of each quarter to the Trust unitholders of record on the 30th day following the end of each quarter (or the next succeeding business day).
Unless otherwise advised by counsel or the Internal Revenue Service (the “IRS”), the Trustee will treat the income and expenses of the Trust for each quarter as belonging to the Trust unitholders of record on the quarterly record date. For federal income tax purposes, Trust unitholders must take into account items of income, gain, loss, deduction and credit consistent with their methods of accounting and without regard to the taxable year or accounting method employed by the Trust and without regard to the quarter in which the Trust makes distributions related to those items to the Trust unitholders. Variances between taxable income and cash distributions may occur. For example, the Trustee could establish a reserve in one quarter using funds that would be included in income in the quarter in which the reserve is created but may not result in a tax deduction or a distribution until a later quarter or possibly in a later taxable year. Similarly, the Trustee could also make a payment in one quarter that would be amortized for income tax purposes over several quarters. See “— Federal Income Tax Matters.”
Periodic Reports
The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and provides the tax information that Trust unitholders need to correctly report their share of the income and deductions of the Trust. The Trustee also causes to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust Units are listed or admitted to trading, and also causes the Trust to comply with the provisions of the Sarbanes-Oxley Act of 2002, including but not limited to, by establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.
Each Trust unitholder and his or her representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee.
7
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 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 by proxy 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 Trust unitholders owning a majority of the Trust Units at a meeting where there is a quorum. This is true even if holders owning 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 VOC Brazos 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) December 31, 2030 or (2) the time when 10.6 MMBoe (which is the equivalent of 8.5 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) have been produced and sold. 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 prior to the liquidation date, the Trustee would sell all of the Trust’s assets, which are limited to the net profits interest, and do not include the Underlying Properties, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders.
8
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 net profits interest was conveyed to the Trust by VOC Brazos on May 10, 2011 by means of a conveyance instrument that has been recorded in the appropriate real property records in each county in Kansas and Texas where the oil and natural gas properties to which the Underlying Properties relate are located. The net profits interest burdens the net interest owned by VOC Brazos in the Underlying Properties in existence as of May 10, 2011.
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 30th day of the month following the computation period. VOC Brazos will not pay to the Trust any interest on the net proceeds held by VOC Brazos 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” means the aggregate amount received by VOC Brazos from sales of oil and natural gas produced from the Underlying Properties (other than amounts received for certain future non-consent operations). However, gross proceeds does not include consideration for the transfer or sale of any Underlying Property by VOC Brazos or any subsequent owner to any new owner. Gross proceeds also does not include any amount for oil or natural gas 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, overriding royalties or other burdens against production, delay rentals, shut-in oil and natural gas payments, minimum royalty or other payments for drilling or deferring drilling;
•
any taxes paid by the owner of an Underlying Property to the extent not deducted in calculating gross proceeds, including estimated and accrued general property (ad valorem), production, severance, sales, gathering, excise and other taxes;
•
any extraordinary taxes or windfall profits taxes that may be assessed in the future that are based on profits realized or prices received for production from the Underlying Properties;
•
costs paid by an owner of a property comprising the Underlying Properties under any joint operating agreement pursuant to the terms of the Conveyance;
•
all other costs and expenses, development costs and liabilities of drilling, recompleting, workovers, operating and producing oil and natural gas, 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 development 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 and natural gas (provided, however, that any proceeds attributable to treatment or processing will offset such costs or changes, if any);
•
any overhead charge incurred pursuant to any operating agreement relating to an Underlying Property;
•
costs for recording the Conveyance and costs estimated to record the termination and for the release of the Conveyance;
9
•
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 VOC Brazos (or any subsequent owner of the Underlying Properties), amounts reserved for approved 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 (provided that such costs shall not be debited from gross proceeds when actually incurred).
Certain non-production revenues, including salvage value for equipment related to plugged and abandoned wells, as detailed in the Conveyance, offset the costs outlined above in calculating the net proceeds. If any excess amounts have not been used to offset costs at the time when the later to occur of (1) December 31, 2030 or (2) the time when 10.6 MMBoe (which is the equivalent of 8.5 MMBoe in respect of the net profits interest) have been produced from the Underlying Properties and sold, then Trust unitholders will not be entitled to receive the benefit of such excess amounts.
During each twelve-month period beginning on the later to occur of (1) December 31, 2027 and (2) the time when 9.8 MMBoe have been produced from the Underlying Properties and sold (which is the equivalent of 7.8 MMBoe in respect of the net profits interest), which we refer to herein, in either case, as the “Capital Expenditure Limitation Date,” the sum of the development expenditures and amounts reserved for approved development 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 development expenditures and amounts reserved for approved development 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.
As is customary in the oil and natural gas industry, VOC Brazos pays an overhead fee to the VOC Operators to operate the Underlying Properties on behalf of VOC Brazos. The operating activities include various engineering, accounting and administrative functions.
The fee is based on a monthly charge per active operated well, which totaled $1.8 million paid to the VOC Operators in 2022, $2.0 million paid in 2023, and $2.1 million paid in 2024 for all of the Underlying Properties for which VOC Brazos was designated as the operator. The fee is adjusted annually and will increase or decrease each year based on changes in the Overhead Adjustment Index (“OAI”) published by the Council of Petroleum Accountants Society (“COPAS”) for that year.
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 except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.
Additional Provisions
If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:
•
amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the Underlying Property until actually collected;
•
amounts received by the owner of the Underlying Property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and
10
•
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 VOC Brazos makes to the Trust due to adjustments to prior calculations of net proceeds or otherwise will reduce future amounts payable to the Trust until VOC Brazos recovers the overpayments plus interest at the prime rate.
The Conveyance generally permits VOC Brazos 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 VOC Brazos’ interest unless certain conditions set forth in the following paragraph are satisfied. Except in certain cases where the net profits interest is released, 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, VOC Brazos 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 VOC Brazos 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.
As the designated operator of a property comprising the Underlying Properties, VOC Brazos may enter into farm-out, operating, participation and other similar agreements to develop the property. VOC Brazos may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.
VOC Brazos 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, VOC Brazos or any transferee of an Underlying Property is required under the applicable conveyance to operate, or to use commercially reasonable efforts to cause the operators of the Underlying Properties to operate these properties as would a reasonably prudent operator in the State of Kansas or Texas 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.
VOC Brazos must maintain books and records sufficient to determine the amounts payable for the net profits interest to the Trust. Quarterly and annually, VOC Brazos 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 VOC Brazos during normal business hours and upon reasonable notice.
Federal Income Tax Matters
The following is a summary of certain U.S. 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 that may or may not be retroactively applied. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Trust or the Trust unitholders.
The summary is limited to Trust unitholders who are individual citizens or residents of the United States. Accordingly, the following summary has limited application to domestic corporations and persons subject to specialized federal income tax treatment. Each Trust unitholder should consult his or her own tax advisor with respect to his or her particular circumstances.
11
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 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 VOC Brazos 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 will agree to be bound by the Trust’s application of those regulations, including the Trust’s determination of the rate at which interest will be deemed to accrue on the net profits interest. No assurance can be given that the IRS or another taxing authority will not assert that the net profits interest should be treated differently. Any such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in Trust Units and could require a Trust unitholder to accrue income at a rate different than that determined by the Trust.
Widely Held Fixed Investment Trust Reporting Information
The Trustee assumes that some Trust Units are held by middlemen, as such term is broadly defined in Treasury regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, Texas 77002, telephone number 1-855-802-1094, is the representative of the Trust that will provide tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Trust unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Trust unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units. Any generic tax information provided by the Trustee of the Trust is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.
12
Available Trust Tax Information
In compliance with the reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting booklet that is intended to be used only to assist Trust unitholders in the preparation of their 2024 federal and state income tax returns. The projected payment schedule for the net profits interest is included with the tax information booklet. This tax information booklet, when available, can be obtained at https://voc.q4web.com/home/default.aspx.
Description of the Underlying Properties
The Underlying Properties consist of VOC Brazos’ net interests in substantially all of its oil and natural gas properties after deduction of all royalties and other burdens on production thereon as of May 10, 2011, which properties are located in the states of Kansas and Texas. The VOC Operators are currently the operators or contract operators of substantially all of the Underlying Properties.
VOC Brazos’ interests in the properties comprising the Underlying Properties require VOC Brazos 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 overriding royalty and 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 the landowner’s 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 10.6 MMBoe of proved reserves attributable to the Underlying Properties expected to be produced over the term of the Trust. The Trust is entitled to receive 80% of the net proceeds from the sale of production of oil and natural gas attributable to the Underlying Properties that are produced during the term of the Trust, whereas total reserves as reflected on the summary reserve reports and attributable to the Underlying Properties include all reserves expected to be economically produced during the economic life of the Underlying Properties.
In general, the producing wells included in the Underlying Properties have stable production profiles and their production is long-lived. Based on the reserve report, annual production from the Underlying Properties is expected to decline at an average annual rate of 7.4% over the next 20 years assuming no additional development drilling or other development expenditures are made on the Underlying Properties after 2032. VOC Brazos expects total development expenditures for the Underlying Properties through December 31, 2032 will be approximately $36.4 million, which it expects will partially offset the natural decline in production otherwise expected to occur with respect to the Underlying Properties as described in more detail below.
Reserves
The engineering department of Vess Oil Corporation, who serves as contract operator for VOC Brazos, maintains oversight and compliance responsibility for the internal reserve estimate process and, in accordance with internal policies and procedures, provides appropriate data to independent third party engineers for the annual estimation of year-end reserves. This engineering department accumulates historical production data for the Underlying Properties, calculates historical lease operating expenses and differentials, updates working interests and net revenue interests, and obtains logs, 3-D seismic and other geological and geophysical information. This data is forwarded to Cawley, Gillespie & Associates, Inc. (“CG&A”), thereby allowing CG&A to prepare estimated proved reserves in their entirety based on such data.
Estimates of the proved oil and gas reserves attributable to the Trust as of December 31, 2022, 2023 and 2024 are based on reports prepared by CG&A. CG&A has been in business since 1961 and serves many organizations and individuals in the petroleum industry, including owners and operators of oil and gas
13
properties, exploration groups, planners, and professionals in investment and finance. One of the principal businesses of CG&A is providing detailed assessment of producing reservoirs. CG&A is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists and does not own an interest in the Underlying Properties and is not employed on a contingent basis. Mr. W. Todd Brooker, President, is the technical person at CG&A who is primarily responsible for overseeing CG&A’s preparation of the reserve estimates. Mr. Brooker is a graduate of the University of Texas at Austin with a Bachelor of Science degree in Petroleum Engineering and has 33 years of experience in petroleum engineering. He is a licensed professional engineer in the State of Texas (License #83462).
Oil and gas proved reserves are disclosed by significant geographic area, using the 12-month average beginning-of-month price for the year, based on the use of reliable technologies to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Reserve and related information for 2022, 2023 and 2024 is presented consistent with these requirements.
Proved Reserves of VOC Energy Trust. The following table sets forth, as of December 31, 2024, estimated proved reserves attributable to the Trust derived from the reserve report. A summary of the reserve report is included below.
| | | |
Oil
(MBbls) |
| |
Natural
gas (MMcf) |
| |
Oil
equivalents (MBoe) |
| |||||||||
|
Proved Developed
|
| | | | 1,524 | | | | | | 1,020 | | | | | | 1,694 | | |
|
Proved Undeveloped
|
| | | | 353 | | | | | | 168 | | | | | | 381 | | |
|
Total Proved
|
| | | | 1,877 | | | | | | 1,188 | | | | | | 2,075 | | |
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. VOC Brazos 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.
| | | |
VOC Energy Trust
|
| |||||||||||||||
| | | |
Oil
(MBbl) |
| |
Natural
Gas (MMcf) |
| |
Oil
Equivalents (MBoe) |
| |||||||||
| Proved Reserves: | | | | | | | | | | | | | | | | | | | |
|
Balance, December 31, 2021
|
| | | | 3,249 | | | | | | 2,199 | | | | | | 3,614 | | |
|
Revisions of previous estimates
|
| | | | (15) | | | | | | 37 | | | | | | (7) | | |
|
Production(1)
|
| | | | (410) | | | | | | (250) | | | | | | (451) | | |
|
Balance, December 31, 2022
|
| | | | 2,824 | | | | | | 1,986 | | | | | | 3,156 | | |
|
Revisions of previous estimates
|
| | | | (158) | | | | | | (410) | | | | | | (227) | | |
|
Production(1)
|
| | | | (387) | | | | | | (220) | | | | | | (424) | | |
|
Balance, December 31, 2023
|
| | | | 2,279 | | | | | | 1,356 | | | | | | 2,505 | | |
|
Revisions of previous estimates
|
| | | | (46) | | | | | | 41 | | | | | | (39) | | |
|
Production(1)
|
| | | | (356) | | | | | | (209) | | | | | | (391) | | |
|
Balance, December 31, 2024
|
| | | | 1,877 | | | | | | 1,188 | | | | | | 2,075 | | |
| Proved Developed Reserves: | | | | | | | | | | | | | | | | | | | |
|
Balance, December 31, 2021
|
| | | | 2,421 | | | | | | 1,429 | | | | | | 2,658 | | |
|
Balance, December 31, 2022
|
| | | | 2,226 | | | | | | 1,712 | | | | | | 2,512 | | |
|
Balance, December 31, 2023
|
| | | | 1,860 | | | | | | 1,154 | | | | | | 2,052 | | |
|
Balance, December 31, 2024
|
| | | | 1,524 | | | | | | 1,020 | | | | | | 1,694 | | |
14
| | | |
VOC Energy Trust
|
| |||||||||||||||
| | | |
Oil
(MBbl) |
| |
Natural
Gas (MMcf) |
| |
Oil
Equivalents (MBoe) |
| |||||||||
| Proved Undeveloped Reserves: | | | | | | | | | | | | | | | | | | | |
|
Balance, December 31, 2021
|
| | | | 828 | | | | | | 770 | | | | | | 956 | | |
|
Proved undeveloped reserves converted to proved developed by drilling
|
| | | | (33) | | | | | | (15) | | | | | | (35) | | |
|
Additional proved undeveloped reserves added
|
| | | | 23 | | | | | | 0 | | | | | | 23 | | |
|
Revisions of previous estimates
|
| | | | (220) | | | | | | (481) | | | | | | (300) | | |
|
Balance, December 31, 2022
|
| | | | 598 | | | | | | 274 | | | | | | 644 | | |
|
Proved undeveloped reserves converted to proved developed by drilling
|
| | | | 0 | | | | | | 0 | | | | | | 0 | | |
|
Additional proved undeveloped reserves added
|
| | | | 111 | | | | | | 48 | | | | | | 119 | | |
|
Revisions of previous estimates
|
| | | | (290) | | | | | | (120) | | | | | | (310) | | |
|
Balance, December 31, 2023
|
| | | | 419 | | | | | | 202 | | | | | | 453 | | |
|
Proved undeveloped reserves converted to proved developed by drilling
|
| | | | 0 | | | | | | 0 | | | | | | 0 | | |
|
Additional proved undeveloped reserves added
|
| | | | 157 | | | | | | 83 | | | | | | 171 | | |
|
Revisions of previous estimates
|
| | | | (223) | | | | | | (117) | | | | | | (243) | | |
|
Balance, December 31, 2024
|
| | | | 353 | | | | | | 168 | | | | | | 381 | | |
| | |||||||||||||||||||
(1)
Reflects sales volumes produced during the noted year regardless of whether royalty payments thereon have been remitted to the Trust by VOC Brazos.
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 Underlying Properties as of December 31, 2024 for the remainder of the term of the Trust, as presented in the summary prepared by CG&A of its reserve report as of December 31, 2024 for the Trust. The estimates of proved reserves have not been filed with or included in reports to any federal authority or agency. The discounted cash flow value shown in the table is not intended to represent the current market value of the estimated oil and natural gas reserves attributable to the Trust’s interests.
| | | |
Proved
Developed Producing |
| |
Proved
Developed Non-Producing |
| |
Proved
Undeveloped |
| |
Total
Proved |
| ||||||||||||
| | | |
(dollars in thousands)
|
| |||||||||||||||||||||
| Net Reserves | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Oil (MBbl)
|
| | | | 1,892.9 | | | | | | 12.2 | | | | | | 441.4 | | | | | | 2,346.5 | | |
|
Gas (MMcf)
|
| | | | 935.2 | | | | | | 0.0 | | | | | | 111.0 | | | | | | 1,046.2 | | |
|
NGL (MBbl)
|
| | | | 87.3 | | | | | | 0.0 | | | | | | 25.4 | | | | | | 112.7 | | |
| Revenue | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Oil
|
| | | $ | 136,731.3 | | | | | $ | 867.6 | | | | | $ | 32,714.7 | | | | | $ | 170,313.6 | | |
|
Gas
|
| | | | 1,151.4 | | | | | | 0.0 | | | | | | 69.9 | | | | | | 1,221.3 | | |
|
NGL
|
| | | | 1,777.9 | | | | | | 0.0 | | | | | | 497.9 | | | | | | 2,275.8 | | |
|
Severance Taxes
|
| | | | 3,303.9 | | | | | | 39.3 | | | | | | 1,545.3 | | | | | | 4,888.6 | | |
|
Ad Valorem Taxes
|
| | | | 3,602.7 | | | | | | 52.1 | | | | | | 1,181.5 | | | | | | 4,836.2 | | |
|
Operating Expenses
|
| | | | 68,492.9 | | | | | | 39.9 | | | | | | 1,872.6 | | | | | | 70,405.4 | | |
|
Future Development Costs
|
| | | | 330.0 | | | | | | 78.0 | | | | | | 35,801.8 | | | | | | 36,209.8 | | |
|
80% Net Profits Interest Net Operating Income (NPI)(1)
|
| | | $ | 51,144.9 | | | | | $ | 526.6 | | | | | $ | (5,694.9) | | | | | $ | 45,976.6 | | |
|
80% NPI(2)
|
| | | $ | 40,563.3 | | | | | $ | 419.2 | | | | | $ | (6,202.0) | | | | | $ | 34,780.5 | | |
15
(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 the Underlying Properties. The net profits interest will terminate on the later to occur of (1) December 31, 2030, or (2) the time when 10.6 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 for the year ended December 31, 2024, CG&A estimated that the net profits interest would terminate on December 31, 2030 based on the calculation that 10.6 MMBoe would have been produced from the Underlying Properties and sold (which amount is the equivalent of 8.5 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 $75.48 per Bbl and a Henry Hub natural gas price of $2.13 per MMBtu. As specified by the SEC, these prices are 12-month averages based upon the price on the first day of each month during 2024. The price adjustments were based on oil price differentials forecast at −$4.50 per Bbl for all Kansas Underlying Properties. For Texas properties, oil price differentials were applied at −$1.00 per Bbl for the Kurten (Woodbine) Field and Madisonville West Field wells, −$2.50 per Bbl for the Sand Flat Unit Field Wells and −$4.50 per Bbl for the Hitts Lake North Field wells. Oil price differentials were not escalated. Gas and NGL price differentials varied by property as provided by VOC Brazos and were also not escalated. The base price differentials may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. Operating expenses, workover expenses, COPAS overhead charges and investments were forecast on a per property basis as furnished by VOC Brazos. Expenses and investments were held constant in accordance with SEC rules and guidelines.
For Kansas properties, severance taxes were applied at 4.33 percent of revenue until exemption levels were forecasted to be reached. The severance tax rate was dropped to zero when a rate of 6 Bbl/day per well was reached or when gross gas production value reached $87/day per gas well. Severance taxes were forecasted at 4.6 percent of oil revenue and 7.5 percent of gas and NGL revenue for properties in Texas. Ad valorem taxes for Kansas properties were applied at 6.0 percent of revenue but dropped to 2.0 percent as properties qualified for the tax exemption. Kansas oil and gas conservation taxes were included within the severance tax estimates. Ad valorem taxes were applied at 3.29 percent of revenue (after severance taxes) for the Texas properties.
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 VOC Brazos owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by VOC Brazos. Although many of VOC Brazos’ 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 Texas. The following is a summary of the approximate acreage of the Underlying Properties at December 31, 2024.
16
| | | |
Gross
|
| |
Net
|
| ||||||
| | | |
(acres)
|
| |||||||||
| Developed Acreage: | | | | | | | | | | | | | |
|
Kansas
|
| | | | 57,242 | | | | | | 33,319.4 | | |
|
Texas
|
| | | | 23,693 | | | | | | 16,841.3 | | |
|
Total
|
| | | | 80,935 | | | | | | 50,160.7 | | |
|
Undeveloped Acreage:
|
| | | | — | | | | | | — | | |
The following is a summary of the producing wells on the Underlying Properties as of December 31, 2024:
| | | |
Operated Wells
|
| |
Non-Operated
Wells |
| |
Total
|
| |||||||||||||||||||||||||||
| | | |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| ||||||||||||||||||
|
Oil
|
| | | | 680 | | | | | | 432.9 | | | | | | 32 | | | | | | 7.6 | | | | | | 712 | | | | | | 440.5 | | |
|
Natural gas
|
| | | | 7 | | | | | | 3.5 | | | | | | 3 | | | | | | 0.7 | | | | | | 10 | | | | | | 4.2 | | |
|
Total
|
| | | | 687 | | | | | | 436.4 | | | | | | 35 | | | | | | 8.3 | | | | | | 722 | | | | | | 444.7 | | |
The following is a summary of the number of developmental wells drilled by VOC Brazos on the Underlying Properties during the last three years. VOC Brazos did not drill any exploratory wells during the periods presented.
| | | |
Year Ended December 31,
|
| |||||||||||||||||||||||||||||||||
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||||||||||||||||||||
| | | |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| |
Gross
|
| |
Net
|
| ||||||||||||||||||
| Completed: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Oil wells
|
| | | | 2 | | | | | | 0.2 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
|
Natural gas wells
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
|
Non-productive
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
|
Total
|
| | | | 2 | | | | | | 0.2 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
In 2022, two wells were drilled and completed. Total capital expenditures for these wells were $1,655,613.
In 2023, no wells were drilled and completed.
In 2024, no wells were drilled and completed.
VOC Brazos 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” for more information regarding VOC Brazos’ joint venture agreement with Hawkwood Energy East Texas, LLC, the Hawkwood Earning Wells, and the Hawkwood Development Wells (each as defined therein).
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 received by the Trust from the Underlying Properties.
| | | |
Year Ended December 31,
|
| |||||||||||||||
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
| Sales prices: | | | | | | | | | | | | | | | | | | | |
|
Oil (per Bbl)
|
| | | $ | 89.35 | | | | | $ | 75.33 | | | | | $ | 76.66 | | |
|
Natural gas (per Mcf)
|
| | | $ | 6.80 | | | | | $ | 4.68 | | | | | $ | 2.95 | | |
|
Lease operating expense (per Boe)
|
| | | $ | 24.74 | | | | | $ | 26.17 | | | | | $ | 29.07 | | |
|
Production and property taxes (per Boe)
|
| | | $ | 3.47 | | | | | $ | 3.74 | | | | | $ | 3.51 | | |
17
Major Producing Areas
The following table summarizes the estimated proved reserves by operating area attributable to the Underlying Properties according to the reserve report and the corresponding pre-tax PV-10 value as of December 31, 2024.
| | | |
Proved Reserves(1)
|
| |||||||||||||||||||||||||||||||||
|
Operating Area
|
| |
Oil
(MBbls) |
| |
Natural
Gas (MMcf) |
| |
Total
(MBoe) |
| |
% of
Total Reserves |
| |
Pre-Tax
PV-10% Value(2) |
| |
% of
Pre-Tax PV-10% Value |
| ||||||||||||||||||
| | | |
(In Thousands)
|
| |||||||||||||||||||||||||||||||||
| Kansas (149 Fields) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Fairport
|
| | | | 464 | | | | | | 0 | | | | | | 464 | | | | | | 7.3% | | | | | $ | 7,693 | | | | | | 10.3% | | |
|
Marcotte
|
| | | | 165 | | | | | | 0 | | | | | | 165 | | | | | | 2.6 | | | | | | 2,676 | | | | | | 3.6 | | |
|
Chase-Silica
|
| | | | 118 | | | | | | 0 | | | | | | 118 | | | | | | 1.8 | | | | | | 1,912 | | | | | | 2.6 | | |
|
Bindley
|
| | | | 128 | | | | | | 0 | | | | | | 128 | | | | | | 2.0 | | | | | | 1,875 | | | | | | 2.5 | | |
|
Mueller
|
| | | | 90 | | | | | | 0 | | | | | | 90 | | | | | | 1.4 | | | | | | 1,610 | | | | | | 2.2 | | |
|
Codell
|
| | | | 68 | | | | | | 0 | | | | | | 68 | | | | | | 1.1 | | | | | | 1,567 | | | | | | 2.1 | | |
|
Rosa Northwest
|
| | | | 58 | | | | | | 0 | | | | | | 58 | | | | | | 0.9 | | | | | | 1,358 | | | | | | 1.8 | | |
|
Diebolt
|
| | | | 93 | | | | | | 0 | | | | | | 93 | | | | | | 1.5 | | | | | | 1,294 | | | | | | 1.7 | | |
|
Wesley
|
| | | | 36 | | | | | | 0 | | | | | | 36 | | | | | | 0.5 | | | | | | 748 | | | | | | 1.0 | | |
|
Zurich
|
| | | | 36 | | | | | | 0 | | | | | | 36 | | | | | | 0.6 | | | | | | 741 | | | | | | 1.0 | | |
|
Lippoldt
|
| | | | 30 | | | | | | 0 | | | | | | 30 | | | | | | 0.5 | | | | | | 728 | | | | | | 1.0 | | |
|
Other
|
| | | | 946 | | | | | | 303 | | | | | | 997 | | | | | | 15.6 | | | | | | 10,289 | | | | | | 13.8 | | |
|
Kansas Total
|
| | | | 2,232 | | | | | | 303 | | | | | | 2,283 | | | | | | 35.8 | | | | | | 32,491 | | | | | | 43.6 | | |
| Texas (4 Fields) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
Kurten
|
| | | | 2,808 | | | | | | 3,778 | | | | | | 3,437 | | | | | | 54.0 | | | | | | 29,539 | | | | | | 39.6 | | |
|
Hitts Lake North
|
| | | | 401 | | | | | | 0 | | | | | | 401 | | | | | | 6.3 | | | | | | 8,662 | | | | | | 11.6 | | |
|
Sand Flat
|
| | | | 234 | | | | | | 5 | | | | | | 235 | | | | | | 3.7 | | | | | | 3,601 | | | | | | 4.8 | | |
|
Madisonville West
|
| | | | 12 | | | | | | 25 | | | | | | 16 | | | | | | 0.2 | | | | | | 270 | | | | | | 0.4 | | |
|
Texas Total
|
| | | | 3,455 | | | | | | 3,808 | | | | | | 4,089 | | | | | | 64.2 | | | | | | 42,072 | | | | | | 56.4 | | |
|
Total
|
| | | | 5,687 | | | | | | 4,111 | | | | | | 6,372 | | | | | | 100.0% | | | | | $ | 74,563 | | | | | | 100.0% | | |
(1)
In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2024 through December 1, 2024 and were held constant for the life of the properties. This yielded a base price for oil of $75.48 per barrel and a base price for natural gas of $2.13 per MMBtu.
(2)
Because the Trust bears no federal tax expense and taxable income is passed through to the Trust unitholders, no provision for federal or state income taxes is included in the summary reserve reports and therefore the standardized measure of discounted future net cash flows attributable to the Underlying Properties is equal to the pre-tax PV-10 value. PV-10 may not be considered a GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. The pre-tax PV-10 value and the standardized measure of discounted future net cash flows do not purport to present the fair value of the oil and natural gas reserves attributable to Underlying Properties.
Kansas. As of December 31, 2024, proved reserves attributable to the portion of the Kansas Underlying Properties were approximately 2.3 MMBoe and were located in three primary areas: Central
18
Kansas Uplift, Western Kansas and South-Central Kansas. As of December 31, 2024, the VOC Operators operated 98.4% of the total proved reserves attributable to the Kansas Underlying Properties based on PV-10 value.
The major fields in the Central Kansas Uplift include Fairport Field, Marcotte Field and Chase-Silica Field, all of which are producing primarily from the Arbuckle and Lansing Kansas City zones. The major fields in Western Kansas include the Bindley, Griston SW and Rosa Northwest fields, which are producing primarily from the Mississippian, Morrow, Lansing Kansas City and Cherokee zones. The major fields in South Central Kansas include the Gerberding, Spivey Grabs and Alford fields, which are producing primarily from the Mississippian, Simpson and Lansing Kansas City zones.
Texas. As of December 31, 2024, proved reserves attributable to the Texas Underlying Properties were approximately 4.1 MMBoe and are located in two areas: Central Texas and East Texas. As of December 31, 2024, the VOC Operators operated approximately 99.1% of the total proved reserves attributable to the Texas Underlying Properties based on PV-10 value.
Central Texas production is attributable to the Kurten Woodbine Unit, which is producing primarily from the EagleBine Interval, Buda and Georgetown zones. East Texas properties include the Sand Flat field and Hitts Lake North field, each of which is producing primarily from the Paluxy and Chisum zones.
The following table summarizes the production by product for the years indicated for the only field, Kurten, that contains 15% or more of total proved reserves attributable to the Underlying Properties from the above table:
| | | |
Oil
(MBbl) |
| |
Natural
Gas (MMcf) |
| |
Oil
Equivalents (MBoe) |
| |||||||||
|
2022
|
| | | | 124 | | | | | | 172 | | | | | | 153 | | |
|
2023
|
| | | | 107 | | | | | | 146 | | | | | | 131 | | |
|
2024
|
| | | | 94 | | | | | | 150 | | | | | | 119 | | |
Marketing and Post-Production Services
Pursuant to the terms of the Conveyance, VOC Brazos has the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Underlying Properties. The terms of the Conveyance do not permit VOC Brazos to charge any marketing fee when determining the net proceeds calculated under the net profits interest. As a result, the net proceeds to the Trust from the sales of oil and natural gas production from the Underlying Properties are determined based on the same price that VOC Brazos receives for oil and natural gas production attributable to VOC Brazos’ remaining interest in the Underlying Properties.
Texas is a mature oil producing state with a well-developed crude oil refining, transportation and marketing infrastructure. According to the Texas Railroad Commission, more than 6,300 operators reported aggregate oil production of approximately 1.923 billion barrels for the State of Texas during 2024. There were 34 operating oil refineries located in Texas in 2024 with combined capacity to refine over 6.28 million barrels of oil per day. With oil production in the state of Texas averaging approximately 5.27 million barrels of oil per day, Texas refineries are net importers of crude oil. As a result, oil producers in Texas benefit from competitive marketing conditions for their oil production as a result of the high demand from the crude oil marketing companies and refineries located in Texas.
Kansas is a mature oil producing state with a well-developed transportation infrastructure for crude oil transportation and marketing. According to the Kansas Geological Society, more than 1,300 operators reported aggregate oil production of approximately 26.9 million barrels for the state of Kansas in 2024. Kansas is home to three oil refineries located in McPherson, El Dorado and Coffeyville, Kansas. These refineries have combined capacity to refine approximately 408,200 barrels of oil per day. With oil production in the state of Kansas averaging approximately 74,000 barrels of oil per day, Kansas is a net importer of crude oil. As a result, Kansas operators benefit from the competitive marketing conditions for their oil production as a result of the high demand from the refineries located in Kansas.
19
Vess Oil Corporation generally sells production from the Underlying Properties to several purchasers, including MV Purchasing, LLC, an affiliate of VOC Brazos (“MV Purchasing”), under short-term arrangements using market-sensitive pricing. These sales to purchasers are under terms ranging from one month to six months, using market-sensitive pricing. Five 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 to be acquired by one or more single purchasers. For the years ended December 31, 2022, 2023 and 2024, MV Purchasing purchased 35%, for each year, of the production sold from the Underlying Properties. VOC Brazos does not believe that loss of any of these parties as a purchaser would have a material adverse impact on the business of VOC Brazos, as substitute purchasers are generally available; however, a purchaser’s failure to pay for purchased crude oil could have a significant adverse impact on VOC Brazos’ business.
Oil production is typically transported by truck from the field to the closest gathering facility or refinery. VOC Brazos sells the majority of the oil production from the Underlying Properties under short-term arrangements using market sensitive pricing. The price received by VOC Brazos for the oil production from the Underlying Properties is usually based on the NYMEX price applied to equal daily quantities on the month of delivery, which price is then reduced for differentials based upon delivery location and oil quality. The average differential for oil production during the years ended December 31, 2022, 2023 and 2024 received by the Trust from the Underlying Properties was $2.49, $2.91 and $2.58 per barrel, respectively.
All natural gas produced by VOC Brazos 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. Vess Oil Corporation currently sells all of its natural gas production attributable to the Kurten Woodbine Unit in Texas to ET Gathering & Processing LLC on a year-to-year basis. Vess Oil Corporation currently sells all of its natural gas production attributable to wells in Kingman County, Kansas to Durango Midstream and Superior Midstream on a month-to-month basis. All of the natural gas production in Barber County, Kansas is currently sold to Targa Resources Corp. on a month-to-month basis.
VOC Brazos does not have any volume commitments or take or pay arrangements.
Sale and Abandonment of Underlying Properties
VOC Brazos and any transferee of any of an Underlying Property will have the right to abandon its interest in any well or property if it reasonably believes a well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce the potential conflict of interest between VOC Brazos and the Trust in determining whether a well is capable of producing in commercially paying quantities, VOC Brazos is required under the applicable conveyance to use commercially reasonable efforts to cause the operators of the Underlying Properties to operate these properties as would a reasonably prudent operator 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. For the years ended December 31, 2022, 2023 and 2024, VOC Brazos plugged and abandoned 16, 7 and 6 wells, respectively, located on leases within the Underlying Properties based on its determination that such wells could no longer produce oil or natural gas in commercially economic quantities.
VOC Brazos 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, VOC Brazos 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 VOC Brazos 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. No Underlying Properties were sold, and therefore no
20
net sales proceeds were paid to the Trust for its share of interest in any such Underlying Properties, during 2023 or 2024. VOC Brazos has not identified any of the Underlying Properties for sale as of December 31, 2024.
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 VOC Brazos’ 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.
VOC Brazos’ interests in the Underlying Properties are typically subject, in one degree or another, to one or more of the following:
•
royalties, overriding royalties and other burdens, express and implied, under oil and natural gas leases;
•
overriding royalties, production payments and similar interests and other burdens created by VOC Brazos or its predecessors in title;
•
a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title;
•
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;
•
pooling, unitization and communitization agreements, declarations and orders;
•
easements, restrictions, rights-of-way and other matters that commonly affect property;
•
conventional rights of reassignment that obligate VOC Brazos to reassign all or part of a property to a third party if VOC Brazos intends to release or abandon such property; and
•
rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and the net profits interest therein.
VOC Brazos has informed the Trustee that VOC Brazos believes that the burdens and obligations affecting the Underlying Properties are conventional in the industry for similar properties. VOC Brazos also has informed the Trustee that VOC Brazos 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.
VOC Brazos recorded the Conveyance in Kansas and Texas in the real property records in each Kansas or Texas county in which the Underlying Properties are located. Although under Texas law it is well-established that the recording in the appropriate real property records of an interest such as the net profits interest constitutes the Conveyance of a fully vested real property interest to the Trust, the law in Kansas is less certain. VOC Brazos and the Trust believe that the recording in the appropriate real property records in Kansas of the net profits interest should constitute the conveyance of a fully vested real property interest, interests in hydrocarbons in place or to be produced or a production payment as such is defined under the United States Bankruptcy Code. In a bankruptcy of VOC Brazos, creditors of VOC Brazos would be able to claim the net profits interest as an asset of the bankruptcy estate to satisfy obligations to them if the conveyance of the net profits interest did not constitute the conveyance of a real property interest or interests in hydrocarbons in place or to be produced under applicable state law or a production payment, in which case the Trust would be an unsecured creditor of VOC Brazos at risk of losing the entire value of the net profits interest to senior creditors.
VOC Brazos believes that its title to the Underlying Properties is, and the Trust’s title to the net profits interest is, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties
21
or royalty interests. Please see “Item 1A. Risk Factors — Financial Risks — The Trust Units may lose value as a result of title deficiencies with respect to the Underlying Properties.”
Competition and Markets
The oil and natural gas industry is highly competitive. VOC Brazos 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 VOC Brazos, 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 VOC Brazos and other companies in the oil and natural gas industry.
Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Future price fluctuations for oil and natural gas 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 VOC Brazos 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
22
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 VOC Brazos sells oil and natural gas 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, VOC Brazos 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 VOC Brazos were to violate the anti-market manipulation laws and regulations, VOC Brazos could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
As to these various developments, VOC Brazos has advised the Trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.
State and Other Regulation
In general, the jurisdictions in which royalty properties are located have statutory provisions regulating the production and sale of crude oil and natural gas. The regulations often require permits for the drilling of wells but extend also to the spacing of wells, the prevention of waste of oil and gas resources, the rate of production, prevention and clean-up of pollution and other matters.
Environmental Matters and Regulation
General. The operations of the Underlying Properties are subject to stringent and complex federal, regional, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may impose significant obligations on VOC Brazos’ operations, including requirements to, among other things:
•
obtain permits to conduct regulated activities;
•
restrict the types, quantities and concentration of various substances that can be released or emitted into the environment in the performance of drilling and production activities;
•
limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
•
initiate remedial activities or corrective actions to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;
•
apply specific health and safety criteria addressing workover protection; and
•
impose substantial liabilities on VOC Brazos for pollution resulting from VOC Brazos’ operations.
Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of VOC Brazos’ operations. Moreover, these laws, rules and regulations may 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. VOC Brazos believes that it is in substantial compliance with all existing environmental laws and regulations applicable to its current operations and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. However, the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly emission or discharge limits or waste handling, disposal or remediation obligations could have a material adverse effect on VOC Brazos’ development expenditures, results of operations and financial position. VOC Brazos may be unable to pass on those increases to its customers.
23
The following is a summary of the more significant existing environmental, health and safety laws and regulations, each as amended from time to time, to which VOC Brazos’ business operations are subject:
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, VOC Brazos handles materials in the course of its operations that may be regulated as CERCLA hazardous substances, despite the so-called “petroleum exclusion.”
VOC Brazos 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, VOC Brazos 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.
The real properties upon which VOC Brazos conducts its operations have been used for oil and natural gas exploration and production for many years. Although VOC Brazos believes that it has utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the real properties upon which VOC Brazos conducts its operations, or on or under other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for treatments or disposal. In addition, the Underlying Properties may have been operated by third parties or by previous owners or operators whose treatment and disposal or release of hazardous substances, wastes or hydrocarbons was not under VOC Brazos’ control. These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, VOC Brazos 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 and Hydraulic Fracturing. 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
24
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 VOC Brazos’ regulatory and permitting obligations under the CWA. In 2023, the EPA and the USACE issued a final rule (the “2023 rule”) that is described by the EPA and the USACE as following the 1986 regulations as modified by subsequent U.S. Supreme Court decisions and guidance issued by the EPA and USACE interpreting the decisions. Shortly thereafter, the Supreme Court issued its decision in Sackett II which overturned a substantial portion of the basis for the 2023 rule. The USACE and the EPA subsequently amended the 2023 rule and excluded a number of types of wetlands and streams from CWA jurisdiction, but the rule is subject to litigation regarding the sufficiency of the agencies’ interpretation of the Sackett II decision. The 2023 rule is presently in effect in about half of the states while it is enjoined in the other half. In those states where the rule is enjoined, the EPA and the USACE define WOTUS in accordance with an earlier regulatory definition adjusted in light of the Supreme Court’s Sackett II decision. VOC Brazos’ regulatory obligations and permitting costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given the ongoing litigation.
USACE Nationwide Permits (“NWPs”) are a streamlined form of permitting used to authorize activities related to development activities with minimal individual or cumulative adverse effects in wetlands or other waters of the United States under the CWA. Some NWPs are also used to authorize activities that impact traditional navigable waters under the Rivers and Harbors Act. NWP 12 will expire in March 2026 and be replaced with a new version. In addition, a federal court in Washington, D.C. is currently hearing a challenge to NWP 12. An adverse decision in the litigation may restrict or remove the ability to use NWP 12 to permit regulated impacts, resulting in the need to apply for a more time-consuming individual permit. This could result in additional cost and time for permitting projects.
In February 2025, the USACE began implementing emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency. This may result in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects subject to the Executive Order.
The Oil Pollution Act of 1990, as amended (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and the CWA include inspection and maintenance programs to minimize spills from oil storage and conveyance systems; the use of secondary containment systems to prevent spills from reaching nearby waterbodies; proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill; and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. VOC Brazos has developed and implemented SPCC plans for the Underlying Properties as required under the CWA.
It is customary to recover oil and natural gas from deep shale and tight sand formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions
25
of the federal Safe Drinking Water Act to exclude certain hydraulic fracturing activities from the definition of “underground injection.” At present, hydraulic fracturing is regulated at the state and local level. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal, state and local level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Repeal of the exemption would allow the EPA to promulgate new regulations. Many states have adopted rules that required operators to disclose chemicals and water volumes associated with hydraulic fracturing. In addition, the EPA finalized a study of the potential environmental impacts of hydraulic fracturing activities in 2016, finding that under certain circumstances the “water cycle” activities associated with hydraulic fracturing could impact drinking water resources. More recently, the injection of water produced as a result of hydraulic fracturing has been associated with seismic activity leading to restrictions on injection in some areas. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for VOC Brazos to perform hydraulic fracturing activities. Moreover, required disclosure without protection for trade secret or proprietary products could discourage service companies from using such products and as a result impact the degree to which some oil and gas wells may be efficiently and economically completed or brought into production. Finally, VOC Brazos believes that enactment of legislation regulating hydraulic fracturing at the federal level may have a material adverse effect on its business.
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 VOC Brazos 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 VOC Brazos’ properties.
The EPA has established pollution control standards for oil and gas sources under the CAA. In 2012 and 2016, the EPA adopted federal New Source Performance Standards (“NSPS”) that require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels, and for equipment leaks. These NSPS apply to sources that are newly constructed or modified after the rules’ applicability dates. More recently, the EPA adopted a final rule in 2024 that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed or modified after December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. Additionally, the EPA for the first time adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.
The EPA is also charged with establishing National Ambient Air Quality Standards (“NAAQS”), the implementation of which can indirectly impact VOC Brazos’ 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 VOC Brazos’ ability to obtain such permits, and result in increased expenditures for pollution control equipment.
The 2024 presidential election in the United States may impact the air quality-related requirements that apply to VOC Brazos. The Trump Administration may adopt a different approach to many actions taken
26
under the prior presidential administration, including the 2024 revisions to the emissions standards and guidelines for new and existing sources in the oil and gas industry, as well as the 2024 changes to the NAAQS for fine particulate matter. The outcome of the Trump Administration’s evaluation of the prior administration’s regulatory approach is not certain at this time, but President Trump has made it clear that his energy agenda prioritizes an increase in domestic oil and gas production.
VOC Brazos may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues., VOC Brazos currently does not expect that such requirements will have a material adverse effect on its operations.
Climate Change. In response to its 2009 finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in 2024. The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. President Trump also issued an executive order directing the EPA to review the legality and continuing applicability of its 2009 GHG endangerment finding. The outcome of that review is not currently known; however, it has the potential to eliminate the basis for the EPA’s regulation of GHGs under the CAA.
The EPA has established GHG standards for oil and gas sources based on the GHG endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require reductions in GHG and volatile organic compound emissions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.
The Inflation Reduction Act of 2002 (the “IRA”) included new Clean Air Act section 136(c) directing the EPA to collect the Waste Emissions Charge (“WEC”) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In February 2025, the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the Congressional Review Act (“CRA”), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA. In addition, the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.
In addition to the federal actions, more than one third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state level initiatives to date have focused on large sources of GHG emissions, such as coal fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. For example, the states of Colorado and New Mexico have adopted rules
27
regulating GHGs from the oil and gas industry that are based on the federal standards. Congress may in the future consider adopting other legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on VOC Brazos’ 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, VOC Brazos’ equipment and operations could require VOC Brazos 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 VOC Brazos’ 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, VOC Brazos’ products may become more desirable in the market with more stringent limitations on GHG emissions. To the extent that its products are competing with lower GHG-emitting energy, VOC Brazos’ products may become less desirable in the market with more stringent limitations on greenhouse gas emissions. VOC Brazos 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 VOC Brazos’ assets and operations and cause VOC Brazos to incur costs in preparing for and responding to them. Additionally, energy needs could increase or decrease as a result of extreme weather conditions, depending on the duration and magnitude of those conditions.
Endangered Species Act. The federal Endangered Species Act, as amended (“ESA”), prohibits taking of listed endangered, and in some cases threatened, species. Under the ESA, federal agencies are obligated to consult with the U.S. Fish and Wildlife Service or National Marine Fisheries Service if an agency’s actions, including permit actions, may affect listed species or designated critical habitat. If endangered species are located in areas of the Underlying Properties where seismic surveys, development activities or abandonment operations may be conducted, the work could be prohibited or delayed or expensive mitigation may be required, depending on the implications for protected species and designated critical habitat. On August 27, 2019, the U.S. Fish and Wildlife Service published a final rule adopting several changes to the federal regulations that implement the ESA, including changes to the procedures and criteria for listing or removing species from the Lists of Endangered and Threatened Wildlife and Plants and for designating critical habitat. The Biden Administration rescinded one of the rules adopted by the prior administration, dealing with critical habitat, and issued a revised rule making changes to the federal consultation process. These changes could make a federal review process occasioned by the application for permits, rights of way, or leases more complex in certain circumstances. In addition, designation of new species as threatened or endangered could cause VOC Brazos to incur additional costs arising from species protection measures, could result in limitations on activities, and could require a more complex regulatory compliance process. In January 2025, the Trump Administration directed the use of the emergency consultation procedures for permitting for energy projects in the Declaring a National Energy Emergency Executive Order.
National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires the federal government to undertake an environmental review prior to making a decision on most proposed federal actions — such as permits, leases, and rights-of-way. Until 2025, agencies undertook NEPA reviews pursuant to binding regulations issued by the White House Council on Environmental Quality (“CEQ”) as well as pursuant to the federal agency’s own NEPA procedures. CEQ issued its rules after being directed to do so by an Executive Order issued in the Carter Administration. After two federal courts held that CEQ did not have authority to issue binding regulations, the Trump Administration revoked the Carter Administration Executive Order and directed CEQ to withdraw the regulations. In their place, agencies are directed to develop procedures that hew to the statutory text over the course of 2025 with the goal of having them finalized in early 2026. In the meantime, agencies will continue to use their own NEPA procedures and may
28
continue to follow the CEQ regulations, using them as guidance. This may result in delays and uncertainty in permitting reviews as agencies adjust to a new NEPA approach.
Employee Health and Safety. The operations of VOC Brazos are subject to a number of federal and state laws and regulations, including 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 the federal Superfund Amendment and Reauthorization Act and comparable state statutes require in certain circumstances that information be maintained concerning hazardous materials used or produced in VOC Brazos’ operations and that this information be provided to employees, state and local government authorities and citizens. VOC Brazos believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.
29
Item 1A. Risk Factors.
Operating Risks
Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the Trust and cash distributions to Trust unitholders.
The reserves attributable to the Underlying Properties and quarterly cash distributions of the Trust are highly dependent upon the prices realized from the sale of oil and natural gas. Prices of oil and natural gas 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 VOC Brazos. These factors include, among others:
•
regional, domestic and foreign supply and perceptions of supply of oil and natural gas;
•
the level of demand and perceptions of demand for oil and natural gas;
•
political conditions or hostilities in oil and natural gas producing regions, including the Middle East, North Africa and South America;
•
the armed conflicts between Russia and Ukraine and between Israel and Iran and its proxies and the potential destabilizing effects such conflicts may pose for the global oil and gas markets;
•
the occurrence or threat of epidemic or pandemic diseases or other public health event or any government response to such occurrence or threat;
•
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;
•
the levels of production of oil and natural gas of non-OPEC countries;
•
anticipated future prices of oil and natural gas and other commodities;
•
weather conditions and seasonal trends;
•
technological advances affecting energy consumption and energy supply;
•
U.S. and worldwide economic conditions;
•
trade barriers and tariffs;
•
the price and availability of alternative fuels;
•
the proximity, capacity, cost and availability of gathering and transportation facilities;
•
the volatility and uncertainty of regional pricing differentials;
•
governmental regulations and taxation;
•
energy conservation and environmental measures; and
•
acts of force majeure.
Crude oil prices have been volatile over the last several years, and in 2024 ranged from a high of $86.91 to a low of $65.75. The NYMEX crude oil prices per Bbl were $80.26, $71.65 and $71.72 as of December 31, 2022, 2023 and 2024, respectively. Neither VOC Brazos nor the Trust can predict the timing or the duration of any economic cycle and, depending on the prices realized, the operating results of VOC Brazos and the financial condition of the Trust could be materially and adversely affected.
Low prices of oil and natural gas will reduce the amount of the net proceeds to which the Trust is entitled and may ultimately reduce the amount of oil and natural gas 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. Specifically, VOC Brazos may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the net profits interest relating to the
30
abandoned well or property. In making such decisions, VOC Brazos and any transferee will be required under the applicable conveyance to operate, or to use commercially reasonable efforts to cause the operators of the Underlying Properties to operate, these properties as would a reasonably prudent operator, acting with respect to its own properties (without regard to the existence of the net profits interest).
Because substantially all the Underlying Properties are located in mature fields, 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 variety 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 or natural gas will reduce the amount of cash available for distribution to Trust unitholders.
The volatility of commodity prices also reduces the accuracy of estimates of future cash distributions to 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 reserves and future production estimated to be attributable to the Underlying Properties and the net profits interest. It is not possible to measure underground accumulations of oil and natural gas in an exact manner, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary negatively and in material amounts from estimates. Furthermore, development expenditures and production costs relating to the Underlying Properties could be higher than current estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:
•
historical production from the area compared with production rates from other producing areas;
•
oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and development expenditures; and
•
the effect of expected governmental regulation.
Changes in these assumptions and amounts of actual production and development costs could materially decrease reserve estimates.
The estimated reserves attributable to the net profits interest and the estimated future net revenues attributable to the net profits interest are based on estimates of reserve quantities and revenues for the Underlying Properties. See “Item 1. Business — Description of the Underlying Properties — Reserves” for a discussion of the method of allocating proved reserves to the Underlying Properties and the net profits interest. The quantities of reserves attributable to the Underlying Properties and the net profits interest may decrease in the future as a result of future decreases in the prices of oil, natural gas or natural gas liquids.
The processes of drilling and completing wells are high risk activities.
The processes of drilling and completing wells are subject to numerous risks beyond the Trust’s and VOC Brazos’ control, including risks that could delay VOC Brazos’ current drilling schedule and the risk that drilling will not result in commercially viable oil production. VOC Brazos is not obligated to undertake any development activities, so any drilling and completion activities will be subject to the reasonable discretion of VOC Brazos. Furthermore, VOC Brazos’ future business, financial condition, results of operations, liquidity or ability to finance its share of planned development expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:
•
delays imposed by or resulting from compliance with regulatory requirements, including permitting;
31
•
unusual or unexpected geological formations;
•
shortages of or delays in obtaining equipment and qualified personnel;
•
equipment malfunctions, failures or accidents;
•
unexpected operational events and drilling conditions;
•
reductions in oil or natural gas prices;
•
market limitations for oil or natural gas;
•
pipe or cement failures;
•
casing collapses;
•
lost or damaged drilling and service tools;
•
loss of drilling fluid circulation;
•
uncontrollable flows of oil and natural gas;
•
fires and natural disasters;
•
environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases;
•
adverse weather conditions; and
•
oil or natural gas property title problems.
If drilling of development wells is delayed or cancelled, or development wells have lower than anticipated production, due to one or more of the factors above or for any other reason, estimated future distributions to Trust unitholders may be reduced.
Risks associated with the production, gathering, transportation and sale of oil and natural gas could adversely affect cash distributions by the Trust.
The amount of cash to be received by the Trust from VOC Brazos with respect to the net profits interest, the value of the Trust Units and the amount of cash distributions to the Trust unitholders will depend upon, among other things, oil and natural gas production and prices and the costs incurred by VOC Brazos to develop and produce oil and natural gas reserves attributable to the Underlying Properties. Drilling, production or transportation accidents as well as adverse weather conditions that temporarily or permanently halt the production and sale of oil or natural gas at any of the Underlying Properties will reduce Trust distributions by reducing the amount of net proceeds received by the Trust and available for distribution. For example, accidents may occur that result in personal injuries, property damage, damage to productive formations or equipment and environmental damages. To the extent VOC Brazos is not able to recover from insurance any costs incurred by VOC Brazos in connection with any such accidents, the net proceeds payable to the Trust and available for distribution to Trust unitholders may be reduced or delayed.
In addition, curtailments or damage to pipelines used by VOC Brazos to transport oil and natural gas production to markets for sale could reduce the amount of net proceeds received by the Trust and available for distribution to Trust unitholders. Any such curtailment or damage to the gathering systems used by VOC Brazos could also require VOC Brazos to find alternative means to transport the oil and natural gas production from the Underlying Properties, which could require VOC Brazos to incur additional costs that will have the effect of reducing net proceeds received by the Trust and available for distribution. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production or related 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
32
nations, such as Russia, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices OPEC members and other oil exporting nations might not agree to future production cuts or other actions to support and stabilize oil prices, and they may not reduce oil prices or increase production in the future. Uncertainty regarding future actions that OPEC members or other oil exporting countries may take could lead to continued volatility in the price of oil, which could adversely affect the financial condition and economic performance of the operators of the Underlying Properties and may 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 and natural gas on the Underlying Properties could be materially and adversely affected by severe or unseasonable weather.
Production of oil and natural gas on the Underlying Properties could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:
•
evacuation of personnel and curtailment of operations;
•
weather-related damage to drilling rigs or other facilities, resulting in suspension of operations;
•
inability to deliver materials to worksites; and
•
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.
VOC Brazos does not have any long-term contracts related to the sale of production of oil and natural gas from the Underlying Properties and may be unable to find purchasers.
VOC Brazos does not have any firm commitment contracts for the sale of any production nor has it received security or other guaranty of payment for the production it sells. Therefore, there can be no assurance that VOC Brazos will be able to find buyers for its production, that buyers will pay the purchase price therefor or that the price at which the production is sold will be the current market price for such hydrocarbons at the time of delivery. During the year ended December 31, 2024, VOC Brazos sold approximately 35% of the oil produced from the Underlying Properties to MV Purchasing, an affiliate of VOC Brazos. Any nonpayment by a purchaser of production, including MV Purchasing, or inability by VOC Brazos to sell any production, could reduce cash available for distribution to Trust unitholders.
Shortages or increases in costs of equipment, services and qualified personnel could result in a reduction in the amount of cash available for distribution to the Trust unitholders.
The demand for qualified and experienced personnel to 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 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 received by the Trust and available for distribution to the Trust unitholders or restrict the ability of VOC Brazos to drill the development wells and conduct the operations which it currently has planned for the Underlying Properties.
Due to lack of geographic diversification of the Underlying Properties, adverse developments in Kansas or Texas could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to Trust unitholders.
The operations of the Underlying Properties are focused on the production and development of oil and natural gas within the states of Kansas and Texas. As a result, the results of operations and cash flows of the Underlying Properties depend upon continuing operations in these areas. Due to the lack of
33
diversification in geographic location, adverse developments in exploration and production of oil and natural gas in either of these areas of operation could have a significantly greater impact on the results of operations and cash flows of the Underlying Properties, which could reduce the amount of cash received by the Trust and available for distribution to Trust unitholders, than if the operations were more diversified.
Financial Risks
The reserves attributable to the Underlying Properties are depleting assets and production from those properties 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 attributable to the net profits interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties will decline over time. Furthermore, over approximately 92% of the estimated oil recovery attributable to the Underlying Properties has already been extracted from the producing wells located on the Underlying Properties. Based on the estimated production volumes in the reserve report as of December 31, 2024, the oil and natural gas production from proved reserves attributable to the Underlying Properties is projected to decline at an average rate of approximately 7.4% per year over the next 20 years, assuming the level of development drilling and development expenditures on the Underlying Properties disclosed elsewhere in this Form 10-K through 2032 and none thereafter. Actual decline rates may vary from this projected decline rate. If expected future development is delayed, reduced or cancelled, the average rate of decline will likely exceed 7.4% per year.
The Trust Agreement provides that the Trust’s 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. 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 Trust Units may lose value as a result of title deficiencies with respect to the Underlying Properties.
VOC Brazos acquired the Underlying Properties beginning in the early 1980s. The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the net profits interest and distributions to Trust unitholders. VOC Brazos does not obtain title insurance covering mineral leaseholds, and VOC Brazos’ failure to cure any title defects may cause VOC Brazos to lose its rights to production from the Underlying Properties. In the event of any such material title problem, proceeds available for distribution to Trust unitholders and the value of the Trust Units may be reduced.
The amount of cash available for distribution by the Trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the Trust.
The net profits interest will bear its share of all costs and expenses related to the Underlying Properties, such as lease operating expenses, production and property taxes and development expenses, which will reduce the amount of cash received by the Trust and available for distribution to Trust unitholders. Accordingly, higher costs and expenses related to the Underlying Properties will directly decrease the amount of cash received by the Trust in respect of its net profits interest, including those costs and expenses related to development pursuant to the joint venture arrangements described in “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations — Planned Development and Workover Program.” If the activities pursuant to such arrangements are pursued, other than with respect to certain excepted wells, such activities would result in increased development costs burdening the net profits interest relative to historical development costs. As a result of such increased development costs, cash available for
34
distribution by the Trust would be temporarily reduced, and in some periods there may be no distributions to Trust unitholders, until anticipated production for the various development efforts in the Kurten Woodbine Unit can be brought on line. In addition, cash available for distribution by the Trust will be further reduced by the Trust’s general and administrative expenses.
If production and development costs on the Underlying Properties together with the other costs exceed gross proceeds of production from the Underlying Properties, the Trust will not receive net proceeds from those properties until future gross proceeds from production exceed the total of the excess costs, plus accrued interest. If the Trust does not receive net proceeds pursuant to the net profits interest, or if such net proceeds are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs. If annual cash proceeds attributable to the net profits interest are less than $1 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. From the first quarter of 2022 to the second quarter of 2023, the Trustee withheld a portion of the proceeds otherwise available for distribution each quarter to build an approximately $1.175 million cash reserve for the payment of future known, anticipated, or contingent expenses or liabilities of the Trust. This amount is in addition to the letter of credit in the amount of $1.7 million provided to the Trustee by VOC Brazos to protect the Trust against the risk that it does not have sufficient cash to pay future expenses. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to the Trust unitholders.
A purchaser’s failure to pay VOC Brazos for purchased production could have a significant adverse impact on VOC Brazos, which in turn could result in VOC Brazos not having sufficient net proceeds attributable to the Net Profits Interest for VOC Brazos to distribute cash to the Trust.
A purchaser’s failure to pay for purchased production could have a significant adverse impact on VOC Brazos’ business, which in turn could adversely affect the Trust. A tightening of credit in the financial markets may make it more difficult for purchasers to obtain financing, and depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by such purchasers, which may reduce the net proceeds payable to the Trust and the amount of cash available for distribution to Trust unitholders.
The bankruptcy of VOC Brazos or any operator of the Underlying Properties could impede the operation of the wells and the development of the proved undeveloped reserves.
VOC Brazos is a privately held limited partnership engaged in the production and development of oil and natural gas from properties located in Kansas and Texas. VOC Brazos intends to implement a development and workover program, including the expenditure through 2032 of approximately $36.4 million to drill additional wells and recomplete and workover other wells. Without this development and workover program, the average decline rate over the life of the Trust of the oil and natural gas production from the proved reserves attributable to the Underlying Properties will likely exceed the 7.4% per year projected in the reserve report.
The operator of substantially all of the Underlying Properties is a privately held corporation engaged in the operation of oil and natural gas wells in Kansas and Texas. Therefore, the value of the net profits interest and the Trust’s ultimate cash available for distribution will be highly dependent on the financial condition of VOC Brazos and the operator. Neither VOC Brazos nor the operator is a reporting company or files periodic reports with the SEC. Therefore, Trust unitholders do not have access to financial information about VOC Brazos or the operator. Furthermore, neither VOC Brazos nor the operator has agreed with the Trust to maintain a certain net worth or to be restricted by other similar covenants.
35
The ability of VOC Brazos to develop the Underlying Properties and the ability of the operator to operate the wells on the Underlying Properties depends on the future financial condition and economic performance and access to capital of VOC Brazos and the operator, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of VOC Brazos and the operator.
In the event of the bankruptcy of VOC Brazos or the operator, the Trust would have to seek a new party to perform the development and workover program or the operations of the wells operated by such operator. The Trust may not be able to find a replacement driller or operator, and it may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period. As a result, such a bankruptcy may result in reduced production from the reserves and decreased distributions to Trust unitholders.
Risks Related to the Structure of the Trust
Neither the Trust nor the Trust’s unitholders have the ability to influence VOC Brazos or control the operations or development of the Underlying Properties.
The Trust and the Trust’s unitholders have no voting rights with respect to VOC Brazos and therefore have no managerial, contractual or other ability to influence VOC Brazos’ activities or the operations of the Underlying Properties. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. Vess Oil Corporation operates, or operates on a contract basis, substantially all of the Underlying Properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property.
VOC Brazos may transfer all or a portion of the Underlying Properties at any time without Trust unitholder consent, subject to specified limitations.
VOC Brazos may at any time transfer all or part of the Underlying Properties, subject to and burdened by the net profits interest, and may abandon individual wells or properties that it reasonably believes would no longer produce oil or natural gas in commercially paying quantities. For the years ended December 31, 2022, 2023 and 2024, VOC Brazos plugged and abandoned 16, 7 and 6 wells, respectively, located on leases on the Underlying Properties. Trust unitholders will not be entitled to vote on any transfer of the Underlying Properties, and the Trust will not receive any proceeds from any such transfer, except in certain limited circumstances when the net profits interest is released in connection with such transfer, in which case the Trust will receive an amount equal to the fair market value (net of sales costs) of the net profits interest released. Following any sale or transfer of any of the Underlying Properties, if the net profits interest is not released in connection with such sale or transfer, the net profits interest will continue to burden the transferred property and net proceeds attributable to such property will be calculated as part of the computation of net proceeds described in this Form 10-K. VOC Brazos may delegate to the transferee responsibility for all of VOC Brazos’ obligations relating to the net profits interest on the portion of the Underlying Properties transferred.
In addition, VOC Brazos 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 VOC Brazos to a non-affiliate of the relevant Underlying Properties and are conditioned upon the Trust’s receiving an amount equal to the fair market value to the Trust of such net profits interest. Any net sales proceeds paid to the Trust will be distributable to Trust unitholders for the quarter in which they are received.
The Trustee may, under certain circumstances, sell the net profits interest and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.
The Trustee must sell the net profits interest if the holders of a majority of the Trust Units approve the sale or vote to dissolve the Trust. The Trustee must also sell the net profits interest if the annual cash proceeds
36
from the Underlying Properties attributable to the net profits interest are less than $1.0 million for each of any two consecutive years. The sale of the net profits interest will result in the dissolution of the Trust. The net proceeds of any such sale will be distributed to the Trust unitholders; however, Trust unitholders may not recover their investment in the Trust Units.
Conflicts of interest could arise between VOC Brazos and its affiliates, on the one hand, and the Trust and the Trust unitholders, on the other hand.
As working interest owners in, and operators of substantially all the wells on, the Underlying Properties, VOC Brazos and its affiliates could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
•
VOC Brazos’ interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. VOC Brazos may also make decisions with respect to development expenditures that adversely affect the Underlying Properties. These decisions include reducing development expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.
•
VOC Brazos may sell some or all of the Underlying Properties without taking into consideration the interests of the Trust unitholders. Such sales may not be in the best interests of the Trust unitholders. These purchasers may lack VOC Brazos’ experience or its creditworthiness. VOC Brazos also has the right, under certain limited circumstances, to cause the Trust to release all or a portion of the net profits interest in connection with a sale of a portion of the Underlying Properties to which such net profits interest relates.
•
MV Purchasing, an affiliate of VOC Brazos, is expected to market and/or purchase a substantial portion of the oil produced from the Underlying Properties, and it is expected to profit from this arrangement. Provisions in the Conveyance, however, require that charges and other terms under contracts with affiliates of VOC Brazos be comparable to prices and other terms prevailing in the area for similar services or sales. During the year ended December 31, 2024, VOC Brazos sold approximately 35% of the oil produced from the Underlying Properties to MV Purchasing.
•
VOC Partners, LLC has registration rights and can sell its Trust Units without considering the effects such sale may have on Trust Unit prices or on the Trust itself. In addition, VOC Partners, LLC can vote its Trust Units in its sole discretion without considering the interests of the other Trust unitholders.
The Trust is managed by a Trustee who cannot be replaced except by a vote of the Trust unitholders holding a majority of the Trust Units at a special meeting, which may make it difficult for Trust unitholders to remove or replace the Trustee.
The business and affairs of the Trust are managed by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Trust Units, including Trust Units held by VOC Partners, LLC, at a special meeting of Trust unitholders called by either the Trustee or the holders of not less than 10% of the outstanding Trust Units. VOC Partners, LLC owns 25% of the outstanding Trust Units. As a result, it will be difficult for public unitholders to remove or replace the Trustee without the cooperation of VOC Partners, LLC as long as it holds a significant percentage of total Trust Units.
Financial information of the Trust is not prepared in accordance with GAAP.
The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements because revenues are not accrued in the
37
month of production and cash reserves may be established for specified contingencies and deducted which could not be accrued in GAAP financial statements.
The Trust is a smaller reporting company and benefits from certain reduced governance and disclosure requirements, including that the Trust’s independent registered public accounting firm is not required to attest to the effectiveness of the Trust’s internal control over financial reporting. The Trust cannot be certain if the omission of reduced disclosure requirements applicable to smaller reporting companies will make the Trust Units less attractive to investors.
Currently, the Trust is a “smaller reporting company,” meaning that the outstanding Trust Units held by nonaffiliates had a value of less than $250 million at the end of the Trust’s most recently completed second fiscal quarter. As a smaller reporting company, the Trust is not required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, meaning the Trust’s auditors are not required to attest to the effectiveness of the Trust’s internal control over financial reporting. As a result, investors and others may be less comfortable with the effectiveness of the Trust’s internal controls and the risk that material weaknesses or other deficiencies in internal controls go undetected may increase. In addition, as a smaller reporting company, the Trust takes advantage of its ability to provide certain other less comprehensive disclosures in its SEC filings, including, among other things, providing only two years of audited financial statements in annual reports. Consequently, it may be more challenging for investors to analyze the Trust’s results of operations and financial prospects, as the information the Trust provides to Trust unitholders may be different from what one might receive from other public companies in which one holds shares. As a smaller reporting company, the Trust is not required to provide this information.
Risks Related to Ownership of the Trust Units
The disposal by an affiliate of VOC Brazos of its remaining Trust Units may reduce the market price of the Trust Units.
As of the date of this Form 10-K, an affiliate of VOC Brazos, VOC Partners, LLC, owned 25% of the outstanding Trust Units. VOC Partners, LLC may use some or all of the remaining Trust Units it owns for a number of business purposes, including:
•
selling them for cash; and
•
exchanging them for interests in oil and natural gas properties or securities of oil and natural gas companies.
If it sells additional Trust Units or exchanges Trust Units in connection with acquisitions, then additional Trust Units will be available for sale in the market. The sale of additional Trust Units may reduce the market price of the Trust Units. The Trust has entered into a registration rights agreement with VOC Partners, LLC pursuant to which the Trust has agreed to file a registration statement or a shelf registration statement to register the resale of the remaining Trust Units held by VOC Partners, LLC and any transferee of the Trust Units upon request by such holders. See “Item 13. Certain Relationships and Related Transactions, and Director Independence — Registration Rights.”
The market price for the Trust Units may not reflect the value of the net profits interest held by the Trust.
The market price for publicly traded securities similar to the Trust Units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of production and development costs. Consequently, the market price for the Trust Units may not necessarily be indicative of the value that the Trust would realize if it sold the net profits interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the Trust unitholder.
38
Trust unitholders have limited ability to enforce provisions of the net profits interest, and VOC Brazos’ liability to the Trust is limited.
The Trust Agreement permits the Trustee to sue VOC Brazos or any other future owner of the Underlying Properties to enforce the terms of the Conveyance. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, Trust unitholders’ recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder’s ability to directly sue VOC Brazos or any other third party other than the Trustee. As a result, Trust unitholders will not be able to sue VOC Brazos or any future owner of the Underlying Properties to enforce these rights. Furthermore, the Conveyance provides that, except as set forth in the Conveyance, VOC Brazos will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of corporations under the General Corporation Law of the State of Delaware. Courts in jurisdictions outside of Delaware, however, may not give effect to such limitation.
Legal, Environmental and Regulatory Risks
The Trust may be treated as an unsecured creditor with respect to the net profits interest attributable to properties in Kansas in the event of the bankruptcy of VOC Brazos if a court were to hold that the Conveyance and recording of the net profits interest was not a conveyance of a fully vested real property interest or an interest in hydrocarbons in place or to be produced.
VOC Brazos and the Trust believe that the recording in the appropriate real property records in Kansas of the net profits interest should constitute the conveyance of a fully vested real property interest, interests in hydrocarbons in place or to be produced or a production payment as such is defined under the United States Bankruptcy Code. In a bankruptcy of VOC Brazos, creditors of VOC Brazos would be able to claim the net profits interest as an asset of the bankruptcy estate to satisfy obligations to them if the conveyance of the net profits interest did not constitute the conveyance of a real property interest or interests in hydrocarbons in place or to be produced under applicable state law or a production payment, in which case the Trust would be an unsecured creditor of VOC Brazos at risk of losing the entire value of the net profits interest to senior creditors.
The operations of the Underlying Properties are subject to environmental laws and regulations that may result in significant costs and liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.
The oil and natural gas exploration and production operations of VOC Brazos are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that apply to VOC Brazos’ operations, including the requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; the incurrence of significant development expenditures to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the EPA and analogous state environmental and oil and gas agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of VOC Brazos’ operations. Furthermore, the inability to comply with environmental laws and regulations in a cost effective manner, such as removal and disposal of produced water and other generated oil and gas wastes, could
39
impair VOC Brazos’ ability to produce oil and natural gas commercially from the Underlying Properties, which would reduce proceeds attributable to the net profits interest.
There is inherent risk of incurring significant environmental costs and liabilities in the performance of VOC Brazos’ operations as a result of its handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to its operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, VOC Brazos could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether VOC Brazos was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which VOC Brazos’ wells are drilled and facilities where VOC Brazos’ petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose VOC Brazos to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require VOC Brazos to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. VOC Brazos may be unable to recover some or any of these costs from insurance, in which case the amount of cash received by the Trust may be decreased. The net profits interest held by the Trust will bear 80% of all costs and expenses incurred by VOC Brazos in regard to environmental costs and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to VOC Brazos’ acquisition of the Underlying Properties unless such costs and expenses result from VOC Brazos’ gross negligence or willful misconduct. In addition, as a result of the increased cost of compliance, VOC Brazos may decide to discontinue drilling.
The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose VOC Brazos to significant liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.
The production and development operations on the Underlying Properties are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, VOC Brazos must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. VOC Brazos may incur substantial costs in order to maintain compliance with these existing laws and regulations, and the net profits interest will bear its share of these costs. In addition, VOC Brazos’ costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to VOC Brazos’ operations. Such costs could have a material adverse effect on VOC Brazos’ business, financial condition and results of operations and reduce the amount of cash received by the Trust in respect of the net profits interest, VOC Brazos must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent VOC Brazos is a shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity, and such compliance costs will be borne indirectly in part by the Trust.
Laws and regulations governing exploration and production may also affect production levels. VOC Brazos is required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. These and other laws and regulations can limit the amount of oil and natural gas VOC Brazos can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.
40
New laws or regulations, or changes to existing laws or regulations, may unfavorably impact VOC Brazos, could result in increased operating costs or have a material adverse effect on VOC Brazos’ financial condition and results of operations and reduce the amount of cash received by the Trust. These and other potential regulations could increase the operating costs of the Underlying Properties, reduce VOC Brazos’ liquidity, delay VOC Brazos’ operations or otherwise alter the way VOC Brazos conducts its business, any of which could have a material adverse effect on the net profits interest and the Trust’s cash flows.
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that VOC Brazos produces while the physical effects of climate change could disrupt VOC Brazos’ production and cause VOC Brazos to incur significant costs in preparing for or responding to those effects.
In response to its 2009 finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in 2024. The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. President Trump also issued an executive order directing the EPA to review the legality and continuing applicability of its 2009 GHG endangerment finding. The outcome of that review is not currently known; however, it has the potential to eliminate the basis for the EPA’s regulation of GHGs under the CAA.
The EPA has established GHG standards for oil and gas sources based on its endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require further emissions reductions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.
The Inflation Reduction Act of 2022 (“IRA”) included new CAA section 136(c) directing the EPA to collect the Waste Emissions Charge (“WEC”) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with the EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In February 2025, the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the Congressional Review Act (“CRA”), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA. In addition, the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.
Additionally, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the
41
future. For example, the states of Colorado and New Mexico have adopted rules regulating GHGs from the oil and gas industry that are based on the federal standards. In addition, Congress may consider adopting legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on VOC Brazos’ 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, VOC Brazos’ equipment and operations could require VOC Brazos to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas it produces. Legislation or regulations that may be adopted to address climate change could also affect the markets for VOC Brazos’ products by making its products less desirable than competing sources of energy. To the extent that its products are competing with lower GHG-emitting energy, VOC Brazos’ products may become less desirable in the market with more stringent limitations on greenhouse gas emissions. VOC Brazos cannot predict with any certainty at this time how these possibilities may affect its operations.
In addition, new and emerging regulatory initiatives in the U.S. related to climate change could adversely affect the Trust. In 2024, the SEC issued a final rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The final rule mandates extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy and greenhouse gas emissions, for certain public companies. Compliance with the final rule may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on the personnel, systems and resources of VOC Brazos or the Trust or both. The SEC’s climate disclosure requirements may change under the Trump Administration. In February 2025, the acting SEC Chair issued a statement that the SEC would not defend the 2024 disclosure rule in court and that the SEC would revisit the 2024 rule. The outcome of the SEC’s review may result in changes to SEC climate-related disclosure requirements, but the outcome of that review is uncertain. Even in the absence of federal requirements, however, some states have adopted climate disclosure laws or rules that are not affected by the SEC’s review.
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 VOC Brazos’ assets and operations and cause VOC Brazos 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.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect VOC Brazos’ services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. The EPA finalized a study of the potential environmental impacts of hydraulic fracturing activities in December 2016, finding that under certain circumstances the “water cycle” activities associated with hydraulic fracturing could impact drinking water resources. Some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. If hydraulic fracturing is regulated at the federal level, VOC Brazos’ fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in Texas or Kansas such legal requirements could make it more difficult or costly for VOC Brazos to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. More recently, the injection of water produced as a result of hydraulic fracturing has been associated with seismic activity leading to restrictions on injection in some areas. Restrictions on hydraulic fracturing and disposal of water from such production could reduce the amount of oil and natural gas that VOC Brazos is ultimately able to produce in commercially paying quantities from the Underlying Properties.
42
Tax Risks Related to the Trust Units
The Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Trust Units. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor Trust” for federal income tax purposes, or that the net profits interest is not properly treated as a production payment (and thus would fail to qualify as a debt instrument) for federal income tax purposes, the Trust unitholders may receive different and potentially less advantageous tax treatment than expected.
If the Trust were not treated as a grantor Trust for federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to Trust unitholders could be reduced as a result.
If the net profits interest were not treated as a production payment (and thus would fail to qualify as a debt instrument for federal income tax purposes) the amount, timing and character of income, gain, or loss in respect of an investment in the Trust could be affected.
Neither VOC Brazos nor the Trustee has requested a ruling from the IRS regarding these tax questions. Such a ruling may not be granted if requested; moreover, the IRS could challenge these positions on audit.
Cybersecurity Risks
Cyber-attacks or other failures in telecommunications or information technology systems could result in information theft, data corruption and significant disruption of the business operations of VOC Brazos and its VOC Operators.
VOC Brazos and its VOC Operators rely on information technology (“IT”) systems and networks in connection with various business activities, including exploration, development and production activities. VOC Brazos and its VOC Operators rely on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. These threats pose a risk to the security of the systems and networks of VOC Brazos and its VOC Operators, the confidentiality, availability and integrity of their data and the physical security of employees and assets. VOC Brazos and its VOC Operators have experienced, and expect to continue to experience, attempts from hackers and other third parties to gain unauthorized access to IT systems and networks. Although prior cyber-attacks have not had a material adverse effect on the operations or financial performance of VOC Brazos or of its VOC Operators, VOC Brazos and its VOC Operators may not be successful in preventing cyber-attacks or mitigating their effect. Any cyber-attack could have a material adverse effect on the reputation, competitive position, business, financial condition and results of operations of VOC Brazos and its VOC Operators, and could have a material adverse effect on the Trust. Cyber-attacks or security breaches also could result in litigation or regulatory action, as well as significant additional expense to VOC Brazos and its VOC Operators to implement further data protection measures.
In addition to the risks presented to the systems and networks of VOC Brazos and its VOC Operators, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack of this nature would be outside the ability of VOC Brazos and its VOC Operators to control, but could have a material adverse effect on the business, financial condition and results of operations of VOC Brazos and its VOC Operators, and could have a material adverse effect on the Trust.
Cyber-attacks or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of the Trustee’s operations.
The Trustee depends heavily upon IT systems and networks in connection with its business activities. Despite a variety of security measures implemented by the Trustee, events such as the loss or theft of back-up
43
tapes or other data storage media could occur, and the Trustee’s computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within the respective companies.
If a cyber-attack were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the Trustee’s computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust, which could result in litigation, increased costs and regulatory penalties. Although steps are taken to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.
Item 1B. Unresolved Staff Comments.
None.
Item 1C. Cybersecurity.
The Trust has no directors or executive officers. The affairs of the Trust are managed by the Trustee. The Trust falls under the cybersecurity program of The Bank of New York Mellon Corporation (“BNY Mellon”), the parent corporation of The Bank of New York Mellon Trust Company, N.A. As further described in its 2024 Annual Report, BNY Mellon maintains a broad range of defenses aimed at remaining abreast of and responding to evolving cybersecurity threats impacting it, its operations, its clients, its third-party service providers and the broader financial services sector.
Risk Management Strategy and Procedures
BNY Mellon has implemented policies and procedures designed to detect, prevent and respond to malicious and accidental disruptions to the delivery of critical technology services. BNY Mellon’s cybersecurity risk management program is embedded in its three lines of defense model.
As part of its first line of defense, BNY Mellon maintains a dedicated Information Security Division (“ISD”), led by the Chief Information Security Officer (the “CISO”), that is responsible for the day-to-day management of risks from cybersecurity threats. ISD’s responsibilities include cybersecurity threat intelligence, incident response and other cybersecurity operations aimed at enabling BNY Mellon to identify, assess and manage existing and emerging cybersecurity threats. ISD monitors for potential threats and communicates relevant risks to the CISO and other members of executive management. Additionally, ISD maintains a cybersecurity incident response and reporting process pursuant to which cybersecurity incidents are classified according to their severity based upon an assessment of multiple factors. Certain cybersecurity incidents may activate enterprise-wide resiliency processes, which include, among other things, escalation through the management and Board committee structures described below. In addition, BNY Mellon maintains a preparedness program designed to reinforce cybersecurity risk management practices and compliance with BNY Mellon’s policies and procedures. The preparedness program includes mandatory training for all employees, contractors and consultants, enhanced training for those in roles presenting higher risk, calibrated phishing email simulations, distribution of information security awareness materials and cybersecurity event simulation exercises. In addition, BNY Mellon leverages both internal and external assessments and engages with third-party assessors, consultants and auditors to evaluate and test its cybersecurity controls and provide guidance on potential improvements, including design and operating effectiveness. BNY Mellon has standing arrangements with third parties to assist BNY Mellon in identifying, assessing and managing cybersecurity threats, including in connection with risk assessments, penetration testing, legal advice and other aspects of BNY Mellon’s cybersecurity risk management and incident response processes.
BNY Mellon has a defined third-party governance framework to help manage the risk posed to it by the use of third-party service providers. BNY Mellon evaluates the risk posed by third-party service engagements based on multiple factors. BNY Mellon has protocols that seek to mitigate cybersecurity risks associated with third-party service providers based on the risk level assigned to such third party, which
44
may include mandatory contractual obligations or the implementation of additional controls by BNY Mellon and/or the applicable service provider.
ISD is subject to ongoing review and challenge from Technology Risk Management, which is a part of the independent second line of defense risk function. Technology Risk Management, together with the broader Risk & Compliance group, is responsible for and manages BNY Mellon’s risk management framework and establishes guidance for ISD and management designed to help identify, assess and manage cybersecurity risk.
BNY Mellon’s Internal Audit function serves as the third line of defense and provides an independent view on how effectively the organization as a whole manages cybersecurity risk.
Risk Management Oversight and Governance
BNY Mellon’s management is responsible for assessing and managing BNY Mellon’s material risks from cybersecurity threats with oversight provided by its Board of Directors (the “Board”) and the Board committees. The Risk Committee of the Board has primary responsibility for oversight of the overall operation of BNY Mellon’s risk management framework, including policies and practices addressing cybersecurity risk, and is responsible for the oversight of the second line of defense with respect to its cybersecurity risk management responsibilities. The Technology Committee of the Board and the full Board regularly receive reports and briefings from management concerning cybersecurity matters, including any significant changes to BNY Mellon’s cybersecurity program. BNY Mellon also has protocols for escalating cybersecurity threats and incidents to the Technology Committee of the Board and the full Board. In addition, the Audit Committee of the Board monitors and oversees the performance of Internal Audit, including with respect to its cybersecurity risk management responsibilities.
At the management level, BNY Mellon’s Technology Oversight Committee, which is the senior management committee responsible for the governance and oversight of BNY Mellon’s significant technology projects and initiatives, reviews reports from management concerning ISD and is responsible for, among other things, escalating issues, including significant cybersecurity threats and incidents, to the Technology Committee of the Board. The Technology Oversight Committee is chaired by the Chief Information Officer (the “CIO”) and its members include the CISO.
BNY Mellon’s Technology Risk Committee is the most senior governance committee primarily focused on cybersecurity and technology risk issues and is a part of the second line of defense risk function. It is responsible for, among other things, overseeing and reviewing emerging cybersecurity risks, significant cybersecurity incidents and remediation plans. The Technology Risk Committee receives reports from management and has protocols for escalating certain issues and risks to the Senior Risk and Control Committee and the Risk Committee of the Board. The Technology Risk Committee is chaired by the interim Chief Technology Risk Officer. Members include key leaders from the first line of defense, including the CISO.
BNY Mellon’s CIO, CISO and interim Chief Technology Risk Officer each have extensive experience in assessing and managing risks from cybersecurity threats. BNY Mellon’s CISO joined BNY Mellon in 2022 and previously served as head of information security at a Fortune 500 biopharmaceutical company and an information technology company, as well as the Global Chief Technology Officer at a large cybersecurity company. BNY Mellon’s CIO joined BNY Mellon in September 2024 from a large multinational company, where she was responsible for overseeing information technology and cybersecurity operations. BNY Mellon’s interim Chief Technology Risk Officer joined BNY Mellon in November 2024 and has previous experience as Global Head of Cyber, Technology and Information Security Risk Management at a global systemically important financial institution and over a decade of experience serving the U.S. intelligence community in a variety of cybersecurity-related positions.
Item 2. Properties.
Reference is made to “Item 1. Business — Description of the Underlying Properties” and “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations — Planned Development and Workover Program,” which are incorporated herein by reference.
45
Item 3. Legal Proceedings.
Currently, there are no legal proceedings pending to which the Trust is a party or of which any of its property is the subject.
Item 4. Mine Safety Disclosures.
None.
46
PART II
Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
The Trust Units commenced trading on the New York Stock Exchange on May 10, 2011 under the symbol “VOC.” As of March 20, 2025, the 17,000,000 units outstanding were held by six unitholders of record.
Each quarter, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the net profits interest and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust’s expenses for that quarter. Available funds are reduced by any cash that the Trustee decides to hold as a reserve against future expenses. Quarterly cash distributions during the term of the Trust are made by the Trustee on or before the 45th day following the end of each quarter to the Trust unitholders of record on the 30th day following the end of each quarter (or the next succeeding business day).
Equity Compensation Plans
The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.
Recent Sales of Unregistered Securities
There were no equity securities sold by the Trust during the year ended December 31, 2023 that were not registered under the Securities Act of 1933, as amended (the “Securities Act”).
Purchases of Equity Securities
There were no purchases of Trust Units by the Trust or any affiliated purchaser during the fourth quarter of the year ended December 31, 2024.
Item 6.
[Reserved]
Item 7.
Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.
The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The Trust’s purpose is, in general, to hold the net profits interest, to distribute to the Trust unitholders cash that the Trust receives in respect of the net profits interest, and to perform certain administrative functions in respect of the net profits interest and the Trust Units. The Trust derives substantially all of its income and cash flows from the net profits interest.
Critical Accounting Policies and Estimates
The Trust uses the modified cash basis of accounting to report receipts by the Trust of the net profits interest and payments of expenses incurred. The net profits interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses (which are capitalized in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”)) of the Underlying Properties, times 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the Conveyance.
47
The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, Trust corpus, earnings and distributions as follows:
(a)
Income from the net profits interest is recorded when distributions are received by the Trust;
(b)
Distributions to Trust unitholders are recorded when paid by the Trust;
(c)
Trust general and administrative expenses (which include the Trustee’s fees as well as accounting, engineering, legal and other professional fees) are recorded when paid;
(d)
Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under U.S. GAAP;
(e)
Amortization of the investment in net profits interest, calculated using the units-of-production method based upon total estimated proved reserves, is charged directly to Trust corpus and does not affect distributable income; and
(f)
The Trust evaluates its investment in the net profits interest periodically to determine whether its aggregate value has been impaired below its total capitalized cost based on the Underlying Properties. The Trust will provide a write-down to its investment in the net profits interest if and when total capitalized costs, less accumulated amortization, exceed undiscounted future net cash flows attributable to the Trust’s interests in the proved oil and gas reserves of the Underlying Properties.
While these statements differ from financial statements prepared in accordance with U.S. GAAP, the modified cash basis of reporting revenues and distributions is considered most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts received from VOC Brazos.
This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
The following is a summary of income from net profits interest received by the Trust for the years ended December 31, 2022, 2023 and 2024, consisting of the February, May, August and November distributions for each respective year.
| | | |
Year Ended December 31,
|
| |||||||||||||||
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
| Sales volumes: | | | | | | | | | | | | | | | | | | | |
|
Oil (Bbl)
|
| | | | 523,379(1) | | | | | | 495,672(2) | | | | | | 456,682(3) | | |
|
Natural gas (Mcf)
|
| | | | 315,726(1) | | | | | | 297,928(2) | | | | | | 263,696(3) | | |
|
Total (BOE)
|
| | | | 576,000 | | | | | | 545,327 | | | | | | 500,631 | | |
| Average sales prices: | | | | | | | | | | | | | | | | | | | |
|
Oil (per Bbl)
|
| | | $ | 89.35 | | | | | $ | 75.33 | | | | | $ | 76.66 | | |
|
Natural gas (per Mcf)
|
| | | $ | 6.80 | | | | | $ | 4.68 | | | | | $ | 2.95 | | |
| Gross proceeds: | | | | | | | | | | | | | | | | | | | |
|
Oil sales
|
| | | $ | 46,765,144(1) | | | | | $ | 37,338,475(2) | | | | | $ | 35,010,647(3) | | |
|
Natural gas sales
|
| | | | 2,146,497(1) | | | | | | 1,394,915(2) | | | | | | 777,977(3) | | |
|
Total gross proceeds
|
| | | | 48,911,641 | | | | | | 38,733,390 | | | | | | 35,788,624 | | |
| Costs: | | | | | | | | | | | | | | | | | | | |
| Production and development costs: | | | | | | | | | | | | | | | | | | | |
|
Lease operating expenses
|
| | | | 14,247,873 | | | | | | 14,268,658 | | | | | | 14,552,598 | | |
|
Production and property taxes
|
| | | | 1,996,482 | | | | | | 2,037,664 | | | | | | 1,755,415 | | |
|
Development expenses
|
| | | | 3,174,725 | | | | | | 1,852,171 | | | | | | 2,452,213 | | |
|
Total costs
|
| | | | 19,419,080 | | | | | | 18,158,493 | | | | | | 18,760,226 | | |
48
| | | |
Year Ended December 31,
|
| |||||||||||||||
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
|
Excess of revenues over direct operating expenses and lease equipment and development costs
|
| | | | 29,492,561 | | | | | | 20,574,897 | | | | | | 17,028,398 | | |
|
Times net profits interest over the term of the Trust
|
| | | | 80% | | | | | | 80% | | | | | | 80% | | |
|
Income from net profits interest before reserve adjustments
|
| | | | 23,594,050 | | | | | | 16,459,918 | | | | | | 13,622,718 | | |
|
Cash reserve
|
| | | | 0 | | | | | | 0 | | | | | | 0 | | |
|
Income from net profits interest
|
| | | $ | 23,594,050 | | | | | $ | 16,459,918 | | | | | $ | 13,622,718 | | |
| | |||||||||||||||||||
(1)
Oil and gas sales volumes and related revenues for the year ended December 31, 2022 (consisting of VOC Brazos’ February, May, August and November 2022 net profits interest distributions to the Trust) generally represent the production by VOC Brazos from September 2021 through August 2022.
(2)
Oil and gas sales volumes and related revenues for the year ended December 31, 2023 (consisting of VOC Brazos’ February, May, August and November 2023 net profits interest distributions to the Trust) generally represent the production by VOC Brazos from September 2022 through August 2023.
(3)
Oil and gas sales volumes and related revenues for the year ended December 31, 2024 (consisting of VOC Brazos’ February, May, August and November 2024 net profits interest distributions to the Trust) generally represent the production by VOC Brazos from September 2023 through August 2024.
Comparison of Results of the Trust for the Years Ended December 31, 2024 and 2023
The following represents a discussion of the Comparison of Results of the Trust for the Years Ended December 31, 2024 and 2023. Refer to “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on March 16, 2024, for a discussion of the Comparison of Results of the Trust for the Years Ended December 31, 2023 and 2022.
Income from net profits interest. Income from net profits interest is recorded on a modified cash basis when the Trust receives net profits interest proceeds from VOC Brazos. Net profits interest proceeds that VOC Brazos remits to the Trust are based on the oil and gas production VOC Brazos has received payment for within one month following the end of the most recent fiscal quarter. VOC Brazos receives payment for its crude oil sales generally within 30 days following the month in which it is produced. Income from net profits interest is generally a function of oil and gas gross proceeds, lease operating expenses, production and property taxes and development expenses as follows:
Total oil and natural gas sales. Oil and natural gas sales were $35,788,624 for the year ended December 31, 2024, a decrease of $2,944,766 or 7.6% from $38,733,390 for the year ended December 31, 2023. Revenues are a function of oil and natural gas sales prices and volumes sold. The decrease in gross proceeds was due to a decrease in oil and gas sales volumes compared to 2023 and a decrease in the market price for natural gas sales offset slightly by an increase in the market price for oil sales during 2024 compared to 2023. Oil sales volumes were 456,682 Bbls for the year ended December 31, 2024, a decrease of 38,990 Bbls or 7.9% from 495,672 Bbls for the year ended December 31, 2023, while natural gas sales volumes were 263,696 Mcf, a decrease of 34,232 Mcf from 297,928 Mcf for the year ended December 31, 2023. These oil and natural gas sales volume decreases are partially the result of severe winter storms in January 2024 that affected Kansas and Texas and resulted in curtailment of production on certain of the Underlying Properties, as discussed in the Trust’s Current Report on Form 8-K filed on January 19, 2024. The snow and ice associated with those storms disabled electrical power to the affected Underlying Properties for an extended period, rendering some properties inaccessible and generally created difficult working periods. During the year ended December 31, 2024, the average price for oil increased 1.8% to $76.66 per Bbl and the average price for natural gas decreased 37.0% to $2.95 per Mcf.
Costs. Lease operating expenses were $14,552,598 for the year ended December 31, 2024, an increase of $283,940 or 2.0% from $14,268,658 for the year ended December 31, 2023. The increase was primarily due to increases in the costs of oilfield goods and services. Production and property taxes were $1,755,415 for
49
the year ended December 31, 2024, a decrease of $282,249 or 13.9% from $2,037,664 for the year ended December 31, 2023. The decrease is primarily due to a decrease in production taxes of $224,273 or 21.5% as a result of lower sales volumes for oil and natural gas sales along with a decrease in property taxes of $57,976 or 5.8%.
Development expenses were $2,452,213 for the year ended December 31, 2024, an increase of $600,042 or 32.4% from $1,852,171 for the year ended December 31, 2023. Such increase was primarily due to increased development activity during the year ended December 31, 2024 as compared to the year ended December 31, 2023.
Excess of revenues over direct operating expenses and lease equipment and development costs. The excess of revenues over direct operating expenses and lease equipment and development costs from the Underlying Properties was $17,028,398 for the year ended December 31, 2024, a decrease of $3,546,499 or 17.2% from $20,574,897 for the year ended December 31, 2023. The Trust’s 80% net profits interest of these totals was $13,622,718 and $16,459,918, respectively. During the years ended December 31, 2024 and 2023, VOC Brazos did not withhold or release any dollar amounts due to the Trust from previously established cash reserves for future development, maintenance or operating expenditures, which resulted in income from the net profits interest of $13,622,718 and $16,459,918, respectively, for such years. These amounts were reduced by a Trustee holdback for current estimated expenses of $1,212,718 and $1,013,888 for the years ended December 31, 2024 and 2023, respectively, and a Trustee holdback for future estimated expenses of $231,030 for the year ended December 31, 2023. The Trustee paid general and administrative expenses of $897,342 for the year ended December 31, 2024, a decrease of $167,152 from $1,064,494 for the year ended December 31, 2023. These factors resulted in distributable income for the year ended December 31, 2024 of $12,410,000, a decrease of $2,805,000 from $15,215,000 for the year ended December 31, 2023.
Liquidity and Capital Resources
Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the net profits interest and payments from other sources (such as interest earned on any amounts reserved by the Trustee) in that quarter, over the Trust’s expenses paid for that quarter. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future expenses. As of December 31, 2024, the Trustee held $1,744,677 as cash and cash equivalents on the accompanying Statements of Assets and Trust Corpus, which includes the $1.175 million cash reserve described below, as such a reserve. The Trust paid, out of the first cash payment received by the Trust, the Trustee’s and Delaware Trustee’s legal expenses incurred in forming the Trust, in connection with the initial public offering (that were not otherwise paid by VOC Brazos) and related matters, as well as the Delaware Trustee’s acceptance fee in the amount of $5,000.
From the first quarter of 2022 to the second quarter of 2023, the Trustee withheld a portion of the proceeds otherwise available for distribution each quarter to build an approximately $1.175 million cash reserve for the payment of future known, anticipated or contingent expenses or liabilities of the Trust. This amount is in addition to the letter of credit in the amount of $1.7 million provided to the Trustee by VOC Brazos to protect the Trust against the risk that it does not have sufficient cash to pay future expenses. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Trust unitholders, The interest earned on this cash reserve is used to reduce the reported general and administrative expense each quarter on the statements of distributable income.
The Trustee can authorize the Trust to borrow money to pay Trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee as lender provided the terms of the loan are fair to the Trust unitholders. The Trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make no other short-term investments with the funds
50
distributed to the Trust. The Trustee has no current plans to authorize the Trust to borrow money. If the Trust borrows funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid. During the year ended December 31, 2024, the Trust made no borrowings.
As substantially all of the Underlying Properties are located in mature fields, VOC Brazos does not expect future costs for the Underlying Properties to change significantly as compared to recent historical costs other than changes due to fluctuations in the cost of oilfield services generally. However, see “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations — Planned Development and Workover Program” below. VOC Brazos has agreed to post a letter of credit in the amount of $1.7 million in favor of the Trustee to protect the Trustee against the risk that the Trust does not have sufficient cash to pay its expenses.
The Trust pays the Trustee an administrative fee of $150,000 per year. The Trust paid an annual fee to the Delaware Trustee of $2,510 per year. The Trust also incurs, either directly or as a reimbursement to the Trustee, legal, accounting, tax and engineering fees, printing costs and other expenses that are deducted by the Trust before distributions are made to Trust unitholders, including the $18,750 administrative services fee payable quarterly to VOC Brazos pursuant to an administrative services agreement. The Trust is also responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to Trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees.
The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.
Planned Development and Workover Program
The primary goals of VOC Brazos’ development and workover program have been to develop proved undeveloped reserves, manage workovers and minimize the natural decline in production in areas in which it operates. However, VOC Brazos is not obligated to undertake any development activities, so any drilling and completing activities will be subject to the reasonable discretion of VOC Brazos. No assurance can be given, however, that any development well will produce in commercially paying quantities or that the characteristics of any development well will match the characteristics of VOC Brazos’ existing wells or VOC Brazos’ historical drilling success rate. With respect to the Underlying Properties, VOC Brazos expects, but is not obligated, to implement the following development strategies specific to each of its primary operating areas:
•
Kansas. VOC Brazos’ historical development and workover program for the Kansas Underlying Properties has included recompleting certain existing wells, drilling infill development wells, conducting 3-D seismic surveys, completing workovers and applying new production technologies. VOC Brazos expects to incur future development expenditures for these properties through December 31, 2027 of approximately $1.1 million, of which VOC Brazos contemplates spending approximately $1.0 million to drill and complete three vertical wells. The remaining approximately $0.1 million is expected to be used for recompletions and workovers of three wells.
•
Texas. VOC Brazos’ historical development and workover program for the Texas Underlying Properties has included recompleting certain existing wells, drilling infill development wells, completing workovers and applying new production technologies. In particular, since 2003, through its ownership in the Kurten Woodbine Unit, VOC Brazos has pursued operational, strategic and technological initiatives to economically produce and sell hydrocarbons from the Woodbine Interval, also commonly referred to as the Eaglebine formation, which is the correlative interval defined as encompassing all depths from the base of the Austin Chalk to the top of the Buda formation. VOC Brazos has: (a) operated approximately 100 primary and secondary recovery vertical wells in various Woodbine sands, (b) drilled, completed and operated 13 horizontal wells primarily from, but not limited to, the Woodbine C sand, (c) conducted geologic evaluations, including 3-D seismic data acquisition and analysis, of the source shale present throughout the Woodbine Interval, and (d) most recently, pursued development of the lower depths of the source shale present throughout the Woodbine Interval, defined as the Lower Woodbine Organic Shale (“LWOS”).
51
•
In 2018, VOC Brazos entered into a new joint venture agreement with Hawkwood Energy East Texas, LLC (“Hawkwood”). Under the terms of the new joint venture agreement, Hawkwood carried VOC Brazos for its share of drilling and completion costs for four LWOS wells (the “Hawkwood Earning Wells”). In exchange, Hawkwood earned a working interest representing 50% of VOC Brazos’ interest in each Hawkwood Earning Well and up to a 50% interest in VOC Brazos’ acreage in the south half of the Kurten Woodbine Unit. After the Hawkwood Earning Wells were completed, Hawkwood has no contractual limitation of the number of wells per year to propose and drill after 2020 (collectively, the “Hawkwood Development Wells”). No new Hawkwood Development Wells were drilled in 2022, 2023 or 2024.
•
In 2022, Wildfire Energy Operating, LLC (“Wildfire”) acquired Hawkwood. As a result, Wildfire retained the rights of Hawkwood under the joint venture agreement.
•
VOC Brazos is evaluating the potential economic benefits associated with development of the LWOS. If these activities are pursued, such activities would result in increased development costs burdening the net profits interest of the Trust relative to historical development costs. As a result of such increased development costs, cash available for distribution by the Trust would be temporarily reduced, and in certain periods there may be no distributions to Trust unitholders, until anticipated production from the various development efforts in the Kurten Woodbine Unit can be brought on-line. To address these emerging opportunities, VOC Brazos will continue to evaluate the appropriate strategy and capital plan to fund development for the Trust.
•
VOC Brazos expects to incur future development expenditures for the Texas Underlying Properties through December 31, 2032 of approximately $34.5 million to drill and complete eight non-joint venture agreement wells, all within the Woodbine Interval of the Kurten Woodbine Unit. Additionally, VOC Brazos expects to incur approximately $0.8 million to convert 15 horizontal wells from gas lift to rod pump and workover 2 wells. The Trust will indirectly bear an 80% share of these development expenditures as described below.
The Trust is not directly obligated to pay any portion of the capital expenditures made with respect to the Underlying Properties; however, capital expenditures made by VOC Brazos with respect to the Underlying Properties will be deducted from the gross proceeds in calculating the net proceeds from which cash will be paid to the Trust. As a result, the Trust will indirectly bear an 80% (subject to certain limitations during the final three years of the Trust, as described above under “Item 1. Business — Computation of Net Proceeds — Net Profits Interest”) share of any capital expenditures made with respect to the Underlying Properties. Accordingly, higher or lower capital expenditures will, in general, directly decrease or increase, respectively, the cash received by the Trust in respect of its net profits interest, which will have a corresponding effect on cash available for distribution to Trust unitholders. As the cash received by the Trust in respect of the net profits interest will be reduced by the Trust’s pro rata share of these capital expenditures, VOC Brazos expects that it will incur capital expenditures with respect to the Underlying Properties throughout the term of the Trust on a basis that balances the impact of the capital expenditures on current cash distributions to the Trust unitholders with the longer term benefits of increased oil and natural gas production expected to result from the capital expenditures. In addition, VOC Brazos may establish a capital reserve of up to $1.0 million in the aggregate at any given time to reduce the impact on distributions of uneven capital expenditure timing. However, if annual cash proceeds attributable to the net profits interest are less than $1 million for each of two consecutive years, then under the terms of the Trust Agreement, the Trust would be required to dissolve.
VOC Brazos, as the designated operator of the Underlying Properties, is entitled to make all determinations related to capital expenditures with respect to the Underlying Properties, and there are no limitations on the amount of capital expenditures that VOC Brazos may incur with respect to the Underlying Properties. VOC Brazos is required under the Conveyance to use commercially reasonable efforts to cause the operators of the Underlying Properties to operate these properties as would a reasonably prudent operator acting with respect to its own properties (without regard to the existence of the net profits interest). As the Trust unitholders would not be expected to fully realize the benefits of capital expenditures made with respect to the Underlying Properties towards the end of the term of the Trust, during each twelve-month period beginning on the later to occur of (1) December 31, 2027 and (2) the time when 9.8 MMBoe have been produced from the Underlying Properties and sold (which is the equivalent of 7.8 MMBoe in respect of the
52
net profits interest), capital expenditures that may be taken into account in calculating net proceeds attributable to the net profits interest will be limited to the average annual capital expenditures during the preceding three years, as increased by 2.5% to account for expected increased costs due to inflation.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
The Trust is a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and is not required to provide the information under this item.
53
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Unitholders of VOC Energy Trust
and The Bank of New York Mellon Trust Company, N.A., as Trustee
and The Bank of New York Mellon Trust Company, N.A., as Trustee
Opinion on the financial statements
We have audited the accompanying statements of assets and trust corpus of VOC Energy Trust (the “Trust”) as of December 31, 2024 and 2023, the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets and trust corpus of the Trust as of December 31, 2024 and 2023, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2024, in conformity with the modified cash basis of accounting described in Note B to the financial statements.
Basis of accounting
As described in Note B to the financial statements, these financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
Basis for opinion
These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Trustee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.
/s/ Grant Thornton LLP
We have served as the Trust’s auditor since 2010.
Oklahoma City, Oklahoma
March 20, 2025
March 20, 2025
54
VOC ENERGY TRUST
STATEMENTS OF ASSETS AND TRUST CORPUS
STATEMENTS OF ASSETS AND TRUST CORPUS
| | | |
December 31,
|
| |||||||||
| | | |
2023
|
| |
2024
|
| ||||||
|
ASSETS
|
| | | | | | | | | | | | |
|
Cash and cash equivalents
|
| | | $ | 1,429,301 | | | | | $ | 1,744,677 | | |
|
Investment in net profits interest
|
| | | | 140,591,606 | | | | | | 140,591,606 | | |
|
Accumulated amortization and impairment
|
| | | | (128,648,342) | | | | | | (130,464,406) | | |
|
Total assets
|
| | | $ | 13,372,565 | | | | | $ | 11,871,877 | | |
|
TRUST CORPUS
|
| | | | | | | | | | | | |
|
Trust corpus, 17,000,000 Trust Units issued and outstanding at December 31, 2023 and 2024, respectively
|
| | | $ | 13,372,565 | | | | | $ | 11,871,877 | | |
STATEMENTS OF DISTRIBUTABLE INCOME
| | | |
Year Ended December 31,
|
| |||||||||||||||
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
|
Income from net profits interest
|
| | | $ | 23,594,050 | | | | | $ | 16,459,918 | | | | | $ | 13,622,718 | | |
|
Cash on hand withheld for Trust expenses
|
| | | | (961,673) | | | | | | (180,424) | | | | | | (315,376) | | |
|
General and administrative expenses(1)
|
| | | | (957,377) | | | | | | (1,064,494) | | | | | | (897,342) | | |
|
Distributable income
|
| | | $ | 21,675,000 | | | | | $ | 15,215,000 | | | | | $ | 12,410,000 | | |
|
Distributions per Trust Unit (17,000,000 Trust Units issued and outstanding at December 31, 2022, 2023 and 2024, respectively)
|
| | | $ | 1.275 | | | | | $ | 0.895 | | | | | $ | 0.730 | | |
(1)
Includes $114,330, $118,902 and $123,659 paid to VOC Brazos and $150,000, $150,000 and $150,000 paid to The Bank of New York Mellon Trust Company, N.A. for the years ended December 31, 2022, 2023 and 2024, respectively.
STATEMENTS OF CHANGES IN TRUST CORPUS
| | | |
Year Ended December 31,
|
| |||||||||||||||
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
|
Trust corpus, beginning of year
|
| | | $ | 16,005,190 | | | | | $ | 15,048,316 | | | | | $ | 13,372,565 | | |
|
Income from net profits interest
|
| | | | 23,594,050 | | | | | | 16,459,918 | | | | | | 13,622,718 | | |
|
Cash distributions
|
| | | | (21,675,000) | | | | | | (15,215,000) | | | | | | (12,410,000) | | |
|
Trust expenses
|
| | | | (957,377) | | | | | | (1,064,494) | | | | | | (897,342) | | |
|
Amortization of net profits interest
|
| | | | (1,918,547) | | | | | | (1,856,175) | | | | | | (1,816,064) | | |
|
Trust corpus, end of year
|
| | | $ | 15,048,316 | | | | | $ | 13,372,565 | | | | | $ | 11,871,877 | | |
55
VOC ENERGY TRUST
NOTES TO FINANCIAL STATEMENTS
NOTE A — ORGANIZATION OF THE TRUST
VOC Energy Trust (the “Trust”) is a statutory trust formed on November 3, 2010 (capitalized on December 17, 2010) under the Delaware Statutory Trust Act pursuant to a trust agreement dated November 3, 2010 (as amended and restated on May 10, 2011, the “Trust Agreement”) among VOC Brazos Energy Partners, L.P., a Texas limited partnership (“VOC Brazos”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”). The Trust was created to acquire and hold a term net profits interest for the benefit of the Trust unitholders.
VOC Brazos is a privately held limited partnership engaged in the production and development of oil and natural gas from properties located in Texas. VOC Kansas Energy Partners, L.L.C., a Kansas limited liability company (“VOC Kansas”), is a privately held limited liability company engaged in the production and development of oil and natural gas from properties primarily located in Kansas along with a limited number of Texas properties. In connection with the closing of the initial public offering of units of beneficial interest in the Trust (“Trust Units”) in May 2011, VOC Brazos acquired all of the membership interests in VOC Kansas in exchange for newly issued limited partner interests in VOC Brazos pursuant to a Contribution and Exchange Agreement, dated August 30, 2010, as amended, by and between VOC Brazos and VOC Kansas. This resulted in VOC Kansas becoming a wholly owned subsidiary of VOC Brazos.
The Trust was created to acquire and hold a term net profits interest representing the right to receive 80% of the net proceeds (calculated as described below in Note C) from production from the Underlying Properties (as defined below) (the “net profits interest”). The net profits interest consists of working interests in substantially all of the oil and natural gas properties held by VOC Brazos and VOC Kansas in the States of Kansas and Texas as of the date of the conveyance of the net profits interest to the Trust (the “Conveyance”). The properties in which the Trust holds the net profits interest are referred to as the “Underlying Properties.”
The net profits interest is passive in nature, and the Trustee has no management control over and no responsibility relating to the operation of the Underlying Properties. The net profits interest entitles the Trust to receive 80% of the net proceeds attributable to VOC Brazos’ interest from the sale of production from the Underlying Properties during the term of the Trust. The net profits interest will terminate on the liquidation date, which is the later to occur of (1) December 31, 2030 or (2) the time when 10.6 million barrels of oil equivalent (“MMBoe”) (which is the equivalent of 8.5 MMBoe in respect of the net profits interest) have been produced from the Underlying Properties and sold, and the Trust will soon thereafter wind up its affairs and terminate.
As of December 31, 2024, cumulatively, since inception, the Trust has received payment for 80% of the net proceeds attributable to VOC Brazos’ interest from the sale of 9.1 MMBoe of production from the Underlying Properties (which is the equivalent of 7.3 MMBoe (unaudited) in respect of the net profits interest).
The Trust will dissolve 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 $1.0 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 prior to the liquidation date, the Trustee would sell all of the Trust’s assets, which are limited to the net profits interest, and do not include the Underlying Properties, either by private sale or public auction, and distribute the net proceeds of the sale to the Trust unitholders.
The Trustee can authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee
56
or the Delaware Trustee as a lender provided the terms of the loan are similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself and make other short-term investments with the funds distributed to the Trust.
NOTE B — TRUST ACCOUNTING POLICIES
A summary of the significant accounting policies of the Trust follows.
1.
Basis of accounting
The Trust uses the modified cash basis of accounting to report receipts by the Trust of the net profits interest and payments of expenses incurred. The net profits interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses (which are capitalized in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”)) of the Underlying Properties times 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the Conveyance.
The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, Trust corpus, and distributable income as follows:
(a)
Income from net profits interest is recorded when distributions are received by the Trust;
(b)
Distributions to Trust unitholders are recorded when paid by the Trust;
(c)
Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal and other professional fees) are recorded when paid;
(d)
Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under U.S. GAAP;
(e)
Amortization of the investment in net profits interest, calculated using the units-of-production method based upon total estimated proved reserves, is charged directly to Trust corpus and does not affect distributable income; and
(f)
The Trust evaluates its investment in the net profits interest periodically to determine whether its aggregate value has been impaired below its total capitalized cost based on the Underlying Properties. The Trust will provide a write-down to its investment in the net profits interest if and when total capitalized costs, less accumulated amortization, exceed undiscounted future net cash flows attributable to the Trust’s interests in the proved oil and gas reserves of the Underlying Properties.
While these statements differ from financial statements prepared in accordance with U.S. GAAP, the modified cash basis of reporting revenues and distributions is considered most meaningful because quarterly distributions to the Trust unitholders are based on net cash receipts.
This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (the “SEC”) as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, requiring public entities to disclose information about their reportable segments’ significant expenses and other segment items on an interim and annual basis. Public entities with a single reportable segment are required to apply the disclosure requirements in ASU 2023-07, as well as all existing segment disclosures and reconciliation requirements in ASC 280 on an interim and annual basis. The Trust adopted ASU 2023-07 during the year ended December 31, 2024.
2.
Cash equivalents
For purposes of these statements, the Trust considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
57
3.
Use of estimates
The preparation of financial statements requires estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Actual results could differ from those estimates.
Significant estimates affecting these financial statements include estimates of proved oil and gas reserves, which are used to compute the Trust’s amortization of net profits interest.
4.
Segment reporting
The Trust has one business activity as the owner of an investment in net profits interest, as reported in accompanying the Statements of Assets and Trust Corpus, and operates in a single operating and reportable segment. Operating segments are defined as components of an entity for which separate financial information is evaluated regularly by the chief operating decision maker, which is the Trustee. The segment participates in activities and derives its income from net profits interest (net sales proceeds from oil and gas production) as reported in the accompanying Statements of Distributable Income, and the Trustee uses this in making decisions about the allocation of cash reserves for current and future Trust general and administrative expenses and the ultimate distribution to the Trust unitholders. See Note C.
NOTE C — NET PROFITS INTEREST
Under the Conveyance, 80% of the aggregate net proceeds attributable to the sale of oil and natural gas production from the Underlying Properties for each calendar quarter will be paid to the Trust on or before the 30th day of the month following the end of each quarter. VOC Brazos will not pay to the Trust any interest on the net proceeds held by VOC Brazos prior to payment to the Trust. The Trustee will make distributions to Trust unitholders quarterly.
“Gross proceeds” means the aggregate amount received by VOC Brazos from sales of oil and natural gas produced from the Underlying Properties (other than amounts received for certain future non-consent operations). However, gross proceeds does not include consideration for the transfer or sale of any Underlying Property by VOC Brazos or any subsequent owner to any new owner. Gross proceeds also does not include any amount for oil or natural gas 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 costs:
•
all payments to mineral or landowners, such as royalties, overriding royalties or other burdens against production, delay rentals, shut-in oil and natural gas payments, minimum royalty or other payments for drilling or deferring drilling;
•
any taxes paid by the owner of an Underlying Property to the extent not deducted in calculating gross proceeds, including estimated and accrued general property (ad valorem), production, severance, sales, gathering, excise and other taxes;
•
any extraordinary taxes or windfall profits taxes that may be assessed in the future that are based on profits realized or prices received for production from the Underlying Properties;
•
costs paid by an owner of a property comprising the Underlying Properties under any joint operating agreement pursuant to the terms of the Conveyance;
•
all other costs and expenses, development costs and liabilities of drilling, recompleting, workovers, operating and producing oil and natural gas, including allocated expenses such as labor, vehicle and travel costs and materials and any plugging and abandonment liabilities (net of any development costs for which a reserve had already been made to the extent such development 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 and natural gas (provided, however, that any proceeds attributable to treatment or processing will offset such costs or changes, if any);
58
•
any overhead charge incurred pursuant to any operating agreement or other arrangement relating to an Underlying Property as permitted under the applicable conveyance, including the overhead fees payable by VOC Brazos to its affiliates Vess Oil Corporation (“Vess Oil”), L.D. Drilling Inc. and Davis Petroleum (Vess Oil, L.D. Drilling Inc. and Davis Petroleum are referred to collectively as the “VOC Operators”); effective September 1, 2022, Vess Oil took over, from Davis Petroleum, operations of the Underlying Properties in which VOC Brazos had an ownership interest; and effective July 1, 2023, Vess Oil took over, from L.D. Drilling, Inc., operations of the Underlying Properties in which VOC Brazos had an ownership interest;
•
costs for recording the Conveyance and costs estimated to record the termination and for release of the Conveyance;
•
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 VOC Brazos (or any subsequent owner of the Underlying Properties), amounts reserved for approved 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 (provided that such costs shall not be debited from gross proceeds when actually incurred).
Certain other non-production revenues, including salvage value for equipment related to plugged and abandoned wells, as detailed in the Conveyance, offset the costs outlined above in calculating the net proceeds.
If any excess amounts have not been used to offset costs at the time when the later to occur of (1) December 31, 2030, or (2) the time when 10.6 MMBoe (which is the equivalent of 8.5 MMBoe in respect of the net profits interest) have been produced from the Underlying Properties and sold, then Trust unitholders will not be entitled to receive the benefit of such excess amounts.
During each twelve-month period beginning on the later to occur of (1) December 31, 2027 and (2) the time when 9.8 MMBoe have been produced from the Underlying Properties and sold (which is the equivalent of 7.8 MMBoe in respect of the net profits interest) (in either case, the “Capital Expenditure Limitation Date”), the sum of the development expenditures and amounts reserved for approved development 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 development expenditures and amounts reserved for approved development 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.
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 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 basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.
The net profits interest was recorded at the historical cost of VOC Brazos on May 10, 2011, the date of the Conveyance, and was calculated as follows:
| |
Oil and gas properties
|
| | | $ | 197,270,173 | | |
| |
Accumulated depreciation and depletion
|
| | | | (17,681,155) | | |
| |
Hedge liability
|
| | | | (1,717,713) | | |
| |
20-year asset retirement liability
|
| | | | (2,131,797) | | |
| |
Net property value to be conveyed
|
| | | | 175,739,508 | | |
| |
Times 80% net profits interest to Trust
|
| | | $ | 140,591,606 | | |
59
NOTE D — INCOME FROM NET PROFITS INTEREST
| | | |
Year Ended December 31,
|
| |||||||||||||||
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
|
Excess of revenues over direct operating expenses and lease equipment and development costs(1)
|
| | | $ | 29,492,561 | | | | | $ | 20,574,897 | | | | | $ | 17,028,398 | | |
|
Times net profits interest over the term of the Trust
|
| | | | 80% | | | | | | 80% | | | | | | 80% | | |
|
Income from net profits interest before reserve adjustments
|
| | | | 23,594,050 | | | | | | 16,459,918 | | | | | | 13,622,718 | | |
|
Cash reserve(2)
|
| | | | 0 | | | | | | 0 | | | | | | 0 | | |
|
Income from net profits interest
|
| | | $ | 23,594,050(3) | | | | | $ | 16,459,918(4) | | | | | $ | 13,622,718(5) | | |
(1)
Pursuant to the terms of the Conveyance, lease equipment and development costs are to be deducted when calculating the distributable income to the Trust.
(2)
Pursuant to the terms of the Conveyance, VOC Brazos can reserve up to $1,000,000 for future development, maintenance or operating expenditures at any time. The reserve balance was $1,000,000 at each of December 31, 2022, 2023 and 2024.
(3)
The income from the net profits interest for the year ended December 31, 2022 (consisting of VOC Brazos’ February, May, August and November 2022 net profits interest distributions to the Trust) generally represents the production by VOC Brazos from September 2021 through August 2022.
(4)
The income from the net profits interest for the year ended December 31, 2023 (consisting of VOC Brazos’ February, May, August and November 2023 net profits interest distributions to the Trust) generally represents the production by VOC Brazos from September 2022 through August 2023.
(5)
The income from the net profits interest for the year ended December 31, 2024 (consisting of VOC Brazos’ February, May, August and November 2024 net profits interest distributions to the Trust) generally represents the production by VOC Brazos from September 2023 through August 2024.
For the years ended December 31, 2022, 2023 and 2024, MV Purchasing, LLC (“MV Purchasing”), an affiliate of VOC Brazos, purchased 35%, for each year, of the production sold from the Underlying Properties. Sales to MV Purchasing are under short-term arrangements, ranging from one to six months, using market sensitive pricing.
NOTE E — INCOME TAXES
Tax counsel to the Trust advised the Trust at the time of formation that, under then current tax laws, in its opinion the net profits interest should be treated as a debt instrument for federal income tax purposes, and the Trust should be required to treat a portion of each payment it receives with respect to the net profits interest as interest income in accordance with the “noncontingent bond method” under the original issue discount rules contained in the Internal Revenue Code of 1986, as amended, and the corresponding regulations. Tax counsel to the Trust also advised the Trust at the time of formation that in its opinion the Trust will be treated as a grantor trust for federal income tax purposes. On the basis of this advice, Trust unitholders will be considered to own and receive the Trust’s assets and income and will be directly taxable thereon as if no trust were in existence. No provision for federal or state income taxes has been made in the accompanying statements.
NOTE F — DISTRIBUTIONS TO UNITHOLDERS
The Trustee determines for each quarter the amount available for distribution to the Trust unitholders. This distribution is expected to be made on or before the 45th day following the end of each quarter to the Trust unitholders of record on the 30th day of the month following the end of each quarter (or the next succeeding business day). Such amounts will be equal to the excess, if any, of the cash received by the Trust relating to the preceding quarter, over the expenses of the Trust paid for such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for future expenses of the Trust. From the first quarter of 2022 to the second quarter of 2023, the Trustee withheld a portion of the proceeds otherwise available for distribution each quarter to build an approximately
60
$1.175 million cash reserve for the payment of future known, anticipated or contingent expenses or liabilities of the Trust. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Trust unitholders. The interest earned on this cash reserve is used to reduce the reported general and administrative expense each quarter on the statements of distributable income. This cash reserve is included in cash and cash equivalents on the accompanying Statements of Assets and Trust Corpus.
|
Date paid
|
| |
Period covered
|
| |
Distribution
per unit |
| |
Available
distribution before reserve change |
| |
Reserve
released (established) to (from) distribution(1) |
| |
Total
distribution |
| ||||||
|
February 14, 2022
|
| |
October 1, 2021 through
December 31, 2021 |
| | | $ | 0.250 | | | |
$4.250 million
|
| | | $ | 0 | | | |
$4.250 million
|
|
|
May 14, 2022
|
| |
January 1, 2022 through
March 31, 2022 |
| | | $ | 0.280 | | | |
$4.760 million
|
| | | $ | 0 | | | |
$4.760 million
|
|
|
August 12, 2022
|
| |
April 1, 2022 through
June 30, 2022 |
| | | $ | 0.380 | | | |
$6.460 million
|
| | | $ | 0 | | | |
$6.460 million
|
|
|
November 14, 2022
|
| |
July 1, 2022 through
September 30, 2022 |
| | | $ | 0.365 | | | |
$6.205 million
|
| | | $ | 0 | | | |
$6.205 million
|
|
|
February 14, 2023
|
| |
October 1, 2022 through
December 31, 2022 |
| | | $ | 0.230 | | | |
$3.910 million
|
| | | $ | 0 | | | |
$3.910 million
|
|
|
May 12, 2023
|
| |
January 1, 2023 through
March 31, 2023 |
| | | $ | 0.230 | | | |
$3.910 million
|
| | | $ | 0 | | | |
$3.910 million
|
|
|
August 14, 2023
|
| |
April 1, 2023 through
June 30, 2023 |
| | | $ | 0.210 | | | |
$3.570 million
|
| | | $ | 0 | | | |
$3.570 million
|
|
|
November 14, 2023
|
| |
July 1, 2023 through
September 30, 2023 |
| | | $ | 0.225 | | | |
$3.825 million
|
| | | $ | 0 | | | |
$3.825 million
|
|
|
February 14, 2024
|
| |
October 1, 2023 through
December 31, 2023 |
| | | $ | 0.190 | | | |
$3.230 million
|
| | | $ | 0 | | | |
$3.230 million
|
|
|
May 15, 2024
|
| |
January 1, 2024 through
March 31, 2024 |
| | | $ | 0.180 | | | |
$3.060 million
|
| | | $ | 0 | | | |
$3.060 million
|
|
|
August 14, 2024
|
| |
April 1, 2024 through
June 30, 2024 |
| | | $ | 0.180 | | | |
$3.060 million
|
| | | $ | 0 | | | |
$3.060 million
|
|
|
November 14, 2024
|
| |
July 1, 2024 through
September 30, 2024 |
| | | $ | 0.180 | | | |
$3.060 million
|
| | | $ | 0 | | | |
$3.060 million
|
|
(1)
Pursuant to the terms of the Conveyance, VOC Brazos can reserve up to $1,000,000 for future development, maintenance or operating expenditures at any time.
NOTE G — RELATED PARTY TRANSACTIONS
Trustee Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $150,000 to the Trustee and paid $2,510 to the Delaware Trustee for 2022, 2023 and 2024, respectively.
Agreement with VOC Brazos. In May 2011, the Trustee, not in its individual capacity but solely as Trustee of the Trust, entered into an administrative services agreement with VOC Brazos whereby, in connection with the conveyance of the net profits interest to the Trust, VOC Brazos agreed to provide the Trust with accounting, bookkeeping and informational services relating to the net profits interest in exchange for an administrative services fee of $18,750 that will be paid to VOC Brazos on a quarterly basis, The
61
administrative services agreement will terminate on the earliest to occur of: (i) the date the Trust shall have dissolved and commenced winding up in accordance with the Trust Agreement, (ii) the date that all of the net profits interest has been terminated or is no longer held by the Trust and (iii) a date mutually agreed to by VOC Brazos and the Trustee. The quarterly fee increases by 4% each year. For 2022, 2023 and 2024, $114,330, $118,902 and $123,659 respectively, was paid to VOC Brazos as administrative fees.
Joint Venture Agreement. In 2018, VOC Brazos entered into a joint venture agreement with Hawkwood Energy East Texas, LLC (“Hawkwood”). Under the terms of the joint venture agreement, Hawkwood carried VOC Brazos for its share of drilling and completion costs for four wells in the Lower Woodbine Organic Shale (the “Hawkwood Earning Wells”). In exchange, Hawkwood earned a working interest representing 50% of VOC Brazos’ interest in each Hawkwood Earning Well and up to a 50% interest in VOC Brazos’ acreage in the south half of the Kurten Woodbine Unit. After the Hawkwood Earning Wells were completed, Hawkwood has no contractual limitation of the number of wells per year to propose and drill after 2020 (collectively, the “Hawkwood Development Wells”).
In 2022, Wildfire Energy Operating, LLC (“Wildfire”) acquired Hawkwood. As a result, Wildfire retained the rights of Hawkwood under the joint venture agreement.
VOC Brazos is evaluating the potential economic benefits associated with development of the LWOS. If these activities are pursued, such activities would result in increased development costs burdening the net profits interest of the Trust relative to historical development costs. As a result of such increased development costs, cash available for distribution by the Trust would be temporarily reduced, and in certain periods there may be no distributions to Trust unitholders, until anticipated production from the various development efforts in the Kurten Woodbine Unit can be brought on-line. If annual cash proceeds attributable to the net profits interest are less than $1 million for each of two consecutive years, then under the terms of the Trust Agreement, the Trust would be required to dissolve. To address these emerging opportunities, VOC Brazos will continue to evaluate the appropriate strategy and capital plan to fund development for the Trust.
NOTE H — ADVANCE FOR TRUST EXPENSES
Under the terms of the Trust Agreement, the Trustee is allowed to borrow money to pay Trust expenses. During 2022, 2023 and 2024, the Trust did not borrow any money. Any advances will be shown as additions to Trust Corpus when the borrowing is made, and any repayments will be shown as reductions to Trust Corpus when the borrowing is repaid. Under the terms of the Trust Agreement, VOC Brazos has provided a letter of credit in the amount of $1.7 million to the Trustee to protect the Trust against the risk that it does not have sufficient cash to pay future expenses.
From the first quarter of 2022 to the second quarter of 2023, the Trustee withheld a portion of the proceeds otherwise available for distribution each quarter to build an approximately $1.175 million cash reserve for the payment of future known, anticipated, or contingent expenses or liabilities of the Trust. This amount is in addition to the letter of credit in the amount of $1.7 million discussed above. The Trustee may increase or decrease the targeted amount at any time and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Trust unitholders. The interest earned on this cash reserve is used to reduce the reported general and administrative expense each quarter on the statements of distributable income. This cash reserve is included in cash and cash equivalents on the accompanying Statements of Assets and Trust Corpus.
NOTE I — OTHER EVENTS
Subsequent event
On January 17, 2025, the Trust announced a Trust distribution to Trust unitholders of record on January 30, 2025 of $1,445,000, or $0.085 per unit, which was paid on February 13, 2025. Such distribution consisted of the net proceeds of production collected by VOC Brazos from October 1, 2024 through December 31, 2024.
62
NOTE J — DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)
The Trust is required to disclose proved reserves in accordance with the SEC’s reporting rules, which require that the average, first-day-of-the-month price during the 12-month period before the end of the year be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2022, 2023 and 2024 has been presented in accordance with these rules.
Estimates of the proved oil and gas reserves attributable to the Trust as of December 31, 2022, 2023 and 2024 are based on reports of Cawley, Gillespie & Associates, Inc., independent petroleum and geological engineers, and the contract property management engineering staff of the manager of VOC Brazos who operates the Underlying Properties, in accordance with the SEC’s rules and definitions. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” and “proved undeveloped” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.
The reserve data below represent estimates only and should not be construed as being exact. Moreover, the discounted values should not be construed as representative of the current market value of the net profits interest. A market value determination would include many additional factors including: (i) anticipated future oil and gas prices; (ii) the effect of federal income taxes, if any, on the Trust; (iii) an allowance for return on investment; (iv) the effect of governmental legislation; (v) the value of additional potential reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities; and (vi) other business risks.
The following tables set forth (i) the estimated net quantities of proved, proved developed and proved undeveloped oil and natural gas reserves attributable to the Trust, and (ii) the standardized measure of the discounted future net profits interest income attributable to the Trust and the nature of changes in such standardized measure between years. These tables are prepared on the accrual basis, which is the basis on which VOC Brazos maintains its production records and is different from the basis on which the Trust is reporting.
63
ESTIMATED QUANTITIES OF OIL AND GAS RESERVES
| | | |
Oil (Bbls)
|
| |
Gas (Mcf)
|
| |
Oil
Equivalents (Boe) |
| |||||||||
| Proved reserves | | | | | | | | | | | | | | | | | | | |
|
Balance at December 31, 2021
|
| | | | 3,248,585 | | | | | | 2,198,451 | | | | | | 3,614,992 | | |
|
Revisions of previous estimates
|
| | | | (14,586) | | | | | | 37,575 | | | | | | (8,323) | | |
|
Production
|
| | | | (409,508) | | | | | | (250,304) | | | | | | (451,225) | | |
|
Balance at December 31, 2022
|
| | | | 2,824,491 | | | | | | 1,985,722 | | | | | | 3,155,444 | | |
|
Revisions of previous estimates
|
| | | | (158,724) | | | | | | (410,161) | | | | | | (227,084) | | |
|
Production
|
| | | | (386,949) | | | | | | (219,530) | | | | | | (423,537) | | |
|
Balance at December 31, 2023
|
| | | | 2,278,818 | | | | | | 1,356,031 | | | | | | 2,504,823 | | |
|
Revisions of previous estimates
|
| | | | (45,938) | | | | | | 41,186 | | | | | | (39,074) | | |
|
Production
|
| | | | (355,664) | | | | | | (208,689) | | | | | | (390,446) | | |
|
Balance at December 31, 2024
|
| | | | 1,877,216 | | | | | | 1,188,528 | | | | | | 2,075,303 | | |
| Proved developed reserves | | | | | | | | | | | | | | | | | | | |
|
December 31, 2021
|
| | | | 2,421,006 | | | | | | 1,427,988 | | | | | | 2,659,004 | | |
|
December 31, 2022
|
| | | | 2,226,219 | | | | | | 1,711,724 | | | | | | 2,511,506 | | |
|
December 31, 2023
|
| | | | 1,859,926 | | | | | | 1,153,974 | | | | | | 2,052,255 | | |
|
December 31, 2024
|
| | | | 1,524,133 | | | | | | 1,020,585 | | | | | | 1,694,231 | | |
| Proved undeveloped reserves | | | | | | | | | | | | | | | | | | | |
|
December 31, 2021
|
| | | | 827,579 | | | | | | 770,463 | | | | | | 955,988 | | |
|
Proved undeveloped reserves converted to proved developed by drilling
|
| | | | (32,610) | | | | | | (15,504) | | | | | | (35,194) | | |
|
Additional proved undeveloped reserves added
|
| | | | 22,971 | | | | | | 0 | | | | | | 22,971 | | |
|
Revisions of previous estimates
|
| | | | (219,668) | | | | | | (480,961) | | | | | | (299,827) | | |
|
December 31, 2022
|
| | | | 598,272 | | | | | | 273,998 | | | | | | 643,938 | | |
|
Additional proved undeveloped reserves added
|
| | | | 110,695 | | | | | | 47,904 | | | | | | 118,679 | | |
|
Revisions of previous estimates
|
| | | | (290,075) | | | | | | (119,845) | | | | | | (310,047) | | |
|
December 31, 2023
|
| | | | 418,892 | | | | | | 202,057 | | | | | | 452,570 | | |
|
Additional proved undeveloped reserves added
|
| | | | 157,199 | | | | | | 83,252 | | | | | | 171,074 | | |
|
Revisions of previous estimates
|
| | | | (223,008) | | | | | | (117,366) | | | | | | (242,570) | | |
|
December 31, 2024
|
| | | | 353,083 | | | | | | 167,943 | | | | | | 381,074 | | |
The Trust recognized net decreases in reserves for its share of VOC Brazos’ total during 2022 associated with the production of properties of 451,225 Boe. This decrease was also compounded by a negative revision due to increases in development costs and a net negative decrease of reserves of 1,496 Boe due to the removal of proved undeveloped locations in a previously adopted development plan.
The Trust recognized net decreases in reserves for its share of VOC Brazos’ total during 2023 associated with the production of properties of 423,537 Boe. This decrease was also compounded by a negative revision due to increases in development costs and a net negative decrease of reserves of 93,677 Boe due to the removal of proved undeveloped locations in a previously adopted development plan.
The Trust recognized net decreases in reserves for its share of VOC Brazos’ total during 2024 associated with the production of properties of 390,446 Boe. This decrease was also compounded by a negative revision due to increases in development costs and a net negative decrease of reserves of 77,751 Boe due to the removal of proved undeveloped locations in a previously adopted development plan.
64
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
FROM PROVED OIL AND GAS RESERVES
Estimates of future net cash flows from proved reserves of crude oil and natural gas are computed using the average, first-day-of-the-month price during the 12-month period for 2022, 2023 and 2024.
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
|
Future cash inflows
|
| | | $ | 269,711,309 | | | | | $ | 175,123,174 | | | | | $ | 139,048,563 | | |
| Future costs | | | | | | | | | | | | | | | | | | | |
|
Production
|
| | | | (95,488,937) | | | | | | (76,651,487) | | | | | | (64,104,176) | | |
|
Development
|
| | | | (33,370,634) | | | | | | (29,432,877) | | | | | | (28,967,821) | | |
|
Future net cash flows
|
| | | | 140,851,738 | | | | | | 69,038,810 | | | | | | 45,976,566 | | |
|
Less 10% discount factor
|
| | | | (42,470,509) | | | | | | (18,870,992) | | | | | | (11,196,048) | | |
|
Standardized measure of discounted future net cash
flows |
| | | $ | 98,381,229 | | | | | $ | 50,167,818 | | | | | $ | 34,780,518 | | |
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
FLOWS FROM PROVED OIL AND GAS RESERVES
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
|
Standardized measure at beginning of year
|
| | | $ | 67,618,206 | | | | | $ | 98,381,229 | | | | | $ | 50,167,818 | | |
|
Net proceeds to the Trust
|
| | | | (23,594,049) | | | | | | (16,459,918) | | | | | | (13,622,718) | | |
|
Net changes in price and production costs
|
| | | | 53,018,239 | | | | | | (44,045,655) | | | | | | (5,726,482) | | |
|
Changes in estimated future development costs
|
| | | | (8,340,638) | | | | | | 5,061,640 | | | | | | 43,263 | | |
|
Development costs incurred during the year
|
| | | | 1,264,823 | | | | | | 57,549 | | | | | | — | | |
|
Revisions of quantity estimates
|
| | | | (602,964) | | | | | | (4,152,012) | | | | | | (1,572,839) | | |
|
Accretion of discount
|
| | | | 6,761,821 | | | | | | 9,838,123 | | | | | | 5,016,782 | | |
|
Changes in production rates, timing and other
|
| | | | 2,255,791 | | | | | | 1,486,862 | | | | | | 474,694 | | |
|
Standardized measure at end of year
|
| | | $ | 98,381,229 | | | | | $ | 50,167,818 | | | | | $ | 34,780,518 | | |
The average, first-day-of-the-month price during the 12-month period for 2022, 2023 and 2024 used in determining future net revenues related to the standardized measure calculation are as follows:
| | | |
2022
|
| |
2023
|
| |
2024
|
| |||||||||
|
Oil (per Bbl)
|
| | | $ | 90.85 | | | | | $ | 75.24 | | | | | $ | 72.58 | | |
|
Gas (per Mcf)
|
| | | $ | 5.59 | | | | | $ | 1.76 | | | | | $ | 1.17 | | |
65
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of disclosure controls and procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information to be disclosed by the Trust in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and regulations promulgated by the SEC. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by VOC Brazos to The Bank of New York Mellon Trust Company, N.A., as trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, the Trustee carried out an evaluation of the Trust’s disclosure controls and procedures. Elaina Rodgers, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.
Due to the contractual arrangements of (i) the Trust Agreement and (ii) the Conveyance, the Trustee relies on (A) information provided by VOC Brazos, including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers. See “Item 1A. Risk Factors — Risks Related to the Structure of the Trust — Neither the Trust nor the Trust’s unitholders have the ability to influence VOC Brazos or control the operations or development of the Underlying Properties” in this Form 10-K, and “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of certain risks relating to these arrangements and reliance on information when reported by VOC Brazos to the Trustee and recorded in the Trust’s results of operations.
Changes in Internal Control Over Financial Reporting. During the fourth quarter ended December 31, 2024, there has been no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of VOC Brazos.
Trustee’s Report on Internal Control Over Financial Reporting. The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), by the Trust. The Trust’s internal control over financial reporting is a process designed under the supervision of the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Trust’s financial statements for external purposes in accordance with the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts, which is a comprehensive basis of accounting other than generally accepted accounting principles.
As of December 31, 2024, the Trustee assessed the effectiveness of the Trust’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Trustee determined that the Trust maintained effective internal control over financial reporting as of December 31, 2024, based on those criteria.
Item 9B. Other Information.
Rule 10b5-1 Trading Plans. During the three months ended December 31, 2024, no officer or employee of the Trustee who performs policy-making functions for the Trust adopted, modified, or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, as such terms are defined in Item 408(a) of Regulation S-K, with respect to the Trust Units.
Item 9C. Disclosures Regarding Foreign Jurisdictions that Prevent Inspections.
Not applicable.
66
PART III
Item 10.
Directors, Executive Officers and Corporate Governance.
The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust Units at a meeting at which a quorum is present.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons. However, employees of the Trustee must comply with the code of ethics of The Bank of New York Mellon Trust Company, N.A.
Insider Trading Policy
Because the Trust has no directors, officers or employees, and because the Trustee does not have the authority under the terms of the Trust Agreement to engage in transactions in the Trust Units on behalf of the Trust, the Trust has not adopted an insider trading policy applicable to such persons or to the Trust itself. It is the policy of the Trustee that any transaction in Trust Units by any officer or employee of the Trustee who performs policy-making functions for the Trust must comply with the insider trading policies of The Bank of New York Mellon Corporation, the parent corporation of The Bank of New York Mellon Trust Company, N.A.
Item 11.
Executive Compensation.
During the years ended December 31, 2022, 2023 and 2024, the Trustee received compensation from the Trust in the amount of $150,000 for each year. The Trust does not have any executive officers. Because the Trust does not have a board of directors, it does not have a compensation committee.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
(a)
Security Ownership of Certain Beneficial Owners.
The following table sets forth certain information regarding the beneficial ownership of the Trust Units as of March 20, 2025 by each person who, to the Trust’s knowledge, beneficially owns more than 5% of the outstanding Trust Units.
|
Beneficial Owner
|
| |
Trust Units
Beneficially Owned |
| |
Percent of
Class(1) |
| ||||||
|
VOC Partners, LLC(2)
|
| | | | 4,252,250 | | | | | | 25.0% | | |
|
Robert J. Raymond(3)
|
| | | | 1,856,962 | | | | | | 10.9% | | |
(1)
Based on 17,000,000 Trust Units outstanding as of March 20, 2025.
(2)
The information is based on a Schedule 13D filing with the SEC on August 18, 2011. The address of the beneficial owner is 1700 Waterfront Parkway, Building 500, Wichita, KS 67206.
(3)
The information is based on a Schedule 13G dated February 8, 2019 filed jointly by Robert J. Raymond (“Raymond”), RR Advisors, LLC (“Advisors”), RCH Black Fund GP, L.P. (“RCH GP”), and RCH Black Fund, L.P. (“RCH LP” and, together with Raymond, Advisors and RCH GP, the “Reporting
67
Persons”). The principal business address of the Reporting Persons is 3953 Maple Avenue, Suite 180, Dallas, Texas 75219. According to the filing, Raymond has sole voting power and dispositive power with respect to 202,056 Trust Units; Raymond and Advisors each have shared voting and dispositive power with respect to 1,654,906 Trust Units; and RCH GP and RCH LP each have shared voting and dispositive power with respect to 1,619,837 Trust Units. According to the filing, each Reporting Person expressly disclaims (a) the existence of any group and (b) beneficial ownership with respect to any Trust Units other than the Trust Units owned of record by such Reporting Person.
(b)
Security Ownership of Management.
Not applicable.
(c)
Changes in Control.
The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
Under the terms of the Conveyance governing the net profits interest, VOC Brazos is obligated to make certain payments to the Trust on a quarterly basis. Please see “Item 1. Business — Computation of Net Proceeds” for more information about these agreements.
Administrative Services Agreement
The Trust has entered into an administrative services agreement with VOC Brazos that obligates the Trust, throughout the term of the Trust, to pay to VOC Brazos each quarter an administrative services fee for accounting, bookkeeping and informational services performed by VOC Brazos on behalf of the Trust relating to the net profits interest. The annual fee is payable in equal quarterly installments and increases by 4% each year. For 2022, 2023 and 2024, $114,330, $118,902 and $123,659, respectively, was paid to VOC Brazos as administrative fees. The administrative services agreement will terminate upon the termination of the net profits interest unless earlier terminated by mutual agreement of the Trustee and VOC Brazos.
Registration Rights
The Trust entered into a registration rights agreement with VOC Brazos in connection with VOC Brazos’ conveyance to the Trust of the net profits interest. In the registration rights agreement, the Trust agreed, for the benefit of VOC Brazos and any transferee of its Trust Units (each, a “holder”), to register the Trust Units it holds. Specifically, the Trust agreed:
•
subject to certain restrictions, to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable Trust Units;
•
to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and
•
to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the Trust Units covered by the registration statement have been sold pursuant to such registration statement or until all registrable Trust Units:
•
have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;”
•
have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the Trust Units; or
68
•
become eligible for resale pursuant to Rule 144(k) (or any similar rule then in effect under the Securities Act).
The holders will have the right to require the Trust to file up to three registration statements and will have piggyback registration rights in certain circumstances.
In connection with the preparation and filing of any registration statement, VOC Brazos will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trustee, and any underwriting discounts and commissions, which will be borne by the seller of the Trust Units.
Item 14.
Principal Accountant Fees and Services.
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.
The following table presents fees for professional audit services rendered by Grant Thornton LLP for the audit of the Trust’s financial statements for 2023 and 2024 and fees billed for other services rendered by Grant Thornton LLP.
| | | |
2023
|
| |
2024
|
| ||||||
|
Audit fees
|
| | | $ | 266,646 | | | | | $ | 275,348 | | |
|
Audit related fees
|
| | | | — | | | | | | — | | |
|
Tax fees
|
| | | | — | | | | | | — | | |
|
All other fees
|
| | | | — | | | | | | — | | |
|
Total fees
|
| | | $ | 266,646 | | | | | $ | 275,348 | | |
69
PART IV
Item 15. Exhibit and Financial Statement Schedules
(a)(1) Financial Statements
The following financial statements are set forth under Part II, Item 8 of this Form 10-K on the pages indicated:
| | | |
Page in this
Form 10-K |
| |||
| VOC Energy Trust | | | | | | | |
| | | | | 54 | | | |
| | | | | 55 | | | |
| | | | | 55 | | | |
| | | | | 55 | | | |
| | | | | 56 | | | |
(a)(2) Schedules
Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(a)(3) Exhibits
70
| |
Exhibit
Number |
| | | | |
Description
|
|
| |
32.1*
|
| | — | | | | |
| |
97.1
|
| | — | | | | |
| |
99.1*
|
| | — | | | |
*
Filed or furnished herewith.
Item 16. Form 10-K Summary
None.
71
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
VOC ENERGY TRUST
By:
THE BANK OF NEW YORK MELLON
TRUST COMPANY, N.A., AS TRUSTEE
TRUST COMPANY, N.A., AS TRUSTEE
By
/s/ ELAINA C. RODGERS
Elaina C. Rodgers
Vice President
Vice President
March 20, 2025
The Registrant, VOC Energy Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust Agreement under which it serves.
72
Exhibit 31.1
CERTIFICATION
I, Elaina C. Rodgers, certify that:
| 1. | I have reviewed this annual report on Form 10-K of VOC Energy Trust, for which The Bank of New York Mellon Trust Company, N.A. acts as Trustee; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report; |
| 4. | I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and I have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared; and |
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and |
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors: |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report information; and |
| (b) | Any fraud, whether or not material, that involves any persons who have a significant role in the registrant’s internal control over financial reporting. |
In giving the foregoing certifications in paragraphs 4 and 5, I have relied to the extent I consider reasonable on information provided to me by VOC Brazos Energy Partners, L.P.
| Date: March 20, 2025 | /s/ ELAINA C. RODGERS | |
| Elaina C. Rodgers | ||
| Vice President | ||
| The Bank of New York Mellon Trust Company, N.A., Trustee for VOC Energy Trust |
Exhibit 32.1
March 20, 2025
Via EDGAR
Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549
| Re: | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
Ladies and Gentlemen:
In connection with the Annual Report of VOC Energy Trust (the “Trust”) on Form 10-K for the year ended December 31, 2024 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:
| (1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
| (2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust. |
The above certification is furnished solely pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. 1350) and is not being filed as part of the Report or as a separate disclosure document.
| THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., | ||
| Trustee for VOC Energy Trust | ||
| By: | /s/ ELAINA C. RODGERS | |
| Elaina C. Rodgers | ||
| Vice President | ||
Exhibit 99.1
Cawley, Gillespie & Associates, Inc.
petroleum consultants
| 13640 BRIARWICK DRIVE, SUITE 100 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 1900 | ||
| AUSTIN, TEXAS 78729-1106 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||
| 512-249-7000 | 817- 336-2461 | 713-651-9944 | ||
| www.cgaus.com |
February 19, 2025
Bank of New York Mellon Trust Company, N.A.
as Trustee of VOC Energy Trust
Attn: Elaina C. Rodgers
601 Travis Street, Floor 16
Houston, Texas 77002
| Re: | Evaluation Summary | |
| VOCET Energy Trust Net Profits Interests | ||
| Total Proved Reserves | ||
| As of December 31, 2024 | ||
| Pursuant to the Guidelines of the | ||
| Securities and Exchange Commission for Reporting Corporate Reserves and | ||
| Future Net Revenue |
Dear Trustee:
As requested, this report was prepared on February 19, 2025 for VOC Energy Trust (“Trust”) for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the Trust term net profits interests. We evaluated 100% of the reserves associated with the Trust, which are made up of various oil and gas properties in Kansas and Texas owned by VOC Kansas Energy Partners, LLC and VOC Brazos Energy Partners, LP (“Companies”). This evaluation, effective December 31, 2024, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the proved reserves is presented below.
| Proved Developed Producing | Proved Developed Non-Producing | Proved Undeveloped | Total Proved | |||||||||||||||
| Net Reserves | ||||||||||||||||||
| Oil | - MBBL | 1,892.9 | 12.2 | 441.4 | 2,346.5 | |||||||||||||
| Gas | - MMCF | 935.2 | 0.0 | 111.0 | 1,046.2 | |||||||||||||
| NGL | - MBBL | 87.3 | 0.0 | 25.4 | 112.7 | |||||||||||||
| Revenue | ||||||||||||||||||
| Oil | - M$ | 136,731.3 | 867.6 | 32,714.7 | 170,313.6 | |||||||||||||
| Gas | - M$ | 1,151.4 | 0.0 | 69.9 | 1,221.3 | |||||||||||||
| NGL | - M$ | 1,777.9 | 0.0 | 497.9 | 2,275.8 | |||||||||||||
| Severance Taxes | - M$ | 3,303.9 | 39.3 | 1,545.3 | 4,888.6 | |||||||||||||
| Ad Valorem Taxes | - M$ | 3,602.7 | 52.1 | 1,181.5 | 4,836.2 | |||||||||||||
| Future Production Costs | - M$ | 68,492.9 | 39.9 | 1,872.6 | 70,405.4 | |||||||||||||
| Future Development Costs | - M$ | 330.0 | 78.0 | 35,801.8 | 36,209.8 | |||||||||||||
| 80% NPI Net Cash Flow (BFIT) | - M$ | 51,144.9 | 526.6 | (5,694.9 | ) | 45,976.6 | ||||||||||||
| 80% NPI Disc. @ 10% (Present Worth) | - M$ | 40,563.3 | 419.2 | (6,202.0 | ) | 34,780.5 | ||||||||||||
Future revenue was calculated prior to deducting state production taxes and ad valorem taxes; however, future net cash flow was calculated after deducting these taxes, future development costs, and operating expenses, but before federal income taxes. For this report, 80% NPI net cash flow is shown to represent 80% of the future net cash flow, per the guidelines of the Trust, as described below. 80% NPI net cash flow has been discounted at an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine net present worth. Present worth indicates the time value of money and should not be construed as being fair market value.
The oil reserves include oil and condensate. Oil and natural gas liquid (“NGL”) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (“MCF”) at contract temperature and pressure base. Our estimates include proved reserves only. Neither probable or possible reserves, nor interest in acreage beyond the location of proven reserves have been estimated.
Proved Developed reserves are the summation of the Proved Developed Producing and Proved Developed Non-Producing reserve estimates. Proved Developed reserves were estimated at 1,905.1 Mbbl oil, 935.2 MMcf gas and 87.3 Mbbl NGLs (or 2,148.3 MBOE). Of the Proved Developed reserves, 2,136.1 MBOE were attributed to producing zones in existing wells and 12.2 MBOE were attributed to zones in existing wells not producing. Barrels of oil equivalent (“BOE”) is expressed as oil and NGL volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels.
For a detailed description of the report layout, please refer to the Table of Contents following this letter. The data presented in each Table I is explained in page one (1) of the Appendix.
Net Profits Calculations
The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of hydrocarbon production within the Companies’ underlying properties. The net profits interests will terminate on the later to occur (1) December 31, 2030, or (2) the time when 10.6 million barrels of oil equivalent (“MMBOE”) have been produced from the underlying properties and sold, and the trust will soon thereafter wind up its affairs and terminate. For this report, it was estimated that the Trust would terminate December 31, 2030 based on the calculation that 10.6 MMBOE would be produced from the underlying properties and sold (which amount is the equivalent of 8.5 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) by October 31, 2027. The cash flow tables in this report reflect the termination date of December 31, 2030.
Hydrocarbon Pricing
The base SEC oil and gas prices calculated for year end 2024 were $75.48/bbl and $2.130/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot market prices during 2024 and the base gas price is based upon Henry Hub spot market prices during 2024.
Oil price differentials were forecast at -$4.50 per BBL for all Kansas properties. For Texas properties, oil price differentials were applied at -$1.00 per BBL for the Kurten (Woodbine) Field and Madisonville West Field wells, -$2.50 per BBL for the Sand Flat Field wells, and -$4.50 per BBL for the Hitts Lake North Field wells. Gas and NGL price differentials varied by property as provided. These base price differentials may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the proved properties was estimated to be $72.58 per BBL for oil, $1.167 per MCF for gas and $20.20 per BBL for NGLs. All economic factors were held constant in accordance with SEC guidelines.
Economic Parameters
Ownership was accepted as furnished and has not been independently confirmed. Capital expenses (Future Development Costs), lease operating expenses (Future Production Costs) and ad valorem tax values were forecast as provided by your office and were thoroughly reviewed by us for accuracy and completeness. These values appear to be reasonable and appropriate for this evaluation. Lease operating expenses (column 22) and overhead (COPAS, column 26) shown in the tables provided herein were determined at the well level using averages determined from historical lease operating statements. Overhead costs include fixed rate administrative overhead for operated properties. Workover Expenses (column 25) were applied to cover the annual costs for recurring well work and wellbore abandonment. The variable costs consist of fees for water disposal, gas compression, processing and transportation, and other variable expenses and can be found as Other Deductions (column 27). All economic parameters were held constant (not escalated) throughout the life of these properties.
Future development costs for PDNP and PUD properties include recompletion, drilling, and completion costs for both vertical and horizontal wells as provided by the Companies. For certain producing and undeveloped horizontal wells, a future development cost for conversion to rod pump is included. All future development costs were held constant (not escalated) throughout the life of these properties.
For Kansas properties, severance taxes were applied at 4.33 percent of revenue until exemption levels were forecasted to be reached. The severance tax rate was dropped to zero (0) when a rate of six (6) BBL/day per well was reached, or when gross gas production value reached $87/day per gas well. Severance taxes were forecasted at 4.6 percent of oil revenue and 7.5 percent of gas and NGL revenue for properties in Texas. Ad valorem taxes for Kansas properties were applied at 6.0 percent of revenue, but dropped to 2.0 percent as properties qualified for the tax exemption. Kansas oil and gas conservation taxes were included within the severance tax estimates shown herein. Ad valorem taxes were applied at 3.29 percent of revenue (after severance taxes) for Texas properties.
Reserve Estimation Methods
The methods employed in estimating reserves are described in page two (2) of the Appendix. We evaluated 324 PDP properties for this report, most with monthly production data typically updated through 10/31/2024, as provided by the Companies. Certain PDP properties consist of multiple-well leases. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting PDNP and PUD reserves for the Companies’ properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages three (3) and four (4) of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
This evaluation includes 11 PUD locations in various fields throughout Kansas and Texas. It should be noted that certain PUD locations do not reach commerciality as of the Trust termination date, but are still included in this report as they are projected to reach positive cumulative discounted cash flow at a later date. Each of these drilling locations proposed as part of the Companies’ development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Companies have indicated they have intent to complete this development plan within the next five (5) years. Furthermore, the Companies have demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.
General Discussion
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have been included as part of the workover expenses described previously.
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties, VOC Energy Trust, or the Companies and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
| Yours very truly, | |
 | |
| W. Todd Brooker, P.E. | |
| President | |
| CAWLEY, GILLESPIE & ASSOCIATES, INC. | |
| Texas Registered Engineering Firm (F-693) |
APPENDIX
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
“(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”