Item 5. Market for Registrant’s Common Equity
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
The Trust Units trade on the
New York Stock Exchange under the symbol “PVL.” At December 31, 2025, there were 33,000,000 Trust Units outstanding.
On March 20, 2026, there were six unitholders of record. This number does not include owners for whom Trust Units may be held in
“street” name.
Distributions
Each month, 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 month, over the Trust’s
incurred expenses for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.
The holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) are entitled to monthly
distributions payable on or before the tenth business day after the record date (or the next succeeding business day). For further information
on distributions to Trust unitholders, see Note 5 of the Notes to Financial Statements in Part II, Item 8 of this Form 10-K.
Recent Sales of Unregistered Securities
There were no equity securities sold by the Trust
during the year ended December 31, 2025.
Purchases of Equity Securities
There were no purchases of Trust Units by the Trust
or any affiliated purchaser during the fourth quarter of 2025.
Item 6. [Reserved]
47
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.
This discussion contains forward-looking statements.
Please refer to “Forward-Looking Statements” for an explanation of these types of statements.
Overview
Permianville Royalty Trust, previously known as
Enduro Royalty Trust, a statutory trust created in May 2011, completed its initial public offering in November 2011. The Trust’s
only asset and source of income is the Net Profits Interest, which entitles the Trust to receive 80% of the net profits from oil and natural
gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has
any management control over or responsibility for costs relating to the operation of the Underlying Properties. Additionally, third parties
operate substantially all of the wells on the Underlying Properties and, therefore, the Sponsor is not in a position to control the timing
of development efforts, associated costs, or the rate of production of the reserves.
The Trust is required to make monthly cash distributions
of substantially all of its monthly cash receipts, after deducting the Trust’s administrative expenses, to holders of record (generally
the last business day of each calendar month) on or before the tenth business day after the record date. The Net Profits Interest is entitled
to a share of the profits from and after July 1, 2011 attributable to production occurring on or after June 1, 2011. The amount
of Trust revenues and cash distributions to Trust unitholders depends on, among other things:
· oil and natural gas sales prices;
· volumes of oil and natural gas produced and sold attributable to the Underlying
Properties;
· production and development costs;
· price differentials;
· potential reductions or suspensions of production;
· the amount and timing of Trust administrative expenses; and
· the establishment, increase, or decrease of reserves for approved development
expenses or future liabilities of the Trust.
Generally, the Sponsor receives cash payment for
oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced.
2025 Recap and 2026 Outlook
COERT believes that the outlook for oil and gas
industry remains mixed, particularly in light of the recent commencement of hostilities in the Persian Gulf and the resulting increase
in oil prices. COERT believes that natural gas-weighted capital expenditures will remain elevated compared to prior years as the continued
development of U.S. liquified natural gas (“LNG”) export capacity provides a tailwind for operators of the Underlying Properties
and other U.S. energy assets. Specifically, the Haynesville shale region, where the Underlying Properties have seen increased activity
in recent years, is nearest to the LNG export terminals on the U.S. Gulf Coast. COERT expects Haynesville shale activity to remain elevated.
COERT also expects oil-directed capital expenditures to decline from prior years but to be even more volatile given the rise in oil prices
in the first quarter of 2026.
Meanwhile, the continuing trend of consolidation
within the oil and gas industry may alter the level and targeted area of capital expenditures. In recent years, several of the largest
operators on the Underlying Properties have sold assets to other large operators or have been acquired by larger super majors, which can
affect the pace of capital expenditures. COERT indicates that the operators who have taken over operations of several of the largest Underlying
Properties generally are larger, better-capitalized entities with higher credit ratings.
48
The average NYMEX oil and natural gas prices
experienced continued volatility in 2025, with average oil prices continuing their trend of average annual declines. The average
NYMEX oil price of $64.73 per Bbl in calendar year 2025 was down from $75.79 per Bbl in calendar year 2024, a decline of 15%. The
price range varied from high of $80.04 per Bbl in January 2025 to a low of $55.27 per Bbl in December 2025. Similar to the
prior year, the second half of 2025 saw more muted prices, which could potentially weigh on the outlook for capital activity by
operators in 2026. Oil prices generally declined in the second half of 2025, as the Trump Administration’s global trade and
economic policies led to greater market uncertainty. Natural gas prices, while volatile, nevertheless experienced a meaningful
improvement year-over-year, reflecting continued demand growth from U.S. LNG exports and increasing power usage for digital
infrastructure and other sectors. The average NYMEX natural gas price increased from $2.41 per MMBtu in calendar year 2024 to $3.62
per MMBtu in calendar year 2025, an increase of 50%. Despite this increase, the range of natural gas prices during the year remained
wide, with a low of $2.70 per MMBtu in August 2025 and a high of $5.29 per MMBtu in December 2025. The increase in natural
gas prices has outpaced overall capital expenditures in the industry, however, as the Baker Hughes average weekly U.S. natural gas
rig count increased from 105 in calendar year 2024 to 113 in calendar year 2025, an increase of less than 8%. COERT believes that
the outperformance of the natural gas commodity to the natural gas rig count is representative of the shift in industry sentiment to
prioritize free cash flow over production growth compared to prior cycles. This industry behavior, coupled with the mixed outlook
for oil prices compared to natural gas prices, was also reflected in the Underlying Properties during 2025. Capital expenditures on
the Underlying Properties declined 35% from the record spending in calendar year 2024. Although revenue from the Underlying
Properties in 2025 declined 24% due primarily to the decline in oil prices, the Income from Net Profits Interest to the Trust only
declined 8% year-over-year, as the reduction in capital expenditures helped to offset the decline in revenues.
Given increasing geopolitical uncertainty and its
impact on forward commodity prices, as well as continued turnover in the ownership of some of the operators of the Underlying Properties,
COERT believes that planned capital expenditures during 2026 remain somewhat uncertain. Based on currently available information, COERT
anticipates 2026 capital expenditures on the Underlying Properties to range from $9.0 million to $15.0 million, or $7.2 million to
$12.0 million net to the Trust’s 80% Net Profits Interest. This would represent a modest decrease at the midpoint from the
2025 levels. COERT indicates that the majority of the expected capital expenditures remain directed in the Haynesville area of the Underlying
Properties given higher relative natural gas prices and accelerated drilling activity by a certain super major oil company that operates
a portion of those properties. COERT indicates that it continues to have access to adequate capital and liquidity to fund such capital
expenditures as they come due.
COERT believes there could be further opportunity
in 2026 for prospective divestitures of some or all of the Underlying Properties, as operators of some of the Underlying Properties look
to consolidate non-operated interests and acreage given recent merger and acquisition activity in the industry.
Capex Drilling Activity Update
Presented
below is a summary of the current status of certain notable capital projects recently undertaken on the Underlying Properties pursuant
to the capital expenditure program described above.
The following table is not intended to be a comprehensive
list reflecting all capital expenditures to date. In addition, there can often be a several-month delay from the time of capital expenditures
to the time of production and cash flows attributable to the Underlying Properties, especially given the non-operated nature of the Underlying
Properties.
Operator
Region
Number
of Wells
Underlying
Properties
W/I
Project
Capex
Cumulative
Total
Status
Large Cap E&P 1
Delaware
3
5.0 %
D&C New Drills
–
3 Pre Drills
Large Cap E&P 2
Midland
6
0.8 %
D&C New Drills
$ 1,000
6 Drilling in Process
Large Cap E&P 3
Delaware
19
1.0 %
D&C New Drills
–
19 Pre Drills
Large Super Major 1
Haynesville
3
8.9 %
D&C New Drills
$ 436,000
3 Drilling in Process
PE-Backed Private 1
Delaware
2
4.6 %
D&C New Drills
$ 203,000
2 Producing awaiting first revenue
PE-Backed Private 2
Delaware
7
1.2 %
D&C New Drills
$ 127,000
4 Drilling in Process
49
The Sponsor expects that a majority of the projects
above that are still in process or awaiting first revenues will be completed and will begin producing during 2026.
Results of Operations
The following table displays oil and natural gas
sales volumes and average prices from the Underlying Properties, representing the amounts included in the net profits calculation for
the distributions paid during the years ended December 31, 2025 and 2024.
Underlying Properties Sales Volumes
Average Price
Month of Distribution
Oil
(Bbls)
Natural Gas
(Mcf)
Oil
(per Bbl)
Natural Gas
(per Mcf)
2025:
September
326,589
4,167,300
$ 70.50
$ 2.37
October
34,446
702,645
$ 65.41
$ 2.81
November
39,977
825,273
$ 62.17
$ 2.91
December
35,657
777,070
$ 64.30
$ 2.96
Total—2025 (1)
436,669
6,472,288
$ 63.88
$ 2.76
2024:
February
115,343
711,124
$ 83.99
$ 2.38
August
346,439
2,610,841
$ 77.10
$ 2.18
September
41,469
394,278
$ 79.53
$ 1.39
October
38,579
374,304
$ 77.69
$ 1.69
November
52,287
1,105,204
$ 79.43
$ 2.44
December
40,886
384,143
$ 75.88
$ 1.78
Total—2024 (2)
635,003
5,579,894
$ 78.84
$ 3.79
(1) The table for the year ended December 31, 2025 does not separately display sales volumes for January through August because
the Trust did not pay a distribution with respect to those months, as the net profits interest calculation for each such period was negative.
(2) The table for the year ended December 31, 2024 does not separately display sales volumes for January, March, July and August because
the Trust did not pay a distribution with respect to those months, as the net profits interest calculation for each such period was negative.
50
Computation of Income from Net Profits Interest Received by the
Trust
In connection with the closing of the initial public
offering in November 2011, Enduro contributed the Net Profits Interest to the Trust in exchange for 33,000,000 newly issued Trust
Units. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale and production of oil and natural gas
attributable to the Underlying Properties that are produced during the term of the Conveyance, which commenced on July 1, 2011. The
Trust’s Income from Net Profits Interest consists of monthly net profits attributable to the Net Profits Interest. Net profits income
for the years ended December 31, 2025 and 2024 were determined as shown in the following table:
Year Ended December 31,
2025
2024
Gross profits:
Oil sales
$ 30,117,726
$ 50,291,248
Natural gas sales
16,959,057
11,341,855
Total
47,076,783
61,633,103
Costs:
Direct operating expenses:
Lease operating expenses
19,379,000
26,801,000
Compression, gathering and transportation
5,778,000
3,773,000
Production, ad valorem and other taxes
3,005,000
4,140,000
Development expenses
13,149,000
20,345,000
Total
41,311,000
55,059,000
Gross proceeds from sale/lease of undeveloped acreage
389,043
146,400
Net profits attributable to Underlying Properties
$ 6,154,826
$ 6,720,503
Percentage allocable to Net Profits Interest
80 %
80 %
Income from Net Profits Interest
$ 4,923,860
$ 5,376,503
Capex Reserve – Release (Holdback) for anticipated capital expenditures (1)
(250,000 )
(1,000,000 )
Less: COERT Loan Repayment
(751,956 )
(527,076 )
Less: Trust general and administrative expenses and cash withheld for expenses
(687,897 )
(1,027,825 )
Release of Escrow (2)
282,072
—
Distributable income
$ 3,516,070
$ 2,821,500
(1) See discussion under “—Years Ended December 31, 2025 and 2024” below.
(2) Represents the release by the Sponsor of the $250,000 withheld from the net proceeds allocable to the Trust from the Sponsor’s
sale in August 2023 of certain oil and gas properties in the Permian Basin, which amount was intended to cover possible indemnification
obligations arising during the indemnification period following the closing of the sale. Together with interest, this amount equated to
$282,072.
In 2024, net profits from the Underlying Properties
were positive, which eliminated the cumulative Net Profits Interest shortfall of $1.2 million and the cumulative outstanding Sponsor advances
to the Trust of $0.5 million. Because the Net Profits Interest shortfall that existed as of December 31, 2023 was eliminated
in 2024, revenues and the associated direct operating and development expenses for the last month of 2023 are included in the calculation
of distributable income detailed in the table above for the year ended December 31, 2024, and the related sales volumes are detailed
in the table below.
The following table displays oil and natural gas
sales volumes and average prices from the Underlying Properties, representing the amounts included in the net profits calculation for
distributions paid during the years ended December 31, 2025 and 2024:
Year Ended December 31,
2025
2024
Underlying Properties Sales Volumes:
Oil (Bbls)
436,669
635,003
Natural Gas (Mcf)
6,472,288
5,579,894
Combined (Boe)
1,515,384
1,564,985
Average Prices:
Oil – NYMEX (applicable NPI period) ($/Bbl)
$ 67.98
$ 78.04
Differential
$ 0.99
$ 1.16
Oil prices realized ($/Bbl)
$ 68.97
$ 79.20
Natural gas – NYMEX (applicable NPI period) ($/Mcf)
$ 3.07
$ 2.28
Differential
$ (0.45 )
$ (0.25 )
Natural gas prices realized ($/Mcf)
$ 2.62
$ 2.03
51
Years Ended December 31, 2025 and 2024
Net profits attributable to the Underlying Properties
for the year ended December 31, 2025 are calculated from the following:
· oil sales related to oil produced from the Underlying Properties primarily
from September 2024 through August 2025;
· natural gas sales related to natural gas produced from the Underlying Properties
primarily from August 2024 through July 2025; and
· direct operating and development expenses related to expenses and capital
incurred primarily from October 2024 to September 2025.
Net profits attributable to the Underlying Properties
for the year ended December 31, 2025 were $6.2 million compared to $6.7 million for the year ended December 31, 2024. As
discussed in “—Computation of Income from Net Profits Interest Received by the Trust” above, no distribution was made
to Trust unitholders in December 2023 due to the Net Profits Interest shortfall. Accordingly, under the modified cash basis of accounting,
the oil and natural gas sales, direct operating expenses and development expenses attributable to the corresponding production period
were excluded from the calculation of distributable income for the year ended December 31, 2023 and instead were included in the
Trust’s results for the year ended December 31, 2024, once the shortfall was recouped. Therefore, several variances between
the periods are due to the inclusion of thirteen months of results in the year ended December 31, 2024 compared to twelve months
in the year ended December 31, 2025. The $0.5 million decrease in net profits attributable to the Underlying Properties from
the 2024 period to the 2025 period was primarily due to the following items:
· Oil sales decreased $20.2 million, primarily due to a decrease in produced
volumes, which decreased revenues by $15.7 million. This decrease was primarily due to the several new Permian wells that either turned
to sales or completed title work and thereby allowed production attributable to prior periods to be released by the operators of the Underlying
Properties in 2024. Realized oil sales prices decreased by 13% in 2025 compared to 2024, which decreased revenues by $4.5 million.
· Natural gas sales increased $5.6 million compared to 2024, reflecting a $1.8
million increase due to higher produced volumes and a $3.8 million increase due to higher realized prices. The average natural gas price
received increased 29% primarily due to the increase in the average realized natural gas price for the relevant production months.
· Lease operating expenses during the year ended December 31, 2025 were
$19.4 million compared to $26.8 million during the year ended December 31, 2024, a decrease of $7.4 million. Approximately $1.4 million
of the 2024 expenses were attributable to a settlement between COERT and one of the operators of the Underlying Properties relating to
a dispute with respect to certain lease operating expenses from 2018 and 2019 that the operator had mistakenly coded for Enduro instead
of COERT. In May 2023, COERT and the operator agreed to settle the dispute at a discounted amount, resulting in an incremental lease
operating expense adjustment of approximately $0.4 million per month from June 2023 through December 2023, after which no additional
amounts relating to the disputed expenses will be owed to the operator. The remaining decrease in lease operating expenses was primarily
due to several new drilled wells that came online in 2024 compared to 2025.
· Compression, gathering and transportation expenses increased from $3.8 million
in 2024 to $5.8 million in 2025 primarily due to higher sales volumes from three new Haynesville wells that came online in 2025.
· Production, ad valorem and other taxes decreased $1.1 million in 2025 compared
to 2024, primarily due to the decreased produced oil volumes.
52
· Development expenses decreased $7.2 million due to higher drilling and
completion costs related to multiple new wells in the Permian and Haynesville areas during 2024 compared to 2025.
During the year ended December 31, 2024, the
Sponsor withheld from the net profits otherwise payable to the Trust a net aggregate total of $1.0 million for the establishment of a
cash reserve for approved, future development expenses. This reserve was intended to fund an expected increase in development expenses;
however, if those expenses are ultimately delayed or are less than expected, or if the outlook changes, amounts reserved but unspent would
be released as an incremental cash distribution in a future period. This cash reserve for future development was fully released to the
Trust in early 2025. In late 2025, the Sponsor withheld $1.3 million for the establishment of a new cash reserve for future development
expenses.
The Trust withheld $0.7 million and paid $0.8 million
for general and administrative expenses during the year ended December 31, 2025. Expenses paid during the period primarily consisted
of fees for the preparation of 2024 tax information for Trust unitholders, preparation of the Trust’s 2024 reserve report and Annual
Report on Form 10-K, 2024 financial statement audit fees, preparation of the Trust’s 2025 monthly press releases and Quarterly
Reports on Form 10-Q, Trustee fees, and New York Stock Exchange listing fees. For the year ended December 31, 2024, the Trust
withheld $1.6 million and paid $1.0 million for general and administrative expenses.
Liquidity and Capital Resources
The Trust’s principal sources of liquidity
are cash flow generated from the Net Profits Interest and borrowing capacity under the letter of credit described below. 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 other sources (such as interest earned on any amounts reserved by the Trustee) in any given month, over the Trust’s expenses
paid for that month. Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses.
The Trustee may create a cash reserve to pay for
future liabilities of the Trust. In November 2021, the Trustee notified COERT of the Trustee’s intent to build a cash reserve
for the payment of future known, anticipated or contingent expenses or liabilities of the Trust. From February 2022 through March 2023,
the Trustee withheld $37,833, and commencing with the distribution to Trust unitholders paid in April 2023 has been withholding and,
in the future, intends to withhold $50,000, from the funds otherwise available for distribution each month to gradually build a cash reserve
of approximately $2.3 million. The Trustee may increase or decrease the targeted cash reserve amount at any time and may increase
or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the Trust unitholders.
Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or
provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Trust unitholders,
together with interest earned on the funds. As of December 31, 2025, this cash reserve totaled $1,441,386.
If the Trustee determines that the cash on hand
and the cash to be received are, or will be, insufficient to cover the Trust’s liabilities, the Trustee may 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 any person, including the Trustee or the Delaware Trustee or an affiliate thereof, although none of the Trustee,
the Delaware Trustee or any affiliate thereof intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its
assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were to be loaned by the
entity serving as Trustee or Delaware Trustee or an affiliate thereof, would be similar to the terms which such entity would grant to
a similarly situated commercial customer with whom it did not have a fiduciary relationship. In addition, COERT has provided the Trust
with a $1.2 million letter of credit to be used by the Trust if its cash on hand (including available cash reserves) is insufficient to
pay ordinary course administrative expenses. Further, if the Trust requires more than the $1.2 million under the letter of credit to pay
administrative expenses, COERT has agreed to loan funds to the Trust necessary to pay such expenses. Any loan made by COERT to the Trust
would be evidenced by a written promissory note, be on an unsecured basis, and have terms that are no less favorable to COERT than those
that would be obtained in an arm’s length transaction between COERT and an unaffiliated third party. If the Trust borrows funds
or draws on the letter of credit, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are
repaid. Except for the foregoing, the Trust has no source of liquidity or capital resources. The Trustee has no current plans to authorize
the Trust to borrow money other than Sponsor advances to pay the Trust’s monthly operating expenses. At December 31, 2025 and
2024, the Trust held cash reserves of $2,733,791 and $2,193,787, respectively, for future Trust expenses. Since its formation, the Trust
has not borrowed any funds other than Sponsor advances to pay the Trust’s monthly operating expenses and no amounts have been drawn
on the letter of credit.
53
From time to time, if the Trust’s cash on
hand (including available cash reserves, if any) is not sufficient to pay the Trust’s ordinary course administrative expenses that
are due prior to the monthly payment to the Trust of proceeds from the Net Profits Interest, the Sponsor may advance funds to the Trust
to pay such expenses. Such advances are recorded as a liability on the Statements of Assets, Liabilities and Trust Corpus until repaid.
Cash held by the Trustee as a reserve against future
liabilities or for distribution at the next distribution date may be held in a noninterest-bearing account or may be invested in:
· interest-bearing obligations of the United States government;
· money market funds that invest only in United States government securities;
· repurchase agreements secured by interest-bearing obligations of the United
States government; or
· bank certificates of deposit.
The Sponsor has not entered into any hedge contracts
relating to oil and natural gas volumes produced from the Underlying Properties, attributable to the Net Profits Interest for the years
ended December 31, 2025 or 2024, and the terms of the Conveyance prohibit COERT from entering into new hedging arrangements burdening
the Trust.
The Trust pays the Trustee an administrative fee
of $200,000 per year. The Trust pays the Delaware Trustee an annual fee of $2,000. 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. The Trust also is 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.
New Accounting Pronouncements
As the Trust’s financial statements are prepared
on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting
pronouncements have been adopted or issued that would impact the financial statements of the Trust.
Critical Accounting Policies and Estimates
The Trust uses the modified cash basis of accounting
to report Trust receipts of income from 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 of the Underlying Properties plus any payments made or net payments received in connection with
the settlement of certain hedge contracts, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received
by the Trust pursuant to terms of the Conveyance.
Under the terms of the Conveyance, the monthly
Net Profits Interest calculation includes oil and natural gas revenues received. Monthly operating expenses and capital expenditures represent
incurred expenses, and as a result, represent accrued expenses as well as expenses paid during the period.
54
The financial statements of the Trust are prepared
on the following basis:
(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 future expenditures that would not be recorded as contingent liabilities under accounting principles
generally accepted in the United States of America (“GAAP”);
(e) Amortization of the Net Profits Interest
in oil and natural gas properties is calculated on a unit-of-production basis and is charged directly to the Trust corpus. Such amortization
does not affect distributable income of the Trust; and
(f) The Net Profits Interest in oil and natural
gas properties is periodically assessed whenever events or circumstances indicate that the aggregate value may have been impaired below
its total capitalized cost based on the Underlying Properties. If an impairment loss is indicated by the carrying amount of the assets
exceeding the sum of the undiscounted expected future net cash flows of the Net Profits Interest, then an impairment loss is recognized
for the amount by which the carrying amount of the asset exceeds its estimated fair value determined using discounted cash flows.
The financial statements of the Trust differ from
financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves
may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; general and
administrative expenses are recorded when paid instead of when incurred; Any impairment; and amortization of the net profits interest
calculated on a unit-of-production basis is charged directly to trust corpus instead of as an expense. While these statements differ from
financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered
to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts.
This comprehensive basis of accounting other than
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 preparation of financial statements requires
the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from those estimates.
Oil and Natural Gas Reserves. The proved
oil and natural gas reserves for the Underlying Properties are estimated by independent petroleum engineers. Reserve engineering is a
subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers
often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent
to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because
proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly
impacted by changes in product prices. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may
be substantially different from original estimates.
55
The Financial Accounting Standards Board requires
supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved
oil and natural gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during
the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price
for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized
measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows
relating to proved oil and natural gas reserves. Changes in any of these assumptions, including consideration of other factors, could
have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current
fair market value of proved reserves.
Amortization of Net Profits Interest. The
Trust calculates amortization of the Net Profits Interest in oil and natural gas properties on a unit-of-production basis based on the
Underlying Properties’ production and reserves. The reserves upon which the amortization rate is based are quantity estimates which
are subject to numerous uncertainties inherent in the estimation of proved reserves. The volumes considered to be commercially recoverable
fluctuate with changes in prices and operating costs. These estimates are expected to change as additional information becomes available
in the future. Downward revisions in proved reserves may result in an increased rate of amortization. Amortization is recorded on sales
volumes paid by the Trust during the relevant period and is charged directly to the Trust corpus balance. As a result, amortization does
not affect the cash earnings of the Trust.
Impairment of Net Profits Interest. The
Net Profits Interest in oil and natural gas properties is periodically assessed for impairment whenever events or circumstances indicate
that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the
Net Profits Interest. The Trust did not realize any impairment during the years ended December 31, 2025 or 2024. Future downward
revisions in actual production volumes relative to current forecasts, higher than expected operating costs, or lower than anticipated
market pricing could result in recognition of impairment in future periods. Any impairment of the Net Profits Interest will result in
a non-cash charge to Trust corpus and will not affect distributable income. For further information, see “Note 3. Net Profits Interest
in Oil and Gas Properties” of the Notes to Financial Statements in Part II, Item 8 of this Form 10-K.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
As a “smaller reporting company” as
defined in Item 10(f)(1) of Regulation S-K, the Trust is not required to provide information required by this Item.
56