What changed in this filing

/stocks — the workspaceLOADING

Item 5. Market for Registrant’s Common Equity

2021-03-23 compared with 2020-03-16 · 148 added, 238 removed, 263 unchanged (59% of the section changed)

Market for Registrant’s Trust Units, Related Unitholder Matters and Issuer Purchases of Trust Units.

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

The Trust Units trade

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On March 23, 2021, there were four unitholders of record.

This number does not include owners for whom Trust Units

may be held in “street”

This number does not include owners for whom Trust

Units may be held in “street”

Distributions

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Recent Sales of Unregistered Securities

There were no equity securities sold by

the Trust during the year ended December 31, 2019.

There were no equity securities sold by the Trust during the year ended December 31, 2020.

Purchases of Equity Securities

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The average NYMEX oil price and gas price

received for the production months included in 2019 distributions decreased 8% and 9%, respectively, from the prior year as a result

of the corresponding increase in the average NYMEX oil price and average NYMEX gas price for the relevant production months.

In 2019, the exploratory activity on

the Underlying Properties included the successful drilling and completion of three gross wells in the Haynesville area of

Louisiana and two gross wells in the Permian area.

Crude oil prices have declined sharply

in the first quarter of 2020 in response to the economic effects of the coronavirus pandemic and the recent announcement of planned

production increases by Saudi Arabia.

Such factors, if they persist for the near term or longer, could adversely affect the operators

of the Underlying Properties, production from the Underlying Properties and/or distributions to Trust unitholders.

received for the production months included in 2020 distributions decreased 0% and 32%, respectively, from the prior year as a

result of the corresponding decrease in the average NYMEX oil price and average NYMEX gas price for the relevant production months.

In 2020, the development activity on the

Underlying Properties included the successful drilling, with completion activities scheduled for the first half of 2021, of seven

gross wells in the Haynesville area of Louisiana and four gross wells in the Permian area.

Crude oil prices declined sharply in the

first quarter of 2020 in response to the economic effects of the coronavirus pandemic and the dispute over production levels between

Russia and members of OPEC.

Prices have since rebounded for both crude oil and natural gas, but the effects of the global pandemic

have resulted in continuing volatility for commodity prices and an oil and gas industry facing increasing capital constraint.

Such factors, if they persist for the near term or longer, could adversely affect the operators of the Underlying Properties,

production from the Underlying Properties and/or distributions to Trust unitholders.

The operators of the Underlying Properties

continue to evaluate planned capital expenditures during 2021, but based on currently available information, the Sponsor anticipates

2020 capital expenditures to range from $4 million to $6 million attributable

to the properties in which the Trust owns a net profits interest, or $3 million to $5 million net to the Trust’s 80%

net profits interest.

2021 capital expenditures to range from $2.0 million to $4.0 million attributable to the properties in which the Trust owns

a net profits interest, or $1.6 million to $3.2 million net to the Trust’s 80% net profits interest.

New York Stock Exchange Continued Listing

Under the continued listing requirements

of The New York Stock Exchange (“NYSE”), a company will be considered to be out of compliance with the exchange’s

minimum price requirement if the company’s average closing price over a consecutive 30 trading day period (“Average

Closing Price”) is less than $1.00 (the “Minimum Price Requirement”).

Under NYSE rules, a company that

is out of compliance with the Minimum Price Requirement has a cure period of six months to regain compliance if it notifies the

NYSE within 10 business days of receiving a deficiency notice of its intention to cure the deficiency.

A company may regain compliance

if on the last trading day of any calendar month during the cure period the company has a closing share price of at least $1.00

and an average closing share price of at least $1.00 over the 30-trading-day period ending on the last trading day of that month.

If at the expiration of the cure period, both a $1.00 closing share price on the last trading day of the cure period and a $1.00

average closing share price over the 30-trading-day period ending on the last trading day of the cure period are not attained,

the NYSE will commence suspension and delisting procedures.

On September 25, 2020, the Trust received

written notification from the NYSE that the Trust was not in compliance with the Minimum Price Requirement.

On March 11, 2021,

the Trust received written notification from the NYSE that the Trust had regained compliance with the Minimum Price Requirement

as of February 26, 2021.

Results of Operations

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Total—2019 (2)

Total—2017 (4)

(1) The table for the year ended December 31, 2020 does not separately display sales volumes for August through December 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.

In August 2020, direct operating and development expenses and capital expenditures exceeded revenues, which resulted

in negative net profits from the Underlying Properties which was carried forward to be deducted from future net profits generated

by the Underlying Properties.

(2) The table for the year ended December 31, 2019 does not separately display sales volumes for January because the Trust did

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operating and development expenses and capital expenditures exceeded revenues, which resulted in negative net profits from the

Underlying Properties which was carried forward to be deducted from future net profits generated by the Underlying Properties.

In February 2019, net profits from the Underlying Properties were positive, and the aggregate shortfall was deducted from such

net profits when calculating distributions paid in February 2019.

As a result, sales volumes for January 2019 have been included

in the sales volumes for February 2019.

(2) In November 2018, due to reporting delays from operators associated with the transition of ownership from Enduro to the Sponsor,

the average price of natural gas from the Underlying Properties is not comparable to other months presented.

(3) In 2017, there were two months in which direct operating and development expenses exceeded revenues, which resulted in negative

net profits from the Underlying Properties for those periods.

As a result, there were no distributions to Trust unitholders in

November or December 2017, and the aggregate shortfall in net profits of $526,709 was carried forward to be deducted from future

net profits generated by the Underlying Properties.

In January 2018, net profits from the Underlying Properties were positive,

and the aggregate shortfall was deducted from such net profits when calculating distributions

paid in January 2018.

As a result, sales volumes for November and December 2017 have been included in the sales volumes for January

(4) The year ended December 31, 2017 does not include sales volumes for November and December as the Trust did not pay a distribution

in those months, as the net profits interest calculation for such periods was negative.

Underlying Properties that was carried forward to be deducted from future net profits generated by the Underlying Properties.

February 2019, net profits from the Underlying Properties were positive, and the aggregate shortfall was deducted from such net

profits when calculating distributions paid in February 2019.

As a result, sales volumes for January 2019 have been included in

the sales volumes for February 2019.

Computation of Income from Net Profits Interest Received

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from Net Profits Interest.

Net profits income for the years ended December 31, 2019, 2018, and 2017 was determined as shown in

the following table:

Net profits income for the years ended December 31, 2020 and 2019 were determined as shown in the following

Year Ended December 31,

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Gross proceeds from sale/lease of undeveloped acreage

General and administrative expenses paid by Enduro related to divestiture

Net profits attributable to underlying properties

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Net profits allocable to Net Profits Interest

Permianville Cash Reserve

Release of Escrow

Enduro/Sponsor reserve for approved development expenses released (withheld), net

Income from Net Profits Interest

COERT Loan Repayment

Trust general and administrative expenses and cash withheld for expenses

Distributable income generated by properties prior to divestiture

Income from sale of Net Profits Interest

Distributable income

In 2017, there were two months in which

direct operating and development expenses exceeded revenues, thereby causing net profits on the Underlying Properties to be negative.

As a result, there were no distributions to Trust unitholders in November or December 2017 and the aggregate shortfall in net profits

of $526,709 was carried forward to be deducted from future net profits generated by the Underlying Properties in 2018.

profits for these two months in 2017 was negative and there was no distribution paid to unitholders, revenues and the associated

direct operating and development expenses are excluded from the calculation of distributable income detailed in the table above

for the year ended December 31, 2017 as well as the related sales volumes detailed below.

In January 2018, net profits from the Underlying

Properties were positive, and the aggregate shortfall in net profits of $526,709 from November and December 2017 was deducted from

such net profits when calculating distributions paid in January 2018.

Since the 2017 shortfall in net profits was recovered in

2018 and included in 2018 distributions paid to unitholders, revenues and the associated direct operating and development expenses

for November and December 2017 are included in the calculation of distributable income detailed in the table above for the year

ended December 31, 2018 as well as the related sales volumes detailed below.

In 2020, there were

five months in which direct operating and development expenses exceeded revenues, thereby causing net profits attributable to the

Underlying Properties to be negative.

This resulted in an aggregate net profits shortfall of $2.7 million, prior to repayment of

Sponsor advances, as of August 31, 2020.

As a result, there were no distributions to Trust unitholders from August through December

As of December 31, 2020, the remaining aggregate shortfall of $1.7 million will be carried forward to be deducted from future

net profits generated by the Underlying Properties.

As net profits for the five months were negative and therefore no distributions

were paid to unitholders with respect to these five months, the corresponding revenues and associated direct operating and development

expenses are excluded from the calculation of distributable income for 2020 detailed in the table above as well as the related

sales volumes detailed below.

The following table displays oil and natural

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Properties for the year ended December 31, 2020 are calculated from the following:

oil sales related to oil produced from the Underlying Properties primarily from September 2018 through August 2019;

natural gas sales related to natural gas produced from the Underlying Properties primarily from August 2018 through July

direct operating and development expenses related to expenses and capital incurred primarily from October 2018 to September

oil sales related to oil produced from the Underlying Properties primarily from September 2019 through March 2020;

natural gas sales related to natural gas produced from the Underlying Properties primarily from August 2019 through February

direct operating and development expenses related to expenses and capital incurred primarily from October 2019 to April 2020.

Net profits attributable to the Underlying

Properties for the year ended December 31, 2020 were $7.0 million compared to $12.1 million for the year ended December 31,

As a result of direct operating expenses and development expenses exceeding oil and natural gas sales for the last two months

of 2017, the Trust did not pay a distribution to unitholders for the last two months of 2017.

Under the modified cash basis of

accounting, as there was no distribution in November and December 2017, the oil and natural gas sales, direct operating expenses

and development expenses for such periods are not included in the table above or this analysis of net profits attributable to the

Underlying Properties for the year ended December 31, 2017 but are included in the table above or this analysis of net profits

attributable to the Underlying Properties for the year ended December 31, 2018.

Therefore, several variances between years are

due to the inclusion of twelve months of results in the year ended December 31, 2019 compared to fourteen months in the year ended

December 31, 2018.

The $7.0 million decrease in net profits attributable to the Underlying Properties from 2018 to 2019 was primarily

due to the following items:

As a result of direct operating expenses and development expenses exceeding oil and natural gas sales for the last five months

of 2020, the Trust did not pay a distribution to unitholders from August through December 2020.

Accordingly, under the modified

cash basis of accounting, the oil and natural gas sales, direct operating expenses and development expenses for such periods were

not included in the last five months of 2020 and instead will be included in a future period once the net profits shortfall has

been recouped.

Therefore, several variances between the periods are due to the inclusion of only seven months of results in the

year ended December 31, 2020 compared to twelve months included in the year ended December 31, 2019.

The $5.1 million decrease

in net profits attributable to the Underlying Properties from the 2019 period to the 2020 period was primarily due to the

following items:

Oil sales decreased $15.0 million, primarily due to lower sales volumes, which decreased oil sales by $15.0 million.

volumes decreased 14% primarily because the year ended December 31, 2019 included twelve months of oil sales volumes while the

year ended December 31, 2018 included fourteen months of oil sales volumes.

The remaining $3.1 million decrease in oil sales was

due to lower realized prices.

The average oil price received decreased 8% as a result of the corresponding decrease in the average

NYMEX oil price for the relevant production months.

Natural gas sales decreased $4.0 million due to lower

sales volumes, which decreased natural gas sales by $3.0 million.

Natural gas volumes decreased 21% primarily because the year

ended December 31, 2019 included twelve months of natural gas sales volumes while the year ended December 31, 2018 included fourteen

months of natural gas sales volumes The remaining $1.0 million decrease in natural gas sales was due to lower realized prices.

The average natural gas price received decreased 9% as a result of the corresponding decreases in the average NYMEX natural gas

price for the relevant production months.

volumes decreased 43% primarily because the year ended December 31, 2020 included only seven months of oil sales volumes while

the year ended December 31, 2019 included twelve months of oil sales volumes.

Natural gas sales decreased $6.6 million due to lower sales volumes, which decreased natural gas sales by $4.9 million.

gas volumes decreased 49% primarily because the year ended December 31, 2020 included only seven months of natural gas sales volumes

while the year ended December 31, 2019 included twelve months of natural gas sales volumes.

The remaining $1.7 million decrease

in natural gas sales was due to lower realized prices.

The average natural gas price received decreased 32% as a result of the

corresponding decreases in the average NYMEX natural gas price for the relevant production months.

Compression, gathering and transportation (“CGT”) expenses decreased from $2.1 million in 2019 to $1.0 million

The increase in CGT expenses is primarily due to the difference in the number of months included in the respective periods.

The decrease in CGT expenses is primarily due to the difference in the number of months included in the respective periods.

Lease operating expenses decreased $9.5 million in 2020 compared to 2019, primarily attributable to the difference in the number

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Production, ad valorem and other taxes decreased $2.3 million in 2020 compared to 2019 primarily due to the decrease in production

As a percentage of revenues, production, ad valorem and other taxes increased to 8.8% for the year ended December 31,

2019 compared to 8.1% for the year ended December 31, 2018.

Development expenses increased $1.6 million, or 44%, in 2019 compared to 2018 primarily due to the drilling and completion

costs associated with the three new wells in the Permian basin and three new wells in the North Louisiana area.

Development expenses decreased $3.7 million, or 70%, in 2020 compared to 2019 primarily due decrease in drilling activity during

In 2017, pursuant to an agreement between

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primarily consisted of fees for the preparation of 2019 tax information for unitholders, preparation of the Trust’s 2020

reserve report and Annual Report on Form 10-K, 2018 and 2019 financial statement audit fees, preparation of the Trust’s

reserve report and Annual Report on Form 10-K, 2020 financial statement audit fees, preparation of the Trust’s 2020

monthly press releases and Quarterly Reports on Form 10-Q, Trustee fees, and New York Stock Exchange listing fees.

year ended December 31, 2018, the Trust withheld $0.5 million and paid $1.1 million for general and administrative expenses.

Years Ended December 31, 2018 and 2017

Net profits attributable to the Underlying

Properties for the year ended December 31, 2018 are calculated from the following:

oil sales related to oil produced from the Underlying Properties primarily from July 2017 through August 2018;

natural gas sales related to natural gas produced from the Underlying Properties primarily from June 2017 through July 2018;

direct operating and development expenses related to expenses and capital incurred primarily from August 2017 to September

Net profits attributable to the

Underlying Properties for the year ended December 31, 2018 were $19.1 million compared to $9.4 million for the year

ended December 31, 2017.

As a result of direct operating expenses and development expenses exceeding oil and natural gas

sales for the last two months of 2017, the Trust did not pay a distribution to unitholders for the last two months of 2017.

Under the modified cash basis of accounting, as there was no distribution in November and December 2017, the oil and natural

gas sales, direct operating expenses and development expenses for such periods are not included in the table above or this

analysis of net profits attributable to the Underlying Properties for the year ended December 31, 2017 but are included in

the table above or this analysis of net profits attributable to the Underlying Properties for the year ended December 31,

Therefore, several variances between years are due to the inclusion of fourteen months of results in the year ended

December 31, 2018 compared to ten months in the year ended December 31, 2017.

The $9.6 million increase in net profits

attributable to the Underlying Properties from 2017 to 2018 was primarily due to the following items:

Oil sales increased $15.2 million, primarily due to higher sales volumes, which increased oil sales by $8.3 million.

The remaining

$7.0 million increase in oil sales was due to higher realized prices.

The average oil price received increased 19% as a result

of the corresponding increase in the average NYMEX oil price for the relevant production months.

Oil sales volumes increased 29%

primarily due to the year ended December 31, 2018 including fourteen months of oil s including only ten months of oil sales volumes.

Natural gas sales increased $5.4 million due to higher sales volumes, which increased natural gas sales by $5.0 million.

remaining $0.4 million increase in natural gas sales was due to higher realized prices.

The average natural gas price received

increased 3% as a result of the corresponding increases in the average NYMEX natural gas price for the relevant production months.

Natural gas volumes increased 57% primarily because the year ended December 31, 2018 included fourteen months of natural gas sales

volumes while the year ended December 31, 2017 included only ten months of natural gas sales volumes.

During 2018, average monthly

natural gas sales volumes increased 12% due to production volumes from six gross (0.45 net) wells in the Haynesville, which began

production in September 2018.

CGT expenses increased from $2.0 million in 2017 to $2.8 million in 2018.

The increase in CGT expenses is primarily attributable

to the difference in the number of months included in the respective periods.

Lease operating expenses increased $8.5 million in 2018 compared to 2017, primarily attributable to the difference in the number

of months included in the respective periods.

Production, ad valorem and other taxes increased $2.0 million in 2018 compared to 2017 primarily due to the increase in production

As a percentage of revenues, production, ad valorem and other taxes increased to 8.1% for the year ended December 31,

2018 compared to 7.2% for the year ended December 31, 2017.

Development expenses decreased $0.2 million, or 5%, in 2018 compared to 2017 as a result of reduced capital development projects.

Development expenses during the year ended December 31, 2018, included costs related to multiple workovers and the initial costs

for drilling three new wells in the Permian Area.

Development expenses during the year ended December 31, 2017 included costs related

to six gross (0.5 net) wells in North Louisiana commenced drilling and the Haynesville drilling program in North Louisiana.

In September 2017, Enduro completed the

sale of certain properties in the Permian Basin and, in connection with the sale, the Trust released its 80% Net Profits Interest

in the properties in exchange for 80% of the net proceeds of the sales.

The net proceeds of the sales were paid to Trust unitholders

in a special distribution in October 2017.

During the first quarter of 2018, $35,283 in general and administrative expenses incurred

and paid by Enduro that were not initially charged to the Trust as part of the special distribution were deducted in calculating

the net profits attributable to the Underlying Properties.

Further, during the second quarter of 2018, $52,960 was deducted from

the net profits attributable to the Underlying Properties due to the inclusion in prior period distribution calculations of certain

expenses and revenues that related to properties sold as part of these divestitures.

This resulted in total adjustments to the

net profits attributable to the Underlying Properties for 2018 of $88,243.

The Trust withheld $0.5 million and

paid $1.1 million for general and administrative expenses during the year ended December 31, 2018.

Expenses paid during

the period primarily consisted of fees for the preparation of 2017 tax information for unitholders, preparation of the

Trust’s 2017 reserve report and Annual Report on Form 10-K, 2017 and 2018 financial statement audit fees,

preparation of the Trust’s 2018 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, 2017, the Trust withheld $0.9 million and paid $0.7 million for

general and administrative expenses.

ended December 31, 2019, the Trust withheld $0.8 million and paid $0.9 million for general and administrative expenses.

Liquidity and Capital Resources

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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, the Sponsor has agreed to loan funds to the Trust necessary to pay such expenses.

Any loan made

by the Sponsor 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 the Sponsor than those that would be obtained in an arm’s length transaction between the Sponsor 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, 2019 and 2018, the Trust held cash reserves of $90,665 and $827,169,

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.

Further, if the Trust requires more than the $1.2 million under the letter of

credit to pay administrative expenses, the Sponsor has agreed to loan funds to the Trust necessary to pay such expenses.

made by the Sponsor 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 the Sponsor than those that would be obtained in an arm’s length transaction between the Sponsor

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, 2020 and 2019, the Trust held cash reserves of $29,639

and $90,665, 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.

From time to time, if the Trust’s

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As of December 31, 2020 and 2019, Advances to the Trust were $348,821 and $34,818, respectively.

In February 2016, Enduro established a $750,000

reserve from that month’s net profits interest calculation for approved 2016 development expenses.

The Trust, in its discretion,

also withheld $250,000 for anticipated future liabilities of the Trust.

In March 2016, Enduro withheld an additional $100,000 to

increase the previously established reserve for approved development expenses, a total reserve of $850,000.

As a result of lower

than anticipated expenditures during the year, over the course of the remaining 2016 distributions Enduro released $750,000 of

the established reserve, thereby increasing the net profits attributable to the Trust.

In the distribution paid in January 2017,

Enduro released the final $100,000 reserve.

COERT currently does not maintain any reserve for development expenses.

Cash held by the Trustee as a reserve against

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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, 2019, 2018 or 2017, and the terms of the Conveyance prohibit COERT from entering

into new hedging arrangements burdening the Trust.

Profits Interest for the years ended December 31, 2020 or 2019, and the terms of the Conveyance prohibit COERT from entering into

new hedging arrangements burdening the Trust.

The Trust pays the Trustee an administrative

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or the availability of capital resources.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements.

The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with

other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

of December 31, 2020, the Trust had no obligations or commitments to make future contractual payments other than the administrative

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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 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

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Cash distributions of the Trust

are made based on the amount of cash received by the Trust pursuant to terms of the conveyance creating the Net Profits Interest.

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

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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 cash earnings of the Trust;

amortization does not affect cash earnings of the Trust;

(f) The Net Profits Interest in oil and

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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

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.

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.

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.

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

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’

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

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.

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The Trust did not realize any impairment during the years ended December 31, 2019 or 2018.

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 5.

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

Fair Value Measurements”

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity