North European Oil Royalty Trust
Calculation of Cost Depletion Percentage
For 2023 Calendar Year
Based on the Estimate of Remaining Proved Producing
Reserves in the Northwest Basin of the
Federal Republic of Germany
As of October 1, 2023
GRAVES & CO.
CONSULTING LLC
HOUSTON, TEXAS
Table of Contents
Graves & Co.
Consulting
Oil and Gas
Reserves and Valuations
November 27, 2023
The Trustees of
North European Oil Royalty Trust
P. O. Box 187
Keene, New Hampshire 03431
Ref: North European Oil Royalty Trust
Calculation of the Cost Depletion Percentage
For the Calendar Year 2023
Trustees:
In accordance with the request of the Trustees of
North European Oil Royalty Trust (the "Trust"), Graves & Co.
Consulting LLC of Houston, Texas has performed the calculations
necessary to derive the cost depletion percentage for the 2023
calendar year. The cost depletion percentage was prepared for use
by unit owners of the Trust in filing federal income tax returns.
In order to calculate the cost depletion percentage, we prepared a
report of the estimated remaining proved producing reserves
attributable to the overriding royalty interests of the Trust in
the Northwest German Basin of the Federal Republic of Germany with
an effective date of October 1, 2023.
We have reviewed all available information with
respect to 100% of the Trust's proved developed properties used in
the calculation of the cost depletion percentage as discussed later
in this report. It is our opinion that these properties represent
all of the Trust's assets that may be classified as proved for this
purpose as per the Securities and Exchange Commission directives
detailed later in this report.
The reserves associated with this review have been
classified in accordance with the definitions of the Securities and
Exchange Commission as found in Part 210-Form and Content of and
Requirements for Financial Statements, Securities Act of 1933,
Securities Exchange Act of 1934, Public Utility Holding Company Act
of 1935, Investment Company Act of 1940, Investment Advisers Act of
1940, and Energy Policy and Conservation Act of 1975, under Rules of
General Application Section 210.4-10 financial accounting and
reporting for oil and gas producing activities pursuant to the
Federal securities laws and the Energy Policy and Conservation Act
of 1975.
The proved producing reserves are as of October 1,
2023 and the reported sales are for the twelve-month period ending
September 30, 2023. The use of the period ending September 30, 2023
is consistent with prior years and allows the timely calculation of
the royalty reserves and the cost depletion percentage for the
calendar year. Throughout this report the unit price used for crude
oil, condensate, natural gas and sulfur is based upon the prices in
effect at the time of the royalty calculations. The price for each
of the products is then averaged for the twelve-month period to arrive
at the unit price.
Based on the results of our calculation of estimated
remaining proved producing reserves contained in the first part of this
report, we have performed the calculations necessary to derive the cost
depletion percentage for the 2023 calendar year. As detailed in
Attachment B, the cost depletion percentage for the 2023 calendar
year for Trust unit owners is equal to 8.8130% of the unit owner's
cost basis as of January 1, 2023.
Discussion
The scope of this study was to review limited
information we were able to compile and to prepare an estimate of the
proved producing reserves subject to the Trust's royalty interests from
which the cost depletion percentage could be calculated. We prepared
reserve estimates using acceptable evaluation principles for each source.
These estimates were based in large part on the limited information
supplied by the operator of the relevant properties.
The quantities presented herein are estimated reserves
of oil, natural gas, natural gas liquids and sulfur that geologic and
engineering data demonstrate can be recovered from known reservoirs under
current economic conditions with reasonable certainty.
Description of Holdings
The Trust holds various overriding royalty rights on
sales of gas, sulfur and oil from certain concessions and leases in
the Federal Republic of Germany. The Oldenburg concession
(1,386,000 acres), located in the federal state of Lower Saxony, is
held by Oldenburgische Erdolgesellschaft ("OEG"). OEG in turn is owned
by Mobil Erdgas-Erdol GmbH ("Mobil Erdgas"), the German subsidiary of
ExxonMobil Corp. and by BEB Erdgas und Erdol GmbH ("BEB"), a joint
venture of ExxonMobil Corp. and the Royal Dutch Shell Group of Companies.
As a result, by direct and indirect ownership, ExxonMobil Corp. owns
two-thirds of OEG and the Royal Dutch Shell Group owns one-third of
OEG.
In 2002 Mobil Erdgas and BEB formed a new company
ExxonMobil Production Deutschland GmbH to carry out all exploration,
drilling and production within the Oldenburg concession. All sales
activities are still handled by either Mobil Erdgas or BEB.
The Oldenburg concession is currently the primary
source of royalty income for the Trust. All proved producing
reserves within the Oldenburg concession are covered by this report.
Although the Trust has royalty interests in other areas, these areas
are no longer used in the calculation of the annual cost depletion
percentage because there is minimal current production from these
areas.
The Trust's rights in the Oldenburg concession are
described as follows:
- Under one set of rights covering the western part
of the Oldenburg concession (approximately 662,000 acres), the Trust
receives a royalty payment of 4% on gross receipts from sales by
Mobil Erdgas of gas well gas, oil well gas, crude oil and condensate
("Mobil Agreement"). Under the Mobil Agreement there is no deduction
of costs prior to the calculation of royalties from gas well gas or
oil well gas, which together account for over 99% of all
the royalties under said agreement.
- Under another series of rights covering the entire Oldenburg
concession and pursuant to an agreement with OEG, the Trust receives
royalties at the rate of 0.6667% on gross receipts from sales of gas
well gas, oil well gas, crude oil, condensate and sulfur (removed
during the processing of sour gas) less a certain allowed deduction
of costs ("OEG Agreement").
Under the OEG Agreement, 50% of the field handling and treatment costs
as reported for state royalty purposes are deducted from gross sales
receipts prior to the calculation of the royalty to be paid to the
Trust. Sulfur is a by-product of gas production and is not considered
in the computation of total cost depletion.
- The Trust is also entitled to receive from Mobil Erdgas, a 2%
royalty payment on gross receipts from sales of sulfur obtained as a
by-product of sour gas produced from the western part of Oldenburg.
However, the payment of the sulfur royalty is provisional on whether
Mobil Erdgas' selling price meets or exceeds the indexed base price.
Sulfur is a by-product of gas production and is not considered in the
computation of total cost depletion.
Oldenburg
Area - Sales and Reserves
The Trust's royalty income currently comes
exclusively from the Oldenburg area. Gas production accounts for
the majority of the income; however, the hydrogen sulfide in much of
the gas produced necessitates its removal before the gas can be sold.
At the Grossenkneten desulfurization plant, the hydrogen sulfide in
sour gas is removed. The plant's present input capacity stands at
approximately 200 million cubic feet ("MMcf") per day following
ExxonMobil's retirement of Unit 3 in April 2017, and more recently by
the retirement of Unit 2 in June 2023. The elimination of two of the
plant's three trains has effectively reduced the input capacity by
two-thirds.
Total Sales
During the twelve months ending September 30, 2023,
total sales for the Oldenburg area were as follows:
Total Sales |
West |
East |
Total |
|
Gas Well Gas - MMCF |
12,439.6 |
32,513.0 |
44,952.6 |
Oil Well Gas - MMCF |
1.2 |
2.0 |
3.2 |
Oil & Condensate - Barrels |
59,098.0 |
13,820.3 |
72,918.3 |
Sulfur - Short Tons |
55,942.0 |
204,552.7 |
260,494.7 |
Gross Reserves
Estimated gross remaining proved producing reserves
attributable to the total Oldenburg area as of October 1, 2023 are
as follows:
Gross Reserves |
West |
East |
Total |
|
Gas Well Gas - MMCF |
116,518.5 |
395,118.1 |
511,636.6 |
Oil Well Gas - MMCF |
12.1 |
0.0 |
12.1 |
Oil & Condensate - Barrels |
734,066.9 |
52,960.8 |
787,027.7 |
Sulfur - Short Tons |
631,448.4 |
2,228,154.5 |
2,859,602.9 |
Gross reserves are down across the board based on a
combination of gas production constraints, lower oil prices, and higher
operating expenses which shorten the economic life. The exception is
western oil production, which has seen improved production rates and
lower operating expenses.
Net Reserves and Sales
To present an accurate picture of estimated proved
producing reserves net to the Trust, the gross reserve figures
outlined above must be modified by the impact of the different
royalty rates in effect in the Oldenburg concession. A comparison of
the Trust's overriding royalty rates in both the western and eastern
areas of Oldenburg is as follows:
Royalty Source |
West |
East |
Mobil Erdgas Gas & Oil |
4% |
0% |
Mobil Erdgas Sulfur |
2% |
0% |
BEB Gas & Oil |
0.6667%(1) |
0.6667%(1) |
BEB Sulfur |
0.6667%(1) |
0.6667%(1) |
(1)Prior to the
calculation of royalties, 50% of costs as reported for
state royalty purposes are deducted. |
The application of these royalty rates to the estimated
gross remaining proved producing reserves attributable to the western
and eastern Oldenburg areas yields the combined estimated proved
producing reserves net to the Trust. The Trust's estimated remaining
net proved producing reserves as of October 1, 2023 and net sales for
the twelve month period ending September 30, 2023 are as follows:
Net Reserves & Sales |
Reserves |
Sales |
Gas Well Gas - MMCF |
7,828.4 |
759.0 |
Oil Well Gas - MMCF |
0.5 |
0.1 |
Oil & Condensate - Barrels |
32,798.1 |
2,709.3 |
Sulfur - Short Tons |
29,824.4 |
2,722.0 |
A summary of net proved producing reserves by product
and a five-year history of net sales attributable to the royalty
interests of the Trust are presented in Attachment A. Net gas well gas
and sulfur reserves are down compared to 2022 because of gas processing
plant refurbishment and resulting production constraints. Net oil
reserves are up based on performance at Lastrup-West. Though not
material, net oil well gas sales decreased sharply in 2023 resulting in
a corresponding drop in net reserves.
Limitations of Available
Data
The reserves considered in this report are defined as
proved producing reserves. Proved producing reserves are limited to
those quantities which can be expected to be recoverable commercially
from known reservoirs at current prices and costs, under existing
regulatory practices and with existing conventional equipment and
operating methods. Proved producing reserves do not include either
proved developed non producing reserves or any class of probable
reserves.
The estimate of reserves included in this report is
based primarily upon production history or analogy with wells in the
area producing from the same or similar formations. Typically,
geological data, well reports, and well tests are available and
utilized in evaluations; however, no such data was made available
for 2023.
The reserves included in this report are estimates
only and should not be construed as being exact quantities. The
accuracy of the estimates is dependent upon the quality of available
data and upon the independent geological and engineering interpretation
of that data. The quantities presented herein are estimated reserves
of hydrocarbons and produced products that geologic and engineering
data demonstrate can be recovered from known reservoirs under current
economic conditions with reasonable certainty. Reserve estimates
presented in this report are calculated using acceptable methods and
procedures and are believed to be appropriate and reasonable; however,
future reservoir performance may justify revision of these
estimates.
For the purpose of this report, estimated reserves are
scheduled for recovery primarily on the basis of actual producing rates
or appropriate well test information. They were prepared giving
consideration to engineering and geological data, anticipated producing
mechanisms, the number and types of completions, as well as past
performance of analogous reservoirs. Individual well production
histories, when available, were analyzed and an appropriate daily
producing rate was utilized for each individual well in the
preparation of a forecast of future producing rates until an
anticipated economic limit.
No information was received from the operator
concerning activity in the field during the Trust's fiscal year 2023 other
than there was no drilling activity, and five wells were plugged and
abandoned.
The estimates of reserves and the forecasted rates of
production may be subject to regulation by various agencies, changes in
market demand or other factors. Consequently, the volumes of reserves
recovered, and the actual rates of recovery, may vary from the estimates
included herein.
The Trust, as an overriding royalty interest owner,
does not receive proprietary data from the various operators on
producing wells. Data, such as logs, core analysis, reservoir tests,
pressure tests, gas analyses, geologic maps, and individual well
production histories on all of the wells which are used in volumetric
and material balance type reserve estimates, are not available to the
Trust. The lack of such data increases the inherent uncertainties of
our reserve estimate.
The Trust receives quarterly statements from the
operators that report production, sales and revenue data. Utilizing the
same procedures as in prior years, this information has
been used to prepare this annual report. In addition, the Trust retains
a part-time consultant in Germany who is familiar with the German
petroleum industry in general and the operating companies in particular.
His periodic reports and communications were considered in the
preparation of this report.
Overview of Natural Gas
Processing
ExxonMobil operates a natural gas processing plant,
the Grossenkneten Plant at Grossenkneten, Lower Saxony, Germany,
located approximately 40 kilometers to the west of Bremen. The plant
is designed to remove non-hydrocarbon impurities from the natural gas
produced on the Oldenburg concession, especially hydrogen sulfide.
The Grossenkneten plant has supplied natural gas and sulfur to Germany
for over 50 years. Seventy-five percent (75%) of the natural gas
produced on the Oldenburg concession is sour gas requiring
desulfurization at the plant. The following paragraphs provide a
description of the plant and changes in ExxonMobil's
operation of the plant that have impacted Trust royalty income this
year and that may have an impact on Trust royalty income in the
future.
Description of
Grossenkneten Plant
The Grossenkneten Plant consists of complex natural
gas desulfurization and dehydration, sulfur recovery ("Claus-process"),
waste gas purification and ancillary facilities. The ancillary
facilities include a steam boiler, a gas engine, emergency flaring
facilities and a condensing power station.
Every ten years, the plant is shut down for extensive
refurbishment and maintenance, including safety checks and efficiency
improvements. Given the hydrogen sulfide content of the natural gas,
safety requirements for working on the site are very stringent. The
most recent refurbishment occurred from August to October 2020, and
included 3,200 individual maintenance and installation activities.
The refurbishment employed 600 contractors, and the work injected 30
million euros into the local and regional economies. A new gas/gas
heat exchanger was installed, improving the plant's energy efficiency.
Following the refurbishment work, the plant was re-certified for
another ten years, until 2030.
Changes in
ExxonMobil's Plant Operations
The Grossenkneten Plant originally had three trains
in use desulfurizing and dehydrating natural gas. Each operating
train had a treatment capacity of approximately 2.0 billion cubic
meters per year of untreated sour gas. ExxonMobil retired Unit 3
in April 2017, effectively reducing the plant input capacity at that
time by one-third. Consistent with the inherent decline of Oldenburg
gas production, ExxonMobil shut down a second of the three trains
during the summer of 2023. As of June 2023, only one train remains
in use and throughput is understood to be at capacity. This
refurbishment and optimization work negatively impacted the production
from the wells between May and July.
Impacts on Future
Trust Royalty Income
The Trust's German consultant has informed us that
because of the changes in plant operations, production curtailment
estimated at 8.9% is expected until the end of the first quarter in
2024. Although this suggests a modest potential increase in production
starting in the second quarter of 2024, no concomitant adjustment has
been built into the production forecasts for the Trust's wells.
Requirements to periodically cycle off and on weak, low-pressure wells
and high water-cut wells, operations that are consistent with the
maturity of the field, are expected to offset any increase from ending
the curtailment.
ExxonMobil's shutdown of the second train at
Grossenkneten should result in a reduction of certain costs deducted
from the Trust's gross royalties. Offsetting these reductions will be
increased well operating expenses which are the inevitable result of
declining production volumes.
Uncertainties
Related to Future Gas Plant Operations
We possess insufficient data from the plant's operator,
ExxonMobil, that would be necessary to make a quantitative assessment
of the uncertainties related to the economics of future long-term
operations at the Grossenkneten Plant. Accordingly, Graves has decided
not to allocate a risk factor to the reserve calculations used in the
preparation of this report attributable to such uncertainties. Full
retirement of the Grossenkneten plant at some time in the future could
potentially mean the end of production from the Oldenburg concession
and of the Trust's royalty income. The producing life of the concession
and the oil, gas, and sulfur reserves attributable thereto that are set
forth in this report would in such an event be cut short.
Reserve Estimates
We believe that reserve estimates prepared using all
the available data are appropriate and sufficient for the calculation
of the cost depletion percentage. However, due to the limitations of
available data, this estimate of reserves cannot have the same degree
of accuracy that an estimate of reserves prepared using all pertinent
data would have. Our experience in the evaluation of reserves using
such limited data compensates somewhat for the limitations of available
data.
The data in the reports received by the Trust is in
metric tons and cubic meters. The following Metric to English Unit
conversion factors were used:
Gas: |
37.25 cubic feet per cubic meter at 14.7 psia and 60 degrees
Fahrenheit |
Oil: |
7.23 barrels per metric ton |
Sulfur: |
1.1 short tons per metric ton |
Calculation of Cost Depletion
Percentage
The categories of proved producing reserves considered
in the calculation of the cost depletion percentage are oil, oil well
gas, and gas well gas. Sulfur is a by-product of gas production and is
not considered in the computation of total cost depletion percentage.
For each category of reserves, a product base was
established for the Trust as of January 1, 1976. Through the use of
these product bases, we can account for the relative size of each of
these categories of reserves and the corresponding impact on the
calculation of the cost depletion percentage. The product base for each
category of proved producing reserves is reduced annually by an
adjustment that is calculated by multiplying the product base at the
beginning of the current year by the depletion factor for that category
of reserves.
The depletion factor for each category of reserves is
the ratio of the relevant net sales during the current year to the
corresponding adjusted net proved producing reserves at the beginning
of the current year.
Significant items in the cost depletion percentage
calculation that appear on Attachment B as specific item numbers, shown
in parentheses and their sources are as follows:
The adjusted estimated net proved producing
reserves as of 10/1/2022 Line (3) is obtained by adding the estimated
remaining net proved producing reserves as of 10/1/2022 Line (1) and
the adjustments to reserves during the period Line (2). Therefore
Line (3) = Line (1) + Line (2).
The depletion factor Line (6) for each
category of proved producing reserves is obtained by dividing the
relevant net sales Line (4) by the corresponding adjusted estimated net
proved producing reserves as of 10/1/2022 Line (3). Therefore Line (6)
= Line (4) / Line (3).
The product base for each category of proved
producing reserves as of 1/1/2022 Line (7) and the adjustment taken
during 2022 Line (8) were obtained from the previous year's report.
The product base as of 1/1/2023 Line (9) forms the initial starting
point for the calculation of the cost depletion percentage for the
2023 tax year. The product base for 1/1/2023 Line (9) then is Line (7)
- Line (8).
The adjustment to the product base for each
category of proved producing reserves Line (10) is used to reduce the
product base as of the beginning of each year. This adjustment is the
product of the depletion factor for each category of proved producing
reserves Line (6) multiplied by the corresponding product base as of
1/1/2023 Line (9). Therefore Line (10) = Line (6) x Line (9).
The cost depletion percentage Line (11) then
is the sum of the adjustment to the product base of each category of
proved producing reserves [Sum Line (10)] divided by the sum of the
product base for each category as of 1/1/2023 [Sum Line (9)]. Therefore
Line (11) = [Sum Line (10)] / [Sum Line (9)].
The cost depletion percentage represents the total
allowable cost depletion for the 2023 calendar year for the Trust's unit
owners, expressed as a percentage of their cost base as of January 1,
2023.
Neither Graves & Co. Consulting, LLC nor any of its
directors, officers, employees or contractors have any interest in
the subject properties and neither the engagement to make this study
and calculation nor our compensation is contingent on our estimate of
reserves or the results of our calculation.
We appreciate the opportunity to be of service to you
in this matter and will be glad to address any questions or inquiries
you may have.
Sincerely yours,
GRAVES & CO. CONSULTING LLC
/s/ John L. Graves
John L. Graves.
President
/s/ Mel F. Hainey, P.E.
Mel F. Hainey, P.E.
Sr. Reservoir Engineer
(All values expressed in whole numbers.)
Estimated Net Proved Producing Reserves
as of October 1, 2023
Oldenburg
|
Gas Well |
Oil Well |
|
|
|
|
Gas |
Gas |
Oil/Cond. |
Sulfur |
|
|
MMcf |
MMcf |
Barrels |
Short Tons |
|
|
7,828 |
1 |
32,798 |
29,824 |
|
Five Year Net Sales Summary
12 Months Ending September 30, 2023
Oldenburg
|
|
Gas Well |
Oil Well |
|
|
|
|
Gas |
Gas |
Oil/Cond. |
Sulfur |
|
|
MMcf |
MMcf |
Barrels |
Short Tons |
|
2023 |
759 |
0 |
2,709 |
2,722 |
|
2022 |
903 |
1 |
2,791 |
3,255 |
|
2021 |
882 |
1 |
2,779 |
3,110 |
|
2020 |
940 |
5 |
2,877 |
3,334 |
|
2019 |
1,215 |
3 |
3,947 |
3,931 |
|
For the Year Ending December 31, 2023
| OLDENBURG
|
|
Gas Well |
Oil Well |
|
|
Gas |
Gas |
Oil |
|
MMCF |
MMCF |
Barrels |
NEORT NET RESERVES
(Million Cubic Feet of Gas and
Barrels of Oil) |
| | | |
1. Estimated net proved
producing reserves as of 10-1-2022 |
10,582.1 |
15.3 |
28,064.1 |
| | | |
2. Adjustment to reserves
during period |
-1,994.7 |
(14.7) |
7.443.3 |
| | | |
3. Adjusted est. net proved
producing
reserves as of 10-1-2022 |
8,587.4 |
0.6 |
35,507.4 |
| |
| |
4. Net sales from 10-1-2022 to 9-30-2023 |
759.0 |
0.1 |
2,709.3 |
| | | |
5. Estimated remaining net proved
producing reserves as of 10-1-2023 |
7,828.4 |
0.5 |
32,798.1 |
| | | |
RESERVE DEPLETION FACTOR |
| | |
| | | |
6. Depletion factor |
0.08839 |
0.16667 |
0.07630 |
| | | |
NEORT WEIGHTED PRODUCT
BASE ALLOCATION
|
|
|
|
| | | |
7. Product base as of 1-1-2022 |
1.01993 |
0.00000 |
0.02248 |
| | | |
8. Less adjustments taken during 2022 |
0.08021 |
0.00000 |
0.00203 |
| | | |
9. Product base as of 1-1-2023 |
0.93972 |
0.00000 |
0.02045 |
| | | |
10. 2023 Adjustment to product base |
0.08306 |
0.00000 |
0.00156 |
| | | |
11. Cost
depletion percentage for 2023 calendar year for Trust unit
owners is equal to 8.8130 percent
of their 1-1-2023 cost base. |
Footnotes:
Line (1) from reserves review as of
10-1-2022
Line (2) from reserves review as of 10-1-2023
Line (3) = Line (1) + Line (2)
Line (4) from BEB and Mobil Erdgas statements
Line (5) from reserves review as of 10-1-2023
Line (6) = Line (4) / Line (3)
Line (7) from 2022 depletion calculations
Line (8) from 2022 depletion calculations
Line (9) = Line (7) - Line (8)
Line (10) = Line (9) x Line (6)
Line (11) = Sum Line (10) / Sum Line (9)
The following information is from the United
States Securities and Exchange Commission:
PART 210--FORM AND CONTENT OF AND
REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933,
SECURITIES EXCHANGE ACT OF 1934, PUBLIC UTILITY HOLDING COMPANY ACT
OF 1935, INVESTMENT COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF
1940, AND ENERGY POLICY AND CONSERVATION ACT OF 1975
Rules of General Application
Section 210.4-10 Financial accounting and
reporting for oil and gas producing activities pursuant to the
Federal securities laws and the Energy Policy and Conservation Act
of 1975.
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.
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).
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.
- The area of the reservoir considered as proved
includes:
- The area identified by drilling and limited by fluid
contacts, if any, and
- 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.
- 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.
- 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.
- 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:
- 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
- The project has been approved for development by all necessary
parties and entities, including governmental entities.
- 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.
Reasonable certainty. If deterministic
methods are used, reasonable certainty means a high degree of
confidence that the quantities will be recovered. If probabilistic
methods are used, there should be at least a 90% probability that the
quantities actually recovered will equal or exceed the estimate. A
high degree of confidence exists if the quantity is much more likely
to be achieved than not, and, as changes due to increased availability
of geoscience (geological, geophysical, and geochemical), engineering,
and economic data are made to estimated ultimate recovery (EUR) with
time, reasonably certain EUR is much more likely to increase or remain
constant than to decrease.
Reliable technology. Reliable technology
is a grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to
provide reasonably certain results with consistency and repeatability
in the formation being evaluated or in an analogous formation.
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.
- 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.
- 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.
- Probable reserves estimates also include potential incremental
quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
Possible Reserves
Possible reserves are those additional reserves that
are less certain to be recovered than probable reserves.
- 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.
- 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.
- 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.
- 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.
- 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.
- Pursuant to paragraph (a)(22)(iii) of this section, 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.
Developed Oil and Gas Reserves
Developed oil and gas reserves are reserves of any
category that can be expected to be recovered:
- 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
- Through installed extraction equipment and infrastructure
operational at the time of the reserves estimate if the extraction is
by means not involving a well.
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.
- 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.
- 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.
- 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.
Additional Definitions:
Deterministic Estimate
The method of estimating reserves or resources is called
deterministic when a single value for each parameter (from the
geoscience, engineering, or economic data) in the reserves calculation
is used in the reserves estimation procedure.
Probabilistic Estimate
The method of estimation of reserves or resources is
called probabilistic when the full range of values that could
reasonably occur for each unknown parameter (from the geoscience and
engineering data) is used to generate a full range of possible outcomes
and their associated probabilities of occurrence.
Reasonable Certainty
If deterministic methods are used, reasonable certainty
means a high degree of confidence that the quantities will be
recovered. If probabilistic methods are used, there should be at least
a 90% probability that the quantities actually recovered will equal or
exceed the estimate. A high degree of confidence exists if the quantity
is much more likely to be achieved than not, and, as changes due to
increased availability of geoscience (geological, geophysical, and
geochemical), engineering, and economic data are made to estimated
ultimate recovery (EUR) with time, reasonably certain EUR is much more
likely to increase or remain constant than to decrease.
Graves & Co.
Consulting
Oil and Gas
Reserves and Valuations
Certificate of
Qualification
I, Mel F. Hainey, Registered Professional
Engineer, do hereby certify:
1. That I am a Sr. Reservoir Engineer of the
consulting firm of Graves & Co. Consulting LLC with
offices at 1800 West Loop South, Suite 750, Houston, Texas 77027.
2. That I have prepared a reserve report on the
interests of the North European Oil Royalty
Trust in
the Northwest Basin of the Federal Republic of Germany as of
October 1, 2023
for the purpose of calculating the
cost depletion percentage applicable to Trust unit
owners for the 2023 calendar year.
3. That I have no direct or indirect interest, nor do
I expect to receive any direct or indirect
interest,
in the properties or in any securities of the North European Oil
Royalty Trust.
4. That I attended The University of Texas at
Austin and that I graduated with a Bachelor of
Science
Degree in Electrical Engineering in 1975 with a Master of Science
Degree in Engineering in 1977.
5. That I am a Registered Professional Engineer in
the State of Texas, Registration Number
65528, and
that I am a member in good standing of the Texas Society of Professional
Engineers and the Society of Petroleum Engineers.
6. That I have in excess of forty years of
experience in the petroleum engineering including the
evaluation of oil and gas properties in
the United States, Canada, Indonesia, Turkey and
Germany, and that I have been practicing
as a consultant in petroleum reservoir engineering
since 2016
..
Signed November 27, 2023
GRAVES & CO. CONSULTING LLC
/s/ Mel F. Hainey, P.E.
Mel F. Hainey, P.E.
Sr. Reservoir Engineer