Attached files
- 50 -
Exhibit 99.1
NORTH EUROPEAN OIL ROYALTY TRUST
CALCULATION OF COST DEPLETION PERCENTAGE
FOR 2016 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, 2016
Ralph E. Davis Associates, LLC
Houston, Texas
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T A B L E O F C O N T E N T S
Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Description of Holdings . . . . . . . . . . . . . . . . . . . . . . . . 2-3
Oldenburg Area - Sales and Reserves . . . . . . . . . . . . . . . . . . . 4
Total Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Gross Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Net Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Limitations of Available Data . . . . . . . . . . . . . . . . . . . . . 5-7
Calculation of Cost Depletion Percentage . . . . . . . . . . . . . . . 7-8
Attachment A:
Reserve Summary and Five Year Net Sales History . . . . . . . . . . 9
Attachment B:
Calculation of Total Cost Depletion Percentage . . . . . . . . . 10-11
Definitions of Reserves . . . . . . . . . . . . . . . . . . . . . . . 12-17
Certificate of Qualification . . . . . . . . . . . . . . . . . . . . . 18
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Ralph E. Davis Associates, LLC
November 30, 2016
The Trustees of
North European Oil Royalty Trust
P. O. Box 456
Red Bank, New Jersey 07701
Ref: North European Oil Royalty Trust
Calculation of the Cost Depletion
Percentage for the Calendar Year 2016
Trustees:
In accordance with the request of the Trustees of North European Oil
Royalty Trust ("Trustees"), the firm of Ralph E. Davis Associates, LLC
("Davis Associates") of Houston, Texas has performed the calculations
necessary to derive the cost depletion percentage for the 2016 calendar
year. The cost depletion percentage was prepared for use by individual
unit owners of North European Oil Royalty Trust ("Trust") in their tax
preparations. In order to perform the calculation of the cost depletion
percentage we were further requested by the Trustees to prepare 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, 2016.
We have reviewed all available information with respect to 100% of the
Trust's proved developed properties utilized 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 as 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, 2016 and the
reported sales are for the twelve month period ending September 30, 2016.
The use of the period ending September 30, 2016 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
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 2
For the Calendar Year 2016
price used for crude oil, condensate, natural gas and sulfur is based upon
the appropriate price in effect for each of the twelve months during fiscal
2016 and averaged for the period.
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 2016 calendar year. As detailed in Attachment B, the cost depletion
percentage for the 2016 calendar year for Trust unit owners is equal to
10.2769% of their cost base as of January 1, 2016.
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
attributable to the interests of the Trust 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), covering virtually the
entire former Grand Duchy of Oldenburg and 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.
The Oldenburg concession is the major source of royalty income for the
Trust. All proved producing reserves within the Oldenburg concession are
covered by this report. Although the Trust has interests in other producing
areas, reserves and net sales for these areas are no longer used in the
calculation of the annual cost depletion percentage. The exclusion of these
reserves does not have a material effect on the calculation of the cost
depletion percentage. We will continue to monitor the quarterly statements
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 3
For the Calendar Year 2016
and, if increases are noted that could materially add reserves to the Trust,
we will resume estimating future reserves.
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.
a) 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 approximately 99% of all the royalties under said
agreement.
b) 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.
c) 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. The average selling price for
sulfur exceeded the indexed base price since the start of
fiscal 2012 except for the fourth calendar quarter of 2013.
Sulfur is a by-product of gas production and is not considered
in the computation of total cost depletion.
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 4
For the Calendar Year 2016
OLDENBURG AREA - SALES AND RESERVES
------------------------------------
The Trust's royalty income comes primarily 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 620
million cubic feet ("MMcf") per day. However, the operating companies have
informed the Trust that, to promote greater efficiency and cost
effectiveness, the production capacity of Grossenkneten will be reduced in
2017.
TOTAL SALES
-----------
During the twelve months ending September 30, 2016, total sales for the
Oldenburg area were as follows:
WEST EAST TOTAL
---- ---- -----
Gas Well Gas-MMcf 25,022 52,163 77,185
Oil Well Gas-MMcf 28 21 49
Oil & Condensate-Barrels 91,622 35,836 127,458
Sulfur-Short Tons 99,950 370,065 470,015
GROSS RESERVES
--------------
Estimated gross remaining proved producing reserves attributable to
the total Oldenburg area as of October 1, 2016 are as follows:
WEST EAST TOTAL
---- ---- -----
Gas Well Gas-MMcf 228,333 373,577 601,910
Oil Well Gas-MMcf 317 97 414
Oil & Condensate-Barrels 732,500 179,572 912,072
Sulfur-Short Tons 956,382 3,142,246 4,098,628
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 5
For the Calendar Year 2016
NET RESERVES
------------
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:
Mobil Erdgas West East
--------------- ---------- ----------
Gas & Oil 4% 0%
Sulfur 2% 0%
BEB
---------------
Gas & Oil 0.6667%(1) 0.6667%(1)
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, 2016 and net sales for the twelve month period ending September
30, 2016 are as follows:
Reserves Sales
-------- -----
Gas Well Gas-MMcf 12,214 1,392
Oil Well Gas-MMcf 14 1
Oil & Condensate-Barrels 33,371 4,225
Sulfur-Short Tons 42,352 4,761
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.
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
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 6
For the Calendar Year 2016
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. In addition to individual well production history,
geological and well test information, when available, were utilized in the
evaluation.
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 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.
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 plus published information received from
W.E.G. (a German organization comparable to the American Petroleum Institute
or the American Gas Association) 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
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 7
For the Calendar Year 2016
companies in particular. His periodic reports and communications were
considered in the preparation of this report.
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, including twenty-five (25)
years of experience working for the Trust, 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 10/1/15
Line (3) is obtained by adding the estimated remaining net proved
producing reserves as of 10/1/15 Line (1) and the adjustments to
reserves during the period Line (2). Therefore Line (3) =
Line (1) + Line (2).
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 8
For the Calendar Year 2016
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 10/1/15 Line (3). Therefore Line (6) = Line (4) / Line (3).
The product base for each category of proved producing reserves as
of 1/1/15 Line (7) and the adjustment taken during 2015 Line (8)
were obtained from the previous year's report. The product base as
of 1/1/16 Line (9) forms the initial starting point for the
calculation of the cost depletion percentage for the 2016 tax year.
The product base for 1/1/16 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 1/1/16
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 1/1/16 [Sum Line (9)]. Therefore Line (11) =
[Sum Line (10)] / [Sum Line (9)].
The cost depletion percentage represents the total allowable cost
depletion for the 2016 calendar year for the Trust's unit owners, expressed
as a percentage of their cost base as of January 1, 2016.
Neither Ralph E. Davis Associates, LLC nor any of its employees have
any interest in the subject properties and neither the employment 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,
RALPH E. DAVIS ASSOCIATES, LLC
/s/ Allen C. Barron
----------------------------
Allen C. Barron, P.E.
President
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 9
For the Calendar Year 2016
ATTACHMENT A
NORTH EUROPEAN OIL ROYALTY TRUST
RESERVE SUMMARY AND FIVE YEAR NET SALES HISTORY
ESTIMATED NET PROVED PRODUCING RESERVES AS OF OCTOBER 1, 2016
-------------------------------------------------------------
OLDENBURG
---------------------------------------------------------------------------
Gas Well Gas Oil Well Gas Oil/Cond. Sulfur
MMcf MMcf Barrels Short Tons
------------ ------------ ---------- ----------
12,214 14 33,371 42,352(1)
FIVE YEAR NET SALES SUMMARY
---------------------------
12 MONTHS ENDING SEPTEMBER 30, 2016
-----------------------------------
OLDENBURG
---------------------------------------------------------------------------
Gas Well Gas Oil Well Gas Oil/Cond. Sulfur
MMcf MMcf Barrels Short Tons
------------ ------------ ---------- ----------
2016 1,392 1 4,225 4,761(1)
2015 1,642 2 4,667 6,090(2)
2014 1,821 1 4,444 7,436(3)
2013 1,968 1 4,713 8,009(4)
2012 2,174 1 3,897 8,997(5)
(1) Royalty payments under the Mobil Erdgas sulfur royalty representing
all four quarters of fiscal 2016 were received.
(2) Royalty payments under the Mobil Erdgas sulfur royalty representing
all four quarters of fiscal 2015 were received.
(3) Royalty payments under the Mobil Erdgas sulfur royalty representing
the second, third and fourth quarters of fiscal 2014 were received.
(4) Royalty payments under the Mobil Erdgas sulfur royalty representing
all four quarters of fiscal 2013 were received.
(5) Royalty payments under the Mobil Erdgas sulfur royalty representing
the second, third and fourth quarters of fiscal 2012 were received.
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 10
For the Calendar Year 2016
ATTACHMENT B
NORTH EUROPEAN OIL ROYALTY TRUST
CALCULATION OF TOTAL COST DEPLETION PERCENTAGE
FOR THE YEAR ENDING DECEMBER 31, 2016
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 remaining net proved
producing reserves as of 10-1-15 14,400 8 44,174
2. Adjustments to reserves
during period -794 7 -6,578
3. Adjusted est. net proved
producing reserves
as of 10-1-15 13,606 15 37,596
4. Net sales from 10-1-15
to 9-30-16 1,392 1 4,225
5. Estimated remaining net proved
producing reserves
as of 10-1-16 12,214 14 33,371
RESERVE DEPLETION FACTOR
-----------------------------
6. Depletion factor 0.10231 0.06667 0.11238
NEORT WEIGHTED PRODUCT BASE ALLOCATION
-------------------------------------------
7. Product base as of 1-1-15 2.71209 0.00171 0.13487
8. Less adjustments taken
during 2015 0.27760 0.00034 0.01289
9. Product base as of 1-1-16 2.43449 0.00137 0.12198
10. 2016 Adjustment
to product base 0.24907 0.00009 0.01371
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 11
For the Calendar Year 2016
-----------------------------------------------------------------------------
11. Cost depletion percentage for 2016 calendar year for Trust unit owners
is equal to 10.2769 percent of their 1-1-2016 cost base.
-----------------------------------------------------------------------------
Footnotes:
Line (1) from reserves review as of 10-1-15
Line (2) from reserves review as of 10-1-16
Line (3) = Line (1) + Line (2)
Line (4) from BEB and Mobil Erdgas statements
Line (5) from reserves review as of 10-1-16
Line (6) = Line (4) / Line (3)
Line (7) from 2015 depletion calculations
Line (8) from 2015 depletion calculations
Line (9) = Line (7) - Line (8)
Line (10) = Line (9) x Line (6)
Line (11) = Sum Line (10) / Sum Line (9)
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 12
For the Calendar Year 2016
SECURITIES AND EXCHANGE COMMISSION - DEFINITIONS OF RESERVES
------------------------------------------------------------
The following information is taken 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
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 13
For the Calendar Year 2016
must have commenced or the operator must be reasonably certain that it will
commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts,
if any, and
(B) Adjacent undrilled portions of the reservoir that can, with
reasonable certainty, be judged to be continuous with it and to
contain economically producible oil or gas on the basis of
available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a
well penetration unless geoscience, engineering, or performance data and
reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a
highest known oil (HKO) elevation and the potential exists for an associated
gas cap, proved oil reserves may be assigned in the structurally higher
portions of the reservoir only if geoscience, engineering, or performance
data and reliable technology establish the higher contact with reasonable
certainty.
(iv) Reserves which can be produced economically through application of
improved recovery techniques (including, but not limited to, fluid injection)
are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir
with properties no more favorable than in the reservoir as a
whole, the operation of an installed program in the reservoir or
an analogous reservoir, or other evidence using reliable
technology establishes the reasonable certainty of the
engineering analysis on which the project or program was based;
and
(B) The project has been approved for development by all necessary
parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which
economic producibility from a reservoir is to be determined. The price shall
be the average price during the 12-month period prior to the ending date of
the period covered by the report, determined as an unweighted arithmetic
average of the first-day-of-the-month price for each month within such period,
unless prices are defined by contractual arrangements, excluding escalations
based upon future conditions.
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For the Calendar Year 2016
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.
(i) When deterministic methods are used, it is as likely as not that
actual remaining quantities recovered will exceed the sum of estimated proved
plus probable reserves. When probabilistic methods are used, there should be
at least a 50% probability that the actual quantities recovered will equal
or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to
proved reserves where data control or interpretations of available data are
less certain, even if the interpreted reservoir continuity of structure or
productivity does not meet the reasonable certainty criterion. Probable
reserves may be assigned to areas that are structurally higher than the
proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental
quantities associated with a greater percentage recovery of the hydrocarbons
in place than assumed for proved reserves.
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North European Oil Royalty Trust November 30, 2016
Calculation of the Cost Depletion Percentage Page 15
For the Calendar Year 2016
Possible Reserves
-----------------
Possible reserves are those additional reserves that are less certain to be
recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately
recovered from a project have a low probability of exceeding proved plus
probable plus possible reserves. When probabilistic methods are used, there
should be at least a 10% probability that the total quantities ultimately
recovered will equal or exceed the proved plus probable plus possible
reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent
to probable reserves where data control and interpretations of available data
are progressively less certain. Frequently, this will be in areas where
geoscience and engineering data are unable to define clearly the area and
vertical limits of commercial production from the reservoir by a defined
project.
(iii) Possible reserves also include incremental quantities associated
with a greater percentage recovery of the hydrocarbons in place than the
recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible
reserves estimates must be based on reasonable alternative technical and
commercial interpretations within the reservoir or subject project that are
clearly documented, including comparisons to results in successful similar
projects.
(v) Possible reserves may be assigned where geoscience and engineering
data identify directly adjacent portions of a reservoir within the same
accumulation that may be separated from proved areas by faults with
displacement less than formation thickness or other geological
discontinuities and that have not been penetrated by a wellbore, and the
registrant believes that such adjacent portions are in communication with the
known (proved) reservoir. Possible reserves may be assigned to areas that are
structurally higher or lower than the proved area if these areas are in
communication with the proved reservoir.
(vi) Pursuant to paragraph (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.
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Calculation of the Cost Depletion Percentage Page 16
For the Calendar Year 2016
Developed Oil and Gas Reserves
------------------------------
Developed oil and gas reserves are reserves of any category that can be
expected to be recovered:
(i) Through existing wells with existing equipment and operating methods
or in which the cost of the required equipment is relatively minor compared
to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational
at the time of the reserves estimate if the extraction is by means not
involving a well.
Undeveloped Oil and Gas Reserves
--------------------------------
Undeveloped oil and gas reserves are reserves of any category that are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for
recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly
offsetting development spacing areas that are reasonably certain of
production when drilled, unless evidence using reliable technology exists
that establishes reasonable certainty of economic producibility at greater
distances.
(ii) Undrilled locations can be classified as having undeveloped reserves
only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless the specific circumstances,
justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be
attributable to any acreage for which an application of fluid injection or
other improved recovery technique is contemplated, unless such techniques
have been proved effective by actual projects in the same reservoir or an
analogous reservoir, as defined in paragraph (a)(2) of this section, or by
other evidence using reliable technology establishing reasonable certainty.
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.
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Calculation of the Cost Depletion Percentage Page 17
For the Calendar Year 2016
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.
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For the Calendar Year 2016
CERTIFICATE OF QUALIFICATION
----------------------------
I, Allen C. Barron, Registered Professional Engineer, do hereby
certify:
1. That I am President of the consulting firm of Ralph E. Davis
Associates, LLC with offices at 711 Louisiana St., Suite 3100,
Houston, Texas 77002.
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, 2016 for the
purpose of calculating the cost depletion percentage applicable
to Trust unit owners for the 2016 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 Houston and that I graduated
with a Bachelor of Science Degree in Chemical Engineering with
a Petroleum Engineering Option in 1968.
5. That I am a Registered Professional Engineer in the State of
Texas, Registration Number 49284, and that I am a member in
good standing of the National Society of Professional Engineers,
the Texas Society of Professional Engineers, the Society of
Petroleum Engineers, the Society of Petroleum Evaluation
Engineers, the American Association of Petroleum geologists
and other industry organizations.
6. That I have in excess of forty-eight years of experience in the
evaluation of oil and gas properties in the United States,
Canada, South America, Asia and Germany, and that I have
been practicing as a consultant in petroleum reservoir
engineering since 1978.
SIGNED: November 30, 2016
RALPH E. DAVIS ASSOCIATES, LLC
/s/ Allen C. Barron
---------------------------------
Allen C. Barron, P.E.
Presiden
