<SEC-DOCUMENT>0000072633-15-000026.txt : 20151230
<SEC-HEADER>0000072633-15-000026.hdr.sgml : 20151230
<ACCEPTANCE-DATETIME>20151230120814
ACCESSION NUMBER: 0000072633-15-000026
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 4
CONFORMED PERIOD OF REPORT: 20151030
FILED AS OF DATE: 20151230
DATE AS OF CHANGE: 20151230
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: NORTH EUROPEAN OIL ROYALTY TRUST
CENTRAL INDEX KEY: 0000072633
STANDARD INDUSTRIAL CLASSIFICATION: OIL ROYALTY TRADERS [6792]
IRS NUMBER: 222084119
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1031
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-08245
FILM NUMBER: 151312763
BUSINESS ADDRESS:
STREET 1: P O BOX 456
STREET 2: 43 WEST FRONT STREET SUITE 19-A
CITY: RED BANK
STATE: NJ
ZIP: 07701
BUSINESS PHONE: 7327414008
MAIL ADDRESS:
STREET 1: P O BOX 456
STREET 2: 43 WEST FRONT STREET SUITE 19-A
CITY: RED BANK
STATE: NJ
ZIP: 07701
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>tenk15.txt
<TEXT>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended October 31, 2015 or
----------------
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to .
---------------- ----------------
Commission file number 1-8245
------
NORTH EUROPEAN OIL ROYALTY TRUST
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Delaware 22-2084119
----------------------- ------------------------------------
(State of organization) (IRS Employer Identification Number)
Suite 19A, 43 West Front Street, Red Bank, N.J. 07701
---------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number including area code: 732-741-4008
---------------------------------------------------------------
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
---------------------------- -----------------------------------------
Units of Beneficial Interest New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes No X
----- -----
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes No X
----- -----
[X] Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
----- -----
- 2 -
Indicate by check mark whether the registrant has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File required
to be submitted and posted pursuant to Rule 405 of Regulation S-T (section
232.405 of this chapter) during the preceding 12 months (or for such shorter
period that the registrant was required to submit and post such files).
Yes No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated
filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
(Check one):
Large accelerated filer Accelerated filer X
----- -----
Non-accelerated filer Smaller reporting company
----- -----
Indicate by check mark whether the registrant is a shell company (as defined
in Rule 12b-2 of the Exchange Act). Yes No X
----- -----
As of April 30, 2015, the aggregate market value of outstanding units of
beneficial interest of the registrant held by non-affiliates of the
registrant was $128,984,981 on such date.
As of December 30, 2015, there were 9,190,590 units of beneficial interest
("units") of the registrant outstanding.
Documents Incorporated by Reference
-----------------------------------
Items 10, 11, 12, 13 and 14 of Part III have been partially or wholly omitted
from this report and the information required to be contained therein is
incorporated by reference from the registrant's definitive proxy statement
for the 2015 Annual Meeting to be held on February 16, 2016.
- 3 -
Table of Contents
Page
----
PART I
Item 1. Business..................................................... 4
Item 1A. Risk Factors................................................. 8
Item 1B. Unresolved Staff Comments.................................... 10
Item 2. Properties................................................... 11
Item 3. Legal Proceedings............................................ 14
Item 4. Mine Safety Disclosures...................................... 14
PART II
Item 5. Market for Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchase of Equity
Securities.................................................. 15
Item 6. Selected Financial Data...................................... 17
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk... 28
Item 8. Financial Statements and Supplementary Data.................. 29
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 39
Item 9A. Controls and Procedures...................................... 39
Item 9B. Other Information............................................ 41
PART III
Item 10. Directors, Executive Officers and Corporate Governance....... 42
Item 11. Executive Compensation....................................... 42
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.................. 42
Item 13. Certain Relationships and Related Transactions, and Director
Independence................................................ 42
Item 14. Principal Accountant Fees and Services....................... 43
PART IV
Item 15. Exhibits and Financial Statement Schedules................... 43
Signatures............................................................. 44
Exhibit Index.......................................................... 45
- 4 -
PART I
Item 1. Business.
--------
(a) General Development of Business.
-------------------------------
North European Oil Royalty Trust (the "Trust") is a grantor trust
which, on behalf of the owners of beneficial interest in the Trust (the "unit
owners"), holds overriding royalty rights covering gas and oil production in
certain concessions or leases in the Federal Republic of Germany. The rights
are held under contracts with local German exploration and development
subsidiaries of ExxonMobil Corp. ("ExxonMobil") and the Royal Dutch/Shell
Group of Companies ("Royal Dutch/Shell Group"). Under these contracts, the
Trust receives various percentage royalties on the proceeds of the sales of
certain products from the areas involved. At the present time, royalties
are received for sales of gas well gas, oil well gas, crude oil, distillate
and sulfur. See Item 2 of this Report for descriptions of the relationships
of these companies and certain of these contracts.
The royalty rights were received by the Trust from North European
Oil Company (the "Company") upon dissolution of the Company in September
1975. The Company was organized in 1957 as the successor to North European
Oil Corporation (the "Corporation"). The Trust is administered by trustees
(the "Trustees") under an Agreement of Trust dated September 10, 1975, as
amended (the "Trust Agreement").
Neither the Trust nor the Trustees on behalf of the Trust conduct
any active business activities or operations. The function of the Trustees
is to monitor, verify, collect, hold, invest and distribute the royalty
payments made to the Trust. Under the Trust Agreement, the Trustees make
quarterly distributions of the net funds received by the Trust on behalf of
the unit owners. Funds temporarily held by the Trust are invested in
interest bearing bank deposits, money market accounts, certificates of
deposit, U.S. Treasury Bills or other government obligations.
There has been no significant change in the principal operation or
purpose of the Trust during the past fiscal year.
As part of the Sarbanes-Oxley Act of 2002 ("SOX"), the Securities
and Exchange Commission (the "SEC") adopted rules implementing
legislation concerning governance matters for publicly held entities. The
Trust is complying with the requirements of the SEC and SOX and, at this
time, the Trustees have chosen not to request any relief from those
provisions based on the passive nature of the Trust but may do so in the
future. In that connection, the Trustees have directed that certain of the
additional statements and disclosures set forth or incorporated by reference
in this Report, which the SEC requires of corporations, be made even though
some of such statements and disclosures might not now or in the future be
required to be made by the Trust.
In addition, the New York Stock Exchange (the "NYSE"), where units
of beneficial interest of the Trust are listed for trading, has additional
corporate governance rules as set forth in Section 303A of the NYSE Listed
Company Manual. Most of the governance requirements promulgated by the NYSE
are not applicable to the Trust, which is a passive entity acting as a
royalty trust and holds only overriding royalty rights. The Trust does not
- 5 -
engage in any operating or active business. The Trustees have, however,
chosen to constitute an Audit Committee and a Compensation Committee but
may not necessarily do so in the future.
(b) Financial Information about Segments.
------------------------------------
Since the Trust conducts no active business operations, an
analysis by segments is accordingly not applicable to the Trust. To the
extent that royalty income received by the Trust is attributable to sales
of different products, to sales from different geographic areas or to sales
by different operating companies, this information is set forth in Item 2 of
this Report and the Exhibit described in that Item 2.
(c) Narrative Description of Business.
---------------------------------
Under the Trust Agreement, the Trust conducts no active business
operations and is restricted to collection of income from royalty rights and
distribution to unit owners of the net income after payment of administrative
and related expenses.
The overriding royalty rights held by the Trust are derived from
contracts and agreements originally entered into by German subsidiaries of
the predecessor Corporation during the early 1930s. The Trust's primary
royalty rights are based on government granted concessions and remain in
effect as long as there are continued production activities and/or
exploration efforts by the operating companies. It is generally anticipated
that the operating companies will continue production where it remains
economically profitable for them to do so. In addition, the Trust holds
other royalty rights, which are based on leases which have passed their
original expiration dates. These leases remain in effect as long as there
is continued production or the lessor does not cancel the lease. Individual
lessors will normally not seek termination of the rights originally granted
because the leases provide for royalty payments to the lessors if sales of
oil or gas result from discoveries made on the leased land. Additionally,
termination by individual lessors would result in the escheat of mineral
rights to the applicable state.
Royalties are paid to the Trust on sales from production under
these leases and concessions by the operating companies on a regular monthly
or quarterly basis pursuant to the royalty agreements. The operating
companies make royalty payments to the Trust exclusively in Euros. As
promptly as possible after the funds are deposited in the Trust's bank
account in Germany, they are converted into U.S. dollars based upon the
mid-day exchange rate in effect on the date the funds are transferred to the
Trust's bank account in the U.S. The Trust does not engage in activities to
hedge against currency risk and the fluctuations in the conversion rate
impact its financial results. However, since the actual royalty deposits are
held as Euros for such a limited time, the market risk with respect to these
deposits is small. The Trust has not experienced any difficulty in
effecting the conversion of Euros into U.S. dollars.
As the holder of overriding royalty rights, the Trust has no legal
ability, whether by contract or operation of law, to compel production.
Moreover, if an operator should determine to terminate production in any
- 6 -
concession or lease area and to surrender the concession or lease, the
royalty rights for that area would thereby be terminated. Under certain
royalty agreements, the operating companies are required to advise the
Trust of any intention to surrender lease or concession rights. While the
Trust itself is precluded from undertaking any production activities,
possible residual rights might permit the Trust to take up a surrendered
concession or lease and attempt to retain a third party operator to develop
such concession or lease.
The exploration for and the production of gas and oil is a
speculative business. The Trust has no means of ensuring continued income
from its royalty rights at either their present levels or otherwise. The
Trust has no role in any of the operating companies' decision making
processes, such as gas pricing, gas sales or exploration, which can impact
royalty income. In addition, fluctuations in prices and supplies of gas
and oil and the effect these fluctuations might have on royalty income to
the Trust and on reserves net to the Trust cannot be accurately projected.
Finally, natural gas and crude oil are wasting assets. While known reserves
may increase as additional development adds quantities to the reserve
amount, the amount of known and unknown reserves is finite and will decline
over time. Given these factors, along with the uncertainty in worldwide and
local German economic conditions and the fact that the Trustees have no
information beyond that information which is generally available to the
public, the Trustees make no projections regarding future royalty income.
While Germany has laws relating to environmental protection, the
Trustees have no detailed information concerning the present or possible
effect of such laws on operations in areas where the Trust holds royalty
rights on production and sale of products from those areas. There is
currently a moratorium on hydraulic fracturing ("fracking") in place within
Germany. Preliminary indications are that fracking may be permitted on wells
accessing productive zones at depths greater than 3,000 meters. All current
productive zones within the Oldenburg concession are at depths greater than
3,000 meters so fracking would be permitted. The operating companies would
still have to comply with the regulatory requirements governing the use of
fracking which have not yet been finalized. In any event, the operating
companies have stated that they will not be conducting any drilling efforts
during the 2015-2016 period.
Seasonal demand factors affect the income from royalty rights
insofar as they relate to energy demands and increases or decreases in
prices, but on average they are generally not material to the regular annual
income received under the royalty rights.
The Trust, in cooperation with a parallel royalty owner (Unitarian
Universalist Congregation at Shelter Rock, Inc.), arranges for periodic
examinations of the books and records of the operating companies to verify
compliance with the computation provisions of the applicable agreements.
From time to time, these examinations disclose computational errors or errors
from inappropriate application of existing agreements and appropriate
adjustments are requested and made. These periodic examinations may also
disclose matters that are subject to dispute between the parties.
Historically, these disputes have been resolved through negotiations.
- 7 -
(d) Financial Information about Geographic Areas.
---------------------------------------------
The Trust does not engage in any active business operations, and
its sources of income are the overriding royalty rights covering gas, sulfur
and oil production in certain areas in Germany and interest on the funds
temporarily invested by the Trustees. In Item 2 of this Report, there is a
schedule (by product, geographic area and operating company) showing the
royalty income received by the Trust during the fiscal year ended
October 31, 2015.
(e) Trustees and Executive Officers of the Trust.
--------------------------------------------
As specified in the Trust Agreement, the affairs of the Trust are
managed by not more than five individual Trustees who receive compensation
determined under that same agreement. One of the Trustees is designated as
Managing Trustee. Robert P. Adelman has served as Managing Trustee (non-
executive) since November 1, 2006. In addition, Samuel M. Eisenstat serves
as Chairman for the Audit and Compensation Committees, and Lawrence A. Kobrin
serves as Clerk to the Trustees (a role similar to that of a corporate
secretary). For these services, these three individuals receive additional
compensation.
Day-to-day matters are handled by the Managing Director, John R.
Van Kirk, who also serves as CEO and CFO. John R. Van Kirk has held the
position of Managing Director of the Trust since November 1990. The Managing
Director provides office space and services at cost to the Trust.
In addition to the Managing Director, the Trust has one
administrative employee in the United States, whose title is Administrator.
The Trust has retained the services of a consultant in Germany who has broad
experience in the petroleum industry and from whom it receives reports on a
regular basis. The former consultant in Germany continues to be available
for consultation. The Trust also retains an accounting firm and a legal firm
in Germany to advise and represent the Trust as needed. Because the Trust
has only two employees, employee relations or labor contracts are not
directly material to the business or income of the Trust. The Trustees have
no information concerning employee relations of the operating companies.
(f) Available Information.
---------------------
The Trust maintains a website at www.neort.com. The Trust's annual
reports on Form 10-K, quarterly reports on Form 10-Q and the Definitive Proxy
Statements are available through the Trust's website as soon as reasonably
practicable after such reports are filed with or furnished to the SEC. Press
releases and tax letters are available through the website as soon as
practicable after release. The North European Oil Royalty Trust Agreement
(as amended), the Trust's Code of Conduct and Business Ethics, the Trustees'
Regulations and the Trust's Audit Committee Charter are also available
through the Trust's website. The Trust's website and the information
contained in it and connected to it shall not be deemed incorporated by
reference into this Form 10-K.
- 8 -
Item 1A. Risk Factors.
------------
The results of operations and financial condition of the Trust are
subject to various risks. Some of these risks are described below, and you
should take such risks into account in evaluating the Trust or any investment
decision involving the Trust. This section does not describe all risks that
may be applicable to the Trust and it is intended only as a summary of
certain material risk factors. More detailed information concerning the risk
factors described below is contained in other sections of this Annual Report
on Form 10-K.
The Trust does not conduct any active business activities or operations and
---------------------------------------------------------------------------
has no legal ability to compel production.
-----------------------------------------
The Trust holds overriding royalty rights only. It is a passive
entity and conducts no operations. It can exert no influence on the
operating companies that conduct exploration, drilling, production and sales
activities in the areas covered by the Trust's overriding royalty rights.
Thus, the Trust has no means of ensuring continued income from its
overriding royalty rights. The failure of an operator to conduct its
operations, discharge its obligations, deal with regulatory agencies or
comply with laws, rules and regulations, including environmental laws
and regulations, in a proper manner could have an adverse effect on the
net proceeds payable to the Trust. The Trust also has no right to remove
or replace an operator.
The current operating companies are under no obligation to
continue operations in the royalty areas. Natural gas is a wasting asset.
The production and sale of natural gas, from which the Trust derives its
royalties, reduces the amount of remaining proved producing reserves of
natural gas. If the operating companies do not perform additional
development projects which replace at least a portion of the current
production, the anticipated life of the Trust will not be extended and could
be shortened. Absent further additions to the amount of proved producing
reserves, production and sales will reach a point in the future where the
level of sales will no longer be commercially viable and production will
cease. Ultimately, the amount of known and unknown reserves within a
defined area, such as the Oldenburg concession, is finite and will decline
over time.
Trust reserve estimates depend on many assumptions that may prove to be
-----------------------------------------------------------------------
inaccurate, and these inaccuracies may cause errors in the reserve estimates.
----------------------------------------------------------------------------
The value of Trust units may depend in part on the reserves
attributable to the royalty areas. The calculations performed in the
process of estimating proved producing reserves are inherently uncertain.
The accuracy of any reserve estimate is a function of the quality of
available data, engineering interpretation and judgment, and the assumptions
used regarding the quantities of recoverable natural gas and the future
prices of crude oil and natural gas.
- 9 -
The Trust currently receives quarterly reports from the operating
companies with respect to production and sales on either a well-by-well or an
area-wide basis. The Trust also receives annual reports from the operating
companies with respect to current and planned drilling and exploration
efforts. These reports are very limited in nature. The unified exploration
and production venture, ExxonMobil Production Deutschland GmbH ("EMPG"),
which provides these reports to the Trust, continues to limit the information
flow to that which is required by German law, and the Trust has no legal or
contractual right to compel the issuance of additional information. The
Trust's inability to compel the delivery of detailed information with respect
to individual wells increases the possibility of inaccuracy in the petroleum
engineering consultant's estimates of reserves.
Actual production, revenues and expenditures by the operating
companies for the royalty areas, and therefore actual net proceeds payable
to the Trust, will vary from estimates and those variations could be material.
There is currently a moratorium on fracking in place in Germany. When or if
the moratorium will be lifted is unknown at this time. We cannot estimate
the impact the absence of fracking may have had, or will have, on the
development of additional reserves.
The effects of fluctuations in prices of gas and oil and changes in worldwide
-----------------------------------------------------------------------------
and local economic conditions on the royalty income paid to the Trust cannot
----------------------------------------------------------------------------
be accurately projected.
-----------------------
The Trust's distributions are highly dependent upon the prices
realized from the sale of natural gas and a decrease in such prices could
reduce the amount of cash distributions paid to unit owners.
Oil and natural gas prices and demand for these products can
fluctuate widely in response to a variety of factors that are beyond the
control of the Trust. Factors that contribute to these fluctuations include,
among others: (1) worldwide and German economic conditions and levels of
economic activity; (2) political and economic conditions in major oil
producing regions, especially in the Middle East and Russia; (3) weather
conditions; (4) the price of oil or natural gas imported into Germany; (5)
the level of consumer demand in Germany; (6) the increasing role of alternate
energy sources along with the German government's and European Union's role
in promoting those sources; and (7) German and European Union governmental
actions intended to broaden sources of energy supply.
When oil and natural gas prices decline, the Trust is affected in
two ways. First, net income from the royalty areas is reduced. Second,
exploration and development activity by the operating companies on the
royalty areas may decline as some projects may become uneconomic and are
either delayed or eliminated. It is impossible to predict future oil and
natural gas price movements, and this, along with other factors, make
future cash distributions to unit owners impossible to predict.
In recent years, there has been a shift in the structure of
European gas supply contracts resulting in the decoupling of the link between
oil prices and gas prices. Currently, only a minor percentage of gas supply
contracts continue to use some version of the price of oil as a basis for
pricing gas. A comprehensive spot market has developed in Europe in recent
years with corresponding spot market prices for gas where the gas price is
- 10 -
not linked to oil prices. According to the Trust's accountants in Germany,
gas prices are, in the overwhelming majority of contracts, being linked to
spot market prices on a specific exchange with a plus or minus factor
included. While we cannot predict what impact the use of such spot market
prices will have on the Trust and its royalty income, the spot market can be
affected by economic and political changes.
Changes in the dollar value of the Euro have an immediate impact on the Trust.
------------------------------------------------------------------------------
For unit owners, changes in the dollar value of the Euro have an
immediate impact. This impact occurs at the time the royalties, which are
paid to the Trust in Euros, are converted into U.S. dollars at the applicable
exchange rate and transferred from Germany to the United States. In
relation to the dollar, a stronger Euro would yield more dollars and a weaker
Euro would yield less dollars.
Cyber security risks and cyber incidents at the Trust or the operating
----------------------------------------------------------------------
companies could adversely affect our business.
----------------------------------------------
Cyber incidents can result from deliberate attacks or unintentional
events. These incidents can include, but are not limited to, gaining
unauthorized access to digital systems for purposes of misappropriating
assets or sensitive information, corrupting data, or causing operational
disruption. The result of these incidents could include, but are not limited
to, disrupted operations, misstated financial data, liability for stolen
assets or information, increased cyber security protection costs, litigation
and reputational damage adversely affecting investor confidence.
Item 1B. Unresolved Staff Comments.
-------------------------
None.
- 11 -
Item 2. Properties.
----------
The properties of the Trust, which the Trust and Trustees hold
pursuant to the Trust Agreement on behalf of the unit owners, are overriding
royalty rights on sales of gas, sulfur and oil under certain concessions or
leases in the Federal Republic of Germany. The actual leases or concessions
are held either by Mobil Erdgas-Erdol GmbH ("Mobil Erdgas"), a German
operating subsidiary of ExxonMobil, or by Oldenburgische Erdolgesellschaft
("OEG"). As a result of direct and indirect ownership, ExxonMobil owns two-
thirds of OEG and the Royal Dutch/Shell Group owns one-third of OEG. The
Oldenburg concession (1,386,000 acres), covering virtually the entire former
Grand Duchy of Oldenburg and located in the German federal state of Lower
Saxony, provides nearly 100% of the royalties received by the Trust. BEB
Erdgas und Erdol GmbH ("BEB"), a joint venture in which ExxonMobil and the
Royal Dutch/Shell Group each own 50%, administers the concession held by
OEG. In 2002, Mobil Erdgas and BEB formed EMPG to carry out all exploration,
drilling and production activities. All sales activities are still handled
by either Mobil Erdgas or BEB.
Vermilion Energy Inc. ("Vermilion"), a Canadian based international
oil and gas producer, entered into a Farm-In Agreement (the "Farm-In
Agreement") with Mobil Erdgas and BEB. The Farm-In Agreement specifies that
Vermillion has acquired an interest in various portions of a concession or
areas owned by Mobil Erdgas and BEB. Three of these licenses cover the three
northernmost areas of the Oldenburg concession. The Farm-In Agreement commits
Vermilion to financial participation at a 50% level in 11 gross exploratory
wells over the next five years. If Vermilion conducts any successful drilling
within the confines of the Oldenburg concession, sales of that gas or oil
would be subject to the relevant royalty contract.
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 (the "Mobil Agreement"). Under the
Mobil Agreement there is no deduction of costs prior to the calculation of
royalties from gas well gas and oil well gas, which together account for
approximately 98% of all the royalties under said agreement. Historically,
the Trust has received significantly greater royalty payments under the Mobil
Agreement (as compared to the OEG Agreement described below) due to the
higher royalty rate specified by that agreement.
The Trust is also entitled under the Mobil Agreement to receive a
2% royalty on gross receipts of sales of sulfur obtained as a by-product of
sour gas produced from the western part of Oldenburg. The payment of the
sulfur royalty is conditioned upon sales of sulfur by Mobil Erdgas at a
selling price above an agreed upon base price. This base price is adjusted
annually by an inflation index. When the average quarterly selling price
falls below the indexed base price, no sulfur royalties are paid by Mobil
Erdgas. Sulfur royalties under the Mobil Agreement totaled $78,094, $375,614
and $600,514 during fiscal 2015, 2014 and 2013, respectively. The 2015
figure includes negative adjustments from 2014 and 2013 of $80,516 and
$134,832, respectively. The operating companies improperly allocated sulfur
sales to the Mobil Agreement during 2014 and 2013 resulting in the
overpayment of sulfur royalties. In 2015, the operating companies made
negative adjustments to correct the earlier overpayment of sulfur royalties.
- 12 -
Under another set of rights covering the entire Oldenburg
concession and pursuant to the agreement with OEG, the Trust receives
royalties at the rate of 0.6667% on gross receipts from sales by BEB 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 (the "OEG
Agreement"). Under the OEG Agreement, 50% of the field handling, treatment
and transportation costs as reported for state royalty purposes are deducted
from the gross sales receipts prior to the calculation of the royalty to be
paid to the Trust.
In addition to the Oldenburg area, the Trust also holds overriding
royalties at various rates on a number of currently non-producing leases of
various sizes in other areas of Germany. One of these leases, Grosses Meer,
was formerly active but provided no royalties during fiscal 2015, 2014 and
2013.
The following is a schedule of royalty income for the fiscal year
ended October 31, 2015 by product, geographic area and operating company:
By Product:
-----------
Product Royalty Income
------- --------------
Gas Well and Oil Well Gas $ 11,711,215
Sulfur $ 505,660
Oil $ 173,700
By Geographic Area:
-------------------
Area Royalty Income
---- --------------
Western Oldenburg $ 9,649,965
Eastern Oldenburg $ 2,740,610
Non-Oldenburg Areas $ 0
By Operating Company:
---------------------
Company Royalty Income
------- --------------
Mobil Erdgas (under the Mobil Agreement) $ 8,319,874
BEB (under the OEG Agreement) $ 4,070,701
Exhibit 99.1 to this Report is a report entitled Calculation of Cost
Depletion Percentage for the 2015 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, 2015 (the "Cost Depletion Report").
The Cost Depletion Report, dated November 30, 2015, was prepared by Ralph E.
Davis Associates, LLC, 711 Louisiana Street, Suite 3100, Houston, Texas 77002
("Davis Associates"). Davis Associates is an independent petroleum and
natural gas consulting organization specialized in analyzing hydrocarbon
reserves.
- 13 -
The Cost Depletion Report provides documentation supporting the
calculation of the cost depletion percentage for the 2015 calendar year
based on the use of certain production data and the estimated net proved
producing reserves as of October 1, 2015 for the primary area in which the
Trust holds overriding royalty rights. The cost depletion percentage is
prepared for the Trust's unit owners for tax reporting purposes. The cost
depletion percentage recommended by the Trust's independent petroleum and
natural gas consultants for calendar 2015 is 10.2093%. In order to permit
timely filing of the Cost Depletion Report and consistent with the practice
of the Trust in prior years, the information has been prepared for the 12-
month period ended September 30, 2015. While this is one month prior to the
end of the fiscal year of the Trust, the information available for production
and sales through the end of September is the most complete information
available at a date early enough to permit the timely preparation of the
various reports required. Unit owners are referred to the full text of the
Cost Depletion Report contained herein for further details.
The primary purpose of the Cost Depletion Report is the preparation
of the cost depletion percentage for use by unit owners in their own tax
reporting. The only information provided to the Trust that can be utilized
in the calculation of the cost depletion percentage is current and historical
production and sales of proved producing reserves. For the western half of
the Oldenburg Concession, the Trust received quarterly production and sales
information on a well-by-well basis. For the eastern half of the Oldenburg
Concession, the Trust receives cumulative quarterly production and sales
information on two general areas. These general areas encompass numerous
fields with varying numbers of wells. Pursuant to the arrangements under
which the Trust holds royalty rights and the fact that the Trust is not
considered an operating company within Germany, the Trust has no access to
the operating companies' proprietary information concerning producing field
reservoir data. The Trustees have been advised by its German counsel that
publication of such information is not required under applicable law in
Germany and that the royalty rights do not grant the Trust the right to
require or compel the release of such information. Past efforts to obtain
such information from the operating companies have not been successful.
The information made available to the Trust by the operating companies does
not include any of the following: reserve estimates, capitalized costs,
production cost estimates, revenue projections, producing field reservoir
data (including pressure data, permeability, porosity and thickness of
producing zone) or other similar information. While the limited information
available to the Trust permits the calculation of the cost depletion
percentage, it does not change the uncertainty with respect to the estimate
of proved producing reserves. In addition, it is impossible for the Trust or
its consultant to make estimates of proved undeveloped or probable future net
recoverable oil and gas by appropriate geographic areas.
The Trust has the authority to examine, but only for certain
limited purposes, the operating companies' sales and production from the
royalty areas. The Trust also has access to published materials in Germany
from W.E.G. (a German organization equivalent to the American Petroleum
Institute or the American Gas Association). The use of such statistical
information relating to production and sales necessarily involves
extrapolations and projections. Both Davis Associates and the Trustees
believe the use of the material available is appropriate and suitable for
preparation of the cost depletion percentage and the estimates described in
the Cost Depletion Report. Both the Trustees and Davis Associates believe
this report and these estimates to be reasonable and appropriate but assume
that these estimates may vary from statistical estimates which could be made
if reservoir production information (of the kind normally available to
- 14 -
producing companies in the United States) were available. The limited
information available makes it inappropriate to make projections or estimates
of proved or probable reserves of any category or class other than the
estimated net proved producing reserves described in the Cost Depletion
Report.
Attachment A of the Cost Depletion Report shows a schedule of
estimated net proved producing reserves of the Trust's royalty properties,
computed as of October 1, 2015 and a five year schedule of gas, sulfur and
oil sales for the twelve months ended September 30, 2015, 2014, 2013, 2012
and 2011 computed from quarterly sales reports of operating companies
received by the Trust during such periods.
Item 3. Legal Proceedings.
-----------------
The Trust is not a party to any pending legal proceedings.
Item 4. Mine Safety Disclosures.
-----------------------
Not Applicable.
- 15 -
PART II
Item 5. Market for the Registrant's Common Equity, Related Stockholder
--------------------------------------------------------------
Matters and Issuer Purchases of Equity Securities.
--------------------------------------------------
The Trust's units of beneficial interest are listed for trading on
the New York Stock Exchange under the symbol NRT. Under the Trust Agreement,
the Trustees distribute to unit owners, on a quarterly basis, the net royalty
income after deducting expenses and reserving limited funds for anticipated
administrative expenses. As of November 30, 2015, there were 743 unit
owners of record.
The following table presents the high and low closing prices for
the quarterly periods ended in fiscal 2015 and 2014 as reported by the NYSE
as well as the cash distributions paid to unit owners by quarter for the past
two fiscal years.
Fiscal Year 2015
----------------
Low High Distribution
Closing Closing per
Quarter Ended Price Price Unit
------------- --------- --------- ------------
January 31, 2015 $11.80 $18.88 $0.35
April 30, 2015 $11.66 $14.71 $0.33
July 31, 2015 $ 8.73 $14.14 $0.36
October 31, 2015 $ 9.29 $11.46 $0.23
Fiscal Year 2014
----------------
Low High Distribution
Closing Closing per
Quarter Ended Price Price Unit
------------- --------- --------- ------------
January 31, 2014 $18.65 $23.60 $0.54
April 30, 2014 $20.15 $24.40 $0.56
July 31, 2014 $22.87 $24.65 $0.46
October 31, 2014 $18.29 $23.00 $0.39
The quarterly distributions to unit owners represent their
undivided interest in royalty payments from sales of gas, sulfur and oil
during the previous quarter. Each unit owner is entitled to recover a
portion of his or her investment in these royalty rights through a cost
depletion percentage. The calculation of this cost depletion percentage is
set forth in detail in Attachment B to the Cost Depletion Report attached as
Exhibit 99.1 to this Form 10-K.
- 16 -
The Cost Depletion Report has been prepared by Davis Associates
using the limited information described in Item 2 of this Report to which
reference is made. The Trustees believe that the calculations and
assumptions used in the Cost Depletion Report are reasonable according to
the facts and circumstances of available information. The cost depletion
percentage recommended by the Trust's independent petroleum and natural gas
consultants for calendar 2015 is 10.2093%. Specific details relative to the
Trust's income and expenses and cost depletion percentage as they apply to
the calculation of taxable income for the 2015 calendar year are included on
special removable pages in the 2015 Annual Report. Additionally, the tax
reporting information for 2015 is available on the Trust's website,
www.neort.com, in the section marked Tax Letters contained within the Tax
Information section.
The Trust does not maintain any compensation plans under which
units are authorized for issuance. The Trust did not make any repurchases of
Trust units during fiscal 2015, 2014 or 2013 and has never made such
repurchases.
- 17 -
Item 6. Selected Financial Data.
-----------------------
NORTH EUROPEAN OIL ROYALTY TRUST
--------------------------------
SELECTED FINANCIAL DATA (CASH BASIS)
------------------------------------
FOR FIVE FISCAL YEARS ENDED OCTOBER 31, 2015
----------------------------------------------
2015 2014 2013 2012 2011
----------- ----------- ----------- ----------- -----------
German gas,
sulfur
and oil
royalties
received $12,390,575 $18,927,005 $21,546,298 $23,672,808 $25,148,523
=========== =========== =========== =========== ===========
Net Income $11,580,673 $18,044,579 $20,635,306 $22,609,961 $24,195,907
=========== =========== =========== =========== ===========
Net Income
per unit (a) $1.26 $1.96 $2.25 $2.46 $2.63
===== ===== ===== ===== =====
Units of
beneficial
interest
outstanding
at end
of year (a) 9,190,590 9,190,590 9,190,590 9,190,590 9,190,590
Distributions
per unit
paid or to
be paid to
unit owners $1.27 $1.95 $2.25 $2.46 $2.63
===== ===== ===== ===== =====
Total assets
at year end $2,192,866 $3,754,737 $4,918,491 $4,778,200 $5,971,867
========== ========== ========== ========== ==========
(a) Net income per unit was calculated based on the number
of units outstanding at the end of the fiscal year.
- 18 -
Item 7. Management's Discussion and Analysis of Financial Condition
-----------------------------------------------------------
and Results of Operations.
-------------------------
Executive Summary
-----------------
The Trust is a passive fixed investment trust which holds overriding
royalty rights, receives income under those rights from certain operating
companies, pays its expenses and distributes the remaining net funds to its
unit owners. As mandated by the Trust Agreement, distributions of income are
made on a quarterly basis. These distributions, as determined by the
Trustees, constitute substantially all of the funds on hand after provision
is made for Trust expenses then anticipated.
The Trust does not engage in any business or extractive operations
of any kind in the areas over which it holds royalty rights and is precluded
from engaging in such activities by the Trust Agreement. There are no
requirements, therefore, for capital resources with which to make capital
expenditures or investments in order to continue the receipt of royalty
revenues by the Trust.
The properties of the Trust are described in Item 2. Properties of
this Report. Of particular importance with respect to royalty income are the
two royalty agreements, the Mobil Agreement and the OEG Agreement. The Mobil
Agreement covers gas sales from the western part of the Oldenburg concession.
Under the Mobil Agreement, the Trust has traditionally received the majority
of its royalty income due to the higher royalty rate of 4%. The OEG Agreement
covers gas sales from the entire Oldenburg concession but the royalty rate of
0.6667% is significantly lower and gas royalties have been correspondingly
lower.
The operating companies pay monthly royalties to the Trust based
on their sales of natural gas, sulfur and oil. Of these three products,
natural gas provided approximately 95% of the total royalties in fiscal 2015.
The amount of royalties paid to the Trust is primarily based on four factors:
the amount of gas sold, the price of that gas, the area from which the gas is
sold and the exchange rate.
On approximately the 25th of the months of January, April, July and
October, the operating companies calculate the amount of gas sold during the
previous calendar quarter and determine the amount of royalties that were
payable to the Trust based on those sales. This amount is divided into
thirds and forms the monthly royalty payments to the Trust (payable on the
15th of each month) for the Trust's upcoming fiscal quarter. At the same
time that the operating companies determine the actual amount of royalties
that were payable for the prior calendar quarter, they look at the actual
amount of royalties that were paid to the Trust for that period and calculate
the difference between what was paid and what was payable. Additional
amounts payable by the operating companies are paid immediately and any
overpayment is deducted from the payment for the first month of the following
fiscal quarter. In September of each year, the operating companies make the
final determination of any necessary royalty adjustments for the prior
calendar year with a positive or negative adjustment made accordingly.
Currently, the Trust's German accountants review the royalty calculations on
a biennial basis.
- 19 -
There are two types of natural gas found within the Oldenburg
concession, sweet gas and sour gas. Sweet gas has little or no contaminants
and needs no treatment before it can be sold. Sour gas, in comparison, must
be processed at the Grossenkneten desulfurization plant before it can be
sold. The desulfurization process removes hydrogen sulfide and other
contaminants. The hydrogen sulfide in gaseous form is converted to sulfur in
a solid form and sold separately. As needed, EMPG, the operator of the
Grossenkneten desulfurization plant, conducts maintenance on the plant,
generally during the summer months when demand is lower. Maintenance was
conducted from August 31 through October 13, 2015. Historically, sour gas
production capacity during the period of maintenance work has been reduced by
approximately one-third.
Under the Mobil and OEG Agreements, the gas is sold in one of three
ways: (1) directly on the spot market; (2) between Mobil Erdgas and BEB
(intra-company sales); or (3) directly to various distributors under
contracts (which delineate, among other provisions, the timing, manner,
volume and price of the gas sold). While gas supply contracts have in the
past used the price of light heating oil in Germany as one of the primary
pricing components, the number of such contracts now account for only a minor
percentage of all Oldenburg gas sales. In contrast, the price of gas sold on
the spot market or sold between Mobil Erdgas and BEB is largely determined by
the quoted market price of gas then trading as determined by supply and
demand and has no relationship to the price of oil.
The Trust itself does not have access to the specific sales
contracts under which gas from the Oldenburg concession is sold. However,
working under a confidentiality agreement with the operating companies, the
Trust's German accountants review the spot market sales, the intra-company
sales and the contractual sales periodically on behalf of the Trust to verify
their correctness. The Trust's accountants in Germany have begun their
examination of the operating companies for 2013 and 2014.
For unit owners, changes in the dollar value of the Euro have an
immediate impact. This impact occurs at the time the royalties, which are
paid to the Trust in Euros, are converted into U.S. dollars at the applicable
exchange rate and transferred from Germany to the United States. In relation
to the dollar, a stronger Euro would yield more dollars and a weaker Euro
would yield less dollars.
Seasonal demand factors affect the income from the Trust's royalty
rights insofar as they relate to energy demands and increases or decreases in
prices, but on average they are generally not material to the annual income
received under the Trust's royalty rights.
The Trust has no means of ensuring continued income from overriding
royalty rights at their present level or otherwise. The Trust's consultant
in Germany provides general information to the Trust on the German and
European economies and energy markets. This information provides a context
in which to evaluate the actions of the operating companies. The Trust's
consultant receives reports from EMPG with respect to current and planned
drilling and exploration efforts. However, EMPG and the operating companies
continue to limit the information flow to that which is required by German
law.
- 20 -
The low level of administrative expenses of the Trust limits the
effect of inflation on costs. Sustained price inflation would be reflected
in sales prices. Sales prices along with sales volumes form the basis on
which the royalties paid to the Trust are computed.
Results: Fiscal 2015 versus Fiscal 2014
----------------------------------------
For fiscal 2015, the Trust's gross royalty income decreased 34.53%
to $12,390,575 from $18,927,005 in fiscal 2014 continuing to reflect the
disruption in the energy market and the uncertainty of the world economy.
The decrease in royalty income is due to declines in gas sales, gas prices
and average exchange rates under both royalty agreements. The decrease in
the amount of royalty income resulted in the lower distributions. The total
distribution for fiscal 2015 was $1.27 per unit compared to $1.95 per unit
for fiscal 2014. As in prior years, the Trust receives adjustments from the
operating companies based on their final calculations of royalties payable
during the previous periods. During fiscal 2015 the combination of positive
and negative adjustments reduced royalty income by $592,626, the equivalent
of $0.0645 per unit. Due to the incorrect allocation of sulfur sales under
the Mobil Sulfur Agreement, an additional negative adjustment of $215,348,
the equivalent of $0.0234 per unit, was assessed. During fiscal 2014, the
negative adjustments decreased royalty income by $52,676, the equivalent of
$0.0057 per unit.
Gas sales under the Mobil Agreement declined 7.84% to 28.729
Billion cubic feet ("Bcf") in fiscal 2015 from 31.172 Bcf in fiscal 2014.
A significant portion of this decline occurred during the 4th fiscal quarter
and was likely caused by the partial shutdown of the Grossenkneten
desulfurization plant for a six week period. Since the Trust does not
receive information about the decision making process of the operating
companies, it is impossible to determine to what extent, if any, which
factors may have impacted gas sales. However, according to the Trust's
consultant in Germany, it is likely that some portion of the decline in gas
production is due to the normal reduction in well pressure that is
experienced over time.
Quarterly and Yearly Gas Sales under the Mobil Agreement in Billion cubic feet
------------------------------------------------------------------------------
Fiscal Quarter 2015 Gas Sales 2014 Gas Sales Percentage Change
-------------- ---------------- ---------------- -----------------
First 7.876 8.108 - 2.86%
Second 7.642 7.651 - 0.12%
Third 7.382 7.738 - 4.60%
Fourth 5.829 7.675 -24.05%
-------------- ---------------- ---------------- -----------------
Fiscal Year Total 28.729 31.172 - 7.84%
- 21 -
Average prices for gas sold under the Mobil Agreement decreased
10.99% to 2.2162 Euro cents/kWh ("Ecents/kWh") in fiscal 2015 from 2.4899
Ecents/kWh in fiscal 2014.
Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour
------------------------------------------------------------------------------
Fiscal Quarter 2015 Gas Prices 2014 Gas Prices Percentage Change
-------------- ----------------- ----------------- -----------------
First 2.3538 2.7458 -14.28%
Second 2.3212 2.6635 -12.85%
Third 2.0017 2.3661 -15.40%
Fourth 2.1662 2.1709 - 0.22%
-------------- ----------------- ----------------- -----------------
Fiscal Year Avg. 2.2162 2.4899 -10.99%
Converting gas prices into more familiar terms, using the average
exchange rate, yielded a price of $7.22 per thousand cubic feet ("Mcf"), a
25.18% decrease from fiscal 2014's average price of $9.65/Mcf. For fiscal
2015, royalties paid under the Mobil Agreement were converted and transferred
at an average Euro/dollar exchange rate of $1.1323, a decrease of 16.12%
from the average Euro/dollar exchange rate of $1.3499 for fiscal 2014.
Average Euro Exchange Rate under the Mobil Agreement
----------------------------------------------------------------------------
2015 Average 2014 Average
Fiscal Quarter Euro Exchange Rate Euro Exchange Rate Percentage Change
-------------- ------------------ ------------------ -----------------
First 1.2127 1.3597 -10.81%
Second 1.0754 1.3776 -21.94%
Third 1.1113 1.3577 -18.15%
Fourth 1.1301 1.2944 -12.69%
-------------- ------------------ ------------------ -----------------
Fiscal Year Avg. 1.1323 1.3499 -16.12%
Excluding the effects of differences in prices and average exchange
rates, the combination of royalty rates on gas sold from western Oldenburg
results in an effective royalty rate approximately seven times higher than
the royalty rate on gas sold from eastern Oldenburg. This is of particular
significance to the Trust since gas sold from western Oldenburg provides the
bulk of royalties paid to the Trust. For fiscal 2015, the volume of gas sold
from western Oldenburg accounted for only 32.66% of the volume of all gas
sales. However, western Oldenburg gas royalties provided approximately
79.32% or $9,289,836 out of a total of $11,711,215 in overall Oldenburg gas
royalties.
Gas sales under the OEG Agreement decreased 9.47% to 87.952 Bcf in
fiscal 2015 from 97.155 Bcf in fiscal 2014. A significant portion of this
decline occurred during the fourth fiscal quarter and was likely caused by
the partial shutdown of the Grossenkneten desulfurization plant for a six
week period. Since the Trust does not receive information about the decision
making process of the operating companies, it is impossible to determine to
what extent, if any, which factors may have impacted gas sales. However,
according to the Trust's consultant in Germany, it is likely that some
portion of the decline in gas production is due to the normal reduction in
well pressure that is experienced over time.
- 22 -
Quarterly and Yearly Gas Sales under the OEG Agreement in Billion cubic feet
----------------------------------------------------------------------------
Fiscal Quarter 2015 Gas Sales 2014 Gas Sales Percentage Change
-------------- ---------------- ---------------- -----------------
First 23.497 25.467 - 7.74%
Second 23.137 24.355 - 5.00%
Third 22.590 24.194 - 6.63%
Fourth 18.728 23.139 -19.06%
-------------- ---------------- ---------------- -----------------
Fiscal Year Total 87.952 97.155 - 9.47%
Average gas prices for gas sold under the OEG Agreement decreased
10.47% to 2.2939 Ecents/kWh in fiscal 2015 from 2.5622 Ecents/kWh in
fiscal 2014.
Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour
----------------------------------------------------------------------------
Fiscal Quarter 2015 Gas Prices 2014 Gas Prices Percentage Change
-------------- ----------------- ----------------- -----------------
First 2.4808 2.7962 -11.28%
Second 2.4128 2.7096 -10.95%
Third 2.0401 2.4367 -16.28%
Fourth 2.2187 2.2803 - 2.70%
-------------- ----------------- ----------------- -----------------
Fiscal Year Avg. 2.2939 2.5622 -10.47%
Converting gas prices into more familiar terms, using the average
exchange rate, yielded a price of $7.29/Mcf, a 24.85% decrease from fiscal
2014's average price of $9.70/Mcf. For fiscal 2015, royalties paid under
the OEG Agreement were converted and transferred at an average Euro/dollar
exchange rate of $1.1291, a decrease of 16.41% from the average Euro/dollar
exchange rate of $1.3507 for fiscal 2014.
Average Euro Exchange Rate under the OEG Agreement
----------------------------------------------------------------------------
2015 Average 2014 Average
Fiscal Quarter Euro Exchange Rate Euro Exchange Rate Percentage Change
-------------- ------------------ ------------------ -----------------
First 1.1973 1.3604 -11.99%
Second 1.0830 1.3774 -21.37%
Third 1.1159 1.3577 -17.81%
Fourth 1.1309 1.2891 -12.27%
-------------- ------------------ ------------------ -----------------
Fiscal Year Avg. 1.1291 1.3507 -16.41%
Interest income for fiscal 2015 decreased 49.59% to $9,439 as
compared to $18,724 for fiscal 2014 reflecting the reduction in royalty
receipts. Trust expenses decreased 9.08% to $819,341 in fiscal 2015 from
$901,150 in fiscal 2014 primarily due to the absence of accounting costs
associated with the biennial examination of the royalty calculations by the
German operating companies and the reduction in Trustees fees as specified
according to the provisions of the Trust Agreement.
- 23 -
Results: Fiscal 2014 versus Fiscal 2013
----------------------------------------
For fiscal 2014, the Trust's gross royalty income decreased 12.16%
to $18,927,005 from $21,546,298 in fiscal 2013. The decrease in royalty
income is due to declines in gas sales and gas prices under both royalty
agreements. The impact of these factors was partially offset by a slight
increase in average exchange rates. The decrease in the amount of royalty
income resulted in the lower distributions. The total distribution for
fiscal 2014 was $1.95 per unit compared to $2.25 per unit for fiscal 2013.
As in prior years, the Trust receives adjustments from the operating
companies based on their final calculations of royalties payable during the
previous calendar year. The adjustment for the 2013 calendar year
attributable to gas sales under the Mobil Agreement was a reduction of
$561,584 and represented a negative impact of approximately $0.0611 per
unit. This negative adjustment was not applied against the royalty income
payable until the second quarter of fiscal 2015. In the fourth fiscal
quarter of 2013, the 2012 calendar year adjustment represented a minor
positive impact of $0.0043 per unit.
Gas sales under the Mobil Agreement declined 7.85% to 31.172 Bcf
in fiscal 2014 from 33.829 Bcf in fiscal 2013. Since the Trust does not
receive information about the decision making process of the operating
companies, it is impossible to determine to what extent, if any, which
factors may have impacted gas sales. According to the Trust's consultant in
Germany, it is likely that the decline in gas production is due to the
normal reduction in well pressure that is experienced over time.
Quarterly and Yearly Gas Sales under the Mobil Agreement in Billion cubic feet
------------------------------------------------------------------------------
Fiscal Quarter 2014 Gas Sales 2013 Gas Sales Percentage Change
-------------- ---------------- ---------------- -----------------
First 8.108 8.897 - 8.87%
Second 7.651 8.656 -11.61%
Third 7.738 8.102 - 4.49%
Fourth 7.675 8.174 - 6.10%
-------------- ---------------- ---------------- -----------------
Fiscal Year Total 31.172 33.829 - 7.85%
Average prices for gas sold under the Mobil Agreement decreased
8.01% to 2.4899 Ecents/kWh in fiscal 2014 from 2.7066 Ecents/kWh in
fiscal 2013.
Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour
------------------------------------------------------------------------------
Fiscal Quarter 2014 Gas Prices 2013 Gas Prices Percentage Change
-------------- ----------------- ----------------- -----------------
First 2.7458 2.9620 - 7.30%
Second 2.6635 2.4352 + 9.38%
Third 2.3661 2.7651 -14.43%
Fourth 2.1709 2.6583 -18.34%
-------------- ----------------- ----------------- -----------------
Fiscal Year Avg. 2.4899 2.7066 - 8.01%
- 24 -
Converting gas prices into more familiar terms, using the average
exchange rate, yielded a price of $9.65 per Mcf, a 5.76% decrease from fiscal
2013's average price of $10.24/Mcf. For fiscal 2014, royalties paid under
the Mobil Agreement were converted and transferred at an average Euro/dollar
exchange rate of $1.3499, an increase of 2.48% from the average Euro/dollar
exchange rate of $1.3172 for fiscal 2013.
Average Euro Exchange Rate under the Mobil Agreement
----------------------------------------------------------------------------
2014 Average 2013 Average
Fiscal Quarter Euro Exchange Rate Euro Exchange Rate Percentage Change
-------------- ------------------ ------------------ -----------------
First 1.3597 1.3158 + 3.34%
Second 1.3776 1.3105 + 5.12%
Third 1.3577 1.3090 + 3.72%
Fourth 1.2944 1.3334 - 2.92%
-------------- ------------------ ------------------ -----------------
Fiscal Year Avg. 1.3499 1.3172 + 2.48%
Excluding the effects of differences in prices and average exchange
rates, the combination of royalty rates on gas sold from western Oldenburg
results in an effective royalty rate approximately seven times higher than
the royalty rate on gas sold from eastern Oldenburg. This is of particular
significance to the Trust since gas sold from western Oldenburg provides the
bulk of royalties paid to the Trust. For fiscal 2014, the volume of gas sold
from western Oldenburg accounted for only 32.08% of the volume of all gas
sales. However, western Oldenburg gas royalties provided approximately
78.91% or $14,076,205 out of a total of $17,837,669 in overall Oldenburg gas
royalties.
Gas sales under the OEG Agreement decreased 5.91% to 97.155 Bcf in
fiscal 2014 from 103.256 Bcf in fiscal 2013. Since the Trust does not receive
information about the decision making process of the operating companies, it
is impossible to determine to what extent, if any, which factors may have
impacted gas sales. According to the Trust's consultant in Germany, it is
likely that the decline in gas production is due to the normal reduction
in well pressure that is experienced over time.
Quarterly and Yearly Gas Sales under the OEG Agreement in Billion cubic feet
----------------------------------------------------------------------------
Fiscal Quarter 2014 Gas Sales 2013 Gas Sales Percentage Change
-------------- ---------------- ---------------- -----------------
First 25.467 27.117 - 6.08%
Second 24.355 26.508 - 8.12%
Third 24.194 24.436 - 0.99%
Fourth 23.139 25.195 - 8.16%
-------------- ---------------- ---------------- -----------------
Fiscal Year Total 97.155 103.256 - 5.91%
- 25 -
Average gas prices for gas sold under the OEG Agreement decreased
10.29% to 2.5622 Ecents/kWh in fiscal 2014 from 2.8561 Ecents/kWh in
fiscal 2013.
Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour
----------------------------------------------------------------------------
Fiscal Quarter 2014 Gas Prices 2013 Gas Prices Percentage Change
-------------- ----------------- ----------------- -----------------
First 2.7962 3.0363 - 7.91%
Second 2.7096 2.9002 - 6.57%
Third 2.4367 2.7696 -12.02%
Fourth 2.2803 2.7003 -15.55%
-------------- ----------------- ----------------- -----------------
Fiscal Year Avg. 2.5622 2.8561 -10.29%
Converting gas prices into more familiar terms, using the average
exchange rate, yielded a price of $9.70/Mcf, a 7.71% decrease over fiscal
2013's average price of $10.51/Mcf. For fiscal 2014, royalties paid under
the OEG Agreement were converted and transferred at an average Euro/dollar
exchange rate of $1.3507, an increase of 2.82% from the average Euro/dollar
exchange rate of $1.3136 for fiscal 2013.
Average Euro Exchange Rate under the OEG Agreement
----------------------------------------------------------------------------
2014 Average 2013 Average
Fiscal Quarter Euro Exchange Rate Euro Exchange Rate Percentage Change
-------------- ------------------ ------------------ -----------------
First 1.3604 1.3083 + 3.98%
Second 1.3774 1.3105 + 5.10%
Third 1.3577 1.3048 + 4.05%
Fourth 1.2891 1.3352 - 3.45%
-------------- ------------------ ------------------ -----------------
Fiscal Year Avg. 1.3507 1.3136 + 2.82%
Interest income for fiscal 2014 decreased 26.18% to $18,724 as
compared to $25,363 for fiscal 2013 reflecting the reduction in royalty
receipts. Trust expenses decreased 3.76% to $901,150 in fiscal 2014 from
$936,355 in fiscal 2013 primarily due to the absence of legal costs
associated with the previous year's litigation in Germany and the reduction in
Trustees fees as specified according to the provisions of the Trust Agreement.
Report on Exploration and Drilling
----------------------------------
The Trust's German consultant periodically contacts the
representatives of the operating companies to inquire about their planned and
proposed drilling and geophysical work and other general matters. The
following represents a summary of the additional information the Trust's
German consultant received from representatives of EMPG on November 20, 2015.
The Trust is not able to confirm the accuracy of any of the information
supplied by the operating companies. In addition, the operating companies
are not required to take any of the actions outlined and, if they change
their plans with respect to any such actions, they are not obligated to
inform the Trust.
EMPG has continued to abide by its decision to suspend
drilling during 2015 and 2016. However, it has conducted
three workovers of existing wells in 2015 and has planned
- 26 -
five workovers for 2016. Workovers are conducted on older
wells that for various reasons have experienced a drop in
production due to a decline in pressure and can possibly
benefit from further developmental efforts. These reasons
can include the presence of formation debris, bacterial
infestation and formation water influx. Depending on the
difficulties presented by the well and the nature of the
problem, the operators have a number of avenues by which
they can potentially alleviate the problems.
Beyond the four wells still listed as part of the drilling
plans for the Carboniferous zone and subject to the
moratorium on fracking, there are six named wells still
planned and, with one exception, scheduled for the years
2017-2018. Three of the wells, Visbek Z-16a and
Alhorn Z-3, both sour gas wells, and Hemmelte NW T-1,
a sweet gas well, are all located in western Oldenburg.
The most interesting well, but perhaps the riskiest, is
Hemmelte NW T-1 which is planned to develop a new area
of the Bunter zone in western Oldenburg. This well was
initially planned as a dual purpose well tapping both
the Bunter and the deeper Zechstein zones but, due to
technical difficulties, was scaled back. A second well
to access the Zechstein zone at a later date was
initially mentioned but no further information has been
forthcoming. Visbek Z-16a represents a new parallel
sidetrack to a successful sour gas well that suffered
a severe casing collapse six months after it began
production. Alhorn Z-3, another sour gas well, is
intended to re-open the old Alhorn field, which had
been abandoned in 1997. This well's drilling start
has been postponed until 2020.
The remaining three wells, Doetlingen Z-3a and
Goldenstedt Z-12a M1 and Goldenstedt Z-25 M1, both
multilateral wells, are located in eastern Oldenburg
and are all sour gas infill wells. Multilateral wells
take advantage of a single master well to draw from
multiple sidetracks. The obvious advantage is the
cost saving in using a single borehole for more than
one sidetrack.
No firm dates have been announced for any of the six
wells. Information on wells that are not named or are
in preliminary planning stages is not divulged by EMPG.
Critical Accounting Policies
----------------------------
The financial statements, appearing subsequently in this Report,
present financial statement balances and financial results on a modified cash
basis of accounting, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States ("GAAP basis").
Cash basis accounting is an accepted accounting method for royalty trusts
such as the Trust. GAAP basis financial statements disclose income as earned
and expenses as incurred, without regard to receipts or payments. The use of
GAAP would require the Trust to accrue for expected royalty payments. This
- 27 -
is exceedingly difficult since the Trust has very limited information on such
payments until they are received and cannot accurately project such amounts.
The Trust's cash basis financial statements disclose revenue when cash is
received and expenses when cash is paid. The one modification of the cash
basis of accounting is that the Trust accrues for distributions to be paid
to unit owners (those distributions approved by the Trustees for the Trust).
The Trust's distributable income represents royalty income received by the
Trust during the period plus interest income less any expenses incurred by
the Trust, all on a cash basis. In the opinion of the Trustees, the use of
the modified cash basis provides a more meaningful presentation to unit
owners of the results of operations of the Trust and presents to the unit
owners a more accurate calculation of income and expenses for tax reporting
purposes.
Off-Balance Sheet Arrangements
------------------------------
The Trust has no off-balance sheet arrangements.
Contractual Obligations
-----------------------
As shown below, the Trust had no contractual obligations as of
October 31, 2015 other than the distribution announced on October 28, 2015
and payable to unit owners on November 25, 2015, as reflected in the
statement of assets, liabilities and trust corpus.
Payments Due by Period
----------------------
Less than 1-3 3-5 More than
Total 1 Year Years Years 5 Years
------------- ------------- ------- ------- ---------
Distributions
payable to
unit owners $2,113,835 $2,113,835 $0 $0 $0
-----------------------------------
- 28 -
This Report on Form 10-K may contain forward-looking statements
intended to qualify for the safe harbor from liability established by the
Private Securities Litigation Reform Act of 1995. Such statements address
future expectations and events or conditions concerning the Trust. Many
of these statements are based on information provided to the Trust by the
operating companies or by consultants using public information sources.
These statements are subject to certain risks and uncertainties that could
cause actual results to differ materially from those anticipated in any
forward-looking statements. These include:
- risks and uncertainties concerning levels of gas production
and gas sale prices, general economic conditions and currency
exchange rates;
- the ability or willingness of the operating companies to
perform under their contractual obligations with the Trust;
- potential disputes with the operating companies and the
resolution thereof; and
- the risk factors set forth above under Item 1A of this Report.
All such factors are difficult to predict, contain uncertainties
that may materially affect actual results, and are generally beyond the
control of the Trust. New factors emerge from time to time and it is not
possible for the Trust to predict all such factors or to assess the impact
of each such factor on the Trust. Any forward-looking statement speaks
only as of the date on which such statement is made, and the Trust does not
undertake any obligation to update any forward-looking statement to reflect
events or circumstances after the date on which such statement is made.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
----------------------------------------------------------
The Trust does not engage in any trading activities with respect to
possible foreign exchange fluctuations. The Trust does not use any financial
instruments to hedge against possible risks related to foreign exchange
fluctuations. The market risk with respect to funds held in the Trust's
bank account in Germany is negligible because standing instructions at
the Trust's German bank require the bank to process conversions and transfers
of royalty payments as soon as possible following their receipt. The Trust
does not engage in any trading activities with respect to commodity price
fluctuations.
- 29 -
Item 8. Financial Statements and Supplementary Data.
-------------------------------------------
NORTH EUROPEAN OIL ROYALTY TRUST
--------------------------------
INDEX TO FINANCIAL STATEMENTS
------------------------------
Page Number
-----------
Report of Independent Registered Public Accounting Firm F-1
Financial Statements:
Statements of Assets, Liabilities and
Trust Corpus as of October 31, 2015 and 2014 F-2
Statements of Revenue Collected and Expenses Paid
for the Fiscal Years Ended October 31, 2015,
2014 and 2013 F-3
Statements of Undistributed Earnings for the Fiscal
Years Ended October 31, 2015, 2014 and 2013 F-4
Statements of Changes in Cash and Cash Equivalents for
the Fiscal Years Ended October 31, 2015, 2014 and 2013 F-5
Notes to Financial Statements F-6 - F-9
- 30 -
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and the Unit Owners of
North European Oil Royalty Trust
We have audited the accompanying statements of assets, liabilities and trust
corpus of North European Oil Royalty Trust (the "Trust") as of October 31,
2015 and 2014, and the related statements of revenue collected and expenses
paid, undistributed earnings, and changes in cash and cash equivalents for
each of the years in the three-year period ended October 31, 2015. The
Trust's management is responsible for these financial statements. Our
responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
As described in Note 1, these financial statements have been prepared on the
modified cash basis of accounting, which is a comprehensive basis of
accounting other than U.S. generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of the
Trust as of October 31, 2015 and 2014, its revenue collected and expenses
paid, its undistributed earnings, and changes in its cash and cash
equivalents for each of the years in the three-year period ended October 31,
2015, on the basis of accounting described in Note 1.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the Trust's internal control over
financial reporting as of October 31, 2015, based on criteria established in
Internal Control-Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission, and our report dated
December 30, 2015 expressed an unqualified opinion.
/s/ WeiserMazars LLP
New York, NY
December 30, 2015
F-1
- 31 -
NORTH EUROPEAN OIL ROYALTY TRUST
--------------------------------
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (NOTE 1)
-----------------------------------------------------------
OCTOBER 31, 2015 AND 2014
-------------------------
ASSETS 2015 2014
------ ------------ ------------
Current assets --
Cash and cash equivalents $2,192,865 $3,754,736
Producing gas and oil royalty
rights, net of amortization
(Notes 1 and 2) 1 1
------------ ------------
Total Assets $2,192,866 $3,754,737
============ ============
LIABILITIES AND TRUST CORPUS
----------------------------
Current liabilities --
Distributions to be paid
to unit owners, paid
November 2015 and 2014 $2,113,835 $3,584,330
Trust corpus (Notes 1 and 2) 1 1
Undistributed earnings 79,030 170,406
------------ ------------
Total Liabilities and Trust Corpus $2,192,866 $3,754,737
============ ============
The accompanying notes are
an integral part of these financial statements.
F-2
- 32 -
NORTH EUROPEAN OIL ROYALTY TRUST
--------------------------------
STATEMENTS OF REVENUE COLLECTED AND EXPENSES PAID (NOTE 1)
----------------------------------------------------------
FOR THE FISCAL YEARS ENDED OCTOBER 31, 2015, 2014 AND 2013
----------------------------------------------------------
2015 2014 2013
------------ ------------ ------------
German gas, sulfur and
oil royalties received $12,390,575 $18,927,005 $21,546,298
Interest income 9,439 18,724 25,363
------------ ------------ ------------
Trust Income 12,400,014 18,945,729 21,571,661
------------ ------------ ------------
Non-related party expenses (732,209) (819,004) (857,334)
Related party expenses (87,132) (82,146) (79,021)
------------ ------------ ------------
Trust expenses (819,341) (901,150) (936,355)
------------ ------------ ------------
Net income $11,580,673 $18,044,579 $20,635,306
============ ============ ============
Net income per unit $1.26 $1.96 $2.25
======= ======= =======
Distributions per unit paid
or to be paid to
unit owners $1.27 $1.95 $2.25
======= ======= =======
The accompanying notes are
an integral part of these financial statements.
F-3
- 33 -
NORTH EUROPEAN OIL ROYALTY TRUST
--------------------------------
STATEMENTS OF UNDISTRIBUTED EARNINGS (NOTE 1)
---------------------------------------------
FOR THE FISCAL YEARS ENDED OCTOBER 31, 2015, 2014 AND 2013
----------------------------------------------------------
2015 2014 2013
------------ ------------ ------------
Balance, beginning of year $ 170,406 $ 47,477 $ 90,999
Net income 11,580,673 18,044,579 20,635,306
----------- ----------- ------------
11,751,079 18,092,056 20,726,305
Less:
Current year distributions
paid or to be paid
to unit owners 11,672,049 17,921,650 20,678,828
----------- ----------- -----------
Balance, end of year $ 79,030 $ 170,406 $ 47,477
============ ============ ============
The accompanying notes are
an integral part of these financial statements.
F-4
- 34 -
NORTH EUROPEAN OIL ROYALTY TRUST
--------------------------------
STATEMENTS OF CHANGES IN CASH AND CASH EQUIVALENTS (NOTE 1)
-----------------------------------------------------------
FOR THE FISCAL YEARS ENDED OCTOBER 31, 2015, 2014 AND 2013
----------------------------------------------------------
2015 2014 2013
------------ ------------ ------------
Sources of Cash and
Cash Equivalents:
German gas, sulfur and
oil royalties received $12,390,575 $18,927,005 $21,546,298
Interest income 9,439 18,724 25,363
------------ ------------ ------------
12,400,014 18,945,729 21,571,661
------------ ------------ ------------
Uses of Cash and
Cash Equivalents:
Payment of Trust expenses 819,341 901,150 936,355
Distributions paid 13,142,544 19,208,333 20,495,015
------------ ------------ ------------
13,961,885 20,109,483 21,431,370
------------ ------------ ------------
Net increase (decrease)
in cash and cash
equivalents during the year (1,561,871) (1,163,754) 140,291
Cash and cash equivalents,
beginning of year 3,754,736 4,918,490 4,778,199
------------ ------------ ------------
Cash and cash equivalents,
end of year $ 2,192,865 $ 3,754,736 $ 4,918,490
============ ============ ============
The accompanying notes are
an integral part of these financial statements.
F-5
- 35 -
NORTH EUROPEAN OIL ROYALTY TRUST
--------------------------------
NOTES TO FINANCIAL STATEMENTS
-----------------------------
OCTOBER 31, 2015, 2014 AND 2013
-------------------------------
(1) Summary of significant accounting policies:
-------------------------------------------
Basis of accounting -
---------------------
The accompanying financial statements of North European Oil Royalty
Trust (the "Trust") are prepared in accordance with the rules and regulations
of the SEC. Financial statement balances and financial results are presented
on a modified cash basis of accounting, which is a comprehensive basis of
accounting other than accounting principles generally accepted in the United
States ("GAAP basis").
On a modified cash basis, revenue is earned when cash is received and
expenses are incurred when cash is paid. GAAP basis financial statements
disclose revenue as earned and expenses as incurred, without regard to
receipts or payments. The modified cash basis of accounting is utilized to
permit the accrual for distributions to be paid to unit owners (those
distributions approved by the Trustees for the Trust). The Trust's
distributable income represents royalty income received by the Trust during
the period plus interest income less any expenses incurred by the Trust, all
on a cash basis. In the opinion of the Trustees, the use of the modified
cash basis of accounting provides a more meaningful presentation to unit
owners of the results of operations of the Trust.
Producing gas and oil royalty rights -
--------------------------------------
The rights to certain gas and oil royalties in Germany were transferred
to the Trust at their net book value by North European Oil Company (the
"Company") (see Note 2). The net book value of the royalty rights has been
reduced to one dollar ($1) in view of the fact that the remaining net book
value of royalty rights is de minimis relative to annual royalties received
and distributed by the Trust and does not bear any meaningful relationship to
the fair value of such rights or the actual amount of proved producing
reserves.
Federal and state income taxes -
--------------------------------
The Trust, as a grantor trust, is exempt from federal income taxes
under a private letter ruling issued by the Internal Revenue Service.
The Trust has no state income tax obligations.
F-6
- 36 -
Cash and cash equivalents -
---------------------------
Cash and cash equivalents are defined as amounts deposited in bank
accounts and amounts invested in certificates of deposit and U. S. Treasury
bills with original maturities generally of three months or less from the
date of purchase. The investment options available to the Trust are limited
in accordance with specific provisions of the Trust Agreement. As of October
31, 2015, the uninsured amounts held in the Trust's U.S. bank accounts were
$1,940,514. In addition, the Trust held 3,575 Euros, the equivalent of
$3,950, in its German bank account at October 31, 2015.
Net income per unit -
---------------------
Net income per unit is based upon the number of units outstanding at
the end of the period. As of October 31, 2015, 2014 and 2013, there were
9,190,590 units of beneficial interest outstanding.
New accounting pronouncements -
-------------------------------
The Trust is not aware of any recently issued, but not yet effective,
accounting standards that would be expected to have a significant impact on
the Trust's financial position or results of operations.
(2) Formation of the Trust:
-----------------------
The Trust was formed on September 10, 1975. As of September 30, 1975,
the Company was liquidated and the remaining assets and liabilities of the
Company, including its royalty rights, were transferred to the Trust. The
Trust, on behalf of the owners of beneficial interest in the Trust, holds
overriding royalty rights covering gas and oil production in certain
concessions or leases in the Federal Republic of Germany. These rights are
held under contracts with local German exploration and development
subsidiaries of ExxonMobil Corp. and the Royal Dutch/Shell Group of
Companies. Under these contracts, the Trust receives various percentage
royalties on the proceeds of the sales of certain products from the areas
involved. At the present time, royalties are received for sales of gas well
gas, oil well gas, crude oil, distillate and sulfur.
(3) Related party transactions:
---------------------------
John R. Van Kirk, the Managing Director of the Trust, provides office
space and services to the Trust at cost. For such office space and services,
the Trust reimbursed the Managing Director $25,729, $24,634 and $25,602 in
fiscal 2015, 2014 and 2013, respectively.
Lawrence A. Kobrin, a Trustee of the Trust, is a Senior Counsel at Cahill
Gordon & Reindel LLP, which serves as counsel to the Trust. For legal
services, the Trust paid Cahill Gordon & Reindel LLP $61,403, $57,512 and
$53,419 in fiscal 2015, 2014 and 2013, respectively.
F-7
- 37 -
(4) Employee benefit plan:
----------------------
The Trust has established a savings incentive match plan for employees
(SIMPLE IRA) that is available to both employees of the Trust, one of whom is
the Managing Director. The Trustees authorized the making of contributions
by the Trust to the accounts of employees, on a matching basis, of up to 3%
of cash compensation paid to each such employee for the 2015, 2014 and 2013
calendar years.
F-8
- 38 -
(5) Quarterly results (unaudited):
------------------------------
The tables below summarize the quarterly results and distributions of
the Trust for the fiscal years ended October 31, 2015 and 2014:
Fiscal 2015 by Quarter and Year
--------------------------------------------------------------
First Second Third Fourth Year
----------- ---------- ---------- ---------- -------------
Royalties
received $3,442,713 $3,238,135 $3,459,645 $2,250,082 $12,390,575
Net income $3,096,916 $3,074,495 $3,312,307 $2,096,955 $11,580,673
Net income
per unit $0.34 $0.33 $0.36 $0.23 $1.26
Distributions
paid or
to be paid $3,216,706 $3,032,895 $3,308,613 $2,113,835 $11,672,049
Distributions
per unit
paid or to
be paid to
unit owners $0.35 $0.33 $0.36 $0.23 $1.27
Fiscal 2014 by Quarter and Year
--------------------------------------------------------------
First Second Third Fourth Year
----------- ---------- ---------- ---------- -------------
Royalties
received $5,295,533 $5,346,449 $4,462,842 $3,822,181 $18,927,005
Net income $4,958,808 $5,140,001 $4,287,987 $3,657,783 $18,044,579
Net income
per unit $0.54 $0.56 $0.47 $0.40 $1.96
Distributions
paid or
to be paid $4,962,919 $5,146,730 $4,227,671 $3,584,330 $17,921,650
Distributions
per unit
paid or to
be paid to
unit owners $0.54 $0.56 $0.46 $0.39 $1.95
F-9
- 39 -
Item 9. Changes in and Disagreements with Accountants
---------------------------------------------
on Accounting and Financial Disclosure.
--------------------------------------
None.
Item 9A. Controls and Procedures.
-----------------------
Disclosure Controls and Procedures
----------------------------------
The Trust maintains disclosure controls and procedures that are
designed to ensure that information required to be disclosed by the Trust is
recorded, processed, summarized, accumulated and communicated to its
management, which consists of the Managing Director, to allow timely
decisions regarding required disclosure, and reported within the time periods
specified in the Securities and Exchange Commission's rules and forms.
The Managing Director has performed an evaluation of the effectiveness of the
design and operation of the Trust's disclosure controls and procedures as of
October 31, 2015. Based on that evaluation, the Managing Director concluded
that the Trust's disclosure controls and procedures were effective as of
October 31, 2015.
Internal Control over Financial Reporting
-----------------------------------------
Part A. Management's Report on Internal Control over Financial
------------------------------------------------------
Reporting
---------
The Trust's management is responsible for establishing and
maintaining adequate internal control over financial reporting (as such term
is defined in Exchange Act Rule 13a-15(f)) for the Trust. There are inherent
limitations in the effectiveness of any internal control, including the
possibility of human error and the circumvention or overriding of controls.
Accordingly, even effective internal controls can provide only reasonable
assurance with respect to financial statement preparation. Further, because
of changes in conditions, the effectiveness of internal control may vary over
time. Management has evaluated the Trust's internal control over financial
reporting as of October 31, 2015. This assessment was based on criteria for
effective internal control over financial reporting described in the
standards promulgated by the Public Company Accounting Oversight Board and in
the Internal Control-Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on this
evaluation, management concluded that the Trust's internal control over
financial reporting was effective as of October 31, 2015. Management's
assessment of the effectiveness of our internal control over financial
reporting as of October 31, 2015 has been audited by WeiserMazars LLP, the
Trust's independent auditor, as stated in their report which follows.
- 40 -
Part B. Attestation Report of Independent Registered Public
---------------------------------------------------
Accounting Firm
---------------
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and the Unit Owners
of North European Oil Royalty Trust
We have audited North European Oil Royalty Trust's (the "Trust") internal
control over financial reporting as of October 31, 2015, based on criteria
established in Internal Control Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission ("COSO").
The Trust's management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting included in the accompanying
Management's Report on Internal Control over Financial Reporting. Our
responsibility is to express an opinion on the Trust's internal control over
financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting
included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We believe that
our audit provides a reasonable basis for our opinion.
The Trust's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes
in accordance with generally accepted accounting principles. The Trust's
internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of
the assets of the Trust; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts
and expenditures of the Trust are being made only in accordance with
authorizations of management and Trustees of the Trust; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the Trust's assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
- 41 -
In our opinion, the Trust maintained, in all material respects, effective
internal control over financial reporting as of October 31, 2015, based on
criteria established in Internal Control Integrated Framework (2013) issued
by COSO.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the statements of assets,
liabilities and trust corpus as of October 31, 2015 and 2014, and the related
statements of revenue collected and expenses paid, undistributed earnings and
changes in cash and cash equivalents for each of the years in the three-year
period ended October 31, 2015 and our report dated December 30, 2015
expressed an unqualified opinion thereon.
/s/ WeiserMazars LLP
New York, NY
December 30, 2015
Part C. Changes in Internal Control over Financial Reporting
----------------------------------------------------
There have been no changes in the Trust's internal control over
financial reporting that occurred during the fourth quarter of fiscal 2015
that have materially affected, or are reasonably likely to materially affect,
the Trust's internal control over financial reporting.
Item 9B. Other Information.
-----------------
None.
- 42 -
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
------------------------------------------------------
Except as set forth below, the information required by this item
will be contained in the Trust's definitive Proxy Statement for its Annual
Meeting of Unit Owners to be held on February 16, 2016, to be filed pursuant
to Section 14 of the Securities Exchange Act of 1934, and is incorporated
herein by reference.
Code of Ethics
--------------
The Trustees have adopted a Code of Conduct and Business Ethics
(the "Code") for the Trust's Trustees and employees, including the Managing
Director. The Managing Director serves the roles of principal executive
officer and principal financial and accounting officer. A copy of the Code
is available without charge on request by writing to the Managing Director at
the office of the Trust. The Code is also available on the Trust's website,
www.neort.com.
All Trustees and employees of the Trust are required to read and
sign a copy of the Code annually. No waivers or exceptions to the Code have
been granted since the adoption of the Code. Any amendments or waivers to
the Code, to the extent required, will be disclosed in a Form 8-K filing of
the Trust after such amendment or waiver.
Item 11. Executive Compensation.
----------------------
The information required by this item will be contained in the
Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to
be held on February 16, 2016, to be filed pursuant to Section 14 of the
Securities Exchange Act of 1934, and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
--------------------------------------------------------------
and Related Stockholder Matters.
-------------------------------
The information required by this item will be contained in the
Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to
be held on February 16, 2016, to be filed pursuant to Section 14 of the
Securities Exchange Act of 1934, and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director
------------------------------------------------------------
Independence.
------------
The information required by this item will be contained in the
Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to
be held on February 16, 2016, to be filed pursuant to Section 14 of the
Securities Exchange Act of 1934, and is incorporated herein by reference.
- 43 -
Item 14. Principal Accountant Fees and Services.
--------------------------------------
The information required by this item will be contained in the
Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to
be held on February 16, 2016, to be filed pursuant to Section 14 of the
Securities Exchange Act of 1934, and is incorporated herein by reference.
PART IV
Item 15. Exhibits and Financial Statement Schedules.
------------------------------------------
(a) The following is a list of the documents filed as part of this
Report:
1. Financial Statements
Index to Financial Statements for the Fiscal Years
Ended October 31, 2015, 2014 and 2013
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus as of
October 31, 2015 and 2014
Statements of Revenue Collected and Expenses Paid for the
Fiscal Years Ended October 31, 2015, 2014 and 2013
Statements of Undistributed Earnings for the Fiscal Years
Ended October 31, 2015, 2014 and 2013
Statements of Changes in Cash and Cash Equivalents for the
Fiscal Years Ended October 31, 2015, 2014 and 2013
Notes to Financial Statements
2. Exhibits
The Exhibit Index following the signature page lists all
exhibits filed with this Report or incorporated by reference.
- 44 -
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Trust has duly caused this Report to be
signed on its behalf by the undersigned, thereunto duly authorized.
NORTH EUROPEAN OIL ROYALTY TRUST
Dated: December 30, 2015 By: /s/ John R. Van Kirk
--------------------------------------------
John R. Van Kirk, Managing Director
and Principal Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this Report has been signed below by the following persons on behalf
of the Registrant and in the capacities and on the dates indicated.
Dated: December 30, 2015 /s/ Robert P. Adelman
---------------------------------------
Robert P. Adelman, Managing Trustee
Dated: December 30, 2015 /s/ Samuel M. Eisenstat
--------------------------------
Samuel M. Eisenstat, Trustee
Dated: December 30, 2015 /s/ Lawrence A. Kobrin
-------------------------------
Lawrence A. Kobrin, Trustee
Dated: December 30, 2015 /s/ Willard B. Taylor
------------------------------
Willard B. Taylor, Trustee
Dated: December 30, 2015 /s/ Rosalie J. Wolf
----------------------------
Rosalie J. Wolf, Trustee
Dated: December 30, 2015 /s/ John R. Van Kirk
---------------------------------------
John R. Van Kirk, Managing Director
and Principal Accounting Officer
- 45 -
Exhibit Index
-------------
Exhibit Page
------- ----
(3.1) North European Oil Royalty Trust Agreement,
dated September 10, 1975, as amended through
February 13, 2008(incorporated by reference to
Exhibit 3.1 to Current Report on Form 8-K,
filed February 15, 2008. (File No. 0-8378)).
(3.2) Amended and Restated Trustees' Regulations,
amended and restated as of October 31, 2007
(incorporated by reference to Exhibit 3.1 to
Current Report on Form 8-K, filed November 2, 2007
(File No. 0-8378)).
(10.1) Agreement with OEG, dated April 2, 1979,
exhibit to Current Report on Form 8-K
filed May 11, 1979 (incorporated by
reference as Exhibit 1 to Current Report
on Form 8-K, filed May 11, 1979
(File No. 0-8378)).
(10.2) Agreement with Mobil Oil, A.G. concerning
sulfur royalty payment, dated March 30, 1979,
(incorporated by reference to Exhibit 3
to Current Report on Form 8-K, filed
May 11, 1979 (File No. 0-8378)).
(21) There are no subsidiaries of the Trust.
(31) Certification of Chief Executive Officer and Chief 46
Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
(32) Certification of Chief Executive Officer and 48
Chief Financial Officer pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
(99.1) Calculation of Cost Depletion Percentage 49
for the 2015 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, 2015 prepared by
Ralph E. Davis Associates, LLC
(99.2) Order Approving Settlement signed by
Vice Chancellor Jack Jacobs of the
Delaware Court of Chancery
(incorporated by reference as
Exhibit 99.2 to Current Report on
Form 8-K, filed February 26, 1996).
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-31
<SEQUENCE>2
<FILENAME>x31-1230.txt
<TEXT>
- 46 -
Exhibit 31
Certification of Chief Executive Officer
and Chief Financial Officer
Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
I, John R. Van Kirk, certify that:
1. I have reviewed this Annual Report on Form 10-K of North European Oil
Royalty Trust;
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this report;
4. I am responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in
Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under my
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known
to me by others within those entities, particularly during the
period in which this report is being prepared; and
b) Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed
under my supervision, to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles; and
c) Evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report my
conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report
based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the
registrant's most recent fiscal quarter (the registrant's fourth
fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect,
the registrant's internal control over financial reporting; and
- 47 -
5. I have disclosed, based on my most recent evaluation of internal
control over financial reporting, to the registrant's auditors and to
the audit committee of the registrant's board of directors (or persons
performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: December 30, 2015
/s/ John R. Van Kirk
----------------------
John R. Van Kirk
Managing Director
(Chief Executive Officer and
Chief Financial Officer)
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-32
<SEQUENCE>3
<FILENAME>x32-1230.txt
<TEXT>
- 48 -
Exhibit 32
Certification of Chief Executive Officer
and Chief Financial Officer
Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chapter
63, Title 18 U.S.C. Section 1350(a) and (b)), the undersigned hereby
certifies that the Annual Report on Form 10-K for the period ended
October 31, 2015 of North European Oil Royalty Trust ("Trust") fully complies
with the requirements of Section 13(a) or Section 15(d) of the Securities
Exchange Act of 1934 and that the information contained in such Report fairly
presents, in all material respects, the financial condition and results of
operations of the Trust.
Dated: December 30, 2015
/s/ John R. Van Kirk
---------------------
John R. Van Kirk
Managing Director
(Chief Executive Officer and
Chief Financial Officer)
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99
<SEQUENCE>4
<FILENAME>x99-1130.txt
<TEXT>
- 49 -
Exhibit 99.1
NORTH EUROPEAN OIL ROYALTY TRUST
CALCULATION OF COST DEPLETION PERCENTAGE
FOR 2015 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, 2015
Ralph E. Davis Associates, LLC
Houston, Texas
- 50 -
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
- 51 -
Ralph E. Davis Associates, LLC
November 30, 2015
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 2015
Trustees:
In accordance with the request of the Trustees of North European Oil
Royalty Trust (the "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 2015 calendar
year. The cost depletion percentage was prepared for use by individual
Trust unit owners 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 North European
Oil Royalty Trust (the "Trust") in the Northwest German Basin of the Federal
Republic of Germany with an effective date of October 1, 2015.
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, 2015 and the
reported sales are for the twelve month period ending September 30, 2015.
The use of the period ending September 30, 2015 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
- 52 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 2
For the Calendar Year 2015
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
2015 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 2015 calendar year. As detailed in Attachment B, the cost depletion
percentage for the 2015 calendar year for Trust unit owners is equal to
10.2093% of their cost base as of January 1, 2015.
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
- 53 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 3
For the Calendar Year 2015
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 (the "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 98% 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 (the "OEG
Agreement"). Under the OEG Agreement, 50% of the field
handling, treatment and transportation 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 selling price had been
below the indexed base price for more than ten years, but
beginning in the second quarter of fiscal year 2008 the price
for sulfur exceeded the indexed base price. The average
selling price for sulfur continued to exceed the indexed base
price intermittently through fiscal 2011. The Trust received
sulfur royalties under the Mobil Agreement for all four
quarters for fiscal 2012 through fiscal 2015. Sulfur is a
by-product of gas production and is not considered in the
computation of total cost depletion.
- 54 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 4
For the Calendar Year 2015
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. Following earlier renovations and improvements to
the plant, the plant's present input capacity stands at 620 million cubic
feet ("MMcf") per day. The second desulfurization plant, Norddeutsche Erdgas
Aufbereitungs GmbH ("NEAG")was closed at the end of 2013 and all production
from the Rechterfeld, Woestendoellen and Neerstedt fields is being sent to
Grossenkneten.
TOTAL SALES
-----------
During the twelve months ending September 30, 2015, total sales for the
Oldenburg area were as follows:
WEST EAST TOTAL
---- ---- -----
Gas Well Gas-MMcf 28,702 59,211 87,913
Oil Well Gas-MMcf 34 28 62
Oil & Condensate-Barrels 97,690 37,608 135,298
Sulfur-Short Tons 145,716 388,963 534,679
GROSS RESERVES
--------------
Estimated gross remaining proved producing reserves attributable to
the total Oldenburg area as of October 1, 2015 are as follows:
WEST EAST TOTAL
---- ---- -----
Gas Well Gas-MMcf 266,049 377,623 643,672
Oil Well Gas-MMcf 178 111 289
Oil & Condensate-Barrels 911,944 467,109 1,379,053
Sulfur-Short Tons 1,201,404 4,609,627 5,811,031
- 55-
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 5
For the Calendar Year 2015
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, 2015 and net sales for the twelve month period ending September
30, 2015 are as follows:
Reserves Sales
-------- -----
Gas Well Gas-MMcf 14,400 1,642
Oil Well Gas-MMcf 8 2
Oil & Condensate-Barrels 44,174 4,667
Sulfur-Short Tons 58,499 6,090
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
- 56 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 6
For the Calendar Year 2015
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
- 57 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 7
For the Calendar Year 2015
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-four (24)
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 10/1/14
Line (3) is obtained by adding the estimated remaining net proved
producing reserves as of 10/1/14 Line (1) and the adjustments to
reserves during the period Line (2). Therefore Line (3) =
Line (1) + Line (2).
- 58 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 8
For the Calendar Year 2015
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 10/1/14 Line (3). Therefore Line (6) = Line (4) / Line (3).
The product base for each category of proved producing reserves as
of 1/1/14 Line (7) and the adjustment taken during 2014 Line (8)
were obtained from the previous year's report. The product base as
of 1/1/15 Line (9) forms the initial starting point for the
calculation of the cost depletion percentage for the 2015 tax year.
The product base for 1/1/15 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 1/1/15
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 1/1/15 [Sum Line (9)]. Therefore Line (11) =
[Sum Line (10)] / [Sum Line (9)].
The cost depletion percentage represents the total allowable cost
depletion for the 2015 calendar year for the Trust's unit owners, expressed
as a percentage of their cost base as of January 1, 2015.
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
- 59 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 9
For the Calendar Year 2015
ATTACHMENT A
NORTH EUROPEAN OIL ROYALTY TRUST
RESERVE SUMMARY AND FIVE YEAR NET SALES HISTORY
ESTIMATED NET PROVED PRODUCING RESERVES AS OF OCTOBER 1, 2015
-------------------------------------------------------------
OLDENBURG
---------------------------------------------------------------------------
Gas Well Gas Oil Well Gas Oil/Cond. Sulfur
MMcf MMcf Barrels Short Tons
------------ ------------ ---------- ----------
14,400 8 44,174 58,499(1)
FIVE YEAR NET SALES SUMMARY
---------------------------
12 MONTHS ENDING SEPTEMBER 30, 2015
-----------------------------------
OLDENBURG
---------------------------------------------------------------------------
Gas Well Gas Oil Well Gas Oil/Cond. Sulfur
MMcf MMcf Barrels Short Tons
------------ ------------ ---------- ----------
2015 1,642 2 4,667 6,090(1)
2014 1,821 1 4,444 7,436(2)
2013 1,968 1 4,713 8,009(3)
2012 2,174 1 3,897 8,997(4)
2011 2,453 1 4,380 8,243(5)
(1) Royalty payments under the Mobil Erdgas sulfur royalty representing
all four quarters of fiscal 2015 were received.
(2) Royalty payments under the Mobil Erdgas sulfur royalty representing
all four quarters of fiscal 2014 were received.
(3) Royalty payments under the Mobil Erdgas sulfur royalty representing
all four quarters of fiscal 2013 were received.
(4) Royalty payments under the Mobil Erdgas sulfur royalty representing
all four quarters of fiscal 2012 were received.
(5) Royalty payments under the Mobil Erdgas sulfur royalty representing
The second, third and fourth quarters of fiscal 2011 were received.
- 60 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 10
For the Calendar Year 2015
ATTACHMENT B
NORTH EUROPEAN OIL ROYALTY TRUST
CALCULATION OF TOTAL COST DEPLETION PERCENTAGE
For the Year Ending December 31, 2015
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 10-1-14 14,163 6 60,882
2. Adjustments to reserves
during period 1,879 4 -12,041
3. Adjusted est. net proved
producing reserves
as of 10-1-14 16,042 10 48,841
4. Net sales from 10-1-14
to 9-30-15 1,642 2 4,667
5. Estimated remaining net proved
producing reserves
as of 10-1-15 14,400 8 44,174
RESERVE DEPLETION FACTOR
-----------------------------
6. Depletion factor 0.10236 0.20000 0.09555
NEORT WEIGHTED PRODUCT BASE ALLOCATION
-------------------------------------------
7. Product base as of 1-1-14 3.06080 0.00200 0.14471
8. Less adjustments taken
during 2014 0.34871 0.00029 0.00984
9. Product base as of 1-1-15 2.71209 0.00171 0.13487
10. 2015 Adjustment
to product base 0.27760 0.00034 0.01289
- 61 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 11
For the Calendar Year 2015
-----------------------------------------------------------------------------
11. Cost depletion percentage for 2015 calendar year for Trust unit owners
is equal to 10.2093 percent of their 1-1-2015 cost base.
-----------------------------------------------------------------------------
Footnotes:
Line (1) from reserves review as of 10-1-14
Line (2) from reserves review as of 10-1-15
Line (3) = Line (1) + Line (2)
Line (4) from BEB and Mobil Erdgas statements
Line (5) from reserves review as of 10-1-15
Line (6) = Line (4) / Line (3)
Line (7) from 2014 depletion calculations
Line (8) from 2014 depletion calculations
Line (9) = Line (7) - Line (8)
Line (10) = Line (9) x Line (6)
Line (11) = Sum Line (10) / Sum Line (9)
- 62 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 12
For the Calendar Year 2015
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
- 63 -
North European Oil Royalty Trust November 30, 2015
Calculation of the Cost Depletion Percentage Page 13
For the Calendar Year 2015
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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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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For the Calendar Year 2015
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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For the Calendar Year 2015
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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For the Calendar Year 2015
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.
<PAGE>
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For the Calendar Year 2015
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 Street, 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, 2015 for the
purpose of calculating the cost depletion percentage applicable
to Trust unit owners for the 2015 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-five 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, 2015
RALPH E. DAVIS ASSOCIATES, LLC
/s/ Allen C. Barron
---------------------------------
Allen C. Barron, P.E.
President
</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>