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, 2018 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
Securities registered pursuant to Sections 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 X No
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 __
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, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act
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, 2018, the aggregate market value of outstanding units of beneficial interest of the registrant held by non-affiliates of the registrant was $79,822,627 on such date.
As of December 31, 2018, 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 2018 Annual Meeting to be held on February 21, 2019.
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, condensate 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 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) 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 royalties have been deposited in the Trust's bank account in Germany, the Trust's standing instructions with Deutsche Bank are executed thereby converting the majority of the funds into U. S. dollars based upon the available exchange rates. The amount Deutsche Bank converts into dollars provides for the reservation of sufficient funds to handle any outstanding expenses and maintains a minimal balance of 5,000 Euros. Following this conversion to dollars, the royalties are automatically 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 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 generally do not have 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. However, the Trustees were informed by the Trust's German consultant that on July 8, 2016, a hydraulic fracturing ("fracking") law was passed in Germany permitting fracking in sandstone at any depth. The law requires that an environmental impact study be performed as well as requiring that permission by the relevant water authority be granted to protect drinking water supplies. Based upon an analysis of the details of this law, the Trust's German consultant has informed the Trust that fracking will be permitted in all current productive zones within the Oldenburg concession both due to the depths involved and the nature of the productive zones. However, the operating companies would still have to comply with all regulatory requirements governing the use of fracking. The mining authorities are still in the process of finalizing the complete details and procedures required before any fracking may begin.
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), arranges for periodic examinations of the books and records of the operating companies to verify compliance with the computation provisions of the applicable agreements. As a cost savings measure, the royalty examination is conducted on a biennial basis. From time to time, these examinations disclose computational errors or errors from inappropriate application of existing agreements and appropriate adjustments are requested and made. As a result of the amendments to the Trust's royalty agreements which effect pricing simplification, examinations by the Trust's German accountants have been simplified since these examinations are primarily limited to the verification of the gas quantities sold. Although these periodic examinations may also disclose other matters that are subject to dispute between the parties, these disputes have historically been resolved through negotiations. The Trust's accountants in Germany will begin their examination of the operating companies for 2017-2018 in November 2019 when the final sales figures and the German Border Import gas Prices (see page 10) will be available.
(c) Financial Information about Geographic Areas. 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, 2018.
(d) 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. Ahron H. Haspel is independent and has been determined to be a financial expert (both as defined in the SEC rules). Mr. Haspel serves as Chairman for the Audit and Compensation Committees. 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. As a cost saving measure, the Trust is planning to shift to a virtual office format in fiscal 2019. This shift will not impact the operations or administration of 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 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.
(e) Available Information. The Trust maintains a website at www.neort.com. The Trust's Annual Reports, Form 10-K annual reports, Form 10-Q quarterly reports 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.
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.
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 operating companies' 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. Additionally, while the moratorium on fracking has been lifted and there are no wells currently in the drilling portfolio that require fracking, the fracking law has mandated added regulatory steps with respect to all drilling. The law requires that an environmental impact study be performed as well as requiring that permission by the relevant water authority be granted to protect drinking water supplies. These additional regulations will add costs to each well. When used, the process of fracking adds significant costs to drilling. The operating companies will have to evaluate these costs as part of their decision on whether or not to drill.
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. A comprehensive spot market has developed in Europe with corresponding spot market prices for gas where the gas price is not linked to oil prices. According to the Trust's accountants in Germany, gas prices, in the overwhelming majority of contracts, are linked to spot market prices on a specific exchange with a plus or minus factor included. However, following the August 26, 2016 amendments to the royalty agreements regarding the pricing simplification, neither the contractual price nor the spot market price have been a determining factor in the calculation of royalties payable to the Trust. As specified in the amendments, the Trust's pricing procedure now matches the German State royalty calculation basis which is codified in the pertinent German State Royalty Code (Niedersachsische Verordnung uber die Feldes- und die Forderabgabe). As this pricing procedure is currently configured, the state assessment base for natural gas is the average German Border Import gas Price (the "GBIP"). In the royalty calculations for the Trust, the GBIP for the period corresponding to the respective calendar quarter (adjusted by a percentage factor) is the price used in the relevant calculation of quarterly royalties payable. Following the end of a given calendar year, the average GBIP for that year (adjusted by a percentage factor) is the price used in the relevant year-end royalty adjustments.
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 based upon 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. The Trust has undertaken steps to protect itself from cyber security risks, and it does not hold personal data for any unit owners within its computer system. It is believed that the operating companies have undertaken security procedures to protect their operations. Some of the entities with which the Trust works maintain personal data for unit owners on their systems. They are required by various regulations to take steps necessary to ensure the security of their data.
Item 1B. Unresolved Staff Comments.
None
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 of Companies 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 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 effective as of January 1, 2016. The Trust has been advised by its consultant in Germany that, based on conversations with people at EMPG and other sources, the Farm-In Agreement specifies that Vermilion 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 through 2020. Three of these wells will be drilled in areas subject to the Trust's royalties. Vermilion's participation in the development of any well does not impact the Trust's royalty interest and the sale of that gas or oil would be subject to the relevant royalty contract.
Vermilion's first well within the Oldenburg concession is tentatively located in the western portion of the area designated Oldenburg-Land, the southernmost area of the three areas within the concession subject to Vermilion's Farm-In Agreement. Vermilion's well is intended to develop the Rotliegend (Red Sandstone) formation, a previously undeveloped productive zone within the concession but at this time has no start date. Additionally, according to EMPG, Vermilion is expected to drill two other wells within the Oldenburg concession, one in Jeverland and one in Jade-Weser. No details concerning these wells or any other activities by Vermilion are available to the Trust at this date and Vermilion is under no obligation to disclose such information. The information regarding Vermilion's activities within the Oldenburg concession was conveyed to the Trust's German consultant by representatives of EMPG.
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 Sulfur 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 $72,358, $43,932 and ($51,576) during fiscal 2018, 2017 and 2016, respectively. The 2018 figure includes a negative adjustment from 2017 of ($45,785) resulting from the fact that the sulfur price for one quarter fell below the adjusted base price. The 2017 figure includes a negative adjustment from 2016 of ($40,473) and reflects the absence of any payment for sulfur royalties in the third and fourth quarters of fiscal 2017. The 2016 figure includes negative adjustments from 2015, 2013, 2012 and 2011 of ($36,336), ($43,087), ($186,045) and ($56,225), which more than offset sulfur royalties payable. The operating companies had improperly allocated eastern sulfur sales to the Mobil Agreement from 2011 through 2015 resulting in the overpayment of sulfur royalties.
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 and treatment 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.
On August 26, 2016, the Trust executed amendments to its existing royalty agreements with OEG and Mobil establishing a new base for the determination of gas prices upon which the Trust's royalties are determined. This base is set as the state assessment base for natural gas used by the operating companies in their calculation of royalties payable to the State of Lower Saxony. This change reflects a shift from the use of gas ex-field prices ("contractual prices") to the prices calculated for the GBIP. For simplification purposes, we will use "GBIP" when referring to the current state assessment base.
The change to the GBIP is intended to be revenue neutral for the Trust in comparison to the previous pricing methodology. Additionally, this change should reduce the scope and cost of the accounting examination, eliminate ongoing disputes with OEG and Mobil regarding sales to related parties, and reduce prior year adjustments to the normally scheduled year-end reconciliation. The pricing basis has eliminated certain costs (transportation and plant gas storage) that were previously deductible prior to the royalty calculation under the agreement with OEG.
Actual gas sales from the prior calendar quarter are multiplied by the average GBIP for a period starting two months earlier and provide the basis for royalty payments to the Trust during its fiscal quarter. The average GBIP for the corresponding period of actual sales is not available due to the delay in its calculation. For calendar 2016 and forward, the average GBIP under the Mobil and OEG Royalty Agreements was increased by 1% and 3%, respectively. In March of the following calendar year, an average GBIP for the prior calendar year (weighted on a monthly basis by the respective volume of imported gas) is published. In the following calendar year, EMPG makes a final reconciliation based upon the published yearly average GBIP increased by the respective percentage factor and the total volume of gas sold under the royalty agreements during the prior calendar year.
The basis for oil prices is the published price from the State Authority for Mining, Energy and Geology. There are no percentage adjustments factored into the oil royalty calculation. There was no change in the previous methodology used with regard to the determination of royalties attributable to sales of sulfur.
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 2018, 2017 and 2016.
The following is a schedule of royalty income for the fiscal year ended October 31, 2018 by product, geographic area and operating company:
| By Product | |
|---|---|
| Product | Royalty Income |
| Gas Well and Oil Well Gas | $ 6,778,111 |
| Sulfur | $ 284,634 |
| Oil | $ 135,789 |
| By Geographic Area | |
| Area | Royalty Income |
| Western Oldenburg | $ 5,691,631 |
| Eastern Oldenburg | $ 1,506,903 |
| Non-Oldenburg Areas | $ 0 |
| By Operating Company | |
| Company | Royalty Income |
| Mobil Erdgas (under the Mobil Agreement | $ 5,003,106 |
| BEB (under the OEG Agreement) | $ 2,195,428 |
Exhibit 99.1 to this Report is a report entitled Calculation of Cost Depletion Percentage for the 2018 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, 2018 (the "Cost Depletion Report"). The Cost Depletion Report, dated November 30, 2018, was prepared by Graves & Co. Consulting, LLC, 2777 Allen Parkway, Suite 1200, Houston, Texas 77019 ("Graves & Co."). Graves & Co. is an independent petroleum and natural gas consulting organization specialized in analyzing hydrocarbon reserves.
The Cost Depletion Report provides documentation supporting the calculation of the cost depletion percentage for the 2018 calendar year based on the use of certain production data and the estimated net proved producing reserves as of October 1, 2018 for the primary area in which the Trust holds overriding royalty rights. 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, 2018. 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 cost depletion percentage is prepared by Graves & Co. 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 2018 is 11.4193%. 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 2018 calendar year are included on removable pages in the 2018 Annual Report. Additionally, the tax reporting information for 2018 is available on the Trust's website, http://neort.com/tax-letters.html, in the section marked Tax Letters contained within the Tax Information section.
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 their 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 Graves & Co. 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. The Trustees and Graves & Co. 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 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, 2018 and a five-year schedule of gas, sulfur and oil sales for the twelve months ended September 30, 2018, 2017, 2016, 2015 and 2014 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.
PART II
Item 6. Selected Financial Data.
| 2018 | 2017 | 2016 | 2015 | 2014 | |
| German gas, sulfur and oil royalties received | $7,198,534 | $7,762,225 | $6,960,961 | $12,390,575 | $18,927,005 |
| Net Income | $6,407,955 | $7,026,448 | $6,141,141 | $11,580,673 | $18,044,579 |
| Net Income per unit(a) | $0.70 | $0.76 | $0.67 | $1.26 | $1.96 |
| 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 | $0.70 | $0.76 | $0.67 | $1.27 | $1.95 |
| Total assets at year end | $1,457,208 | $2,126,006 | $1,165,348 | $2,192,866 | $3,754,737 |
(a) Net income per unit was calculated based on the number of units outstanding at the end of the fiscal year.
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 94% of the total royalties in fiscal 2018. 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. The pricing component to this royalty calculation no longer conforms to the same period. Due to the delay in the availability of the GBIP, the average GBIP for a three-month period ending two months prior to the end of the relevant calendar quarter is used. The average GBIP is increased by a percentage factor depending upon which royalty agreement forms the underlying basis for the royalty calculation. This timetable, the determination of the appropriate GBIP, and the percentage factor were set forth in the amendments to the Mobil and OEG Royalty Agreements signed on August 26, 2016. The respective royalty 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 would be paid immediately and any overpayment would be deducted from the payment for the first month of the following fiscal quarter. In March of the following calendar year, an average GBIP for the prior calendar year (weighted on a monthly basis by the respective volume of imported gas) is published. In the succeeding calendar 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. They will begin their examination of the operating companies for 2017-2018 in November 2019 when the final sales figures and the GBIP will be available.
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 conducts maintenance on the plant generally during the summer months when demand is lower. The operating companies informed the Trust that, to promote greater efficiency and cost effectiveness, the production capacity of Grossenkneten was reduced by approximately one-third through the retirement of Unit 3 in April 2017. With full operation of the two remaining units, raw gas input capacity stands at approximately 400 million cubic feet ("MMcf") per day.
While originally EMPG had indicated there would be no maintenance conducted during 2018, one of the two units was shut down from March 15 to April 15, 2018. A second unexpected shutdown for both of the units followed for the period from May 18 to June 10, 2018. This shutdown was related to an emissions control issue. While the repairs to address the emissions problem were being conducted, additional problems with a waste heat boiler were discovered in one of the units. Repairs to address these newly discovered problems continued from June 10 to August 21, 2018. During this period, the total throughput capacity was reduced by 40%. As of August 22, 2018, full production capacity at Grossenkneten had been restored.
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 the operating companies will continue to sell gas in one of these three ways, the impact of the respective pricing involved is no longer applicable to the Trust because, under the amended royalty agreements, the price point, which is used as part of the basis for the royalty calculations, is now the average GBIP.
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.
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 2018 versus Fiscal 2017
For fiscal 2018, the Trust's gross royalty income decreased 7.26% to $7,198,534 from $7,762,225 in fiscal 2017. The decrease in the amount of royalty income resulted in the lower distribution. The total distribution for fiscal 2018 was $0.70 per unit compared to $0.76 per unit for fiscal 2017. While gas prices and the average exchange rates under both royalty agreements increased, gas sales under both royalty agreements declined. As a result, royalty income attributable to gas sales under the Mobil Agreement in fiscal 2018 declined by $185,073 as compared to fiscal 2017. Royalty income attributable to gas sales under the OEG Agreement in fiscal 2018 declined by $115,597 as compared to fiscal 2017.
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 2018, the adjustments based on royalties payable for 2017 increased royalty income by $189,529. During fiscal 2017, the adjustments based on royalties payable for 2016 increased royalty income by $411,884. In fiscal 2018 and 2017, Mobil sulfur royalties totaled $72,358 and $43,932, respectively.
Gas sales under the Mobil Agreement declined 19.63% to 18.941 Billion cubic feet ("Bcf") in fiscal 2018 from 23.566 Bcf in fiscal 2017. The most significant factor reducing gas sales for 2018 was the extended repairs being conducted at the Grossenkneten desulfurization plant. While these repairs were being conducted, the plants throughput capacity was affected. For the period extending from the second through the fourth quarters throughput was reduced by 40% for approximately 100 days and by 100% for approximately 20 days. Since approximately two thirds of the gas produced from the concession is sour gas, the reduction or elimination of the throughput had a substantial impact on gas sales. In addition, 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 | 2018 Gas Sales | 2017 Gas Sales | Percentage change |
| First | 5.660 | 6.489 | -12.78% |
| Second | 5.193 | 5.934 | -12.49% |
| Third | 3.593 | 5.500 | -34.67% |
| Fourth | 4.495 | 5.643 | -20.34% |
| Fiscal Year Total | 18.941 | 23.566 | -19.63% |
Average prices for gas sold under the Mobil Agreement increased 10.75% to 1.8164 Euro cents per kilowatt hour ("Ecents/kWh") in fiscal 2018 from 1.6401 Ecents/kWh in fiscal 2017.
| Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour | |||
|---|---|---|---|
| Fiscal Quarter | 2018 Gas Prices | 2017 Gas Prices | Percentage change |
| First | 1.6593 | 1.4789 | +12.20% |
| Second | 1.8262 | 1.7434 | + 4.75% |
| Third | 1.9141 | 1.7406 | + 9.97% |
| Fourth | 1.9231 | 1.6197 | +18.73% |
| Fiscal Year Average | 1.8164 | 1.6401 | +10.75% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $6.18 per thousand cubic feet ("Mcf"), a 19.54% increase from fiscal 2017's average price of $5.17/Mcf. For fiscal 2018, royalties paid under the Mobil Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1914, an increase of 7.94% from the average Euro/dollar exchange rate of $1.1038 for fiscal 2017.
| Average Euro Exchange Rate under the Mobil Agreement | |||
|---|---|---|---|
| Fiscal Quarter | 2018 Average Euro Exchange Rate | 2017 Average Euro Exchange Rate | Percentage change |
| First | 1.1965 | 1.0582 | +13.07% |
| Second | 1.2361 | 1.0625 | +16.34% |
| Third | 1.1705 | 1.1175 | +4.74% |
| Fourth | 1.1550 | 1.1806 | -2.17% |
| Fiscal Year Average | 1.1914 | 1.1038 | +7.94% |
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 2018, the volume of gas sold from western Oldenburg accounted for only 31.43% of the volume of all gas sales. However, western Oldenburg gas royalties provided approximately 80.24% or $5,438,672 out of a total of $6,778,111 in overall Oldenburg gas royalties.
Gas sales under the OEG Agreement decreased 19.16% to 60.264 Bcf in fiscal 2018 from 74.544 Bcf in fiscal 2017. The most significant factor reducing gas sales for 2018 was the extended repairs being conducted at the Grossenkneten desulfurization plant. While these repairs were being conducted, the plants throughput capacity was affected. For the period extending from the second through the fourth quarters throughput was reduced by 40% for approximately 100 days and by 100% for approximately 20 days. Since approximately two thirds of the gas produced from the concession is sour gas, the reduction or elimination of the throughput had a significant impact on gas sales. In addition, 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 OEG Agreement in Billion cubic feet | |||
|---|---|---|---|
| Fiscal Quarter | 2018 Gas Sales | 2017 Gas Sales | Percentage change |
| First | 18.150 | 20.060 | -9.52% |
| Second | 16.373 | 18.885 | -13.30 |
| Third | 11.712 | 17.829 | -34.31% |
| Fourth | 14.029 | 17.770 | -21.05% |
| Fiscal Year Total | 60.264 | 74.544 | -19.16% |
Average gas prices for gas sold under the OEG Agreement increased 10.56% to 1.8514 Ecents/kWh in fiscal 2018 from 1.6745 Ecents/kWh in fiscal 2017.
| Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour | |||
|---|---|---|---|
| Fiscal Quarter | 2018 Gas Prices | 2017 Gas Prices | Percentage change |
| First | 1.6921 | 1.5081 | +12.20% |
| Second | 1.8624 | 1.7779 | +4.75% |
| Third | 1.9520 | 1.7750 | +9.97% |
| Fourth | 1.9612 | 1.6517 | +18.74% |
| Fiscal Year Average | 1.8514 | 1.6745 | +10.56% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $6.18/Mcf, an 18.62% increase from fiscal 2017's average price of $5.21/Mcf. For fiscal 2018, royalties paid under the OEG Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1932, an increase of 7.49% from the average Euro/dollar exchange rate of $1.1101 for fiscal 2017.
| Average Euro Exchange Rate under the OEG Agreement | |||
|---|---|---|---|
| Fiscal Quarter | 2018 Average Euro Exchange Rate | 2017 Average Euro Exchange Rate | Percentage change |
| First | 1.2008 | 1.0590 | +13.39% |
| Second | 1.2364 | 1.0630 | +16.31% |
| Third | 1.1705 | 1.1175 | +4.74% |
| Fourth | 1.1540 | 1.1788 | -2.10% |
| Fiscal Year Average | 1.1932 | 1.1101 | +7.49% |
Interest income for fiscal 2018 of $4,509 increased slightly from interest income of $4,352 for fiscal 2017. Trust expenses increased $54,959, or 7.43%, to $795,088 in fiscal 2018 from $740,129 in fiscal 2017. German accounting expenses were higher due to the completion in fiscal 2018 of the examination of the royalty companies for the 2015-2016 period. Legal expenses were higher resulting from preparations for the planned conversion of the Trust's physical office to a virtual office. The Trust currently handles all interactions with unit owners through email or phone. Similarly, communications and filings with state, federal and financial agencies are made via email or online filings. A physical office is no longer required and the change to a virtual office would effect cost savings. The change will not impact the operations or administration of the Trust.
Results: Fiscal 2017 versus Fiscal 2016
For fiscal 2017, the Trust's gross royalty income increased 11.51% to $7,762,225 from $6,960,961 in fiscal 2016. The increase in the amount of royalty income resulted in the higher distributions. The total distribution for fiscal 2017 was $0.76 per unit compared to $0.67 per unit for fiscal 2016. While gas prices under both royalty agreements increased, gas sales under both royalty agreements declined and average exchange rates were mixed. As a result, royalty income attributable to gas sales under the Mobil Agreement in fiscal 2017 declined by $175,099 as compared to fiscal 2016. Royalty income attributable to gas sales under the OEG Agreement in fiscal 2017 increased by $44,239 as compared to fiscal 2016.
The increase in royalty income for fiscal 2017 is primarily the result of positive adjustments in 2017 and negative adjustments in fiscal 2016. 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 2017, the adjustments based on royalties payable for 2016 increased royalty income by $411,884, the equivalent of $0.0448 per unit. During fiscal 2016, the combination of positive and negative adjustments, including the year-end adjustments, reduced royalty income by $381,886, the equivalent of $0.0416 per unit. A similar situation occurred with respect to royalties paid under the Mobil Sulfur Agreement. In fiscal 2017, Mobil sulfur royalties totaled $43,932. In fiscal 2016 however, royalties under the Mobil Sulfur Agreement resulted in a net negative adjustment of $51,576 due to EMPG's incorrect inclusion in prior years of eastern sulfur sales in the royalty calculation.
Gas sales under the Mobil Agreement declined 5.90% to 23.566 Bcf in fiscal 2017 from 25.043 Bcf in fiscal 2016. 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. The suspension of all drilling activities during the 2015-2017 period likely has also impacted gas sales.
| Quarterly and Yearly Gas Sales under the Mobil Agreement in Billion cubic feet | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Gas Sales | 2016 Gas Sales | Percentage change |
| First | 6.489 | 6.604 | -1.74% |
| Second | 5.934 | 6.834 | -13.17% |
| Third | 5.500 | 4.917 | +11.86% |
| Fourth | 5.643 | 6.688 | -15.63% |
| Fiscal Year Total | 23.566 | 25.043 | -5.90% |
Average prices for gas sold under the Mobil Agreement increased 3.35% to 1.6401 Ecents/kWh in fiscal 2017 from 1.5870 Ecents/kWh in fiscal 2016.
| Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Gas Sales | 2016 Gas Sales | Percentage change |
| First | 1.4789 | 1.8649 | -20.70% |
| Second | 1.7434 | 1.5622 | +11.60% |
| Third | 1.7406 | 1.5363 | +13.30% |
| Fourth | 1.6197 | 1.3753 | +17.77% |
| Fiscal Year Average | 1.6401 | 1.5870 | +3.35% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $5.17/Mcf, a 2.58% decrease from fiscal 2016's average price of $5.04/Mcf. For fiscal 2017, royalties paid under the Mobil Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1038, a decrease of 0.41% from the average Euro/dollar exchange rate of $1.1083 for fiscal 2016.
| Average Euro Exchange Rate under the Mobil Agreement | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Average Euro Exchange Rate | 2016 Average Euro Exchange Rate | Percentage change |
| First | 1.0582 | 1.0881 | -2.75% |
| Second | 1.0625 | 1.1173 | -4.90% |
| Third | 1.1175 | 1.1185 | -0.09% |
| Fourth | 1.1806 | 1.1047 | +6.87% |
| Fiscal Year Average | 1.1038 | 1.1083 | -0.41% |
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 2017, the volume of gas sold from western Oldenburg accounted for only 31.61% of the volume of all gas sales. However, western Oldenburg gas royalties provided approximately 78.79% or $5,845,817 out of a total of $7,419,509 in overall Oldenburg gas royalties.
Gas sales under the OEG Agreement decreased 3.46% to 74.544 Bcf in fiscal 2017 from 77.213 Bcf in fiscal 2016. Since the Trust does not receive information about the decision-making process of the operating companies, it is impossible to determine to what extent EMPG's decisions 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. The suspension of all drilling activities during the 2015-2017 period likely has also impacted gas sales.
| Quarterly and Yearly Gas Sales under the OEG Agreement in Billion cubic feet | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Gas Sales | 2016 Gas Sales | Percentage change |
| First | 20.060 | 20.507 | -2.18% |
| Second | 18.885 | 20.434 | -7.58 |
| Third | 17.829 | 17.520 | +1.76% |
| Fourth | 17.770 | 18.752 | -5.24% |
| Fiscal Year Total | 74.544 | 77.213 | -3.46% |
Average gas prices for gas sold under the OEG Agreement increased 2.96% to 1.6745 ecents/kWh in fiscal 2017 from 1.6264 ecents/kWh in fiscal 2016.
| Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Gas Prices | 2016 Gas Prices | Percentage change |
| First | 1.5081 | 1.9803 | -23.84% |
| Second | 1.7779 | 1.5282 | +16.34% |
| Third | 1.7750 | 1.5667 | +13.30% |
| Fourth | 1.6517 | 1.4025 | +17.77% |
| Fiscal Year Average | 1.6745 | 1.6264 | +2.96% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $5.21/Mcf, a 3.37% increase from fiscal 2016's average price of $5.04/Mcf. For fiscal 2017, royalties paid under the OEG Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1101, an increase of 0.43% from the average Euro/dollar exchange rate of $1.1053 for fiscal 2016.
| Average Euro Exchange Rate under the OEG Agreement | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Average Euro Exchange Rate | 2016 Average Euro Exchange Rate | Percentage change |
| First | 1.0590 | 1.0874 | -2.61% |
| Second | 1.0630 | 1.1171 | -4.84% |
| Third | 1.1175 | 1.1159 | +0.14% |
| Fourth | 1.1788 | 1.1068 | +6.51% |
| Fiscal Year Average | 1.1101 | 1.1053 | +0.43% |
Interest income for fiscal 2017 of $4,352 declined slightly from interest income of $4,548 for fiscal 2016. Trust expenses decreased $84,238, or 10.22%, to $740,129 in fiscal 2017 from $824,367 in fiscal 2016 due to lower legal expenses, both domestic and German. These lower legal expenses resulted from the completion in fiscal 2016 of the amendments to the Mobil and OEG Royalty Agreements. In addition, German accounting expenses were lower due to the completion in fiscal 2016 of the examination of the royalty companies for the 2013-2014 period.
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 most recent information the Trust's German consultant received from representatives of EMPG. 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 resumed drilling in 2018 with the drilling of two sidetracks off the main bore of Goldenstedt Z-25a. The drilling of the initial sidetrack (M1) began in February 2018 and reached a length of 80 meters using the Directional Coiled Tubing ("DCT") drilling method. The DCT drilling method utilizes a smaller drilling rig, drills a smaller diameter bore and must work off an existing main bore. DCT drilling is a faster drilling method, is far less expensive than a traditional rig and is generally available for use on short notice. In March 2018 EMPG used DCT drilling for a second sidetrack (M2) with a length of 528 meters. However, both the first and second sidetracks were unsuccessful.
In an August 6, 2018 press release, EMPG announced the successful drilling of Goldenstedt Z-12a M1. Goldenstedt Z-12a M1, an eastern sour gas well, was drilled in May 2018 and was the first sidetrack off the main bore of Goldenstedt Z-12. The sidetrack extended 400 meters using DCT drilling, found the Zechstein Stassfurt carbonate reservoir in good condition and has begun production.
Brettorf Z-2b M1was originally scheduled to begin drilling in May 2018. However, with the experience gained using the DCT drilling, this well has been postponed until the first quarter of 2019. Doetlingen Z-3A was originally scheduled to begin drilling in December 2018 but has been postponed until July 2019 and will again use the DCT drilling method.
The scheduled 2018 workover was on a western Zechstein well, Visbek Z-16a. Visbek Z-16a suffered a severe casing collapse six months after it began production and was shut down in October 2013. While originally planned as a work over to repair the casing, EMPG began the drilling of the first horizontal section in October 2018 and the first gas production is expected in the beginning of 2019. Two additional unscheduled workovers were completed in 2018, Goldenstedt Z-10a and Cappeln Z-3a.
Of the two wells previously scheduled for 2019, Ahlhorn Z-3, a sour gas well, has been postponed until the second quarter of 2020. This well will attempt to reactivate the Ahlhorn field which was abandoned in 1997. Hemmelte NW T-1, an exploration well, was planned to develop a new area of the sweet gas Bunter zone in western Oldenburg. This well is no longer on the drilling schedule and no reason for the change was given.
The first well, Jeddeloh Z-1, to be drilled by Vermilion under its Farm-In Agreement had been scheduled for 2020. Originally this well was not a candidate for fracking because the water that would normally be used in the fracking process would be absorbed by the type of minerals present. This absorption would cause these minerals to expand filling the gaps that the fracking was intended to create. It is now believed that this well will need to be fracked and a foam or gel will need to be used, which makes the fracking more expensive. According to the Trust's German consultant, "This well is postponed until a time in the future when the approval procedure for fracking will have been defined in more detail by the mining authorities."
No firm dates have been announced for any of the wells described above. 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 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, 2018 other than the distribution announced on October 31, 2018 and payable to unit owners on November 28, 2018, as reflected in the statement of assets, liabilities and trust corpus.
| Payments Due by Period | |||||
|---|---|---|---|---|---|
| Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More than 5 Years | |
| Distributions payable to unit owners | $1,378,589 | $1,378,589 | $ 0 | $ 0 | $ 0 |
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 Disclosure 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.
Item 8. Financial Statements and Supplementary Data.
| Page Number | |
| Report of Independent Registered Public Accounting Firm | F-1 - F-2 |
| Financial Statements: | |
| Statements of Assets, Liabilities and Trust Corpus as of October 31, 2018 and 2017 |
F-3 |
| Statements of Revenue Collected and
Expenses Paid for the Fiscal Years Ended October 31, 2018, 2017 and 2016 |
F-4 |
| Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2018, 2017 and 2016 |
F-5 |
| Statements of Changes in Cash and
Cash Equivalents for the Fiscal Years Ended October 31, 2018, 2017 and 2016 | F-6 |
| Notes to Financial Statements | F-7 - F-10 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and the Unit Owners of
North European Oil Royalty Trust
Opinion on the Financial Statements
We have audited the accompanying statements of assets, liabilities and trust corpus of North European Oil Royalty Trust (the "Trust") as of October 31, 2018 and 2017, 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, 2018, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust as of October 31, 2018 and 2017, 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, 2018, in conformity with the modified cash bash 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) ("PCAOB"), the Trust's internal control over financial reporting as of October 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 28, 2018, expressed an unqualified opinion.
Basis for Opinion
These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on the Trust's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
F-1
Basis of Accounting
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 accounting principles generally accepted in the United States of America.
Mazars USA LLP
We have served as the Trust's auditor since 2006
New York, NY
December 28, 2018
F-2
| 2018 | 2017 | |
|---|---|---|
| ASSETS | ||
| Current assets -- Cash and cash equivalents | $ 1,457,207 | $ 2,126,005 |
| Producing gas and oil royalty rights, net of amortization (Notes 1 and 2) | 1 | 1 |
| Total Assets | $ 1,457,208 | $ 2,126,006 |
| LIABILITIES AND TRUST CORPUS | ||
| Current liabilities -- Distributions
to be paid to unit owners, paid November 2018 and 2017 |
$ 1,378,589 | $ 2,021,929 |
| Trust corpus (Notes 1 and 2) | 1 | 1 |
| Undistributed earnings | 78,618 | 104,076 |
| Total Liabilities and Trust Corpus | $ 1,457,208 | $ 2,126,006 |
The accompanying notes are an integral part of these financial statements.
F-3
| 2018 | 2017 | 2016 | |
|---|---|---|---|
| Gas, sulfur and oil royalties received | $ 7,198,534 | $ 7,762,225 | $ 6,960,961 |
| Interest income | 4,509 | 4,352 | 4,548 |
| Trust Income | 7,203,043 | 7,766,577 | 6,965,509 |
| Non-related party expenses | (705,367) | (669,965) | (715,404) |
| Related party expenses (Note 3) | (89,721) | (70,164) | (108,964) |
| Trust Expenses | (795,088) | (740,129) | (824,368) |
| Net Income | $ 6,407,955 | $ 7,026,448 | $ 6,141,141 |
| Net income per unit | $ 0.70 | $ 0.76 | $ 0.67 |
| Distributions per unit paid or to be paid to unit owners | $ 0.70 | $ 0.76 | $ 0.67 |
The accompanying notes are an integral part of these financial statements.
F-4
| 2018 | 2017 | 2016 | |
| Balance, beginning of period | $ 104,076 | $ 62,476 | $ 79,030 |
| Net income | 6,407,955 | 7,026,448 | 6,141,141 |
| 6,512,031 | 7,088,924 | 6,220,171 | |
| Less: | |||
| Current year distributions
paid or to be paid to unit owners |
6,433,413 | 6,984,848 | 6,157,695 |
| Balance, end of period | $ 78,618 | $ 104,076 | $ 62,476 |
The accompanying notes are an integral part of these financial statements.
F-5
| 2018 | 2017 | 2016 | |
| Sources of Cash and Cash Equivalents: | |||
| Gas, sulfur and oil royalties received | $7,198,534 | $7,762,225 | $6,960,961 |
| Interest income | 4,509 | 4,352 | 4,548 |
| 7,203,043 | 7,766,577 | 6,965,509 | |
| Uses of Cash and Cash Equivalents: | |||
| Payment of Trust expenses | 795,088 | 740,129 | 824,368 |
| Distributions paid | 7,076,753 | 6,065,790 | 7,168,659 |
| 7,871,841 | 6,805,919 | 7,993,027 | |
| Net increase (decrease) in cash and cash equivalents during the period |
(668,798) | 960,658 | (1,027,518) |
| Cash and cash equivalents, beginning of period | 2,126,005 | 1,165,347 | 2,192,865 |
| Cash and cash equivalents, end of period | $ 1,457,207 | $ 2,126,005 | $ 1,165,347 |
The accompanying notes are an integral part of these financial statements.
F-6
(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"). In the opinion of management, all adjustments that are considered necessary for a fair presentation of these financial statements, including adjustments of a normal, recurring nature, have been included.
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.
F-7
Federal and state income taxes -
The Trust, as a grantor trust and also under a private letter ruling issued by the Internal Revenue Service, is exempt from federal income taxes. The Trust has no state income tax obligations.
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, 2018, the uninsured amounts held in the Trust's U.S. bank accounts were $1,201,639. In addition, the Trust held Euros 4,913, the equivalent of $5,568, in its German bank account at October 31, 2018.
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, 2018, 2017 and 2016, 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, condensate and sulfur.
F-8
(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 $26,873, $25,015 and $28,559 in fiscal 2018, 2017 and 2016, respectively. The upcoming shift to a virtual office in 2019 should substantially reduce the expenses that would be associated with maintaining a physical office.
Lawrence A. Kobrin, a Trustee of the Trust, is no longer a partner of the firm but remains 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 $62,848, $45,149 and $80,405 in fiscal 2018, 2017 and 2016, respectively.
(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 2018, 2017 and 2016 calendar years.
F-9
(5) Quarterly results (unaudited):
The tables below summarize the quarterly results and distributions of the Trust for the fiscal years ended October 31, 2018 and 2017:
Fiscal 2018 by Quarter and Year
| First | Second | Third | Fourth | Year | |
| Royalties received | $ 1,770,241 | $ 2,054,020 | $ 1,900,082 | $ 1,474,191 | $ 7,198,534 |
| Net income | $ 1,495,086 | $ 1,820,337 | $ 1,767,631 | $ 1,324,902 | $ 6,407,955 |
| Net Income per unit | $ 0.16 | $ 0.20 | $ 0.19 | $ 0.14 | $ 0.70 |
| Distribution paid or to be paid |
$ 1,562,400 | $ 1,746,212 | $ 1,746,212 | $ 1,378,589 | $ 6,433,413 |
| Distribution per unit or to be paid to unit owners |
$ 0.17 | $ 0.19 | $ 0.19 | $ 0.15 | $ 0.70 |
Fiscal 2017 by Quarter and Year
| First | Second | Third | Fourth | Year | |
| Royalties received | $ 1,724,686 | $ 1,918,830 | $ 1,974,441 | $ 2,144,268 | $ 7,762,225 |
| Net income | $ 1,475,017 | $ 1,699,909 | $ 1,840,694 | $ 2,010,828 | $ 7,026,448 |
| Net Income per unit | $ 0.16 | $ 0.18 | $ 0.20 | $ 0.22 | $ 0.76 |
| Distribution paid or to be paid |
$ 1,378,589 | $ 1,746,212 | $ 1,838,118 | $ 2,021,929 | $ 6,984,848 |
| Distribution per unit or to be paid to unit owners |
$ 0.15 | $ 0.19 | $ 0.20 | $ 0.22 | $ 0.76 |
F-10
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, 2018. Based on that evaluation, the Managing Director concluded that the Trust's disclosure controls and procedures were effective as of October 31, 2018.
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, 2018. 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 (COSO). Based on this evaluation, management concluded that the Trust's internal control over financial reporting was effective as of October 31, 2018. Management's assessment of the effectiveness of our internal control over financial reporting as of October 31, 2018 has been audited by Mazars USA LLP, the Trust's independent auditor, as stated in their report which follows.
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
Opinion on Internal Control over Financial Reporting
We have audited North European Oil Royalty Trust's (the "Trust") internal control over financial reporting as of October 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of October 31, 2018, 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) ("PCAOB"), the statements of assets, liabilities and trust corpus and the related statements of revenue collected and expenses paid, undistributed earnings, and changes in cash and cash equivalents of the Trust, and our report dated December 28, 2018, expressed an unqualified opinion thereon.
Basis for Opinion
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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control over Financial Reporting
A 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 the modified cash basis of accounting described in Note 1, which is a comprehensive basis other than accounting principles generally accepted in the United States of America. A 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 the modified cash basis of accounting, 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.
Mazars USA LLP
New York, NY
December 28, 2018
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 2018 that have materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting.
Item 9B. Other Information.
None.
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 21, 2019, 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 21, 2019, 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 21, 2019, 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 21, 2019, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.
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 21, 2019, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.
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, 2018, 2017 and 2016
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus as of October 31, 2018 and 2017
Statements of Revenue Collected and Expenses Paid for the Fiscal Years Ended October 31, 2018, 2017 and 2016
Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2018, 2017 and 2016
Statements of Changes in Cash and Cash Equivalents for the Fiscal Years Ended October 31, 2018, 2017 and 2016
Notes to Financial Statements
2. Exhibits
The Exhibit Index following the signature page lists all exhibits filed with this Report or incorporated by reference.
Item 16. Form 10-K Summary.
None.
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 28, 2018 | /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 28, 2018 | /s/Robert P. Adelman |
| Robert P. Adelman, Managing Trustee | |
| Dated: December 28, 2018 | /s/Ahron H.Haspel |
| Ahron H. Haspel, Trustee | |
| Dated: December 28, 2018 | /s/Lawrence A. Kobrin |
| Lawrence A. Kobrin, Trustee | |
| Dated: December 28, 2018 | /s/Nancy J.F. Prue |
| Nancy J.F. Prue, Trustee | |
| Dated: December 28, 2018 | /s/Willard B. Taylor |
| Willard B. Taylor, Trustee | |
| Dated: December 28, 2018 | /s/John R. Van Kirk |
| John R. Van Kirk, Managing Director | |
| and Principal Accounting Officer |
Exhibit Index