North European Oil Royalty Trust 10-K

PART I

(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 prior to their distribution are invested in an interest bearing money market account.

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 Trustees have, however, chosen to constitute an Audit Committee and a Compensation Committee but may not necessarily continue to 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 a government granted concessions and remain in effect as long as there are continued production activities and/or exploration efforts within the concession. It is generally anticipated that production activities will continue as long as they remain economically profitable. 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 on a regular monthly or quarterly basis pursuant to the royalty agreements. The Trust receives the royalty payments exclusively in Euros. After the royalties have been deposited in the Trust's account with Deutsche Bank in Germany, sufficient funds are reserved to handle any outstanding or anticipated expenses and maintain a minimal balance of 10,000 Euros. The Trust's standing instructions with Deutsche Bank are then executed converting the remainder of Euro denominated funds into U.S. dollars based upon the available exchange rates. Following this conversion to U.S. 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. 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 or exploration. 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, it is a requirement that the Trust be advised 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. There is no assurance that the Trust could find such a third party.

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 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. 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 and that permission by the relevant water authority be granted in order to ensure the protection of 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 (as defined below) 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 failure by the operating companies to comply with all regulatory requirements could affect the volume of gas, sulfur and oil production by the operating companies and could adversely affect the royalties paid to the Trust.

The Trust, in cooperation with a parallel royalty owner (Unitarian Universalist Congregation at Shelter Rock)("UUCSR")), 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 to be made. As a result of the amendments to the Trust's royalty agreements which effect pricing simplification (see Item 7 of this Report), 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 without the need for litigation. The Trust's accountants in Germany will begin their examination of the operating companies for calendar years 2019 and 2020 in November 2021 when the final sales figures and the German Border Import gas Prices (see Item 7 of this Report) became 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, 2020.

(d) Information about our Trustees and Executive Officers. 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 in a non-executive capacity as Managing Trustee 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. As a cost saving measure, the Trust shifted to a virtual office in fiscal 2019. This shift has not impacted 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 and UUCSR have retained the services of a consultant, an accounting firm and a legal firm in Germany. The consultant has broad experience in the petroleum industry and provides reports on a regular basis. The accounting firm and the legal firm advise and represent as needed. The Trust and the co-royalty holder share the costs of these services in Germany.

(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.

Not applicable.

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 a concession in the Federal Republic of Germany (the "Oldenburg concession"). The Oldenburg concession covers approximately 1,386,000 acres, is located in the German federal state of Lower Saxony, and is the area from which natural gas, sulfur and oil are extracted. The Oldenburg concession currently provides 100% of all the royalties received by the Trust. The Oldenburg concession is held by Mobil Erdgas-Erdol GmbH ("Mobil Erdgas"), a German operating subsidiary of ExxonMobil, and 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. 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 ExxonMobil Production Deutschland GmbH ("EMPG") to carry out all exploration, drilling and production activities. All sales activities upon which the calculation of royalties is based are still handled by either Mobil Erdgas or BEB (the "operating companies").

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 99% 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 an agreement with Mobil Erdgas 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 "Mobil Sulfur Agreement"). 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 $71,280 and $150,157 during fiscal 2020 and 2019, respectively.

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.

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 Farm-In Agreement does not impact the Trust's royalty interests. The Trust has been advised by its consultant in Germany that, based on the consultant's conversations with EMPG employees and other sources, Vermilion has acquired an interest in various portions of a concession or areas owned by Mobil Erdgas and BEB pursuant to the Farm-In Agreement. As of the date of this report, no drilling or development work within the Oldenburg Concession has been done by Vermilion, and the Trust is unaware of any potential extension of the Farm-In Agreement beyond 2020

The following is a schedule of royalty income for the fiscal year ended October 31, 2020 by product, geographic area and operating company:

By Product:
Product	Royalty Income
Gas Well and Oil Well Gas	$3,807,678
Sulfur	$209,345
Oil	$32,994

By Geographic Area:
Area	Royalty Income
Western Oldenburg	$3,240,029
Eastern Oldenburg	$809,988

By Operating Company:
Company	Royalty Income
Mobil Erdgas (under the Mobil Agreement)	$2,872,610
BEB (under the OEG Agreement)	$1,177,407

Exhibit 99.1 to this Report is a report entitled Calculation of Cost Depletion Percentage for the 2020 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, 2020 (the "Cost Depletion Report"). The Cost Depletion Report, dated November 30, 2020, 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 2020 calendar year based on the use of certain production data and the estimated net proved producing reserves as of October 1, 2020 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, 2020. 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 in that report for calendar 2020 is 16.5776%. 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 2020 calendar year are included on removable pages in the 2020 Annual Report. Additionally, the tax reporting information for 2020 is available on the Trust's website, http://neort.com/tax-letters.html.

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 receives 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. 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, 2020 and a five-year schedule of gas, sulfur and oil sales for the twelve months ended September 30, 2020, 2019, 2018, 2017 and 2016 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.

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.

None.

PART II

Item 6. Selected Financial Data.

Not Applicable.

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. The Trust has traditionally received the majority of its royalty income under the Mobil Agreement 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 2020. 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. For purposes of the royalty calculations, the determination of the gas price is explained in detail in the following three paragraphs.

On August 26, 2016, the Mobil and OEG Agreements were amended establishing a new base for the determination of gas prices upon which the Trust's royalties are calculated. This new 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 German Border Import gas Price ("GBIP"). For the royalty calculations, the average GBIP used under the Mobil and OEG Royalty Agreements has been and will continue to be increased by 1% and 3%, respectively.

The change to the GBIP was intended to be revenue neutral for the Trust in comparison to the previous pricing methodology. Additionally, this change was intended to 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 OEG Agreement.

On approximately the 25th of the months of January, April, July and October, the operating companies first calculate the volume of gas sold during the previous calendar quarter. This volume of gas sold is then multiplied by the average adjusted GBIP available at that time. Due to delays in the calculation of the GBIP by the state, the most current GBIP is from a period ending two months prior to the end of the relevant calendar quarter. 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. Any positive adjustments are paid immediately and any negative adjustments would be deducted from the royalty payment for the first month of the next fiscal quarter. In September of 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.

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, which is sold separately. With full operation of the plant, raw gas input capacity stands at approximately 400 million cubic feet ("MMcf") per day. As needed, EMPG conducts maintenance on the plant generally during the summer months when demand is lower. As part of the regular 10-year scheduled maintenance, Grossenkneten underwent an overhaul from September 8, 2020 through October 13, 2020. During this time the plant was completely shut down and no sour gas was processed. Since sour gas accounts for 75% of overall gas sales and 98% of western gas sales, this shutdown significantly impacted royalty income during the fourth quarter of fiscal 2020 and will likely impact royalty income during the upcoming first quarter of fiscal 2021.

For unit owners, changes in the U.S. 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 Trust's bank account in the United States. In relation to the U.S. dollar, a stronger Euro would yield more U.S. dollars and a weaker Euro would yield fewer U.S. 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, and the Trust is not able to confirm the accuracy of any of the information supplied by EMPG or the operating companies.

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.

The Trust has previously distributed information regarding the negative adjustment of Euros 444,931 that is being carried over to the first quarter of fiscal 2021. Given the level of expected royalty payments for the first quarter of fiscal 2021 based upon the prior calendar quarter's actual royalties paid, the Trust anticipates the royalties for the first quarter of fiscal 2021 will be almost completely offset by this negative adjustment. It is possible that the anticipated royalties for the first quarter of fiscal 2021 may be increased by a positive end of quarter royalty adjustment in January; however, the two-week total shutdown of the Grossenkneten desulfurization plant in early October may reduce the potential for such a positive adjustment. No assurances with respect to any positive end of quarter royalty adjustment can be given at this time.

Results: Fiscal 2020 versus Fiscal 2019

For fiscal 2020, the Trust's gross royalty income decreased 51.47% to $4,050,017 from $8,344,712 in fiscal 2019. The decrease in the amount of royalty income resulted in the lower distribution. The total distribution for fiscal 2020 was $0.32 per unit compared to $0.82 per unit for fiscal 2019. Gas prices and gas sales under both royalty agreements declined significantly while the average exchange rates were only down slightly. The royalty income attributable to gas sales under the Mobil Agreement in fiscal 2020 decreased by $2,084,772 as compared to fiscal 2019. Royalty income attributable to gas sales under the OEG Agreement in fiscal 2020 decreased by $1,108,806 as compared to fiscal 2019.

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 2020, the adjustments based on royalties payable for 2017, 2018 and 2019 decreased royalty income by $653,916. During fiscal 2019, the adjustments based on royalties payable for 2018 increased royalty income by $225,450. In fiscal 2020 and 2019, Mobil sulfur royalties totaled $71,280 and $150,157, respectively.

Gas sales under the Mobil Agreement decreased 15.86% to 17.259 Billion cubic feet ("Bcf") in fiscal 2020 from 20.513 Bcf in fiscal 2019. The most significant factor resulting in the decrease in gas sales for 2020 was the negative impact of COVID-19 on the German, European and global economies. 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	2020 Gas Sales	2019 Gas Sales	Percentage change
First	4.884	5.535	-11.76%
Second	4.624	5.195	-10.99%
Third	4.565	4.902	-6.87%
Fourth	3.186	4.881	-34.73%
Fiscal Year Total	17.259	20.513	-15.86%

Average prices for gas sold under the Mobil Agreement decreased 30.10% to 1.3185 Euro cents per kilowatt hour ("Ecents/kWh") in fiscal 2020 from 1.8862 Ecents/kWh in fiscal 2019.

Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour
Fiscal Quarter	2020 Average Gas Prices	2019 Average Gas Prices	Percentage change
First	1.3550	2.0582	-34.17%
Second	1.6349	2.1250	-23.06%
Third	1.2326	1.8620	-33.80%
Fourth	0.9255	1.4612	-36.66%
Fiscal Year Average	1.3185	1.8862	-30.10%

Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $4.21 per thousand cubic feet ("Mcf"), a 30.76% decrease from fiscal 2019's average price of $6.08/Mcf. For fiscal 2020, royalties paid under the Mobil Agreement were converted and transferred at an average Euro/U.S. dollar exchange rate of $1.1145, a decrease of 0.73% from the average Euro/U.S. dollar exchange rate of $1.1227 for fiscal 2019.

Average Euro Exchange Rate under the Mobil Agreement
Fiscal Quarter	2020 Average Euro Exchange Rate	2019 Average Euro Exchange Rate	Percentage change
First	1.1105	1.1349	-2.15%
Second	1.0943	1.1267	-2.88%
Third	1.1143	1.1202	-0.53%
Fourth	1.1761	1.1004	+6.88%
Fiscal Year Average	1.1145	1.1227	-0.73%

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 2020, the volume of gas sold from western Oldenburg accounted for only 30.91% of the volume of all gas sales. However, western Oldenburg gas royalties provided approximately 81.43% or $3,100,714 out of a total of $3,807,678 in overall Oldenburg gas royalties.

Gas sales under the OEG Agreement decreased 16.55% to 55.841 Bcf in fiscal 2020 from 66.912 Bcf in fiscal 2019. The most significant factor resulting in the decrease in gas sales for 2020 was the negative impact of COVID-19 on the German, European and global economies. 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	2020 Gas Sales	2019 Gas Sales	Percentage change
First	16.026	17.536	-8.61%
Second	15.266	16.851	-9.41%
Third	13.948	16.320	-14.53%
Fourth	10.601	16.205	-34.58%
Fiscal Year Total	55.841	66.912	-16.55%

Average gas prices for gas sold under the OEG Agreement decreased 29.91% to 1.3458 Ecents/kWh in fiscal 2020 from 1.9200 Ecents/kWh in fiscal 2019.

Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour
Fiscal Quarter	2020 Average Gas Prices	2019 Average Gas Prices	Percentage change
First	1.3818	2.0989	-34.17%
Second	1.6672	2.1670	-23.06%
Third	1.2570	1.8988	-33.80%
Fourth	0.9438	1.4901	-36.66%
Fiscal Year Average	1.3458	1.9200	-29.91%

Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $4.18/Mcf, a 30.56% decrease from fiscal 2019's average price of $6.02/Mcf. For fiscal 2020, royalties paid under the OEG Agreement were converted and transferred at an average Euro/U.S. dollar exchange rate of $1.1114, a decrease of 0.99% from the average Euro/U.S. dollar exchange rate of $1.1225 for fiscal 2019.

Average Euro Exchange Rate under the OEG Agreement
Fiscal Quarter	2020 Average Euro Exchange Rate	2019 Average Euro Exchange Rate	Percentage change
First	1.1115	1.1352	-2.09%
Second	1.0955	1.1267	-2.77%
Third	1.1141	1.1187	-0.41%
Fourth	1.1730	1.0989	+6.74%
Fiscal Year Average	1.1114	1.1225	-0.99%

Interest income for fiscal 2020 of $2,853 decreased from interest income of $14,451 for fiscal 2019 due to reduced royalty income and lower interest rates in effect. Trust expenses decreased $14,591, or 1.87%, to $766,507 in fiscal 2020 from $781,098 in fiscal 2019 due to the reduced office expenses associated with the conversion to a virtual office and reduced Trustees' fees as specified in the provisions of the Trust Agreement.

Report on Exploration and Drilling

The Trust's German consultant periodically contacts the representatives of the operating companies to inquire about their planned and proposed drilling and geophysical work and other general matters. The following represents a summary of the most recent information the Trust's German consultant received from representatives of EMPG as of November 2020. 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.

Doetlingen Z-3A, which had ceased production in 2013, was plugged and abandoned in 2020. Varenesch Z-1 as well as Varnhorn Z-5 and Z-10 have been secured and are awaiting final plugging and abandonment.

Varnhorn Z-2 underwent a workover and several stimulation jobs to optimize performance. The surface facilities of two Carboniferous wells, Goldenstedt Z-9 and Z-23, had suffered heavy corrosion and suspended production for four weeks during May-June 2020.

Ahlhorn Z-3, a sour gas exploration/re-development well, has been postponed indefinitely due to budget reasons and low gas prices. While preliminary permit requests had been filed with the Mining Authority in October 2019, it is unclear whether drilling will commence in 2021. If drilling is started, the project duration is estimated by EMPG to be about one year. This well will attempt to reactivate the Ahlhorn field which was abandoned in 1997.

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.

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 effect of the novel coronavirus identifies as "COVID-19" on our financial results.

All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and are generally beyond the control of the Trust. New factors emerge from time to time and it is not possible for the Trust to predict all such factors or to assess the impact of each such factor on the Trust. Any forward-looking statement speaks only as of the date on which such statement is made, and the Trust does not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk .

The Trust does not engage in any trading activities with respect to possible foreign exchange fluctuations. The Trust does not use any financial instruments to hedge against possible risks related to foreign exchange fluctuations. The market risk with respect to funds held in the Trust's bank account in Germany is negligible because standing instructions at the Trust's German bank require the bank to process conversions and transfers of royalty payments as soon as possible following their receipt. The Trust does not engage in any trading activities with respect to commodity price fluctuations.

Item 8. Financial Statements and Supplementary Data.

NORTH EUROPEAN OIL ROYALTY TRUST

INDEX TO FINANCIAL STATEMENTS

	Page Number

Report of Independent Registered Public Accounting Firm	F-1 - F-2

Financial Statements:

Statements of Assets, Liabilities and Trust Corpus as of October 31, 2020 and 2019	F-3

Statements of Revenue Collected and Expenses Paid for the Fiscal Years Ended October 31, 2020 and 2019	F-4

Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2020 and 2019	F-5

Statements of Changes in Cash and Cash Equivalents for the Fiscal Years Ended October 31, 2020 and 2019	F-6

Notes to Financial Statements	F-7 - F-9

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, 2020 and 2019, and the related statements of revenue collected and expenses paid, undistributed earnings, and changes in cash and cash equivalents, for each of the two years in the period ended October 31, 2020, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of October 31, 2020 and 2019, and its revenue collected and expenses paid, and changes in its cash and cash equivalents for each of the two years in the period ended October 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

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 included examining, on a test basis, evidence regarding the 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 30, 2020

F-2

NORTH EUROPEAN OIL ROYALTY TRUSTSTATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (NOTE 1)OCTOBER 31, 2020 AND 2019

	2020	2019
ASSETS
Current assets -- Cash and cash equivalents	$649,585	$1,590,893

Producing gas and oil royalty rights, net of amortization (Notes 1 and 2)	1	1

Total Assets	$649,586	$1,590,894


	2020	2019
LIABILITIES AND TRUST CORPUS
Current liabilities -- Distributions to be paid to unit owners, paid November 2020 and 2019	$183,811	$1,470,494

Trust corpus (Notes 1 and 2)	1	1

Undistributed earnings	465,774	120,399

Total Liabilities and Trust Corpus	$649,586	$1,590,894

The accompanying notes are an integral part of these financial statements.

F-3

NORTH EUROPEAN OIL ROYALTY TRUSTSTATEMENTS OF REVENUE COLLECTED AND EXPENSES PAID (NOTE 1)FOR THE FISCAL YEARS ENDED OCTOBER 31, 2020 AND 2019

	2020	2019
Gas, sulfur and oil royalties received	$4,050,017	$8,344,712
Interest income	2,853	14,451
Trust Income	4,052,870	8,359,163
Non-related party expenses	(715,490)	(703,351)
Related party expenses (Note 3)	(51,017)	(77,747)
Trust Expenses	($766,507)	($781,098)
Net Income	$3,286,363	$7,578,065
Net income per unit	$0.36	$0.82
Distributions per unit paid or to be paid to unit owners	$0.32	$0.82

The accompanying notes are an integral part of these financial statements.

F-4

NORTH EUROPEAN OIL ROYALTY TRUSTSTATEMENTS OF UNDISTRIBUTED EARNINGS (NOTE 1)FOR THE FISCAL YEARS ENDED OCTOBER 31, 2020 AND 2019

	2020	2019
Balance, beginning of period	$120,399	$78,618
Net income	3,286,363	7,578,065
	3,406,762	7,656,683
Less:
Current year distributions paid or to be paid to unit owners	2,940,988	7,536,284
Balance, end of period	$465,774	$120,399

The accompanying notes are an integral part of these financial statements.

F-5

NORTH EUROPEAN OIL ROYALTY TRUSTSTATEMENTS OF CHANGES IN CASH AND CASH EQUIVALENTS (NOTE 1)FOR THE FISCAL YEARS ENDED OCTOBER 31, 2020 AND 2019

	2020	2019
Sources of Cash and Cash Equivalents:
Gas, sulfur and oil royalties received	$4,050,017	$8,344,712
Interest income	2,853	14,451
	$4,052,870	$8,359,163
Uses of Cash and Cash Equivalents:
Payment of Trust expenses	$766,507	$781,098
Distributions paid	4,227,671	7,444,379
	$4,994,178	$8,225,477
Net increase (decrease) in cash and cash equivalents during the year	(941,308)	133,686
Cash and cash equivalents, beginning of year	1,590,893	1,457,207
Cash and cash equivalents, end of year	$649,585	$1,590,893

The accompanying notes are an integral part of these financial statements.

F-6

NORTH EUROPEAN OIL ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

OCTOBER 31, 2020 AND 2019

(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.

The Trust receives adjustments from the operating companies based on their final calculations of royalties payable during the prior periods, including the immediately preceding calendar quarter. Negative adjustments are carried over to the succeeding quarter. A negative adjustment of 444,931 Euros from the fourth quarter of fiscal 2020 will be carried over and offset against future royalty revenue received in the first quarter of fiscal 2021.

Producing gas and oil royalty rights -

The rights to certain gas and oil royalties in Germany were transferred to the Trust at their net book value by North European Oil Company (the "Company") (see Note 2). The net book value of the royalty rights has been reduced to one dollar ($1) in view of the fact that the remaining net book value of royalty rights is de minimis relative to annual royalties received and distributed by the Trust and does not bear any meaningful relationship to the fair value of such rights or the actual amount of proved producing reserves.

Federal and state income taxes -

The Trust, as a grantor trust 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.

F-7

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, 2020, the uninsured amounts held in the Trust's U.S. bank accounts were $387,960. In addition, the Trust held Euros 9,977, the equivalent of $11,626, in its German bank account at October 31, 2020.

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, 2020 and 2019, 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.

(3) Related party transactions:

John R. Van Kirk, the Managing Director of the Trust, provides office services to the Trust at cost. For such office services, the Trust reimbursed the Managing Director $4,020, and $26,166 in fiscal 2020 and 2019, respectively.

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 $46,997 and $51,581 in fiscal 2020 and 2019, 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 2020 and 2019 calendar years.

F-8

(5) Quarterly results (unaudited):

The tables below summarize the quarterly results and distributions of the Trust for the fiscal years ended October 31, 2020 and 2019:

Fiscal 2020 by Quarter and Year

	First	Second	Third	Fourth	Year
Royalties received	$1,025,965	$1,275,824	$1,399,614	$348,614	$4,050,017
Net income	$747,737	$1,041,902	$1,278,075	$218,649	$3,286,363
Net Income per unit	$ 0.08	$ 0.11	$ 0.14	$ 0.02	$ 0.36
Distribution paid or to be paid	$735,247	$1,010,965	$1,010,965	$183,811	$2,940,988
Distribution per unit or to be paid to unit owners	$ 0.08	$ 0.11	$ 0.11	$ 0.02	$ 0.32

Fiscal 2019 by Quarter and Year

	First	Second	Third	Fourth	Year
Royalties received	$2,303,000	$2,235,350	$2,146,227	$1,660,135	$8,344,712
Net income	$2,037,785	$2,001,753	$2,022,464	$1,516,063	$7,578,065
Net Income per unit	$ 0.22	$ 0.22	$ 0.22	$ 0.16	$ 0.82
Distribution paid or to be paid	$2,021,930	$2,021,930	$2,021,930	$1,470,494	$7,536,284
Distribution per unit or to be paid to unit owners	$ 0.22	$ 0.22	$ 0.22	$ 0.16	$ 0.82

F-9

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, 2020. Based on that evaluation, the Managing Director concluded that the Trust's disclosure controls and procedures were effective as of October 31, 2020.

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, 2020. 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, 2020.

Part B. Attestation Report of Independent Registered Public Accounting Firm

Not applicable

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 2020 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 17, 2021, 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") beginning in 2004 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 17, 2021, 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.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Item 14. Principal Accountant Fees and Services.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) The following is a list of the documents filed as part of this Report:

1. Financial Statements

Index to Financial Statements for the Fiscal Years Ended October 31, 2020 and 2019

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus as of October 31, 2020 and 2019

Statements of Revenue Collected and Expenses Paid for the Fiscal Years Ended October 31, 2020 and 2019

Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2020 and 2019

Statements of Changes in Cash and Cash Equivalents for the Fiscal Years Ended October 31, 2020 and 2019

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.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Trust has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTH EUROPEAN OIL ROYALTY TRUST

Dated: December 30, 2020	/s/John R. Van Kirk
	John R. Van Kirk, Managing Director
	and Principal Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Dated: December 30, 2020	/s/Robert P. Adelman
	Robert P. Adelman, Managing Trustee

Dated: December 30, 2020	/s/Ahron H.Haspel
	Ahron H. Haspel, Trustee

Dated: December 30, 2020	/s/Lawrence A. Kobrin
	Lawrence A. Kobrin, Trustee

Dated: December 30, 2020	/s/Nancy J. Prue
	Nancy J. Prue, Trustee

Dated: December 30, 2020	/s/Willard B. Taylor
	Willard B. Taylor, Trustee

Dated: December 30, 2020	/s/John R. Van Kirk
	John R. Van Kirk, Managing Director
	and Principal Accounting Officer

Exhibit Index

Exhibit	Page
(3.1)	North European Oil Royalty Trust Agreement, dated September 10, 1975, as amended through February 13, 2008 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K, filed February 15, 2008 (File No. 0-8378)).

(3.2)	Amended and Restated Trustees' Regulations, amended and restated as of October 31, 2007 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K, filed November 2, 2007 (File No. 0-8378)).

(4.1)	Description of Securities	32

(10.1)	Agreement with OEG, dated April 2, 1979, exhibit to Current Report on Form 8-K filed May 11, 1979 (incorporated by reference as Exhibit 1 to Current Report on Form 8-K, filed May 11, 1979 (File No. 0-8378)).

(10.2)	Agreement with Mobil Oil, A.G. concerning sulfur royalty payment, dated March 30, 1979 (incorporated by reference to Exhibit 3 to Current Report on Form 8-K, filed May 11, 1979 (File No. 0-8378)).

(10.3)	English language translation of Amendment Agreement dated August 26, 2016 between Oldenburgische Erdolgesellschaft mbH and North European Oil Royalty Trust (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q for the quarter ended July 31, 2016 (File No. 1-8245)).

(10.4)	English language translation of Amendment Agreement dated August 26, 2016 between Mobil Erdgas-Erdol GmbH and North European Oil Royalty Trust (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q for the quarter ended July 31, 2016 (File No. 1-8245)).

(21)	There are no subsidiaries of the Trust.

(31)	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		33
(32)	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002		35
(99.1)	Calculation of Cost Depletion Percentage for the 2020 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, 2020 prepared by Graves & Co. Consulting, LLC		36
(99.2)	Order Approving Settlement signed by Vice Chancellor Jack Jacobs of the Delaware Court of Chancery (incorporated by reference as Exhibit 99.2 to Current Report on Form 8-K, filed February 26, 1996).

EX-4 2 x4-123020.htm

Exhibit 4.1

DESCRIPTION OF SECURITIES

The following is a summary of information concerning units of beneficial interest of North European Oil Royalty Trust (the "Trust"). The summaries and descriptions below do not purport to be complete statements of the relevant provisions of the Trust Agreement ("Trust Agreement") dated as of September 10, 1975 (as last amended on February 13, 2008) or the Amended and Restated Trustees' Regulations, dated as of October 31, 2007 (the "Regulations "), and are entirely qualified by these documents.

Units. The Trust's units of beneficial interest (the "Units") are registered under Section 12(b) of the Securities Exchange Act of 1934 and are listed on the New York Stock Exchange under the ticker symbol "NRT." The issued and outstanding Units are fully paid and non-assessable. This means the full purchase price for the outstanding Units have been paid and the owners of such Units will not be assessed any additional amounts for such Units.

Distributions and Reserves . The Trustees will, not less than quarterly, distribute and pay to the unit owners, in proportion to their respective beneficial interest of the Units, all rents, royalties, income, proceeds and other receipt of or from the properties held by the Trustees ("Trust Estate "), after payment of, or provision for, the expenses, liabilities and obligations of the Trust Estate and any withholding of the taxes or charges. The Trustees have the right to determine from time to time the amounts to be retained as reserves in connection with anticipated charges or expenses of the Trust, for contingent or unascertained liabilities or obligations of the Trust, or for such other purpose as the Trustees may determine.

Voting Rights. Each Unit is entitled to one vote on all matters submitted to a vote of unit owners. Neither the Trust Agreement nor the Regulations provide for cumulative voting in the election of the Trustees.

Other Rights. The Units are not subject to redemption by operation of a sinking fund or otherwise. Unit owners are not currently entitled to pre-emptive rights.

EX-31 3 x31-123020.htm North European Oil Royalty Trust FY19 10-K Exhibit 31

Exhibit 31

Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, John R. Van Kirk, certify that:

I have reviewed this Annual Report on Form 10-K of North European Oil Royalty Trust;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a 15(e) and 15d 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared; and
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors and to the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/  John R. Van Kirk
   John R. Van Kirk
   Managing Director
   Chief Executive Officer and
   Chief Financial Officer

Dated: December 30, 2020

EX-32 4 x32-123020.htm North European Oil Royalty Trust FY19 10-K Exhibit 32

Exhibit 32

Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chapter 63, Title 18 U.S.C. Section 1350(a) and (b)), the undersigned hereby certifies that the Annual Report on Form 10-K for the period ended October 31, 2020 of North European Oil Royalty Trust ("Trust") fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that the information contained in such Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

/s/  John R. Van Kirk
   John R. Van Kirk
   Managing Director
   Chief Executive Officer and
   Chief Financial Officer

Dated: December 30, 2020

EX-99 5 x99-113020.htm

North European Oil Royalty Trust 10-K (FY2020)

North European Oil Royalty Trust

Calculation of Cost Depletion Percentage For 2020 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, 2020

GRAVES & CO. CONSULTING LLC HOUSTON, TEXAS

Table of Contents


Discussion	2

Description of Holdings	2

Oldenburg Area - Sales and Reserves	4

Total Sales	4

Gross Reserves	4

Net Reserves	5

Limitations of Available Data	5

Calculation of Cost Depletion Percentage	7


Attachments

Attachment A: Reserve Summary and Five Year Net Sales History

Attachment B: Calculation of Total Cost Depletion Percentage

Definitions of Reserves

Certificate of Qualifications

Graves & Co. Consulting Oil and Gas Reserves and Valuations

November 27, 2020

The Trustees of
North European Oil Royalty Trust
P. O. Box 187
Keene, New Hampshire 03431

Ref: North European Oil Royalty Trust
Calculation of the Cost Depletion Percentage
For the Calendar Year 2020

Trustees:

In accordance with the request of the Trustees of North European Oil Royalty Trust (the "Trust"), Graves & Co. Consulting LLC of Houston, Texas has performed the calculations necessary to derive the cost depletion percentage for the 2020 calendar year. The cost depletion percentage was prepared for use by unit owners of the Trust in filing federal income tax returns. In order to calculate the cost depletion percentage, we prepared a report of the estimated remaining proved producing reserves attributable to the overriding royalty interests of the Trust in the Northwest German Basin of the Federal Republic of Germany with an effective date of October 1, 2020.

We have reviewed all available information with respect to 100% of the Trust's proved developed properties used in the calculation of the cost depletion percentage as discussed later in this report. It is our opinion that these properties represent all of the Trust's assets that may be classified as proved for this purpose as per the Securities and Exchange Commission directives detailed later in this report.

The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part 210-Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility Holding Company Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rules of General Application Section 210.4-10 financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.

The proved producing reserves are as of October 1, 2020 and the reported sales are for the twelve-month period ending September 30, 2020. The use of the period ending September 30, 2020 is consistent with prior years and allows the timely calculation of the royalty reserves and the cost depletion percentage for the calendar year. Throughout this report the unit price used for crude oil, condensate, natural gas and sulfur is based upon the prices in effect at the time of the royalty calculations. The price for each of the products is then averaged for the twelve-month period to arrive at the unit price.

Based on the results of our calculation of estimated remaining proved producing reserves contained in the first part of this report, we have performed the calculations necessary to derive the cost depletion percentage for the 2020 calendar year. As detailed in Attachment B, the cost depletion percentage for the 2020 calendar year for Trust unit owners is equal to 16.5776% of the unit owner's cost basis as of January 1, 2020.

Discussion

The scope of this study was to review limited information we were able to compile and to prepare an estimate of the proved producing reserves subject to the Trust's royalty interests from which the cost depletion percentage could be calculated. We prepared reserve estimates using acceptable evaluation principals for each source. These estimates were based in large part on the limited information supplied by the operator of the relevant properties.

The quantities presented herein are estimated reserves of oil, natural gas, natural gas liquids and sulfur that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty.

Description of Holdings

The Trust holds various overriding royalty rights on sales of gas, sulfur and oil from certain concessions and leases in the Federal Republic of Germany. The Oldenburg concession (1,386,000 acres), covering virtually the entire former Grand Duchy of Oldenburg and located in the federal state of Lower Saxony, is held by Oldenburgische Erdolgesellschaft ("OEG"). OEG in turn is owned by Mobil Erdgas-Erdol GmbH ("Mobil Erdgas"), the German subsidiary of ExxonMobil Corp. and by BEB Erdgas und Erdol GmbH ("BEB"), a joint venture of ExxonMobil Corp. and the Royal Dutch/Shell Group of Companies. As a result by direct and indirect ownership, ExxonMobil Corp. owns two-thirds of OEG and the Royal Dutch/Shell Group owns one-third of OEG.

In 2002 Mobil Erdgas and BEB formed a new company ExxonMobil Production Deutschland GmbH to carry out all exploration, drilling and production within the Oldenburg concession. All sales activities are still handled by either Mobil Erdgas or BEB.

The Oldenburg concession is currently the sole source of royalty income for the Trust. All proved producing reserves within the Oldenburg concession are covered by this report. Although the Trust has royalty interests in other areas, these areas are no longer used in the calculation of the annual cost depletion percentage because there is no current production from these areas.

The Trust's rights in the Oldenburg concession are described as follows:

Under one set of rights covering the western part of the Oldenburg concession (approximately 662,000 acres), the Trust receives a royalty payment of 4% on gross receipts from sales by Mobil Erdgas of gas well gas, oil well gas, crude oil and condensate ("Mobil Agreement"). Under the Mobil Agreement there is no deduction of costs prior to the calculation of royalties from gas well gas or oil well gas, which together account for approximately 98% of all the royalties under said agreement.

Under another series of rights covering the entire Oldenburg concession and pursuant to an agreement with OEG, the Trust receives royalties at the rate of 0.6667% on gross receipts from sales of gas well gas, oil well gas, crude oil, condensate and sulfur (removed during the processing of sour gas) less a certain allowed deduction of costs ("OEG Agreement").

Under the OEG Agreement, 50% of the field handling and treatment costs as reported for state royalty purposes are deducted from gross sales receipts prior to the calculation of the royalty to be paid to the Trust. Sulfur is a by-product of gas production and is not considered in the computation of total cost depletion.

The Trust is also entitled to receive from Mobil Erdgas, a 2% royalty payment on gross receipts from sales of sulfur obtained as a by product of sour gas produced from the western part of Oldenburg. However, the payment of the sulfur royalty is provisional on whether Mobil Erdgas' selling price meets or exceeds the indexed base price.

Oldenburg Area - Sales and Reserves

The Trust's royalty income currently comes exclusively from the Oldenburg area. Gas production accounts for the majority of the income; however, the hydrogen sulfide in much of the gas produced necessitates its removal before the gas can be sold. At the Grossenkneten desulfurization plant, the hydrogen sulfide in sour gas is removed. The plant's present input capacity stands at approximately 400 million cubic feet ("MMcf") per day following EMPG's retirement of Unit 3 in April, 2017. The elimination of Unit 3 effectively reduced the input capacity by one third.

Total Sales

During the twelve months ending September 30, 2020, total sales for the Oldenburg area were as follows:

Total Sales	West	East	Total
Gas Well Gas - MMCF	16,987.8	44,371.1	61,358.9
Oil Well Gas - MMCF	94.2	8.4	102.6
Oil & Condensate - Barrels	64,026.4	26,507.6	90,534.0
Sulfur - Short Tons	73,910.5	261,273.2	335,183.7

Gross Reserves

Estimated gross remaining proved producing reserves attributable to the total Oldenburg area as of October 1, 2020 are as follows:

Gross Reserves	West	East	Total
Gas Well Gas - MMCF	67.9	325.8	393.7
Oil Well Gas - MMCF	947.0	66.5	1,013.5
Oil & Condensate - Barrels	987,552.5	352,134.4	1,339,686.9
Sulfur - Short Tons	442,417.8	2,898,872.9	3,341,290.7

Net Reserves

To present an accurate picture of estimated proved producing reserves net to the Trust, the gross reserve figures outlined above must be modified by the impact of the different royalty rates in effect in the Oldenburg concession. A comparison of the Trust's overriding royalty rates in both the western and eastern areas of Oldenburg is as follows:

Royalty Source	West	East
Mobil Erdgas Gas & Oil	4%	0%
Mobil Erdgas Sulfur	2%	0%
BEB Gas & Oil	0.6667%⁽¹⁾	0.6667%⁽¹⁾
BEB Sulfur	0.6667%⁽¹⁾	0.6667%⁽¹⁾
⁽¹⁾Prior to the calculation of royalties, 50% of costs as reported for state royalty purposes are deducted.

The application of these royalty rates to the estimated gross remaining proved producing reserves attributable to the western and eastern Oldenburg areas yields the combined estimated proved producing reserves net to the Trust. The Trust's estimated remaining net proved producing reserves as of October 1, 2020 and net sales for the twelve month period ending September 30, 2020 are as follows:

Net Reserves & Sales	Reserves	Sales
Gas Well Gas - MMCF	4,523.7	939.9
Oil Well Gas - MMCF	41.6	4.8
Oil & Condensate - Barrels	43,706.3	2,877.4
Sulfur - Short Tons	26,310.8	3,334.3

A summary of net proved producing reserves by product and a five year history of net sales attributable to the royalty interests of the Trust are presented in Attachment A.

Limitations of Available Data

The reserves considered in this report are defined as proved producing reserves. Proved producing reserves are limited to those quantities which can be expected to be recoverable commercially from known reservoirs at current prices and costs, under existing regulatory practices and with existing conventional equipment and operating methods. Proved producing reserves do not include either proved developed non producing reserves or any class of probable reserves.

The estimate of reserves included in this report is based primarily upon production history or analogy with wells in the area producing from the same or similar formations. In addition to individual well production history, geological and well test information, when available, were utilized in the evaluation.

The reserves included in this report are estimates only and should not be construed as being exact quantities. The accuracy of the estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data. The quantities presented herein are estimated reserves of hydrocarbons and produced products that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty. Reserve estimates presented in this report are calculated using acceptable methods and procedures and are believed to be appropriate and reasonable; however, future reservoir performance may justify revision of these estimates.

For the purpose of this report, estimated reserves are scheduled for recovery primarily on the basis of actual producing rates or appropriate well test information. They were prepared giving consideration to engineering and geological data, anticipated producing mechanisms, the number and types of completions, as well as past performance of analogous reservoirs. Individual well production histories, when available, were analyzed and an appropriate daily producing rate was utilized for each individual well in the preparation of a forecast of future producing rates until an anticipated economic limit.

No information was received from the operator concerning activity in the field during the Trust's Fiscal 2020.

The estimates of reserves and the forecasted rates of production may be subject to regulation by various agencies, changes in market demand or other factors. Consequently, the volumes of reserves recovered, and the actual rates of recovery, may vary from the estimates included herein.

The Trust, as an overriding royalty interest owner, does not receive proprietary data from the various operators on producing wells. Data, such as logs, core analysis, reservoir tests, pressure tests, gas analyses, geologic maps, and individual well production histories on all of the wells which are used in volumetric and material balance type reserve estimates, are not available to the Trust. The lack of such data increases the inherent uncertainties of our reserve estimate.

The Trust receives quarterly statements from the operators that report production, sales and revenue data. Utilizing the same procedures as in prior years, this information plus published information received from W.E.G. (a German organization comparable to the American Petroleum Institute or the American Gas Association) has been used to prepare this annual report. In addition, the Trust retains a part-time consultant in Germany who is familiar with the German petroleum industry in general and the operating companies in particular. His periodic reports and communications were considered in the preparation of this report.

We believe that reserve estimates prepared using all the available data are appropriate and sufficient for the calculation of the cost depletion percentage. However, due to the limitations of available data, this estimate of reserves cannot have the same degree of accuracy that an estimate of reserves prepared using all pertinent data would have. Our experience in the evaluation of reserves using such limited data compensates somewhat for the limitations of available data.

The data in the reports received by the Trust is in metric tons and cubic meters. The following Metric to English Unit conversion factors were used:

Gas:	37.25 cubic feet per cubic meter at 14.7 psia and 60 degrees Fahrenheit
Oil:	7.23 barrels per metric ton
Sulfur:	1.1 short tons per metric ton

Calculation of Cost Depletion Percentage

The categories of proved producing reserves considered in the calculation of the cost depletion percentage are oil, oil well gas, and gas well gas. Sulfur is a by-product of gas production and is not considered in the computation of total cost depletion percentage.

For each category of reserves, a product base was established for the Trust as of January 1, 1976. Through the use of these product bases, we can account for the relative size of each of these categories of reserves and the corresponding impact on the calculation of the cost depletion percentage. The product base for each category of proved producing reserves is reduced annually by an adjustment that is calculated by multiplying the product base at the beginning of the current year by the depletion factor for that category of reserves.

The depletion factor for each category of reserves is the ratio of the relevant net sales during the current year to the corresponding adjusted net proved producing reserves at the beginning of the current year.

Significant items in the cost depletion percentage calculation that appear on Attachment B as specific item numbers, shown in parentheses and their sources are as follows:

The adjusted estimated net proved producing reserves as of 10/1/2019 Line (3) is obtained by adding the estimated remaining net proved producing reserves as of 10/1/2019 Line (1) and the adjustments to reserves during the period Line (2). Therefore Line (3) = Line (1) + Line (2).

The depletion factor Line (6) for each category of proved producing reserves is obtained by dividing the relevant net sales Line (4) by the corresponding adjusted estimated net proved producing reserves as of 10/1/2019 Line (3). Therefore Line (6) = Line (4) / Line (3).

The product base for each category of proved producing reserves as of 1/1/2019 Line (7) and the adjustment taken during 2019 Line (8) were obtained from the previous year's report. The product base as of 1/1/2020 Line (9) forms the initial starting point for the calculation of the cost depletion percentage for the 2020 tax year. The product base for 1/1/2020 Line (9) then is Line (7) - Line (8).

The adjustment to the product base for each category of proved producing reserves Line (10) is used to reduce the product base as of the beginning of each year. This adjustment is the product of the depletion factor for each category of proved producing reserves Line (6) multiplied by the corresponding product base as of 1/1/2020 Line (9). Therefore Line (10) = Line (6) x Line (9).

The cost depletion percentage Line (11) then is the sum of the adjustment to the product base of each category of proved producing reserves [Sum Line (10)] divided by the sum of the product base for each category as of 1/1/2020 [Sum Line (9)]. Therefore Line (11) = [Sum Line (10)] / [Sum Line (9)].

The cost depletion percentage represents the total allowable cost depletion for the 2020 calendar year for the Trust's unit owners, expressed as a percentage of their cost base as of January 1, 2020.

Neither Graves & Co. Consulting, LLC nor any of its directors, officers, employees or contractors have any interest in the subject properties and neither the employment to make this study and calculation nor our compensation is contingent on our estimate of reserves or the results of our calculation.

We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.

Sincerely yours,

GRAVES & CO. CONSULTING LLC

/s/ John L. Graves
John L. Graves.
President

/s/ Allen C. Barron, P.E.
Allen C. Barron, P.E.
Executive Vice President

Attachment A

North European Oil Royalty Trust
Reserve Summary and Five Year Net Sales History

(All values expressed in whole numbers.)

Estimated Net Proved Producing Reserves
as of October 1, 2020

Oldenburg



Gas Well	Oil Well
Gas	Gas	Oil/Cond.	Sulfur
MMcf	MMcf	Barrels	Short Tons

4,523.7	41.6	43,706.3	26,310.8

Five Year Net Sales Summary
12 Months Ending September 30, 2020

Oldenburg



	Gas Well	Oil Well	Oil/Cond.	Sulfur
	Gas	Gas
	MMcf	MMcf	Barrels	Short Tons
2020	940	5	2,877	3,334
2019	1,215	3	3,947	3,931
2018	1,066	2	3,664	3,085
2017	1,330	2	4,210	4,665
2016	1,392	1	4,225	4,761

Attachment B

North European Oil Royalty Trust
Calculation Of Total Cost Depletion Percentage
For the Year Ending December 31, 2020

	OLDENBURG
	Gas Well	Oil Well
	Gas	Gas	Oil
	MMCF	MMCF	Barrels
NEORT NET RESERVES (Million Cubic Feet of Gas and Barrels of Oil)

1. Estimated net proved producing reserves as of 10-1-2019	6,429.7	17.6	50,074.5

2. Adjustment to reserves during period	(966.1)	28.8	(3,490.8)

3. Adjusted est. net proved producing reserves as of 10-1-2019	5,463.6	46.4	46,583.7

4. Net sales from 10-1-2019 to 9-30-2020	939.9	4.8	2,877.4

5. Estimated remaining net proved producing reserves as of 10-1-2020	4,523.7	41.6	43,706.3

RESERVE DEPLETION FACTOR

6. Depletion factor	1.17203	0.10345	0.06177

NEORT WEIGHTED PRODUCT BASE ALLOCATION

7. Product base as of 1-1-2019	1.70250	0.00093	0.09236

8. Less adjustments taken during 2019	0.27060	0.00013	0.00675

9. Product base as of 1-1-2020	1.43190	0.00080	0.08561

10. 2020 Adjustment to product base	0.24633	0.00008	0.00529

11. Cost depletion percentage for 2020 calendar year for Trust unit
owners is equal to 16.5776 percent of their 1-1-2020 cost base.

Footnotes:

Line (1) from reserves review as of 10-1-2019
Line (2) from reserves review as of 10-1-2020
Line (3) = Line (1) + Line (2)
Line (4) from BEB and Mobil Erdgas statements
Line (5) from reserves review as of 10-1-2020
Line (6) = Line (4) / Line (3)
Line (7) from 2018 depletion calculations
Line (8) from 2018 depletion calculations
Line (9) = Line (7) - Line (8)
Line (10) = Line (9) x Line (6)
Line (11) = Sum Line (10) / Sum Line (9)

Securities and Exchange Commission
Definitions of Reserves

The following information is from the United States Securities and Exchange Commission:

PART 210--FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACT OF 1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF 1940, AND ENERGY POLICY AND CONSERVATION ACT OF 1975

Rules of General Application

Section 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.

Reserves

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible--from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations--prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of the reservoir considered as proved includes:

The area identified by drilling and limited by fluid contacts, if any, and
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Oil and Gas Reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Additional Definitions:

Deterministic Estimate

The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Probabilistic Estimate

The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Reasonable Certainty

If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Graves & Co. Consulting Oil and Gas Reserves and Valuations

Certificate of Qualification

I, Allen C. Barron, Registered Professional Engineer, do hereby certify:

1. That I am Executive Vice President of the consulting firm of Graves & Co. Consulting LLC with offices at 2777 Allen Parkway, Suite 1200, Houston, Texas 77019.

2. That I have prepared a reserve report on the interests of the North European Oil Royalty
Trust in the Northwest Basin of the Federal Republic of Germany as of October 1, 2018
for the purpose of calculating the cost depletion percentage applicable to Trust unit
owners for the 2018 calendar year.

3. That I have no direct or indirect interest, nor do I expect to receive any direct or indirect
interest, in the properties or in any securities of the North European Oil Royalty Trust.

4. That I attended The University of Houston and that I graduated with a Bachelor of
Science Degree in Chemical Engineering with a Petroleum Engineering Option in 1968.

5. That I am a Registered Professional Engineer in the State of Texas, Registration Number
49284, and that I am a member in good standing of the National Society of Professional
Engineers, the Texas Society of Professional Engineers, the Society of Petroleum
Engineers, the Society of Petroleum Evaluation Engineers, the American Association of
Petroleum Geologists and other industry organizations.

6. That I have in excess of fifty years of experience in the evaluation of oil and gas
properties in the United States, Canada, South America, Asia and Germany, and that I
have been practicing as a consultant in petroleum reservoir engineering since 1978.

Signed November 27, 2020

GRAVES & CO. CONSULTING LLC

/s/ Allen C. Barron, P.E.
Allen C. Barron, P.E.
Executive Vice President

		Page
	PART I
Item 1.	Business	1
Items 1A.	Risk Factors	4
Item 1B.	Unresolved Staff Comments	4
Item 2.	Properties	4
Item 3.	Legal Proceedings	8
Item 4.	Mine Safety Disclosures	8
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	8
:
	PART II
Item 6.	Selected Financial Data	8
Item 7.	Management's Discussion and Analysis of Financial Conditions and Results of Operations	8
Items 7A.	Quantitative and Qualitative Disclosures about Market Risk	15
Item 8.	Financial Statements and Supplementary Data	15
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	25
Item 9A.	Controls and Procedures	25
Item 9B.	Other Information	26

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	26
Item 11.	Executive Compensation	26
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	27
Item 13.	Certain Relationships and Related Transactions, and Director Independence	27
Item 14.	Principal Accountant Fees and Services	27

	PART IV
Item 15	Exhibits and Financial Statement Schedules	28
Item 16.	Form 10-K Summary	28

Signatures		29
Exhibit Index		30

NORTH EUROPEAN OIL ROYALTY TRUST

North European Oil Royalty Trust

Attachment A

North European Oil Royalty Trust Reserve Summary and Five Year Net Sales History

Attachment B

North European Oil Royalty Trust Calculation Of Total Cost Depletion Percentage For the Year Ending December 31, 2020

Securities and Exchange Commission Definitions of Reserves

Reserves

Proved Oil and Gas Reserves

Probable Reserves

Possible Reserves

Developed Oil and Gas Reserves

Undeveloped Oil and Gas Reserves

Deterministic Estimate

Probabilistic Estimate

Reasonable Certainty

North European Oil Royalty Trust
Reserve Summary and Five Year Net Sales History

North European Oil Royalty Trust
Calculation Of Total Cost Depletion Percentage
For the Year Ending December 31, 2020

Securities and Exchange Commission
Definitions of Reserves