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 units 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 annual report on Form 10-K (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, after making provisions to cover future anticipated expenses. 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. Accordingly, 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 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 holding 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 concession 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 12,000 Euros. The Trust then converts the remainder of Euro denominated funds into United States ("U.S.") dollars based upon the available exchange rates. Following this conversion to U.S. dollars, the royalties are transferred to the Trust's bank account in the U.S. The Trust does not engage in activities to hedge against currency risk, and the fluctuations in the conversion rate impact its financial results. 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.

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 began their examination of the operating companies for calendar years 2021 and 2022 in October 2023 when the final sales figures and the German Border Import gas Prices (see Item 7 of this Report) were both 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, 2023.

(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 Trustee is designated as Managing Trustee. Nancy J. Floyd Prue has served in a non-executive capacity as Managing Trustee since March 13, 2023. 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. For these services, each of these three individuals receives additional compensation. Willard B. Taylor is the fourth Trustee.

Day-to-day matters are handled by the Managing Director, John R. Van Kirk, who also serves as CEO and CFO. Mr. Van Kirk has held the position of Managing Director of the Trust since November 1990. In addition to the Managing Director, the Trust has one administrative employee in the U.S., whose title is Administrator. The number of total employees of the Trust is two, and the number of full-time employees is two.

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 http://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 Report.

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 100% 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.

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.

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 paid under the Mobil Agreement totaled $34,586 and $316,527 during fiscal 2023 and 2022, respectively.

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 very minor treatment before it can be sold. Sour gas, in comparison, must be processed at the Grossenkneten desulfurization plant which commenced operations in 1972. The desulfurization process removes hydrogen sulfide and other contaminants before the clean gas can be sold. The hydrogen sulfide in gaseous form is converted to sulfur in a solid form and sold separately.

EMPG decommissioned one of the remaining two sulfur processing units ("trains"). The decommissioning was conducted during May-July 2023. For a period of twenty-four days beginning on June 25, 2023, there was no through-put at the plant while the shutdown of one train and the refurbishment and maintenance of the remaining train were completed. The cost of this work was approximately 50 million Euros. The plant is subject to an ongoing schedule of inspections which may result in shutdowns while required repairs are conducted. Full operation of the remaining train is approximately 200 million cubic feet ("MMcf") per day following the shutdown. It is expected that the single train will be sufficient to handle sour gas production through-put from the concession. It is also expected that operating expenses in the future may be reduced by this measure. Since sour gas accounts for 71% of overall gas sales and 97% of western gas sales, any future shutdown of the remaining train could significantly impact royalty income. The Trust has insufficient data to predict whether, when and to what extent any future shutdown may occur.

The following is a schedule of royalty income for the fiscal year ended October 31, 2023 by product, geographic area and operating company:

By Product:
Product	Royalty Income
Gas Well and Oil Well Gas	$21,740,519
Sulfur	$187,563
Oil	$88,021

By Geographic Area:
Area	Royalty Income
Western Oldenburg	$16,192,614
Eastern Oldenburg	$5,823,489
Non-Oldenburg Areas	$0

By Operating Company:
Company	Royalty Income
Mobil Erdgas (under the Mobil Agreement)	$13,951,199
BEB (under the OEG Agreement)	$8,064,904

Exhibit 99.1 to this Report is a report entitled Calculation of Cost Depletion Percentage for the 2023 Calendar Year Based on the Estimate of Remaining Proved Producing Reserves in the Northwest Basin of the Federal Republic of Germany as of October 1, 2023 (the "Cost Depletion Report"). The Cost Depletion Report, dated November 27, 2023, was prepared by Graves & Co. Consulting, LLC, 1800 West Loop South, Suite 750, Houston, Texas 77027 ("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 2023 calendar year based on the use of certain production data and the estimated net proved producing reserves as of October 1, 2023 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, 2023. 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 2023 is 8.8130%. 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 2023 calendar year are included on removable pages in the 2023 Annual Report. Additionally, the tax reporting information for 2023 is available on the Trust's website, http://www.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. 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 complete reservoir production information 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, 2023 and a five-year schedule of gas, sulfur and oil sales for the twelve months ended September 30, 2023, 2022, 2021, 2020 and 2019 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, and no Trust property is the subject of, any pending legal proceedings.

Item 4. Mine Safety Disclosures.

Not Applicable.

PART II

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

None.

Item 6. [Reserved].

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 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 royalties to the Trust based on their sales of natural gas, sulfur and oil. Of these three products, natural gas provided approximately 99% of the total royalties in fiscal 2023. 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 produced 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 to establish a new base to determine gas prices for the calculation of the Trust's royalties. 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 to the prices calculated for the German Border Import gas Price ("GBIP"). The average combined totals of the GBIP for the relevant three-month period are used to provide an average gas price for the quarter. This average gas price is increased by 1% and 3% per the terms of the Mobil and OEG Royalty Agreements and is used by the operators to calculate the royalties payable to the Trust for a given quarter.

The change to the GBIP has reduced the scope and cost of the accounting examination, eliminated ongoing disputes with OEG and Mobil regarding sales to related parties, and reduced prior year adjustments to the normally scheduled year-end reconciliation. The pricing basis has also eliminated certain costs 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 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. The respective royalty amount is divided into thirds and forms the monthly royalty payments to the Trust for the Trust's upcoming fiscal quarter. When the operating companies determine the actual amount of royalties that were payable for the prior calendar quarter, they also 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. Positive adjustments are paid immediately and any negative adjustments are deducted from the next royalty payment. 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.

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 U.S. 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 assets of the Trust are depleting assets and, if the operators developing the concession do not perform additional development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets.

The Trust's consultant in Germany provides general information to the Trust on the German and European economies and energy markets as well as monitoring the continuing impact of the war in Ukraine and ongoing efforts by the European governments to respond to the economic impacts of the war. 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.

Results: Fiscal 2023 versus Fiscal 2022

Russia's current war against Ukraine derailed the European energy system, with Germany hit particularly hard. With Russian gas making up such a large portion of Germany's energy needs, Germany took steps to rebuild its reserves for the following winter and ensure a steady source of future supply. As a result of the increase in demand for alternative sources of gas, in August 2022 the GBIP spiked 645% year over year. These high gas prices resulted in the destruction of some industrial demand and a general reduction in consumer demand. However, the increase in gas prices was short lived and following a warm winter with further reduced demand, the GBIP continued to decline through the end of the year.

Beginning at the end of the second quarter of fiscal 2023, large negative adjustments dictated by the Trust's royalty agreements were accrued and subsequently applied against royalty income in the following quarter. The ongoing price decline in conjunction with the accrued negative adjustments continued to occur in the third and fourth quarters of fiscal 2023. The distribution of $0.21 per unit in the third quarter of fiscal 2023 represented an 80% decline from the second quarter's distribution of $1.05 per unit. There was no distribution for the fourth quarter of fiscal 2023.

For fiscal 2023, the Trust's gross royalty income increased 23.7% to $22,016,103 from $17,800,119 in fiscal 2022. The total distribution for fiscal 2023 was $2.26 per unit compared to $1.83 per unit for fiscal 2022. Gas prices under both royalty agreements were higher while gas sales and average exchange rates were down. The royalty income received under the Mobil Agreement in fiscal 2023 increased by $2,664,909 as compared to fiscal 2022. Royalty income received under the OEG Agreement in fiscal 2023 increased by $1,549,381 as compared to fiscal 2022.

The Trust receives adjustments from the operating companies based on their final calculations of royalties payable during the previous periods. During fiscal 2023, the adjustments based on royalties payable for 2022 would have decreased royalty income by Euros 228,631. However, because there was no royalty income received to offset, this negative amount will carry over into the first quarter of fiscal 2024. During fiscal 2022, the adjustments based on royalties payable for 2021 increased royalty income by $1,550,020. In fiscal 2023 and 2022, Mobil sulfur royalties totaled $34,586 and $316,527, respectively.

Gas sales under the Mobil Agreement decreased 16.4% to 12.439 Billion cubic feet ("Bcf") in fiscal 2023 from 14.874 Bcf in fiscal 2022. Given the lack of drilling by the operating companies during 2023 and the renovation work on Grossenkneten, the Trust's consultant in Germany believes the decline in gas production is due to the combination of the temporary shutdown of processing at Grossenkneten and 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	2023 Gas Sales	2022 Gas Sales	Percentage change
First	3.519	4.105	-14.28%
Second	3.451	3.605	-4.27%
Third	2.957	3.665	-19.32%
Fourth	2.512	3.499	-28.21%
Fiscal Year Total	12.439	14.874	-16.37%

Average prices for gas sold under the Mobil Agreement increased 49.5% to 8.3231 Euro cents per kilowatt hour ("Ecents/kWh") in fiscal 2023 from 5.5665 Ecents/kWh in fiscal 2022.

Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour
Fiscal Quarter	2023 Average Gas Prices	2022 Average Gas Prices	Percentage change
First	14.1664	3.0604	+362.89%
Second	9.1043	5.1442	+76.98%
Third	4.7294	6.1535	-23.14%
Fourth	3.2970	8.3302	-60.42%
Fiscal Year Average	8.3231	5.5665	+49.52%

Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $23.54 per thousand cubic feet ("Mcf"), an increase of 42.1% from fiscal 2022's average price of $16.56/Mcf. For fiscal 2023, royalties paid under the Mobil Agreement were converted and transferred at an average Euro/U.S. dollar exchange rate of 0.9900, a decrease of 4.9% from the average Euro/U.S. dollar exchange rate of 1.0405 for fiscal 2022.

Average Euro Exchange Rate under the Mobil Agreement
Fiscal Quarter	2023 Average Euro Exchange Rate	2022 Average Euro Exchange Rate	Percentage change
First	1.0706	1.1256	-4.89%
Second	1.0698	1.0883	-1.70%
Third	1.1099	1.0236	+8.43%
Fourth	0.0000¹	0.9864	-100.00%
Fiscal Year Average	0.9900	1.0405	-4.85%
^{1. No royalty income was deposited into the Trust's account at Deutsche Bank, and there was no conversion and transfer to the Trust's account with M&T Bank. Consequently, no exchange rate was generated.}

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 2023, the volume of gas sold from western Oldenburg accounted for only 27.7% of the volume of all gas sales. However, western Oldenburg gas royalties provided approximately 73.8% or $16,041,589 out of a total of $21,740,519 in overall Oldenburg gas royalties.

Gas sales under the OEG Agreement decreased 15.8% to 44.944 Bcf in fiscal 2023 from 53.385 Bcf in fiscal 2022. Given the lack of drilling by the operating companies during 2023 and the maintenance work on Grossenkneten, the Trust's consultant in Germany believes the decline in gas production is due to the combination of the temporary shutdown of processing at Grossenkneten and 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	2023 Gas Sales	2022 Gas Sales	Percentage change
First	12.881	13.970	-7.80%
Second	12.242	13.123	-6.71%
Third	10.503	13.341	-21.27%
Fourth	9.318	12.951	-28.05%
Fiscal Year Total	44.944	53.385	-15.81%

Average gas prices for gas sold under the OEG Agreement increased 48.2% to 8.4965 Ecents/kWh in fiscal 2023 from 5.7342 Ecents/kWh in fiscal 2022.

Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour
Fiscal Quarter	2023 Average Gas Prices	2022 Average Gas Prices	Percentage change
First	14.4469	3.1210	+362.89%
Second	9.2846	5.2460	+76.98%
Third	4.8230	6.2753	-23.14%
Fourth	3.3623	8.4951	-60.42%
Fiscal Year Average	8.4965	5.7342	+48.17%

Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $23.85/Mcf, an increase of 43.7% from fiscal 2022's average price of $16.60/Mcf. For fiscal 2023, royalties paid under the OEG Agreement were converted and transferred at an average Euro/U.S. dollar exchange rate of 1.0069, a decrease of 3.0% from the average Euro/U.S. dollar exchange rate of 1.0375 for fiscal 2022.

Average Euro Exchange Rate under the OEG Agreement
Fiscal Quarter	2023 Average Euro Exchange Rate	2022 Average Euro Exchange Rate	Percentage change
First	1.0700	1.1255	-4.93%
Second	1.0698	1.0867	-1.56%
Third	1.1170	1.0236	+9.12%
Fourth	0.0000¹	0.9868	-100.00%
Fiscal Year Average	1.0069	1.0375	-2.95%
^{1. No royalty income was deposited into the Trust's account at Deutsche Bank, and there was no conversion and transfer to the Trust's account with M&T Bank. Consequently, no exchange rate was generated.}

Interest income for fiscal 2023 of $125,003 increased from interest income of $2,244 for fiscal 2022 due to the higher amount of royalties received and higher interest rates. Trust expenses increased $253,674, or 35.5%, to $967,591 in fiscal 2023 from $713,917 in fiscal 2022 due to higher Trustees' fees as specified in the provisions of the Trust Agreement and higher legal expenses.

Report on Drilling and Geophysical Work

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 in December 2023. 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.

The Trust's German consultant has advised the Trust that EMPG has not planned any new wells for calendar 2024 and no major work has been initiated on the exploration side.

Maintenance work, including well cleanup jobs and foam jobs to de-water weak wells, will be continuing to ensure the wells are operating at maximum efficiency and production levels.

Critical Accounting Estimates

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 U.S. ("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. All statements other than statements of historical fact are forward-looking. Such statements address future expectations and events or conditions concerning the Trust. You can identify many forward-looking statements by words such as "may," "will," "would," "should," "could," "expects," "aim," "anticipates," "believes," "estimates," "intends," "plan," "predict," "project," "seek," "potential," "opportunities" and other similar expressions and the negatives of such expressions. However, not all forward-looking statements contain these words. 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:

• the fact that the assets of the Trust are depleting assets and, if the operators developing the concession do not perform additional development projects, the assets may deplete faster than expected;

• 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

• political and economic uncertainty arising from Russia's invasion of Ukraine.

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, 2023 and 2022	F-3

Statements of Revenue Collected and Expenses Paid for the Fiscal Years Ended October 31, 2023 and 2022	F-4

Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2023 and 2022	F-5

Statements of Changes in Cash and Cash Equivalents for the Fiscal Years Ended October 31, 2023 and 2022	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, 2023 and 2022, 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, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust as of October 31, 2023 and 2022, and its revenue collected and expenses paid, undistributed earnings and changes in its cash and cash equivalents for each of the two years in the period ended October 31, 2023, in conformity with the modified cash basis of accounting described in Note 1.

Basis for Opinion

These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on the Trust's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust 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 Trust'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.

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.

F-1

Critical Audit Matters

Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.

/s/ Mazars USA LLP

We have served as the Trust's auditor since 2006
Iselin, NJ
December 29, 2023

F-2

NORTH EUROPEAN OIL ROYALTY TRUSTSTATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (NOTE 1)OCTOBER 31, 2023 AND 2022

	2023	2022
ASSETS
Current assets -- Cash and cash equivalents	$795,201	$7,193,457

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

Total Assets	$795,202	$7,173,458


	2023	2022
LIABILITIES AND TRUST CORPUS
Current liabilities -- Distributions to be paid to unit owners	$0	$6,801,037

Trust corpus (Notes 1 and 2)	1	1

Undistributed earnings	795,201	392,420

Total Liabilities and Trust Corpus	$795,202	$7,193,458

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, 2023 AND 2022

	2023	2022
Gas, sulfur and oil royalties received	$22,016,103	$17,800,119
Interest income	125,003	2,244
Trust Income	$22,141,106	$17,802,363
Operating Expenses	($957,067)	($695,071)
Related party expenses (Note 3)	(10,524)	(18,846)
Trust Expenses	($967,591)	($713,917)
Net Income	$21,173,515	$17,088,446
Net income per unit	$2.30	$1.86
Distributions per unit paid or to be paid to unit owners	$2.26	$1.83

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, 2023 AND 2022

	2023	2022
Balance, beginning of period	$392,420	$122,754
Net income	21,173,515	17,088,446
	21,565,935	17,211,200
Less:
Current year distributions paid or to be paid to unit owners	20,770,734	16,818,780
Balance, end of period	$795,201	$392,420

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, 2023 AND 2022

	2023	2022
Sources of Cash and Cash Equivalents:
Gas, sulfur and oil royalties received	$22,016,103	$17,800,119
Interest income	125,003	2,244
	$22,141,106	$17,802,363
Uses of Cash and Cash Equivalents:
Payment of Trust expenses	$967,591	$713,917
Distributions paid	27,571,771	11,304,426
	$28,539,362	$12,018,343
Net increase (decrease) in cash and cash equivalents during the year	(6,398,256)	5,784,020
Cash and cash equivalents, beginning of year	7,193,457	1,409,437
Cash and cash equivalents, end of year	$795,201	$7,193,457

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

F-6

NORTH EUROPEAN OIL ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

OCTOBER 31, 2023 AND 2022

(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.

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) since 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 additionally 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, 2023, the uninsured amounts held in the Trust's U.S. bank accounts were $538,163. In addition, the Trust held Euros 6,659, the equivalent of $7,038, in its German bank account at October 31, 2023.

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, 2023 and 2022, 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 $10,524 and $5,256 in fiscal 2023 and 2022, 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 2023 and 2022 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, 2023 and 2022:

Fiscal 2023 by Quarter and Year

	First	Second	Third	Fourth	Year
Royalties received	$9,765,883	$9,760,018	$2,490,778	($576)¹	$22,016,103
Net income	$9,536,014	$9,504,566	$2,290,894	($157,959)²	$21,173,515
Net Income per unit	$1.04	$1.03	$0.25	($0.02)	$2.30
Distribution paid or to be paid	$9,190,590	$9,650,120	$1,930,024	$0	$20,770,734
Distribution per unit or to be paid to unit owners	$1.00	$1.05	$0.21	$0.00	$2.26
^{1. At the end of each fiscal quarter, the Trust converts the Euro balance in its account at Deutsche Bank into dollars and includes this amount in the royalty income total. Since there was no royalty income for the fourth fiscal quarter and there was a loss on exchange, the total royalty income for the fourth fiscal quarter is a negative number.}
^{2. The negative net income is comprised of the negative royalty income minus the quarterly expenses plus interest income.}

Fiscal 2022 by Quarter and Year

	First	Second	Third	Fourth	Year
Royalties received	$2,546,539	$3,773,568	$4,442,665	$7,037,347	$17,800,119
Net income	$2,351,819	$3,559,968	$4,292,607	$6,884,050	$17,088,466
Net Income per unit	$0.26	$0.39	$0.47	$0.75	$1.86
Distribution paid or to be paid	$2,297,647	$3,492,424	$4,227,671	$6,801,037	$16,818,779
Distribution per unit or to be paid to unit owners	$0.25	$0.38	$0.46	$0.74	$1.83

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, 2023. Based on that evaluation, the Managing Director concluded that the Trust's disclosure controls and procedures were effective as of October 31, 2023.

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, 2023. 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, 2023.

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 2023 that have materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting.

Item 9B. Other Information.

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Except as set forth below, the information required by this item will be contained in the Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to be held on February 21, 2024, 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 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 chief executive officer and chief financial and accounting officer. A copy of the Code is available without charge on request by writing to the Managing Director at the office of the Trust. The Code is also available on the Trust's website, www.neort.com.

All Trustees and employees of the Trust are required to read and sign a copy of the Code annually. No waivers or exceptions to the Code have been granted since the adoption of the Code. Any amendments or waivers to the Code, to the extent required, will be disclosed in a Form 8-K filing of the Trust after such amendment or waiver.

Item 11. Executive Compensation.

The information required by this item will be contained in the Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to be held on February 21, 2024, 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, 2023 and 2022

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus as of October 31, 2023 and 2022

Statements of Revenue Collected and Expenses Paid for the Fiscal Years Ended October 31, 2023 and 2022

Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2023 and 2022

Statements of Changes in Cash and Cash Equivalents for the Fiscal Years Ended October 31, 2023 and 2022

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 29, 2023	/s/John R. Van Kirk
	John R. Van Kirk, Managing Director
	and Chief Financial 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 29, 2023	/s/Nancy J. Floyd Prue
	Nancy J. Floyd Prue, Managing Trustee

Dated: December 29, 2023	/s/Ahron H.Haspel
	Ahron H. Haspel, Trustee

Dated: December 29, 2023	/s/Lawrence A. Kobrin
	Lawrence A. Kobrin, Trustee

Dated: December 29, 2023	/s/Willard B. Taylor
	Willard B. Taylor, Trustee

Dated: December 29, 2023	/s/John R. Van Kirk
	John R. Van Kirk, Managing Director
	and Chief Financial 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

(97)	Policy for the Recovery of Erroneously Awarded Compensation		36

(99.1)	Calculation of Cost Depletion Percentage for the 2023 Calendar Year Based on the Estimate of Remaining Proved Producing Reserves in the Northwest Basin of the Federal Republic of Germany as of October 1, 2023 prepared by Graves & Co. Consulting, LLC		41

(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 x4-122923.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. 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 preemptive rights.

EX-31 3 x31-122923.htm North European Oil Royalty Trust FY23 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 the modified cash basis of accounting; 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 29, 2023

EX-32 4 x32-122923.htm North European Oil Royalty Trust FY23 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, 2023 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 29, 2023

EX-97 5 x97-122923.htm

Exhibit 97

NORTH EUROPEAN OIL ROYALTY TRUST
POLICY FOR THE
RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

OVERVIEW

In accordance with the applicable rules of The New York Stock Exchange Listed Company Manual (the "NYSE Rules"), Section 10D and Rule 10D-1 of the Securities Exchange Act of 1934, as amended (the "Exchange Act") ("Rule 10D-1"), the Board of Trustees (the "Board") of North European Oil Royalty Trust (the "Trust") has adopted this Policy (the "Policy") to provide for the recovery of erroneously awarded Incentive-based Compensation from Executive Officers. All capitalized terms used and not otherwise defined herein shall have the meanings set forth in Section H, below.

RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

1. Although the Trust does not, as a general rule, employ Incentive-based Compensation, this Policy shall govern all instances where, in fact, the Trust did utilize Incentive-based Compensation. In the event of an Accounting Restatement, the Trust will reasonably promptly recover the Erroneously Awarded Compensation Received in accordance with NYSE Rules and Rule 10D-1 as follows:

"Committee")

(a) For Incentive-based Compensation based on (or derived from) the Trust's stock price or total shareholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in the applicable Accounting Restatement:

i. The amount to be repaid or returned shall be determined by the Committee based on a reasonable estimate of the effect of the Accounting Restatement on the Trust's stock price or total shareholder return upon which the Incentive-based Compensation was Received; and

ii. The Trust shall maintain documentation of the determination of such reasonable estimate and provide the relevant documentation as required to the NYSE.

(ii) The Committee shall have discretion to determine the appropriate means of recovering Erroneously Awarded Compensation based on the particular facts and circumstances. Notwithstanding the foregoing, except as set forth in Section B (2) below, in no event may the Trust accept an amount that is less than the amount of Erroneously Awarded Compensation in satisfaction of an Executive Officer's obligations hereunder.

(iii) To the extent that the Executive Officer has already reimbursed the Trust for any Erroneously Awarded Compensation Received under any duplicative recovery obligations established by the Trust or applicable law, it shall be appropriate for any such reimbursed amount to be credited to the amount of Erroneously Awarded Compensation that is subject to recovery under this Policy.

(iv) To the extent that an Executive Officer fails to repay all Erroneously Awarded Compensation to the Trust when due, the Trust shall take all actions reasonable and appropriate to recover such Erroneously Awarded Compensation from the applicable Executive Officer. The applicable Executive Officer shall be required to reimburse the Trust for any and all expenses reasonably incurred (including legal fees) by the Trust in recovering such Erroneously Awarded Compensation in accordance with the immediately preceding sentence.

2. Notwithstanding anything herein to the contrary, the Trust shall not be required to take the actions contemplated by Section B (1) above if the Committee (which, as specified above, is composed entirely of independent Trustees or in the absence of such a committee, a majority of the independent Trustees serving on the Board) determines that recovery would be impracticable and any of the following two conditions are met:

(i.) The Committee has determined that the direct expenses paid to a third party to assist in enforcing the Policy would exceed the amount to be recovered. Before making this determination, the Trust must make a reasonable attempt to recover the Erroneously Awarded Compensation, documented such attempt(s) and provided such documentation to the NYSE; or

(ii.) Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Trust, to fail to meet the requirements of Section 401(a)(13) or Section 411(a) of the Internal Revenue Code of 1986, as amended, and regulations thereunder.

C. DISCLOSURE REQUIREMENTS

The Trust shall file all disclosures with respect to this Policy required by applicable U.S. Securities and Exchange Commission ("SEC") filings and rules.

D. PROHIBITION OF INDEMNIFICATION

The Trust shall not be permitted to insure or indemnify any Executive Officer against (i) the loss of any Erroneously Awarded Compensation that is repaid, returned or recovered pursuant to the terms of this Policy, or (ii) any claims relating to the Trust's enforcement of its rights under this Policy. Further, the Trust shall not enter into any agreement that exempts any Incentive-based Compensation that is granted, paid or awarded to an Executive Officer from the application of this Policy or that waives the Trust's right to recovery of any Erroneously Awarded Compensation, and this Policy shall supersede any such agreement (whether entered into before, on or after the Effective Date of this Policy).

E. ADMINISTRATION AND INTERPRETATION

This Policy shall be administered by the Committee, and any determinations made by the Committee shall be final and binding on all affected individuals.

The Committee is authorized to interpret and construe this Policy and to make all determinations necessary, appropriate, or advisable for the administration of this Policy and for the Trust's compliance with NYSE Rules, Section 10D, Rule 10D-1 and any other applicable law, regulation, rule or interpretation of the SEC or NYSE promulgated or issued in connection therewith.

F. AMENDMENT; TERMINATION

The Committee may amend this Policy from time to time in its discretion and shall amend this Policy as it deems necessary. Notwithstanding anything in this Section F to the contrary, no amendment or termination of this Policy shall be effective if such amendment or termination would (after taking into account any actions taken by the Trust contemporaneously with such amendment or termination) cause the Trust to violate any federal securities laws, SEC rule or NYSE rule.

G. OTHER RECOVERY RIGHTS

This Policy shall be binding and enforceable against all Executive Officers and, to the extent required by applicable law or guidance from the SEC or NYSE, their beneficiaries, heirs, executors, administrators or other legal representatives. The Committee intends that this Policy will be applied to the fullest extent required by applicable law. Any employment agreement, equity award agreement, compensatory plan or any other agreement or arrangement with an Executive Officer shall be deemed to include, as a condition to the grant of any benefit thereunder, an agreement by the Executive Officer to abide by the terms of this Policy. Any right of recovery under this Policy is in addition to, and not in lieu of, any other remedies or rights of recovery that may be available to the Trust under applicable law, regulation or rule or pursuant to the terms of any policy of the Trust or any provision in any employment agreement, equity award agreement, compensatory plan, agreement or other arrangement.

H.. DEFINITIONS

For purposes of this Policy, the following capitalized terms shall have the meanings set forth below.

(1) "Accounting Restatement" means an accounting restatement due to the material noncompliance of the Trust with any financial reporting requirement under the securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements (a "Big R" restatement), or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period (a "little r" restatement).

(2) "Clawback Eligible Incentive Compensation" means all Incentive-based Compensation Received by an Executive Officer (i) on or after the effective date of the applicable NYSE rules, (ii) after beginning service as an Executive Officer, (iii) who served as an Executive Officer at any time during the applicable performance period relating to any Incentive-based Compensation (whether or not such Executive Officer is serving at the time the Erroneously Awarded Compensation is required to be repaid to the Trust), (iv) while the Trust has a class of securities listed on a national securities exchange or a national securities association, and (v) during the applicable Clawback Period (as defined below).

(3) "Clawback Period" means, with respect to any Accounting Restatement, the three completed fiscal years of the Trust immediately preceding the Restatement Date (as defined below), and if the Trust changes its fiscal year, any transition period of less than nine months within or immediately following those three completed fiscal years.

(4) "Erroneously Awarded Compensation" means, with respect to each Executive Officer in connection with an Accounting Restatement, the amount of Clawback Eligible Incentive Compensation that exceeds the amount of Incentive-based Compensation that otherwise would have been Received had it been determined based on the restated amounts, computed without regard to any taxes paid.

(5) "Executive Officer" means each individual who is currently or was previously designated as an "officer" of the Trust as defined in Rule 16a-1(f) under the Exchange Act. For the avoidance of doubt, the identification of an executive officer for purposes of this Policy shall include each executive officer who is or was identified pursuant to Item 401(b) of Regulation S-K, as applicable, as well as the principal financial officer and principal accounting officer (or, if there is no principal accounting officer, the controller).

(6) "Financial Reporting Measures" means measures that are determined and presented in accordance with the accounting principles used in preparing the Trust's financial statements, and all other measures that are derived wholly or in part from such measures. Stock price and total shareholder return (and any measures that are derived wholly or in part from stock price or total shareholder return) shall, for purposes of this Policy, be considered Financial Reporting Measures. For the avoidance of doubt, a Financial Reporting Measure need not be presented in the Trust's financial statements or included in a filing with the SEC.

(7) "Incentive-based Compensation" means any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure.

(8) "NYSE" means the New York Stock Exchange.

(9) "Received" means, with respect to any Incentive-based Compensation, actual or deemed receipt, and Incentive-based Compensation shall be deemed received in the Trust's fiscal period during which the Financial Reporting Measure specified in the Incentive-based Compensation award is attained, even if the payment or grant of the Incentive-based Compensation to the Executive Officer occurs after the end of that period.

(10) "Restatement Date" means the earlier to occur of (i) the date the Board, a committee of the Board or the officers of the Trust authorized to take such action if Board action is not required, concludes, or reasonably should have concluded, that the Trust is required to prepare an Accounting Restatement, or (ii) the date a court, regulator or other legally authorized body directs the Trust to prepare an Accounting Restatement.

Effective as December 1, 2023

Exhibit A

ATTESTATION AND ACKNOWLEDGEMENT OF POLICY FOR THE RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

By my signature below, I acknowledge and agree that:

- I have received and read the attached Policy for the Recovery of Erroneously Awarded Compensation (this "Policy).

- I hereby agree to abide by all of the terms of this Policy both during and after my employment with the Trust, including, without limitation, by promptly repaying or returning any Erroneously Awarded Compensation to the Trust as determined in accordance with this Policy.

Signature: ______/s/ John R. Van Kirk____________

Printed Name: _____John R. Van Kirk____________

Date:___________December 15, 2023___________

EX-99 6 x99-112923.htm

North European Oil Royalty Trust 10-K (FY2023)

North European Oil Royalty Trust

Calculation of Cost Depletion Percentage For 2023 Calendar Year Based on the Estimate of Remaining Proved Producing Reserves in the Northwest Basin of the Federal Republic of Germany As of October 1, 2023

GRAVES & CO. CONSULTING LLC HOUSTON, TEXAS

Table of Contents


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	6

Overview of Natural Gas Processing	7

Description of Grossenkneten Plant	7

Changes in ExxonMobil's Plant Operations	8

Impacts on Future Trust Royalty Income	8

Uncertainties Related to Future Gas Plant Operations	8

Reserves Estimates	9

Calculation of Cost Depletion Percentage	9

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, 2023

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

Ref: North European Oil Royalty Trust
Calculation of the Cost Depletion Percentage
For the Calendar Year 2023

Trustees:

In accordance with the request of the Trustees of North European Oil Royalty Trust (the "Trust"), Graves & Co. Consulting LLC of Houston, Texas has performed the calculations necessary to derive the cost depletion percentage for the 2023 calendar year. The cost depletion percentage was prepared for use by unit owners of the Trust in filing federal income tax returns. In order to calculate the cost depletion percentage, we prepared a report of the estimated remaining proved producing reserves attributable to the overriding royalty interests of the Trust in the Northwest German Basin of the Federal Republic of Germany with an effective date of October 1, 2023.

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

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

The proved producing reserves are as of October 1, 2023 and the reported sales are for the twelve-month period ending September 30, 2023. The use of the period ending September 30, 2023 is consistent with prior years and allows the timely calculation of the royalty reserves and the cost depletion percentage for the calendar year. Throughout this report the unit price used for crude oil, condensate, natural gas and sulfur is based upon the prices in effect at the time of the royalty calculations. The price for each of the products is then averaged for the twelve-month period to arrive at the unit price.

Based on the results of our calculation of estimated remaining proved producing reserves contained in the first part of this report, we have performed the calculations necessary to derive the cost depletion percentage for the 2023 calendar year. As detailed in Attachment B, the cost depletion percentage for the 2023 calendar year for Trust unit owners is equal to 8.8130% of the unit owner's cost basis as of January 1, 2023.

Discussion

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

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

Description of Holdings

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

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

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

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

Under one set of rights covering the western part of the Oldenburg concession (approximately 662,000 acres), the Trust receives a royalty payment of 4% on gross receipts from sales by Mobil Erdgas of gas well gas, oil well gas, crude oil and condensate ("Mobil Agreement"). Under the Mobil Agreement there is no deduction of costs prior to the calculation of royalties from gas well gas or oil well gas, which together account for over 99% of all the royalties under said agreement.

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

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

The Trust is also entitled to receive from Mobil Erdgas, a 2% royalty payment on gross receipts from sales of sulfur obtained as a by-product of sour gas produced from the western part of Oldenburg. However, the payment of the sulfur royalty is provisional on whether Mobil Erdgas' selling price meets or exceeds the indexed base price. Sulfur is a by-product of gas production and is not considered in the computation of total cost depletion.

Oldenburg Area - Sales and Reserves

The Trust's royalty income currently comes exclusively from the Oldenburg area. Gas production accounts for the majority of the income; however, the hydrogen sulfide in much of the gas produced necessitates its removal before the gas can be sold. At the Grossenkneten desulfurization plant, the hydrogen sulfide in sour gas is removed. The plant's present input capacity stands at approximately 200 million cubic feet ("MMcf") per day following ExxonMobil's retirement of Unit 3 in April 2017, and more recently by the retirement of Unit 2 in June 2023. The elimination of two of the plant's three trains has effectively reduced the input capacity by two-thirds.

Total Sales

During the twelve months ending September 30, 2023, total sales for the Oldenburg area were as follows:

Total Sales	West	East	Total
Gas Well Gas - MMCF	12,439.6	32,513.0	44,952.6
Oil Well Gas - MMCF	1.2	2.0	3.2
Oil & Condensate - Barrels	59,098.0	13,820.3	72,918.3
Sulfur - Short Tons	55,942.0	204,552.7	260,494.7

Gross Reserves

Estimated gross remaining proved producing reserves attributable to the total Oldenburg area as of October 1, 2023 are as follows:

Gross Reserves	West	East	Total
Gas Well Gas - MMCF	116,518.5	395,118.1	511,636.6
Oil Well Gas - MMCF	12.1	0.0	12.1
Oil & Condensate - Barrels	734,066.9	52,960.8	787,027.7
Sulfur - Short Tons	631,448.4	2,228,154.5	2,859,602.9

Gross reserves are down across the board based on a combination of gas production constraints, lower oil prices, and higher operating expenses which shorten the economic life. The exception is western oil production, which has seen improved production rates and lower operating expenses.

Net Reserves and Sales

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

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

The application of these royalty rates to the estimated gross remaining proved producing reserves attributable to the western and eastern Oldenburg areas yields the combined estimated proved producing reserves net to the Trust. The Trust's estimated remaining net proved producing reserves as of October 1, 2023 and net sales for the twelve month period ending September 30, 2023 are as follows:

Net Reserves & Sales	Reserves	Sales
Gas Well Gas - MMCF	7,828.4	759.0
Oil Well Gas - MMCF	0.5	0.1
Oil & Condensate - Barrels	32,798.1	2,709.3
Sulfur - Short Tons	29,824.4	2,722.0

A summary of net proved producing reserves by product and a five-year history of net sales attributable to the royalty interests of the Trust are presented in Attachment A. Net gas well gas and sulfur reserves are down compared to 2022 because of gas processing plant refurbishment and resulting production constraints. Net oil reserves are up based on performance at Lastrup-West. Though not material, net oil well gas sales decreased sharply in 2023 resulting in a corresponding drop in net reserves.

Limitations of Available Data

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

The estimate of reserves included in this report is based primarily upon production history or analogy with wells in the area producing from the same or similar formations. Typically, geological data, well reports, and well tests are available and utilized in evaluations; however, no such data was made available for 2023.

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

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

No information was received from the operator concerning activity in the field during the Trust's fiscal year 2023 other than there was no drilling activity, and five wells were plugged and abandoned.

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

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

The Trust receives quarterly statements from the operators that report production, sales and revenue data. Utilizing the same procedures as in prior years, this information has been used to prepare this annual report. In addition, the Trust retains a part-time consultant in Germany who is familiar with the German petroleum industry in general and the operating companies in particular. His periodic reports and communications were considered in the preparation of this report.

Overview of Natural Gas Processing

ExxonMobil operates a natural gas processing plant, the Grossenkneten Plant at Grossenkneten, Lower Saxony, Germany, located approximately 40 kilometers to the west of Bremen. The plant is designed to remove non-hydrocarbon impurities from the natural gas produced on the Oldenburg concession, especially hydrogen sulfide. The Grossenkneten plant has supplied natural gas and sulfur to Germany for over 50 years. Seventy-five percent (75%) of the natural gas produced on the Oldenburg concession is sour gas requiring desulfurization at the plant. The following paragraphs provide a description of the plant and changes in ExxonMobil's operation of the plant that have impacted Trust royalty income this year and that may have an impact on Trust royalty income in the future.

Description of Grossenkneten Plant

The Grossenkneten Plant consists of complex natural gas desulfurization and dehydration, sulfur recovery ("Claus-process"), waste gas purification and ancillary facilities. The ancillary facilities include a steam boiler, a gas engine, emergency flaring facilities and a condensing power station.

Every ten years, the plant is shut down for extensive refurbishment and maintenance, including safety checks and efficiency improvements. Given the hydrogen sulfide content of the natural gas, safety requirements for working on the site are very stringent. The most recent refurbishment occurred from August to October 2020, and included 3,200 individual maintenance and installation activities. The refurbishment employed 600 contractors, and the work injected 30 million euros into the local and regional economies. A new gas/gas heat exchanger was installed, improving the plant's energy efficiency. Following the refurbishment work, the plant was re-certified for another ten years, until 2030.

Changes in ExxonMobil's Plant Operations

The Grossenkneten Plant originally had three trains in use desulfurizing and dehydrating natural gas. Each operating train had a treatment capacity of approximately 2.0 billion cubic meters per year of untreated sour gas. ExxonMobil retired Unit 3 in April 2017, effectively reducing the plant input capacity at that time by one-third. Consistent with the inherent decline of Oldenburg gas production, ExxonMobil shut down a second of the three trains during the summer of 2023. As of June 2023, only one train remains in use and throughput is understood to be at capacity. This refurbishment and optimization work negatively impacted the production from the wells between May and July.

Impacts on Future Trust Royalty Income

The Trust's German consultant has informed us that because of the changes in plant operations, production curtailment estimated at 8.9% is expected until the end of the first quarter in 2024. Although this suggests a modest potential increase in production starting in the second quarter of 2024, no concomitant adjustment has been built into the production forecasts for the Trust's wells. Requirements to periodically cycle off and on weak, low-pressure wells and high water-cut wells, operations that are consistent with the maturity of the field, are expected to offset any increase from ending the curtailment.

ExxonMobil's shutdown of the second train at Grossenkneten should result in a reduction of certain costs deducted from the Trust's gross royalties. Offsetting these reductions will be increased well operating expenses which are the inevitable result of declining production volumes.

Uncertainties Related to Future Gas Plant Operations

We possess insufficient data from the plant's operator, ExxonMobil, that would be necessary to make a quantitative assessment of the uncertainties related to the economics of future long-term operations at the Grossenkneten Plant. Accordingly, Graves has decided not to allocate a risk factor to the reserve calculations used in the preparation of this report attributable to such uncertainties. Full retirement of the Grossenkneten plant at some time in the future could potentially mean the end of production from the Oldenburg concession and of the Trust's royalty income. The producing life of the concession and the oil, gas, and sulfur reserves attributable thereto that are set forth in this report would in such an event be cut short.

Reserve Estimates

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

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

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

Calculation of Cost Depletion Percentage

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

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

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

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

The adjusted estimated net proved producing reserves as of 10/1/2022 Line (3) is obtained by adding the estimated remaining net proved producing reserves as of 10/1/2022 Line (1) and the adjustments to reserves during the period Line (2). Therefore Line (3) = Line (1) + Line (2).

The depletion factor Line (6) for each category of proved producing reserves is obtained by dividing the relevant net sales Line (4) by the corresponding adjusted estimated net proved producing reserves as of 10/1/2022 Line (3). Therefore Line (6) = Line (4) / Line (3).

The product base for each category of proved producing reserves as of 1/1/2022 Line (7) and the adjustment taken during 2022 Line (8) were obtained from the previous year's report. The product base as of 1/1/2023 Line (9) forms the initial starting point for the calculation of the cost depletion percentage for the 2023 tax year. The product base for 1/1/2023 Line (9) then is Line (7) - Line (8).

The adjustment to the product base for each category of proved producing reserves Line (10) is used to reduce the product base as of the beginning of each year. This adjustment is the product of the depletion factor for each category of proved producing reserves Line (6) multiplied by the corresponding product base as of 1/1/2023 Line (9). Therefore Line (10) = Line (6) x Line (9).

The cost depletion percentage Line (11) then is the sum of the adjustment to the product base of each category of proved producing reserves [Sum Line (10)] divided by the sum of the product base for each category as of 1/1/2023 [Sum Line (9)]. Therefore Line (11) = [Sum Line (10)] / [Sum Line (9)].

The cost depletion percentage represents the total allowable cost depletion for the 2023 calendar year for the Trust's unit owners, expressed as a percentage of their cost base as of January 1, 2023.

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

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

Sincerely yours,

GRAVES & CO. CONSULTING LLC

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

/s/ Mel F. Hainey, P.E.
Mel F. Hainey, P.E.
Sr. Reservoir Engineer

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, 2023

Oldenburg


Gas Well	Oil Well
Gas	Gas	Oil/Cond.	Sulfur
MMcf	MMcf	Barrels	Short Tons
7,828	1	32,798	29,824

Five Year Net Sales Summary
12 Months Ending September 30, 2023

Oldenburg


	Gas Well	Oil Well
	Gas	Gas	Oil/Cond.	Sulfur
	MMcf	MMcf	Barrels	Short Tons
2023	759	0	2,709	2,722
2022	903	1	2,791	3,255
2021	882	1	2,779	3,110
2020	940	5	2,877	3,334
2019	1,215	3	3,947	3,931

Attachment B

North European Oil Royalty Trust
Calculation Of Total Cost Depletion Percentage

For the Year Ending December 31, 2023

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

1. Estimated net proved producing reserves as of 10-1-2022	10,582.1	15.3	28,064.1

2. Adjustment to reserves during period	-1,994.7	(14.7)	7.443.3

3. Adjusted est. net proved producing reserves as of 10-1-2022	8,587.4	0.6	35,507.4

4. Net sales from 10-1-2022 to 9-30-2023	759.0	0.1	2,709.3

5. Estimated remaining net proved producing reserves as of 10-1-2023	7,828.4	0.5	32,798.1

RESERVE DEPLETION FACTOR

6. Depletion factor	0.08839	0.16667	0.07630

NEORT WEIGHTED PRODUCT BASE ALLOCATION

7. Product base as of 1-1-2022	1.01993	0.00000	0.02248

8. Less adjustments taken during 2022	0.08021	0.00000	0.00203

9. Product base as of 1-1-2023	0.93972	0.00000	0.02045

10. 2023 Adjustment to product base	0.08306	0.00000	0.00156

11. Cost depletion percentage for 2023 calendar year for Trust unit
owners is equal to 8.8130 percent of their 1-1-2023 cost base.

Footnotes:

Line (1) from reserves review as of 10-1-2022
Line (2) from reserves review as of 10-1-2023
Line (3) = Line (1) + Line (2)
Line (4) from BEB and Mobil Erdgas statements
Line (5) from reserves review as of 10-1-2023
Line (6) = Line (4) / Line (3)
Line (7) from 2022 depletion calculations
Line (8) from 2022 depletion calculations
Line (9) = Line (7) - Line (8)
Line (10) = Line (9) x Line (6)
Line (11) = Sum Line (10) / Sum Line (9)

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, Mel F. Hainey, Registered Professional Engineer, do hereby certify:

1. That I am a Sr. Reservoir Engineer of the consulting firm of Graves & Co. Consulting LLC with offices at 1800 West Loop South, Suite 750, Houston, Texas 77027.

2. That I have prepared a reserve report on the interests of the North European Oil Royalty
Trust in the Northwest Basin of the Federal Republic of Germany as of October 1, 2023
for the purpose of calculating the cost depletion percentage applicable to Trust unit
owners for the 2023 calendar year.

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

4. That I attended The University of Texas at Austin and that I graduated with a Bachelor of
Science Degree in Electrical Engineering in 1975 with a Master of Science Degree in Engineering in 1977.

5. That I am a Registered Professional Engineer in the State of Texas, Registration Number
65528, and that I am a member in good standing of the Texas Society of Professional Engineers and the Society of Petroleum Engineers.

6. That I have in excess of forty years of experience in the petroleum engineering including the evaluation of oil and gas properties in the United States, Canada, Indonesia, Turkey and Germany, and that I have been practicing as a consultant in petroleum reservoir engineering since 2016

Signed November 27, 2023

GRAVES & CO. CONSULTING LLC

/s/ Mel F. Hainey, P.E.
Mel F. Hainey, P.E.
Sr. Reservoir Engineer

		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	7
Item 4.	Mine Safety Disclosures	7
	PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	8
Item 6.	[Reserved]	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	14
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
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	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

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

Securities and Exchange Commission
Definitions of Reserves