NORTH EUROPEAN OIL ROYALTY TRUST

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, covering 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 essentially 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 royalties from gas well gas and oil well gas together account for approximately 99% of all the royalties under said agreement. Historically, the Trust has received significantly greater royalty payments under the Mobil Agreement (as compared to the OEG Agreement described below) due to the higher royalty rate specified by that agreement.

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, including prior years’ corrections, paid under the Mobil Agreement totaled $188,914 and $154,599 during fiscal 2025 and 2024, 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.

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EMPG decommissioned one of the remaining two sulfur processing units (“trains”). The decommissioning was conducted during May to July 2023. 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 73% 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, 2025 by product, geographic area, and operating company:

Exhibit 99.1 to this Report is a report entitled Calculation of Cost Depletion Percentage for the 2025 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, 2025 (the “Cost Depletion Report”). The Cost Depletion Report, dated December 5, 2025, 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 2025 calendar year based on the use of certain production data and the estimated net proved producing reserves as of October 1, 2025 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, 2025. 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.

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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 2025 is 8.9814%. 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 2025 calendar year are included on removable pages in the 2025 Annual Report. Additionally, the tax reporting information for 2025 is available on the Trust’s website, https://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, 2025 and a five-year schedule of gas, sulfur and oil sales for the twelve months ended September 30, 2025, 2024, 2023, 2022, and 2021 computed from quarterly sales reports of operating companies received by the Trust during such periods.

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