10-K - NRT - Equibles

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended October 31, 2025 or

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission file number 1-8245

NORTH EUROPEAN OIL ROYALTY TRUST

(Exact Name of Registrant as Specified in Its Charter)

Delaware	22-2084119
State or Other Jurisdiction of<br><br> <br>Incorporation or Organization	I.R.S. Employer Identification No.
5 N. Lincoln Street, Keene, N.H.	03431
Address of Principal Executive Offices	Zip Code
	(732) 741-4008
---	---
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Units of Beneficial Interest	NRT	New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☒	Smaller reporting company ☒
	Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal controls over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

On April 30, 2025, the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold was $41,522,551.

As of December 31, 2025, there were 9,190,590 units of beneficial interest (“units”) of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Items 10, 11, 12, 13 and 14 of Part III have been partially or wholly omitted from this report and the information required to be contained therein is incorporated by reference from the registrant’s definitive proxy statement for the 2025 Annual Meeting to be held on February 17, 2026.

Table of Contents

		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	4
Item 1B.	Unresolved Staff Comments	4
Item 1C.	Cybersecurity	4
Item 2.	Properties	5
Item 3.	Legal Proceedings	8
Item 4.	Mine Safety Disclosures	8
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 Condition and Results of Operations	9
Item 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

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PART I

Item 1.	Business.

(a) General Development of Business. North European Oil Royalty Trust (the “Trust”) is a grantor trust which, on behalf of the owners of 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 form an Audit Committee and a Compensation Committee but may not necessarily continue to do so in the future.

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(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 current administrative and related expenses and making provisions for future anticipated 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 15,000 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 fluctuations in the conversion rate impact 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 and no effort has been undertaken to identify such third parties.

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 payable to the Trust and on reserves attributable to the Trust’s royalty interests 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.

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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. In 2016, a law was passed in Germany prohibiting fracking of unconventional reservoirs. Fracking of conventional reservoirs, including sandstone, is permitted subject to drilling permits as well as State and Federal laws. 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. Within the Oldenburg concession, fracking was used in the Carboniferous zone and once in the Zechstein zone but has not been used in the Bunter zone.

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 2023 and 2024 in October 2025 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, 2025.

(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. Andrew S. Borodach and Richard P. Howard were appointed as Trustees on October 1, 2024.

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 reviews the royalty payments by the operating companies on a biennial basis. The Trust and the co-royalty holder regularly share the costs of the consulting and accounting services in Germany. The legal firm advises and represents as needed.

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(e) Available Information. The Trust maintains a website at https://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.

Consistent with the rules applicable to “Smaller Reporting Companies,” we have elected scaled disclosure reporting, and therefore have omitted information required by this Item.

Item 1B.	Unresolved Staff Comments.

None.

Item 1C.	Cybersecurity.

The Trust is a grantor trust, conducts no active operations, has no customers, and maintains no personal or credit data. The Trust’s processes for assessing, identifying, and managing material risks from cybersecurity threats are tailored to its specific circumstances. The Trust’s cybersecurity protocols include, but are not limited to, programs with built-in technological features to prevent disruptions and intrusions, and isolated computer workstations. The Trust’s personnel are aware of the potential of a cybersecurity incident and exercise caution to ensure no such incident occurs. Production downtimes, operational delays, the compromising of confidential or otherwise protected information, destruction or corruption of data, security breaches, theft, other manipulation or improper use of our systems and networks or financial losses from remedial actions could have a material adverse effect on our competitive position, financial condition, reputation or results of operations. The primary entities with which the Trust conducts business are banks, outside service providers, and vendors, which have their own cybersecurity protocols. Interactions between the Trust’s information facilities and outside vendors or service providers involves a combination of passwords, passphrases, and two-factor or independent authorizations.

We have experienced, and could experience in the future, actual or attempted cyber-attacks of our information technology systems or networks. However, there have been no known cybersecurity incidents that have had a material impact, have materially affected or are reasonably likely to materially affect the Trust, including its business strategy, results of operations, or financial condition.

The Managing Director oversees the Trust’s cybersecurity protocols and conducts regular discussions and reviews of such protocols with the Trustees.

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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, 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:

By Product:
Product	Royalty Income
Gas Well and Oil Well Gas	$	8,146,320
Sulfur	$	428,513
Oil	$	75,071
By Geographic Area:
Area	Royalty Income
Western Oldenburg	$	6,686,731
Eastern Oldenburg	$	1,963,173
Non-Oldenburg Areas	$	0
By Operating Company:
Company	Royalty Income
Mobil Erdgas (under the Mobil Agreement)	$	5,836,999
BEB (under the OEG Agreement)	$	2,812,905

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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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.

Market Information

As of October 31, 2025, the Trust had 9,190,590 units issued and outstanding. The Trust’s units are quoted on the New York Stock Exchange under the symbol “NRT.”

Holders

As of October 31, 2025, there were 465 unit owners of record, including Cede & Co., the nominee of the Depository Trust Company. The number of record unit owners may not be representative of the number of beneficial owners of our units, whose units are held in street name by banks, brokers, and other nominees.

Equity Performance Graph

Consistent with the rules applicable to “Smaller Reporting Companies,” we have elected scaled disclosure reporting, and therefore have omitted information required by this Item.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

Item 6.	[Reserved]

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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 the Trust’s anticipated expenses.

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 for 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 94% of the total royalties in fiscal 2025. 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.

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On approximately the 25^th^ 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. While future maintenance and development projects on the underlying assets will affect the quantity of proved reserves and can offset the reduction in the depletion of proved reserves, the timing and size of these projects, if they occur, will depend on the market prices of oil and natural gas. If the operators developing the concession do not perform such additional maintenance or development projects, the future

    rate of production decline of proved reserves may be higher than the rate currently expected by the Trust and 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 cannot 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 2025 versus Fiscal 2024

Negative calendar 2023 adjustments had an impact on both the fourth quarter of fiscal 2024 and the first quarter of fiscal 2025. The actual adjustments affecting scheduled royalty payments in the first quarter of fiscal 2025 totaled ($1,754,663). This adjustment eliminated royalties payable under the OEG Agreement and reduced royalties received under the Mobil Agreement to $505,864 during the first quarter of fiscal 2025. The year-end adjustment for calendar 2024 was $472,384. There is a negative end-of-quarter adjustment for the fourth fiscal quarter that will reduce royalty income for the first quarter of fiscal 2026 by Euros 266,306 ($308,168 based on the exchange rate of 1.157196 as of October 31, 2025).

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For fiscal 2025, the Trust’s gross royalty income increased 49.5% to $8,650,094 from $5,785,303 in fiscal 2024. The total distribution for fiscal 2025 was $0.81 per unit compared to $0.48 per unit for fiscal 2024. Gas prices under both royalty agreements were higher, gas sales were lower, and average exchange rates were up. The royalty income received under the Mobil Agreement in fiscal 2025 increased 30.7% or, $1,301,622, to $5,535,716 compared to $4,234,094 received in fiscal 2024. Royalty income received under the OEG Agreement in fiscal 2025 increased 81.3% or, $1,261,744, to $2,812,905 compared to $1,551,161 received in fiscal 2024.

Gas sales under the Mobil Agreement decreased 4.7% to 11.994 Billion cubic feet (“Bcf”) in fiscal 2025 from 12.592 Bcf in fiscal 2024. With the continued lack of drilling by the operating companies through 2025, there was a slight decline in gas production. Absent a renewed drilling program, the normal reduction in well pressure would be expected to continue and gas production would be expected to decline.

Quarterly and Yearly Gas Sales under the Mobil Agreement in Billion cubic feet

Fiscal Quarter	2025 Gas Sales	2024 Gas Sales	Percentage Change
First	3.199	3.223	- 0.7%
Second	2.863	3.236	-11.5%
Third	2.873	3.073	- 6.5%
Fourth	3.059	3.060	- 0.0%
Fiscal Year Total	11.994	12.592	- 4.7%

Average prices for gas sold under the Mobil Agreement increased 11.1% to 4.1328 Euro cents per kilowatt hour (“€cents/kWh”) in fiscal 2025 from 3.7206 €cents/kWh in fiscal 2024.

Average Gas Prices under the Mobil Agreement in €cents per Kilowatt Hour

Fiscal Quarter	2025 Average<br><br> <br>Gas Prices	2024 Average<br><br> <br>Gas Prices	Percentage<br><br> <br>Change
First	3.8837	3.8530	+ 0.8%
Second	4.5308	4.1601	+ 8.9%
Third	4.4632	3.2503	+37.3%
Fourth	3.7111	3.5886	+ 3.4%
Fiscal Year Average	4.1328	3.7206	+11.1%

Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $13.10 per thousand cubic feet (“Mcf”), an increase of 13.7% from fiscal 2024’s average price of $11.52/Mcf. For fiscal 2025, royalties paid under the Mobil Agreement were converted and transferred at an average Euro/U.S. dollar exchange rate of 1.1080, a 2.3% increase from the average Euro/U.S. dollar exchange rate of 1.0834 for fiscal 2024.

Average Euro Exchange Rate under the Mobil Agreement

Fiscal Quarter	2025 Average<br><br> <br>Euro Exchange Rate	2024 Average<br><br> <br>Euro Exchange Rate	Percentage<br><br> <br>Change
First	1.0341	1.0816	- 4.4%
Second	1.0878	1.0714	+ 1.5%
Third	1.1445	1.0757	+ 6.4%
Fourth	1.1654	1.1071	+ 5.3%
Fiscal Year Average	1.1080	1.0834	+ 2.3%

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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 2025, the volume of gas sold from western Oldenburg accounted for only 30.1% of the volume of all gas sales. However, western Oldenburg gas royalties provided approximately 78.1% or $6,361,719 out of a total of $8,146,510 in overall Oldenburg gas royalties.

Gas sales under the OEG Agreement decreased 7.0% to 39.893 Bcf in fiscal 2025 from 42.918 Bcf in fiscal 2024. Given the continued lack of drilling by the operating companies through 2025, the Trust’s consultant in Germany believes the decline in gas production is due to the normal reduction in well pressure that is experienced over time.

Quarterly and Yearly Gas Sales under the OEG Agreement in Billion cubic feet

Fiscal Quarter	2025 Gas Sales	2024 Gas Sales	Percentage Change
First	10.549	11.085	- 4.8%
Second	9.858	10.870	- 9.3%
Third	9.858	10.454	- 5.7%
Fourth	9.628	10.509	- 8.4%
Fiscal Year Total	39.893	42.918	- 7.0%

Average gas prices for gas sold under the OEG Agreement increased 11.5% to 4.2293 €cents/kWh in fiscal 2025 from 3.7929 €cents/kWh in fiscal 2024.

Average Gas Prices under the OEG Agreement in €cents per Kilowatt Hour

Fiscal Quarter	2025 Average<br><br> <br>Gas Prices	2024 Average<br><br> <br>Gas Prices	Percentage<br><br> <br>Change
First	3.9606	3.9293	+ 0.8%
Second	4.6205	4.2425	+ 8.9%
Third	4.5516	3.3146	+37.3%
Fourth	3.7845	3.6597	+ 3.4%
Fiscal Year Average	4.2293	3.7929	+ 11.5%

Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $13.43/Mcf for fiscal 2025, an increase of 16.8% from fiscal 2024’s average price of $11.50/Mcf. For fiscal 2025, royalties paid under the OEG Agreement were converted and transferred at an average Euro/U.S. dollar exchange rate of 1.1343, an increase of 4.6% from the average Euro/U.S. dollar exchange rate of 1.0848 for fiscal 2024.

Average Euro Exchange Rate under the OEG Agreement

Fiscal Quarter	2025 Average<br><br> <br>Euro Exchange Rate	2024 Average<br><br> <br>Euro Exchange Rate	Percentage<br><br> <br>Change
First	0.0000^1^	0.0000^1^
Second	1.0926	1.0715	+ 2.0%
Third	1.1441	1.0757	+ 6.4%
Fourth	1.1661	1.1071	+ 5.3%
Fiscal Year Average	1.1343	1.0848	+ 4.6%

^1^No royalty income under the OEG Royalty Agreement 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.

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Trust expenses of $795,648 in fiscal 2025 were virtually unchanged from Trust expenses of $797,872 in fiscal 2024.

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 2025. 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 2026 and no major work has been initiated on the exploration side.<br><br> <br><br><br> <br>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 Policies

The financial statements, appearing subsequently in this Report, present financial statement balances and financial results on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the U.S. (“GAAP basis”). Modified 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 modified 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.

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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 the conflict in Ukraine and the Middle East.
---	---

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.

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Item 8.	Financial Statements and Supplementary Data.

NORTH EUROPEAN OIL ROYALTY TRUST

INDEX TO FINANCIAL STATEMENTS

	Page Number
Report of Independent Registered Public Accounting Firms	F-1 – F-2
Financial Statements:
Statements of Assets, Liabilities and Trust Corpus as of October 31, 2025 and 2024	F-3
Statements of Revenue Collected and Expenses Paid for the Fiscal Years Ended October 31, 2025 and 2024	F-4
Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2025 and 2024	F-5
Statements of Changes in Cash and Cash Equivalents for the Fiscal Years Ended October 31, 2025 and 2024	F-6
Notes to Financial Statements	F-7 – F-9

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Report of Independent Registered Public Accounting Firm

Board of Trustees and the Unit Owners

North European Oil Royalty Trust

Opinion on the Financial Statements

We have audited the accompanying statement of assets, liabilities, and trust corpus of North European Oil Royalty Trust (the “Trust”) as of October 31, 2025 and 2024, the related statements of revenue collected and expenses paid, undistributed earnings, and changes in cash and cash equivalents for the years ended October 31, 2025 and 2024 and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of October 31, 2025 and 2024, and its revenues collected and expenses paid, undistributed earnings, and changes in cash and cash equivalents for the years then ended October 31, 2025 and 2024, 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 audit.

We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits 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 include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit 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

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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/ Forvis Mazars, LLP

We have served as the Trust’s auditor since 2024.

Iselin, New Jersey

December 31, 2025

F-2

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NORTH EUROPEAN OIL ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (NOTE 1)

OCTOBER 31, 2025 AND 2024

ASSETS	2025		2024
Current assets - - Cash and cash equivalents	$	4,785,156	$	1,625,343
Producing gas and oil royalty rights,<br><br> <br>net of amortization (Notes 1 and 2)		1		1
Total Assets	$	4,785,157	$	1,625,344
LIABILITIES AND TRUST CORPUS		2025		2024
Current liabilities - - Distributions to be paid to unit owners	$	2,849,083	$	183,812
Trust corpus (Notes 1 and 2)		1		1
Undistributed earnings		1,936,073		1,441,531
Total Liabilities and Trust Corpus	$	4,785,157	$	1,625,344

The accompanying notes are

an integral part of these financial statements.

F-3

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NORTH EUROPEAN OIL ROYALTY TRUST

STATEMENTS OF REVENUE COLLECTED AND EXPENSES PAID (NOTE 1)

FOR THE FISCAL YEARS ENDED OCTOBER 31, 2025 AND 2024

	2025			2024
Gas, sulfur, and oil royalties received	$	8,650,094		$	5,785,303
Interest income		84,474			70,382
Trust Income	$	8,734,568		$	5,855,685
Operating Expenses	$	(784,632	)	$	(790,289	)
Related party expenses (Note 3)		(11,016	)		(7,583	)
Trust Expenses	$	(795,648	)	$	(797,872	)
Net Income	$	7,938,920		$	5,057,813
Net income per unit	$	0.86		$	0.55
Distributions per unit paid or to be paid to unit owners	$	0.81		$	0.48
Units outstanding at end of period		9,190,590			9,190,590

The accompanying notes are

an integral part of these financial statements.

F-4

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NORTH EUROPEAN OIL ROYALTY TRUST

STATEMENTS OF UNDISTRIBUTED EARNINGS (NOTE 1)

FOR THE FISCAL YEARS ENDED OCTOBER 31, 2025 AND 2024

	2025		2024
Balance, beginning of year	$	1,441,531	$	795,201
Net income		7,938,920		5,057,813
		9,380,451		5,853,014
Less:
Current year distributions paid or to be paid to unit owners		7,444,378		4,411,483
Balance, end of year	$	1,936,073	$	1,441,531

The accompanying notes are

an integral part of these financial statements.

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NORTH EUROPEAN OIL ROYALTY TRUST

STATEMENTS OF CHANGES IN CASH AND CASH EQUIVALENTS (NOTE 1)

FOR THE FISCAL YEARS ENDED OCTOBER 31, 2025 AND 2024

	2025		2024
Sources of Cash and Cash Equivalents:
Gas, sulfur, and oil royalties received	$	8,650,094	$	5,785,303
Interest income		84,474		70,382
	$	8,734,568	$	5,855,685
Uses of Cash and Cash Equivalents:
Payment of Trust expenses	$	795,648	$	797,872
Distributions paid		4,779,107		4,227,671
	$	5,574,755	$	5,025,543
Net increase (decrease) in cash and cash equivalents during the year		3,159,813		830,142
Cash and cash equivalents, beginning of year		1,625,343		795,201
Cash and cash equivalents, end of year	$	4,785,156	$	1,625,343

The accompanying notes are

an integral part of these financial statements.

F-6

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NORTH EUROPEAN OIL ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

OCTOBER 31, 2025 AND 2024

(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.

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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. The Trust held €15,000, the equivalent of $17,358, in its German bank account at October 31, 2025.

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, 2025 and 2024, 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 $11,016 and $7,583 in fiscal 2025 and 2024, 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 2025 and 2024 calendar years.

F-8

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(5) Quarterly results (unaudited):

The tables below summarize the quarterly results and distributions of the Trust for the fiscal years ended October 31, 2025 and 2024:

Fiscal 2025 by Quarter and Year

	First		Second		Third		Fourth		Year
Royalties received	$	505,697	$	2,471,301	$	2,617,231	$	3,055,865	$	8,650,094
Net income	$	285,468	$	2,261,006	$	2,459,107	$	2,933,339	$	7,938,919
Net income per unit	$	0.03	$	0.25	$	0.27	$	0.32	$	0.86
Distributions paid or to be paid	$	367,624	$	1,838,118	$	2,389,553	$	2,849,083	$	7,444,378
Distributions per unit paid or to be paid to unit owners	$	0.04	$	0.20	$	0.26	$	0.31	$	0.81

Fiscal 2024 by Quarter and Year

	First		Second		Third		Fourth		Year
Royalties received	$	424,910	$	2,232,767	$	2,457,422	$	670,204	$	5,785,303
Net income	$	179,085	$	2,033,899	$	2,318,094	$	526,734	$	5,057,813
Net income per unit	$	0.02	$	0.22	$	0.25	$	0.06	$	0.55
Distributions paid or to be paid	$	459,529	$	1,838,118	$	1,930,024	$	183,812	$	4,411,483
Distributions per unit paid or to be paid to unit owners	$	0.05	$	0.20	$	0.21	$	0.02	$	0.48

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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, 2025. Based on that evaluation, the Managing Director concluded that the Trust’s disclosure controls and procedures were effective as of October 31, 2025.

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, 2025. 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, 2025.

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 2025 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting.

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Item 9B.	Other Information.

During the quarter ended October 31, 2025, none of our directors or officers (as defined in Section 16 of the Securities Exchange Act of 1934, as amended), adopted or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement” (each as defined in Item 408(a) and (c), respectively, of Regulation S-K).

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 17, 2026, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.

Insider Trading Policy

The Trust has adopted insider trading policies and procedures governing the purchase, sale, and/or other dispositions of the Trust units by the Trustees and employees, or the Trust itself, that are reasonably designed to promote compliance with insider trading laws, rules and regulations, and any listing standards applicable to the Trust. A copy of such policies and procedures is filed hereto as Exhibit 19.1.

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 17, 2026, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.

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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.

28 -

Table of Contents

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<br><br> <br>October 31, 2025 and 2024
	Report of Independent Registered Public Accounting Firm
	Statements of Assets, Liabilities and Trust Corpus as of<br><br> <br>October 31, 2025 and 2024
	Statements of Revenue Collected and Expenses Paid for the<br><br> <br>Fiscal Years Ended October 31, 2025 and 2024
	Statements of Undistributed Earnings for the Fiscal Years Ended <br><br> <br> <br>October 31, 2025 and 2024
	Statements of Changes in Cash and Cash Equivalents for the<br><br> <br>Fiscal Years Ended October 31, 2025 and 2024
	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.

29 -

Table of Contents

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 OPEAN OIL ROYALTY TRUST
Dated: December 31, 2025	John R. Van Kirk
	John R. Van Kirk, Managing Director,
	Chief Executive Officer, and
	Chief Financial Officer

All values are in Euros.

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 31, 2025	/s/	Nancy J. Floyd Prue
		Nancy J. Floyd Prue, Managing Trustee
Dated: December 31, 2025	/s/	Andrew S. Borodach
		Andrew S. Borodach, Trustee
Dated: December 31, 2025	/s/	Ahron H. Haspel
		Ahron H. Haspel, Trustee
Dated: December 31, 2025	/s/	Richard P. Howard
		Richard P. Howard, Trustee
Dated: December 31, 2025	/s/	Lawrence A. Kobrin
		Lawrence A. Kobrin, Trustee
Dated: December 31, 2025	/s/	John R. Van Kirk
		John R. Van Kirk, Managing Director,
		Chief Executive Officer, and
		Chief Financial Officer

30 -

Table of Contents

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<br> (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 (incorporated by reference to Exhibit 4.1 to Annual Report on Form 10-K for the year ended October 31, 2024 (File No. 1-8245)).
(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.<br> 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<br> 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<br> on Form 10-Q for the quarter ended July 31, 2016 (File No. 1-8245)).
(19.1)	Insider Trading Policies and Procedures	32
(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	39

31 -

Table of Contents

(32)	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	41
(97)	Policy for the Recovery of Erroneously Awarded Compensation (incorporated by reference to Exhibit 97 to Annual Report on Form 10-K for the year ended October 31, 2024 (File No. 1-8245))
(99.1)	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,<br> 2025 prepared by Graves & Co. Consulting, LLC	42
(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).

Exhibit 19.1

NORTH EUROPEAN OIL ROYALTY TRUST

POLICY ON INSIDER TRADING

This Insider Trading Policy (this “Policy”) describes the standards of North European Oil Royalty Trust (the “Trust”) on trading, and causing the trading of, the Trust’s securities or securities of certain other publicly traded companies while in possession of confidential information.

This Policy is divided into two parts:

1.	Part I covers prohibition on trading in certain circumstances and applies to all Trustees and employees of the Trust and their respective immediate family members; and
2.	Part II covers special additional trading restrictions and applies to all (i) Trustees, (ii) employees of the Trust, (iii) any persons whom the Compliance Officer may designate as Insiders because they have<br> access to material nonpublic information concerning the Trust, including Trustees and officers of the Trust (together with the Trustees, “Trust Insiders”), and (iv) immediate family members<br> (collectively, “Covered Persons”).
---	---

Part I covers prohibition on trading in certain circumstances and applies to all Trustees and employees of the Trust and their respective immediate family members; and

Part II covers special additional trading restrictions and applies to all (i) Trustees, (ii) employees of the Trust, (iii) any persons whom the Compliance Officer may designate as Insiders because they have access to material nonpublic information concerning the Trust, including Trustees and officers of the Trust (together with the Trustees, “Trust Insiders”), and (iv) immediate family members (collectively, “Covered Persons”).

---

One of the principal purposes of the federal securities laws is to prohibit so-called “insider trading.” Simply stated, insider trading occurs when a person uses material nonpublic information obtained through involvement with the Trust to make decisions to purchase, sell, give away or otherwise trade the Trust’s securities or to provide that information to others outside the Trust. The prohibitions against insider trading apply to trades, tips, and recommendations by virtually any person, including all persons associated with the Trust, if the information involved is “material” and “nonpublic.” These terms are defined in this Policy under Part I, Section 3 below. The prohibitions would apply to any Trustee or employee who buys or sells Trust securities on the basis of material nonpublic information that he or she obtained about the Trust, its customers, suppliers, or other companies with which the Trust has contractual relationships or may be negotiating transactions.

PART I

1.	Applicability.

This Policy applies to all trading or other transactions in the Trust’s securities, including units of beneficial interest, options, and any other securities that the Trust may issue, such as preferred units, notes, bonds, and convertible securities, as well as to derivative securities relating to any of the Trust’s securities, whether or not issued by the Trust. This Policy applies to all Trustees, employees of the Trust, and their respective family members.

2.	General Policy: No Trading or Causing Trading While in Possession of Material Nonpublic Information.

(a) No Trustee or employee or any of their immediate family members may purchase or sell, or offer to purchase or sell, any Trust security, whether or not issued by the Trust, while in possession of material nonpublic information about the Trust. (The terms “material” and “nonpublic” are defined in Part I, Section 3(a) and (b) below.)

(b) No Trustee or employee or any of their immediate family members who knows of any material nonpublic information about the Trust may communicate that information to (“tip”) any other person, including family members and friends, or otherwise disclose such information without the Trust’s authorization.

(c) No Trustee or employee or any of their immediate family members may purchase or sell any security of any other company, whether or not issued by the Trust, while in possession of material nonpublic information about that company or that could affect the share price of that company, when that was obtained in the course of his or her involvement with the Trust. No Trustee or employee or any of their immediate family members who knows of any such material nonpublic information may communicate that information to, or tip, any other person, including family members and friends, or otherwise disclose such information without the Trust’s authorization.

(d) For compliance purposes, you should never trade, tip, or recommend securities (or otherwise cause the purchase or sale of securities) while in possession of information that you have reason to believe is material and nonpublic unless you first consult with, and obtain the advance approval of, the Compliance Officer (which is defined in Part I, Section 3(c) below).

(e) Covered Persons must “pre-clear” all trading in securities of the Trust in accordance with the procedures set forth in Part II, Section 3 below.

3.	Definitions.

(a) Material. Insider trading restrictions come into play only if the information you possess is “material.” Materiality, however, involves a relatively low threshold. Information is generally regarded as “material” if it has market significance, that is, if its public dissemination is likely to affect the market price of securities, or if it otherwise is information that a reasonable investor would want to know before making an investment decision. Information dealing with the following subjects is reasonably likely to be found material in particular situations:

(i) significant changes in the Trust’s prospects;

(ii) significant write-downs in assets or increases in reserves;

(iii) developments regarding significant litigation or government agency investigations;

(iv) liquidity problems;

(v) changes in earnings estimates or unusual gains or losses relating to the operating companies, exploration or drilling activities or well production;

(vi) major changes in the Trust’s management;

(vii) changes in distributions;

(viii) extraordinary borrowings;

(ix) major changes in accounting methods or policies;

(x) award or loss of a significant contract;

(xi) cybersecurity risks and incidents, including vulnerabilities and breaches;

(xii) changes in debt ratings;

(xiii) proposals, plans or agreements, even if preliminary in nature, involving mergers, acquisitions, divestitures, recapitalizations, strategic alliances, licensing arrangements, or purchases or sales of substantial assets; and

(xiv) offerings of Trust securities.

Material information is not limited to historical facts but may also include projections and forecasts. With respect to a future event, such as a merger, acquisition or introduction of a new product, the point at which negotiations or product development are determined to be material is determined by balancing the probability that the event will occur against the magnitude of the effect the event would have on a company’s operations, or price of securities should it occur. Thus, information concerning an event that would have a large effect on the price of securities, such as a merger, may be material even if the possibility that the event will occur is relatively small. When in doubt about whether particular nonpublic information is material, you should presume it is material. If you are unsure whether information is material, you should either consult the Compliance Officer before making any decision to disclose such information (other than to persons who need to know it) or to trade in or recommend securities to which that information relates or assume that the information is material.

(b) Nonpublic. Insider trading prohibitions come into play only when you possess information that is material and “nonpublic.” The fact that information has been disclosed to a few members of the public does not make it public for insider trading purposes. To be “public” the information must have been disseminated in an official announcement by the Trust and in a manner designed to reach investors generally, and the investors must be given the opportunity to absorb the information. This means through a widely disseminated press release or in a filing made with the SEC. Even after public disclosure of information about the Trust, you must wait until the close of business on the second trading day after the information was publicly disclosed before you can treat the information as public.

Nonpublic information may include:

(i) information available to a select group of analysts or brokers or institutional investors (to the extent not required to be disclosed publicly under Regulation FD of the SEC);

(ii) undisclosed facts that are the subject of rumors, even if the rumors are widely circulated; and

(iii) information that has been entrusted to the Trust on a confidential basis until a public announcement of the information has been made and enough time has elapsed for the market to respond to a public announcement of the information (normally two trading days).

As with questions of materiality, if you are not sure whether information is considered public, you should either consult with the Compliance Officer or assume that the information is nonpublic and treat it as confidential.

(c) Compliance Officer. The Trust has appointed John R. Van Kirk, the current Managing Director of the Trust, as the Compliance Officer for this Policy (except with respect to his own trades, for which the Chairman of the Audit Committee of the Trust is so designated). The duties of the Compliance Officer include, but are not limited to, the following:

(i) assisting with implementation and enforcement of this Policy;

(ii) circulating this Policy to all employees and ensuring that this Policy is amended as necessary to remain up-to-date with insider trading laws;

(iii) pre-clearing all trading in securities of the Trust by Covered Persons in accordance with the procedures set forth in Part II, Section 3 below;

(iv) providing approval of any Rule 10b5-1 plans under Part II, Section 1(c) below and any prohibited transactions under Part II, Section 4 below; and

(v) providing a reporting system with an effective whistleblower protection mechanism.

4.	Violations of Insider Trading Laws.

Penalties for trading on or communicating material nonpublic information can be severe, both for individuals involved in such unlawful conduct and their employers and supervisors, and may include jail terms, criminal fines, civil penalties, and civil enforcement injunctions. Given the severity of the potential penalties, compliance with this Policy is absolutely mandatory.

(a) Legal Penalties. A person who violates insider trading laws by engaging in transactions in a company’s securities when he or she has material nonpublic information can be sentenced to a substantial jail term and required to pay a criminal penalty of several times the amount of profits gained or losses avoided.

In addition, a person who tips others may also be liable for transactions by the tippees to whom he or she has disclosed material nonpublic information. Tippers can be subject to the same penalties and sanctions as the tippees, and the Securities and Exchange Commission (the “SEC”) has imposed large penalties even when the tipper did not profit from the transaction.

The SEC can also seek substantial civil penalties from any person who, at the time of an insider trading violation, “directly or indirectly controlled the person who committed such violation,” which would apply to the Trust and/or management and supervisory personnel. These control persons may be held liable for up to the greater of $1 million or three times the amount of the profits gained or losses avoided. Even for violations that result in a small or no profit, the SEC can seek penalties from a company and/or its management and supervisory personnel as control persons.

(b) Trust-imposed Penalties. Employees who violate this Policy may be subject to disciplinary action by the Trust, including dismissal for cause. Any exceptions to the Policy, if permitted, may only be granted by the Compliance Officer, and must be provided before any activity contrary to the above requirements takes place.

5.	Inquiries. If you have any questions regarding any of the provisions of<br> this Policy, please contact the Compliance Officer at jvankirk@neort.com or (732) 741-4008.

PART II

1.	Blackout Periods. All Covered Persons are prohibited from trading in the Trust’s securities during blackout periods as<br> defined below.

(a) Quarterly Blackout Periods. Trading in the Trust’s securities is prohibited during the period beginning at the close of the market on two weeks before the end of each fiscal quarter and ending at the close of business on the second trading day following the date the Trust’s financial results are publicly disclosed and Form 10-Q or Form 10-K is filed. During these periods, Covered Persons generally possess or are presumed to possess material nonpublic information about the Trust’s financial results.

(b) Other Blackout Periods. From time to time, other types of material nonpublic information regarding the Trust (such as negotiation of mergers, acquisitions or dispositions, investigation and assessment of cybersecurity incidents or new product developments) may be pending and not be publicly disclosed. While such material nonpublic information is pending, the Trust may impose special blackout periods during which Covered Persons are prohibited from trading in the Trust’s securities. If the Trust imposes a special blackout period, it will notify the Covered Persons affected. Covered Persons may not disclose to anyone other than those who are also subject to the same “other blackout period” the existence of such period.

2.	Exceptions.

(a) Approved 10b5-1 Plans. The trading restrictions in this Policy do not apply to transactions under a pre-existing written plan, contract, instruction, or arrangement under Rule 10b5-1 under the Securities Exchange Act of 1934 (an “Approved 10b5-1 Plan”) that:

(i) has been reviewed and approved in advance of any trades thereunder by the Compliance Officer (or, if revised or amended, such revisions or amendments have been reviewed and approved by the Compliance Officer in advance of any subsequent trades);

(ii) was entered into in good faith by the Covered Person at a time when the Covered Person was not in possession of material nonpublic information about the Trust, and is operated in good faith;

(iii) gives a third party the discretionary authority to execute such purchases and sales, outside the control of the Covered Person, so long as such third party does not possess any material nonpublic information about the Trust; or explicitly specifies the security or securities to be purchased or sold, the number of securities, the prices and/or dates of transactions, or other formula(s) describing such transactions; and

(iv) otherwise meets the requirements of Rule 10b5-1(c)(1) under the Securities Exchange Act of 1934, including cooling-off periods, restrictions on multiple overlapping plans and other requirements.

(b) Other Exceptions. The trading restrictions in this Policy also do not apply to:

(i) the transfer of units to an entity that does not involve a change in the beneficial ownership of the units (for example, transferring units from one brokerage account to another brokerage account that you control, or to an inter vivos trust of which you are the sole beneficiary during your lifetime); and

(ii) any other transaction, the specific facts of which are reviewed by the Compliance Officer and determined by the Compliance Officer not to constitute a violation of applicable insider trading law.

2.	Trading Window.

Covered Persons are permitted to trade in the Trust’s securities when no blackout period is in effect. Generally, this means that Covered Persons can trade during the period beginning on the close of business on the second trading day following the date the Trust’s financial results are publicly disclosed and Form 10-Q or Form 10-K is filed and ending on the close of the market on two weeks before the end of each fiscal quarter. However, even during this trading window, a Covered Person who is in possession of any material nonpublic information should not trade in the Trust’s securities until the information has been made publicly available or is no longer material. In addition, the Trust may close this trading window if a special blackout period under Part II, Section 1(b) above is imposed and will re-open the trading window once the special blackout period has ended.

3.	Pre-clearance of Securities Transactions.

(a) Because Trust Insiders are likely to obtain material nonpublic information on a regular basis, the Trust requires all such persons to refrain from trading, even during a trading window under Part II, Section 2 above, without first pre-clearing all transactions in the Trust’s securities.

(b) Subject to the exemption in subsection (d) below, no Trust Insider may, directly or indirectly, purchase or sell (or otherwise make any transfer, gift, pledge, or loan of) any Trust security at any time without first obtaining prior approval from the Compliance Officer. These procedures also apply to transactions by such person’s spouse, other persons living in such person’s household and minor children and to transactions by entities over which such person exercises control.

(c) The Compliance Officer shall record the date each request is received and the date and time each request is approved or disapproved. Unless revoked, a grant of permission will normally remain valid until the close of trading two business days following the day on which it was granted. If the transaction does not occur during the two-day period, pre-clearance of the transaction must be re-requested.

(d) Pre-clearance is not required for purchases and sales of securities under an Approved 10b5-1 Plan. With respect to any purchase or sale under an Approved 10b5-1 Plan, the third-party effecting transactions on behalf of the Trust Insider should be instructed to send duplicate confirmations of all such transactions to the Compliance Officer.

4.	Prohibited Transactions.

(a) Trust Insiders are prohibited from trading in the Trust’s equity securities during a blackout period imposed under an “individual account” retirement or pension plan of the Trust, during which at least 50% of the plan participants are unable to purchase, sell or otherwise acquire or transfer an interest in equity securities of the Trust, due to a temporary suspension of trading by the Trust or the plan fiduciary.

(b) Covered Persons, including any person’s spouse, other persons living in such person’s household and minor children and entities over which such person exercises control, are prohibited from engaging in the following transactions in the Trust’s securities unless advance approval is obtained from the Compliance Officer:

(i) Short-term trading. Trust Insiders who purchase or sell Trust securities may not sell or purchase any Trust securities of the same class for at least six months after the purchase or sale, respectively;

(ii) Short sales. Trust Insiders may not sell the Trust’s securities short;

(iii) Options trading. Covered Persons may not buy or sell puts or calls or other derivative securities on the Trust’s securities;

(iv) Trading on margin or pledging. Covered Persons may not hold Trust securities in a margin account or pledge Trust securities as collateral for a loan; and

(v) Hedging. Covered Persons may not enter into hedging or monetization transactions or similar arrangements with respect to Trust securities.

5.	Acknowledgment and Certification. All Covered Persons are required to sign the attached acknowledgment and certification.

ACKNOWLEDGMENT AND CERTIFICATION

The undersigned does hereby acknowledge receipt of the Trust’s Insider Trading Policy. The undersigned has read and understands (or has had explained) such Policy and agrees to be governed by such Policy at all times in connection with the purchase and sale of securities and the confidentiality of nonpublic information.

	(Signature)
	(Please print name)
Date:

Exhibit 31

Certification of Chief Executive Officer and Chief Financial Officer

Pursuant to Section 302

of the Sarbanes-Oxley Act of 2002

I, John R. Van Kirk, certify that:

1.	I have reviewed this Annual Report on Form 10-K of North European Oil Royalty Trust;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which<br> such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash<br> flows of the registrant as of, and for, the periods presented in this report;
---	---
4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in<br> Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
---	---
a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant,<br> 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;
---	---
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the<br> reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
---	---
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the<br> end of the period covered by this report based on such evaluation; and
---	---

d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in<br> 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
5.	I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors and to the audit committee of the registrant’s board of directors (or persons<br> performing the equivalent functions):
---	---
a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to<br> record, process, summarize and report financial information; and
---	---
b)	Any fraud, whether or not, material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
---	---
Date: December 31, 2025
---	---	---
	/s/	John R. Van Kirk
		John R. Van Kirk
		Managing Director,
		Chief Executive Officer,
		and Chief Financial Officer
		(Principal Executive Officer and
		Principal Financial Officer)

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. §1350(a) and (b)), the undersigned hereby certifies that the Annual Report on Form 10-K for the period ended October 31, 2025 of North European Oil Royalty Trust (“Trust”) fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that the information contained in such Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

Dated: December 31, 2025
	/s/	John R. Van Kirk
		John R. Van Kirk
		Managing Director,
		Chief Executive Officer,
		and Chief Financial Officer

Exhibit 99.1

North European Oil Royalty Trust

Calculation of Cost Depletion Percentage

For 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

Table of Contents
Discussion	4
Description of Holdings	4
Oldenburg Area – Sales and Reserves	6
Total Sales	6
Gross Reserves	6
Net Reserves and Sales	7
Limitations of Available Data	8
Overview of Natural Gas Processing	9
Description of Grossenkneten Plant	9
Changes in ExxonMobil’s Plant Operations	10
Impacts on Future Trust Royalty Income	10
Uncertainties Related to Future Gas Plant Operations	10
Reserves Estimates	10
Calculation of Cost Depletion Percentage	11

Attachments

I.	Attachment A:	Reserve Summary and Five-Year Net Sales History
II.	Attachment B:	Calculation of Total Cost Depletion Percentage
III.	Definitions of Reserves
IV.	Certificate of Qualifications

December 1, 2025

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 2025

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 2025 calendar year. The cost depletion percentage is prepared for use by unit owners of the Trust in filing federal income tax returns. To calculate the cost depletion percentage, we have 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 as of October 1, 2025.

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 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 § 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.

Graves & Co. Consulting LLC ■ 1201 Louisiana St, Suite 2720, Houston, Texas 77002

713/650-0811 ■ info@gravesconsulting.us ■ www.gravesconsulting.us

Texas Registered Engineering Firm F-19125

North European Oil Royalty Trust<br><br> <br><br><br> <br>Calculation of the Cost Depletion Percentage<br><br> <br>For Calendar Year 2025	Graves & Co. Consulting LLC<br><br> <br>December 1, 2025<br><br> <br>Page 4

The proved producing reserves are estimated as of October 1, 2025 and the reported sales are for the twelve-month period ending September 30, 2025. Use of the period ending September 30, 2025 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 upon 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 2025 calendar year. As detailed in Attachment B, the cost depletion percentage for the 2025 calendar year for Trust unit owners is equal to 8.9814% of the unit owner’s cost basis as of January 1, 2025.

Discussion

The scope of this study is to review the limited information we are 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 is then 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 geological 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 Corporation and by BEB Erdgas und Erdol GmbH (“BEB”), a joint venture of ExxonMobil and the Royal Dutch Shell Group of Companies. As a result, by direct and indirect ownership, ExxonMobil owns two-thirds of OEG and the Royal Dutch Shell Group owns one-third of OEG.

Graves & Co. Consulting LLC

Texas Registered Engineering Firm F-19125

North European Oil Royalty Trust<br><br> <br><br><br> <br>Calculation of the Cost Depletion Percentage<br><br> <br>For Calendar Year 2025	Graves & Co. Consulting LLC<br><br> <br>December 1, 2025<br><br> <br>Page 5

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.

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”).

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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.

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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, 2025, total sales for the Oldenburg area were as follows:

Gross Sales
	West		East		Total
Gas Well Gas - MMCF		11,987.2		27,904.0		39,891.2
Oil Well Gas - MMCF		9.1		3.0		12.1
Oil & Condensate - Barrels		67,725.0		14,625.8		82,350.8
Sulfur - Short Tons		52,937.0		160,669.3		213,606.3

Compared with the prior year, gas well gas sales are down consistent with normal decline. Oil sales in the West are up compared to 2024 but oil sales in the East are down for the year except for a strong first quarter; overall, oil sales are slightly up for 2025. Sulfur sales have been steady throughout the year but are slightly down compared to 2024.

Gross Reserves

Estimated gross remaining proved producing reserves attributable to the total Oldenburg area as of October 1, 2025 are as follows:

Gross Reserves
	West		East		Total
Gas Well Gas - MMCF		122,053.6		281,936.1		403,989.7
Oil Well Gas - MMCF		31.0		0.0		31.0
Oil & Condensate - Barrels		275,497.1		27,832.5		303,329.6
Sulfur - Short Tons		605,369.6		1,743,529.7		2,348,899.3

Gross gas reserves are up because of successful clean out and scale removal well work and somewhat higher gas prices. Gross oil reserves are up because of lower operating expenses; in the West, the economic life nearly doubled; in the East, positive cashflows have added economic reserves. Gross sulfur production is steady and prices are higher resulting in higher reserves.

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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
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, 2025 and net sales for the twelve-month period ending September 30, 2025 are as follows:

Net Reserves & Sales
	Reserves		Sales
Gas Well Gas - MMCF		7,069.0		682.0
Oil Well Gas - MMCF		1.5		0.5
Oil & Condensate - Barrels		12,320.3		3,062.7
Sulfur - Short Tons		26,536.1		2,399.0

Net gas well gas reserves are up nearly 5% compared to 2024 because of successful well work and higher prices. Net oil reserves are up about 100% from 2024 due primarily to lower operating expenses extending the economic life. Net sulfur reserves are up because of higher prices. The successful well work partially offset the normal decline for gas and sulfur sales; the dip in third quarter 2024 oil production (reflected in our 2024 report) resulted in oil sales being up for 2025.

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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 and possible 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 2025.

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 geological 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 other than there was no drilling activity.

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.

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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, geological 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 gross production, gross sales, gross revenue, gross operating expense, and net revenue. 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 in the past 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.

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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.

Impacts on Future Trust Royalty Income

During 2023, the Trust’s German consultant informed us that changes in plant operations would result in curtailments until the end of the first quarter in 2024. With the completion of this work, most production forecasts have now been brought back to their prior decline trend.

ExxonMobil’s shutdown of the second train at Grossenkneten resulted in a flattening in the rising trend line of certain costs related to gas well gas and sulfur that are deducted from the Trust’s gross royalties. This flattening is likely the result of any reductions in costs being offset by increased unit-of-production 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, 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.

Reserves 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.

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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 10/1/2024 Line (3) is obtained by adding the estimated remaining net proved producing reserves as of 10/1/2024 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 10/1/2024 Line (3). Therefore Line (6) = Line (4) / Line (3).

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The product base for each category of proved producing reserves as of 1/1/2024 Line (7) and the adjustment taken during 2024 Line (8) were obtained from the previous year’s report. The product base as of 1/1/2025 Line (9) forms the initial starting point for the calculation of the cost depletion percentage for the 2025 tax year. The product base for 1/1/2025 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 1/1/2025 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 1/1/2025 [Sum Line (9)]. Therefore Line (11) = [Sum Line (10)] / [Sum Line (9)].

The cost depletion percentage represents the total allowable cost depletion for the 2025 calendar year for the Trust’s unit owners, expressed as a percentage of their cost base as of January 1, 2025.

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.

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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
John L. Graves
President
Mel F. Hainey, P.E.
Sr. Reservoir Engineer

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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, 2025

Oldenburg
Gas Well Gas	Oil Well Gas	Oil/Cond.	Sulfur
MMcf	MMcf	Barrels	Short Tons
7,069	2	12,320	26,536

Five Year Net Sales Summary

12 Months Ending September 30, 2025

Oldenburg
	Gas Well Gas	Oil Well Gas	Oil/Cond.	Sulfur
	MMcf	MMcf	Barrels	Short Tons
2025	682	1	3,063	2,399
2024	715	0	2,794	2,479
2023	759	0	2,709	2,722
2022	903	1	2,791	3,255
2021	882	1	2,779	3,110

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Attachment B

North European Oil Royalty Trust

Calculation of Total Cost Depletion Percentage

For the Year Ending September 30, 2025

			OLDENBURG
			Gas Well Gas		Oil Well Gas		Oil
			MMCF		MMCF		Barrels
NEORT NET RESERVES (Million Cubic Feet of Gas and Barrels of Oil)
	1.	Estimated remaining net proved
		producing reserves as of 10-1-2024		6,743.8		0.5		6,136.0
	2.	Adjustments to reserves during period		1,007.2		1.5		9,247.0
	3.	Adjusted est. net proved producing
		reserves as of 10-1-2024		7,751.0		2.0		15,383.0
	4.	Net sales from 10-1-2024 to 9-30-2025		682.0		0.5		3,062.7
	5.	Estimated remaining net proved
		producing reserves as of 10-1-2025		7,069.0		1.5		12,320.3
RESERVE DEPLETION FACTOR
	6.	Depletion factor		0.08799		0.25000		0.19910
NEORT WEIGHTED PRODUCT BASE ALLOCATION
	7.	Product base as of 1-1-2024		0.85666		0.00000		0.01889
	8.	Less adjustments taken during 2024		0.08212		0.00000		0.00591
	9.	Product base as of 1-1-2025		0.77454		0.00000		0.01298
	10.	2025 Adjustment to product base		0.06815		0.00000		0.00258
	11.	Cost depletion percentage for 2025 calendar year for Trust unitowners is equal to 8.9814 percent of their 1-1-2025 cost<br> base.

Footnotes:

Line (1) from reserves review as of 10-1-2024	Line (7) from 2024 depletion calculations
Line (2) from reserves review as of 10-1-2025	Line (8) from 2024 depletion calculations
Line (3) = Line (1) + Line (2)	Line (9) = Line (7) - Line (8)
Line (4) from BEB and Mobil Erdgas statements	Line (10) = Line (9) x Line (6)

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

§ 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

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

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

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

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

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

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

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

Probable Reserves

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

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

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

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

Possible Reserves

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

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

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

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

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

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

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

Developed Oil and Gas Reserves

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

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

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

Undeveloped Oil and Gas Reserves

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

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

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

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

Additional Definitions:

Deterministic Estimate

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

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.

Certificate of Qualification

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

1.	That I am a Sr. Reservoir Engineer for the consulting firm Graves & Co. Consulting LLC with offices at 1201 Louisiana, Suite 2720, Houston, Texas 77002.
2.	That I have prepared a reserve report on the interests of the North European Oil Royalty Trust in the Northwest Basin of the Federal Republic of Germany as of October 1, 2025 for the purpose of calculating the cost depletion percentage<br> applicable to Trust unit owners for the 2025 calendar year.
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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.
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4.	That I attended The University of Texas at Austin and graduated with a Bachelor of Science Degree in Electrical Engineering in 1975 and with a Master of Science Degree in Engineering in 1977.
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5.	That I am a Registered Professional Engineer in the State of Texas, Registration Number 65528, and I am a member in good standing of the Texas Society of Professional Engineers and the Society of Petroleum Engineers.
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6.	That I have in excess of forty years of experience in 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<br> in petroleum reservoir engineering since 2016.
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Signed: December 1, 2025
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	GRAVES & CO. CONSULTING LLC
	Mel F. Hainey, P.E.
	Sr. Reservoir Engineer

Graves & Co. Consulting LLC ■ 1800 West Loop South, Suite 750, Houston, Texas 77027

713/650-0811 ■ info@gravesconsulting.us ■ www.gravesconsulting.us

Texas Registered Engineering Firm F-19125