FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended October 31, 2017 or
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to .
Commission file number 1-8245
Securities registered pursuant to Section 12(b) of the Act
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ___ No X
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d)of the Act. Yes ___ No X
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ___ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
| Large Accelerated filer | Accelerated filer X |
| Non-accelerated filer | Smaller reporting company |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes __ No X
As of April 28, 2017, the aggregate market value of outstanding units of beneficial interest of the registrant held by non-affiliates of the registrant was $65,041,363 on such date.
As of December 29, 2017, 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 2017 Annual Meeting to be held on February 20, 2018.
PART I
Item 1. Business.
(a) General Development of Business. North European Oil Royalty Trust (the "Trust") is a grantor trust which, on behalf of the owners of beneficial interest in the Trust (the "unit owners"), holds overriding royalty rights covering gas and oil production in certain concessions or leases in the Federal Republic of Germany. The rights are held under contracts with local German exploration and development subsidiaries of ExxonMobil Corp. ("ExxonMobil") and the Royal Dutch/Shell Group of Companies ("Royal Dutch/Shell Group"). Under these contracts, the Trust receives various percentage royalties on the proceeds of the sales of certain products from the areas involved. At the present time, royalties are received for sales of gas well gas, oil well gas, crude oil, condensate and sulfur. See Item 2 of this Report for descriptions of the relationships of these companies and certain of these contracts.
The royalty rights were received by the Trust from North European Oil Company (the "Company") upon dissolution of the Company in September 1975. The Company was organized in 1957 as the successor to North European Oil Corporation (the "Corporation"). The Trust is administered by trustees (the "Trustees") under an Agreement of Trust dated September 10, 1975, as amended (the "Trust Agreement").
Neither the Trust nor the Trustees on behalf of the Trust conduct any active business activities or operations. The function of the Trustees is to monitor, verify, collect, hold, invest and distribute the royalty payments made to the Trust. Under the Trust Agreement, the Trustees make quarterly distributions of the net funds received by the Trust on behalf of the unit owners. Funds temporarily held by the Trust are invested in interest bearing bank deposits, money market accounts, certificates of deposit, U.S. Treasury Bills or other government obligations.
There has been no significant change in the principal operation or purpose of the Trust during the past fiscal year.
As part of the Sarbanes-Oxley Act of 2002 ("SOX"), the Securities and Exchange Commission (the "SEC") adopted rules implementing legislation concerning governance matters for publicly held entities. The Trust is complying with the requirements of the SEC and SOX and, at this time, the Trustees have chosen not to request any relief from those provisions based on the passive nature of the Trust but may do so in the future. In that connection, the Trustees have directed that certain of the additional statements and disclosures set forth or incorporated by reference in this Report, which the SEC requires of corporations, be made even though some of such statements and disclosures might not now or in the future be required to be made by the Trust.
In addition, the New York Stock Exchange (the "NYSE"), where units of beneficial interest of the Trust are listed for trading, has additional corporate governance rules as set forth in Section 303A of the NYSE Listed Company Manual. Most of the governance requirements promulgated by the NYSE are not applicable to the Trust, which is a passive entity acting as a royalty trust and holds only overriding royalty rights. The Trust does not engage in any operating or active business. The Trustees have, however, chosen to constitute an Audit Committee and a Compensation Committee but may not necessarily do so in the future.
(b) Financial Information about Segments. Since the Trust conducts no active business operations, an analysis by segments is accordingly not applicable to the Trust. To the extent that royalty income received by the Trust is attributable to sales of different products, to sales from different geographic areas or to sales by different operating companies, this information is set forth in Item 2 of this Report and the Exhibit described in that Item 2.
(c) Narrative Description of Business. Under the Trust Agreement, the Trust conducts no active business operations and is restricted to collection of income from royalty rights and distribution to unit owners of the net income after payment of administrative and related expenses.
The overriding royalty rights held by the Trust are derived from contracts and agreements originally entered into by German subsidiaries of the predecessor Corporation during the early 1930s. The Trust's primary royalty rights are based on government granted concessions and remain in effect as long as there are continued production activities and/or exploration efforts by the operating companies. It is generally anticipated that the operating companies will continue production where it remains economically profitable for them to do so. In addition, the Trust holds other royalty rights, which are based on leases which have passed their original expiration dates. These leases remain in effect as long as there is continued production or the lessor does not cancel the lease. Individual lessors will normally not seek termination of the rights originally granted because the leases provide for royalty payments to the lessors if sales of oil or gas result from discoveries made on the leased land. Additionally, termination by individual lessors would result in the escheat of mineral rights to the applicable state.
Royalties are paid to the Trust on sales from production under these leases and concessions by the operating companies on a regular monthly or quarterly basis pursuant to the royalty agreements. The operating companies make royalty payments to the Trust exclusively in Euros. As promptly as possible after the Trust receives notification that funds have been deposited in the Trust's bank account in Germany, the Trust instructs Deutsche Bank to convert the majority of the funds into U.S. dollars based upon the available exchange rates presented to the Trust. The amount the Trust schedules for conversation allows for sufficient funds to handle any outstanding expenses and maintains a minimal balance of 5,000 Euros. Following this conversion to dollars, the royalties are automatically transferred to the Trust's bank account in the U.S. The Trust does not engage in activities to hedge against currency risk; and the fluctuations in the conversion rate impact its financial results. However, since the actual royalty deposits are held as Euros for such a limited time, the market risk with respect to these deposits is small. The Trust has not experienced any difficulty in effecting the conversion of Euros into U.S. dollars.
As the holder of overriding royalty rights, the Trust has no legal ability, whether by contract or operation of law, to compel production. Moreover, if an operator should determine to terminate production in any concession or lease area and to surrender the concession or lease, the royalty rights for that area would thereby be terminated. Under certain royalty agreements, the operating companies are required to advise the Trust of any intention to surrender lease or concession rights. While the Trust itself is precluded from undertaking any production activities, possible residual rights might permit the Trust to take up a surrendered concession or lease and attempt to retain a third-party operator to develop such concession or lease.
The exploration for and the production of gas and oil is a speculative business. The Trust has no means of ensuring continued income from its royalty rights at either their present levels or otherwise. The Trust has no role in any of the operating companies' decision-making processes, such as gas pricing, gas sales or exploration, which can impact royalty income. In addition, fluctuations in prices and supplies of gas and oil and the effect these fluctuations might have on royalty income to the Trust and on reserves net to the Trust cannot be accurately projected. Finally, natural gas and crude oil are wasting assets. While known reserves may increase as additional development adds quantities to the reserve amount, the amount of known and unknown reserves is finite and will decline over time. Given these factors, along with the uncertainty in worldwide and local German economic conditions and the fact that the Trustees have no information beyond that information which is generally available to the public, the Trustees make no projections regarding future royalty income.
While Germany has laws relating to environmental protection, the Trustees generally do not have detailed information concerning the present or possible effect of such laws on operations in areas where the Trust holds royalty rights on production and sale of products from those areas. However, the Trustees were informed by the Trust's German consultant that on July 8, 2016, a hydraulic fracturing ("fracking") law was passed in Germany permitting fracking in sandstone at any depth. The new law requires that an environmental impact study be performed as well as requiring that permission by the relevant water authority be granted to protect drinking water supplies. Based upon an analysis of the details of this law, the Trust's German consultant has informed the Trust that fracking will be permitted in all current productive zones within the Oldenburg concession both due to the depths involved and the nature of the productive zones. However, the operating companies would still have to comply with all regulatory requirements governing the use of fracking. Historically, the only productive zone within the concession that required fracking has been the Carboniferous zone. No Carboniferous wells are currently listed in the drilling schedule through 2020.
Seasonal demand factors affect the income from royalty rights insofar as they relate to energy demands and increases or decreases in prices, but on average they are generally not material to the regular annual income received under the royalty rights.
The Trust, in cooperation with a parallel royalty owner (Unitarian Universalist Congregation at Shelter Rock), arranges for periodic examinations of the books and records of the operating companies to verify compliance with the computation provisions of the applicable agreements. From time to time, these examinations disclose computational errors or errors from inappropriate application of existing agreements and appropriate adjustments are requested and made. As a result of the recent amendments to the Trust's royalty agreements which effect pricing simplification, future examinations by the Trust's German accountants will be simplified since these examinations will be 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. With the changes put in place with regard to oil pricing set forth in the 2016 amendments to the royalty agreements, the Trust has decided to examine the new royalty calculation process for oil in addition to the royalty calculation process for gas. The examination of the oil royalty calculation has not been done for many years due to the small amount of royalties involved. The Trust has determined that, given the changed royalty calculation process, it would be prudent to review the oil royalty calculation for this two-year period.
(d) Financial Information about Geographic Areas. The Trust does not engage in any active business operations, and its sources of income are the overriding royalty rights covering gas, sulfur and oil production in certain areas in Germany and interest on the funds temporarily invested by the Trustees. 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, 2017.
(e) Trustees and Executive Officers of the Trust. As specified in the Trust Agreement, the affairs of the Trust are managed by not more than five individual Trustees who receive compensation determined under that same agreement. One of the Trustees is designated as Managing Trustee. Robert P. Adelman has served as Managing Trustee (non-executive) since November 1, 2006. Ahron H. Haspel was appointed as a Trustee on June 5, 2017 to replace Rosalie J. Wolf. Samuel M. Eisenstat, who served as the Chairman for the Audit and Compensation Committees for many years, passed away on October 30, 2017. Mr. Haspel is independent and has been determined to be a financial expert (both as defined in the SEC rules) and was appointed to serve as Chairman for the Audit and Compensation Committees on November 2, 2017. Lawrence A. Kobrin serves as Clerk to the Trustees (a role similar to that of a corporate secretary). For these services, these three individuals receive additional compensation.
Day-to-day matters are handled by the Managing Director, John R. Van Kirk, who also serves as CEO and CFO. John R. Van Kirk has held the position of Managing Director of the Trust since November 1990. The Managing Director provides office space and services at cost to the Trust.
In addition to the Managing Director, the Trust has one administrative employee in the United States, whose title is Administrator. The Trust has retained the services of a consultant in Germany who has broad experience in the petroleum industry and from whom it receives reports on a regular basis. The Trust also retains an accounting firm and a legal firm in Germany to advise and represent the Trust as needed. Because the Trust has only two employees, employee relations or labor contracts are not directly material to the business or income of the Trust. The Trustees have no information concerning employee relations of the operating companies.
(f) Available Information . The Trust maintains a website at www.neort.com. The Trust's Annual Reports, Form 10-K annual reports, Form 10-Q quarterly reports and the Definitive Proxy Statements are available through the Trust's website as soon as reasonably practicable after such reports are filed with or furnished to the SEC. Press releases and tax letters are available through the website as soon as practicable after release. The North European Oil Royalty Trust Agreement (as amended), the Trust's Code of Conduct and Business Ethics, the Trustees' Regulations and the Trust's Audit Committee Charter are also available through the Trust's website. The Trust's website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Form 10-K.
Item 1. Risk Factors .
The results of operations and financial condition of the Trust are subject to various risks. Some of these risks are described below, and you should take such risks into account in evaluating the Trust or any investment decision involving the Trust. This section does not describe all risks that may be applicable to the Trust and it is intended only as a summary of certain material risk factors. More detailed information concerning the risk factors described below is contained in other sections of this Annual Report on Form 10-K.
The Trust does not conduct any active business activities or operations and has no legal ability to compel production .
The Trust holds overriding royalty rights only. It is a passive entity and conducts no operations. It can exert no influence on the operating companies that conduct exploration, drilling, production and sales activities in the areas covered by the Trust's overriding royalty rights. Thus, the Trust has no means of ensuring continued income from its overriding royalty rights. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. The Trust also has no right to remove or replace an operator.
The current operating companies are under no obligation to continue operations in the royalty areas. Natural gas is a wasting asset. The production and sale of natural gas, from which the Trust derives its royalties, reduces the amount of remaining proved producing reserves of natural gas. If the operating companies do not perform additional development projects which replace at least a portion of the current production, the anticipated life of the Trust will not be extended and could be shortened. Absent further additions to the amount of proved producing reserves, production and sales will reach a point in the future where the level of sales will no longer be commercially viable and production will cease. Ultimately, the amount of known and unknown reserves within a defined area, such as the Oldenburg concession, is finite and will decline over time.
Trust reserve estimates depend on many assumptions that may prove to be inaccurate, and these inaccuracies may cause errors in the reserve estimates.
The value of Trust units may depend in part on the reserves attributable to the royalty areas. The calculations performed in the process of estimating proved producing reserves are inherently uncertain. The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment, and the assumptions used regarding the quantities of recoverable natural gas and the future prices of crude oil and natural gas.
The Trust currently receives quarterly reports from the operating companies with respect to production and sales on either a well-by-well or an area-wide basis. The Trust also receives annual reports from the operating companies with respect to current and planned drilling and exploration efforts. These reports are very limited in nature. The operating companies' unified exploration and production venture, ExxonMobil Production Deutschland GmbH ("EMPG"), which provides these reports to the Trust, continues to limit the information flow to that which is required by German law, and the Trust has no legal or contractual right to compel the issuance of additional information. The Trust's inability to compel the delivery of detailed information with respect to individual wells increases the possibility of inaccuracy in the petroleum engineering consultant's estimates of reserves.
Actual production, revenues and expenditures by the operating companies for the royalty areas, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Additionally, while the moratorium on fracking has been lifted and there are no wells currently in the drilling portfolio that require fracking, the fracking law has mandated added regulatory steps with respect to all drilling. The new law requires that an environmental impact study be performed as well as requiring that permission by the relevant water authority be granted to protect drinking water supplies. These additional regulations will add costs to each well. When used, the process of fracking adds significant costs to drilling. The operating companies will have to evaluate these costs as part of their decision on whether or not to drill.
The effects of fluctuations in prices of gas and oil and changes in worldwide and local economic conditions on the royalty income paid to the Trust cannot be accurately projected..
The Trust's distributions are highly dependent upon the prices realized from the sale of natural gas and a decrease in such prices could reduce the amount of cash distributions paid to unit owners.
Oil and natural gas prices and demand for these products can fluctuate widely in response to a variety of factors that are beyond the control of the Trust. Factors that contribute to these fluctuations include, among others: (1) worldwide and German economic conditions and levels of economic activity; (2) political and economic conditions in major oil producing regions, especially in the Middle East and Russia; (3) weather conditions; (4) the price of oil or natural gas imported into Germany; (5) the level of consumer demand in Germany; (6) the increasing role of alternate energy sources along with the German government's and European Union's role in promoting those sources; and (7) German and European Union governmental actions intended to broaden sources of energy supply.
When oil and natural gas prices decline, the Trust is affected in two ways. First, net income from the royalty areas is reduced. Second, exploration and development activity by the operating companies on the royalty areas may decline as some projects may become uneconomic and are either delayed or eliminated. It is impossible to predict future oil and natural gas price movements, and this, along with other factors, make future cash distributions to unit owners impossible to predict.
In recent years, there has been a shift in the structure of European gas supply contracts resulting in the decoupling of the link between oil prices and gas prices. A comprehensive spot market has developed in Europe with corresponding spot market prices for gas where the gas price is not linked to oil prices. According to the Trust's accountants in Germany, gas prices, in the overwhelming majority of contracts, are linked to spot market prices on a specific exchange with a plus or minus factor included. However, following the August 26, 2016 amendments to the royalty agreements regarding the pricing simplification, neither the contractual price nor the spot market price will be a determining factor in the calculation of royalties payable to the Trust. As specified in the amendments, the Trust's new pricing procedure now matches the German State royalty calculation basis which is codified in the pertinent German State Royalty Code (Niedersachsische Verordnung uber die Feldes- und die Forderabgabe). As this pricing procedure is currently configured, the state assessment base for natural gas is the average German Border Import gas Price (the "GBIP"). In the royalty calculations for the Trust, the GBIP for the period corresponding to the respective calendar quarter (adjusted by a percentage factor) will be the price used in the relevant calculation of quarterly royalties payable. Following the end of a given calendar year, the average GBIP for that year (adjusted by a percentage factor) will be the price used in the relevant year-end royalty adjustments.
Changes in the dollar value of the Euro have an immediate impact on the Trust.
For unit owners, changes in the dollar value of the Euro have an immediate impact. This impact occurs at the time the royalties, which are paid to the Trust in Euros, are converted into U.S. dollars based upon the applicable exchange rate and transferred from Germany to the United States. In relation to the dollar, a stronger Euro would yield more dollars and a weaker Euro would yield less dollars.
Cyber security risks and cyber incidents at the Trust or the operating companies could adversely affect our business .
Cyber incidents can result from deliberate attacks or unintentional events. These incidents can include, but are not limited to, gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. The result of these incidents could include, but are not limited to, disrupted operations, misstated financial data, liability for stolen assets or information, increased cyber security protection costs, litigation and reputational damage adversely affecting investor confidence. The Trust has undertaken steps to protect itself from cyber security risks, and it does not hold personal data for any unit owners within its computer system. It is believed that the operating companies have undertaken security procedures to protect their operations. Some of the entities with which the Trust works maintain personal data for unit owners on their systems. They are required by various regulations to take steps necessary to ensure the security of their data.
Item 1B. Unresolved Staff Comments.
None
Item 2. Properties .
The properties of the Trust, which the Trust and Trustees hold pursuant to the Trust Agreement on behalf of the unit owners, are overriding royalty rights on sales of gas, sulfur and oil under certain concessions or leases in the Federal Republic of Germany. The actual leases or concessions are held either by Mobil Erdgas-Erdol GmbH ("Mobil Erdgas"), a German operating subsidiary of ExxonMobil, or by Oldenburgische Erdolgesellschaft ("OEG"). As a result of direct and indirect ownership, ExxonMobil owns two-thirds of OEG and the Royal Dutch/Shell Group of Companies owns one-third of OEG. The Oldenburg concession (1,386,000 acres), covering virtually the entire former Grand Duchy of Oldenburg and located in the German federal state of Lower Saxony, provides 100% of the royalties received by the Trust. BEB Erdgas und Erdol GmbH ("BEB"), a joint venture in which ExxonMobil and the Royal Dutch/Shell Group each own 50%, administers the concession held by OEG. In 2002, Mobil Erdgas and BEB formed EMPG to carry out all exploration, drilling and production activities. All sales activities are still handled by either Mobil Erdgas or BEB.
Vermilion Energy Inc. ("Vermilion"), a Canadian based international oil and gas producer, entered into a Farm-In Agreement (the "Farm-In Agreement") with Mobil Erdgas and BEB. The Farm-In Agreement specifies that Vermilion has acquired an interest in various portions of a concession or areas owned by Mobil Erdgas and BEB. Three of these licenses cover the three northernmost areas of the Oldenburg concession. The Farm-In Agreement commits Vermilion to financial participation at a 50% level in 11 gross exploratory wells over the next five years. If Vermilion conducts any successful drilling within the confines of the Oldenburg concession, sales of that gas or oil would be subject to the relevant royalty contract. The Trust's German consultant has confirmed for the Trust that Vermilion will lead the development of its first well within the Oldenburg concession with a possible start time in 2020. The well is tentatively located in the western portion of the area designated Oldenburg-Land, the southernmost area of the three areas within the concession subject to Vermilion's Farm-In Agreement. Vermilion's well is intended to develop the Rotliegend (Red Sandstone) formation, a previously undeveloped productive zone within the concession. The information regarding Vermilion's activities within the Oldenburg concession was conveyed to the Trust's German consultant by representatives of EMPG.
Under one set of rights covering the western part of the Oldenburg concession (approximately 662,000 acres), the Trust receives a royalty payment of 4% on gross receipts from sales by Mobil Erdgas of gas well gas, oil well gas, crude oil and condensate (the "Mobil Agreement"). Under the Mobil Agreement there is no deduction of costs prior to the calculation of royalties from gas well gas and oil well gas, which together account for approximately 98% of all the royalties under said agreement. Historically, the Trust has received significantly greater royalty payments under the Mobil Agreement (as compared to the OEG Agreement described below) due to the higher royalty rate specified by that agreement.
The Trust is also entitled under the Mobil Sulfur Agreement to receive a 2% royalty on gross receipts of sales of sulfur obtained as a by-product of sour gas produced from the western part of Oldenburg. The payment of the sulfur royalty is conditioned upon sales of sulfur by Mobil Erdgas at a selling price above an agreed upon base price. This base price is adjusted annually by an inflation index. When the average quarterly selling price falls below the indexed base price, no sulfur royalties are paid by Mobil Erdgas. Sulfur royalties under the Mobil Agreement totaled $43,932, ($51,576) and $78,094 during fiscal 2017, 2016 and 2015, respectively. The 2016 figure includes negative adjustments from 2015, 2013, 2012 and 2011 of $36,336, $43,087, $186,045 and $56,225, which more than offset sulfur royalties payable. The 2015 figure includes negative adjustments from 2014 and 2013 of $80,516 and $134,832, respectively. The operating companies had improperly allocated eastern sulfur sales to the Mobil Agreement during 2015, 2014, 2013, 2012 and 2011 resulting in the overpayment of sulfur royalties.
Under another set of rights covering the entire Oldenburg concession and pursuant to the agreement with OEG, the Trust receives royalties at the rate of 0.6667% on gross receipts from sales by BEB of gas well gas, oil well gas, crude oil, condensate and sulfur (removed during the processing of sour gas) less a certain allowed deduction of costs (the "OEG Agreement"). Under the OEG Agreement, 50% of the field handling and treatment costs as reported for state royalty purposes are deducted from the gross sales receipts prior to the calculation of the royalty to be paid to the Trust.
On August 26, 2016, the Trust executed amendments to its existing royalty agreements with OEG and Mobil establishing a new base for the determination of gas prices upon which the Trust's royalties are determined. This 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. Currently, this change reflects a shift from the use of gas ex-field prices ("contractual prices") to the prices calculated for the GBIP. For simplification purposes, we will use GBIP when referring to the current state assessment base.
The change to the GBIP is intended to be revenue neutral for the Trust. Additionally, this change should reduce the scope and cost of the accounting examination, eliminate ongoing disputes with OEG and Mobil regarding sales to related parties, and reduce prior year adjustments to the normally scheduled year-end reconciliation. The new pricing basis will also eliminate certain costs (transportation and plant gas storage) that were previously deductible prior to the royalty calculation under the agreement with OEG.
Actual gas sales from the prior calendar quarter will be multiplied by the average GBIP for a period starting two months earlier and will provide the basis for royalty payments to the Trust during its fiscal quarter. The average GBIP for the corresponding period of actual sales is not available due to the delay in its calculation. In the final calculation of royalties payable for calendar 2015, the average GBIP under the Mobil and OEG Royalty Agreements was increased by 2% and 5%, respectively. For calendar 2016 and forward, the average GBIP under the Mobil and OEG Royalty Agreements will be increased by 1% and 3%, respectively. In March of the following calendar year, an average GBIP for the prior calendar year (weighted on a monthly basis by the respective volume of imported gas) is published. In the following calendar year, EMPG will make a final reconciliation based upon the published yearly average GBIP increased by the respective percentage factor and the total volume of gas sold under the royalty agreements during the prior calendar year.
The new basis for oil prices would be the published price from the State Authority for Mining, Energy and Geology. There are no percentage adjustments factored into the oil royalty calculation. There was no change in the previous methodology used with regard to the determination of royalties attributable to sales of sulfur.
In addition to the Oldenburg area, the Trust also holds overriding royalties at various rates on a number of currently non-producing leases of various sizes in other areas of Germany. One of these leases, Grosses Meer, was formerly active but provided no royalties during fiscal 2017, 2016 and 2015.
The following is a schedule of royalty income for the fiscal year ended October 31, 2017 by product, geographic area and operating company:
| By Product | |
|---|---|
| Product | Royalty Income |
| Gas Well and Oil Well Gas | $ 7,419,509 |
| Sulfur | $ 223,900 |
| Oil | $ 118,816 |
| By Geographic Area | |
| Area | Royalty Income |
| Western Oldenburg | $ 6,047,591 |
| Eastern Oldenburg | $ 1,714,634 |
| Non-Oldenburg Areas | $ 0 |
| By Operating Company | |
| Company | Royalty Income |
| Mobil Erdgas (under the Mobil Agreement | $ 5,272,080 |
| BEB (under the OEG Agreement) | $ 2,490,145 |
Exhibit 99.1 to this Report is a report entitled Calculation of Cost Depletion Percentage for the 2017 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, 2017 (the "Cost Depletion Report"). The Cost Depletion Report, dated November 30, 2017, was prepared by Graves & Co. Consulting, LLC, 2777 Allen Parkway, Suite 1200, Houston, Texas 77019 ("Graves & Co."). Graves & Co. is an independent petroleum and natural gas consulting organization specialized in analyzing hydrocarbon reserves.
The Cost Depletion Report provides documentation supporting the calculation of the cost depletion percentage for the 2017 calendar year based on the use of certain production data and the estimated net proved producing reserves as of October 1, 2017 for the primary area in which the Trust holds overriding royalty rights. The cost depletion percentage is prepared for the Trust's unit owners for tax reporting purposes. The cost depletion percentage recommended by the Trust's independent petroleum and natural gas consultants for calendar 2017 is 11.6635%. 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, 2017. While this is one month prior to the end of the fiscal year of the Trust, the information available for production and sales through the end of September is the most complete information available at a date early enough to permit the timely preparation of the various reports required. Unit owners are referred to the full text of the Cost Depletion Report contained herein for further details.
The primary purpose of the Cost Depletion Report is the preparation of the cost depletion percentage for use by unit owners in their own tax reporting. The only information provided to the Trust that can be utilized in the calculation of the cost depletion percentage is current and historical production and sales of proved producing reserves. For the western half of the Oldenburg Concession, the Trust received quarterly production and sales information on a well-by-well basis. For the eastern half of the Oldenburg Concession, the Trust receives cumulative quarterly production and sales information on two general areas. These general areas encompass numerous fields with varying numbers of wells. Pursuant to the arrangements under which the Trust holds royalty rights and the fact that the Trust is not considered an operating company within Germany, the Trust has no access to the operating companies' proprietary information concerning producing field reservoir data. The Trustees have been advised by their German counsel that publication of such information is not required under applicable law in Germany and that the royalty rights do not grant the Trust the right to require or compel the release of such information. Past efforts to obtain such information from the operating companies have not been successful. The information made available to the Trust by the operating companies does not include any of the following: reserve estimates, capitalized costs, production cost estimates, revenue projections, producing field reservoir data (including pressure data, permeability, porosity and thickness of producing zone) or other similar information. While the limited information available to the Trust permits the calculation of the cost depletion percentage, it does not change the uncertainty with respect to the estimate of proved producing reserves. In addition, it is impossible for the Trust or its consultant to make estimates of proved undeveloped or probable future net recoverable oil and gas by appropriate geographic areas.
The Trust has the authority to examine, but only for certain limited purposes, the operating companies' sales and production from the royalty areas. The Trust also has access to published materials in Germany from W.E.G. (a German organization equivalent to the American Petroleum Institute or the American Gas Association). The use of such statistical information relating to production and sales necessarily involves extrapolations and projections. Both Graves & Co. and the Trustees believe the use of the material available is appropriate and suitable for preparation of the cost depletion percentage and the estimates described in the Cost Depletion Report. The Trustees and Graves & Co. believe this report and these estimates to be reasonable and appropriate but assume that these estimates may vary from statistical estimates which could be made if reservoir production information (of the kind normally available to producing companies in the United States) were available. The limited information available makes it inappropriate to make projections or estimates of proved or probable reserves of any category or class other than the estimated net proved producing reserves described in the Cost Depletion Report.
Attachment A of the Cost Depletion Report shows a schedule of estimated net proved producing reserves of the Trust's royalty properties, computed as of October 1, 2017 and a five-year schedule of gas, sulfur and oil sales for the twelve months ended September 30, 2017, 2016, 2015, 2014 and 2013 computed from quarterly sales reports of operating companies received by the Trust during such periods.
Item 3. Legal Proceedings.
The Trust is not a party to any pending legal proceedings.
Item 4. Mine Safety Disclosures.
Not Applicable.
PART II
The Trust's units of beneficial interest are listed for trading on the New York Stock Exchange under the symbol NRT. Under the Trust Agreement, the Trustees distribute to unit owners, on a quarterly basis, the net royalty income after deducting expenses and reserving limited funds for anticipated administrative expenses. As of November 30, 2017, there were 659 unit owners of record.
The following table presents the high and low closing prices for the quarterly periods ended in fiscal 2017 and 2016 as reported by the NYSE as well as the cash distributions paid to unit owners by quarter for the past two fiscal years.
| Fiscal Year 2017 | |||
| Quarter Ended | Low Closing Price | High Closing Price | Distribution per Unit |
| January 31, 2017 | $ 6.24 | $ 7.67 | $ 0.15 |
| April 30, 2017 | $ 7.03 | $ 8.11 | $ 0.19 |
| July 31, 2017 | $ 6.11 | $ 7.69 | $ 0.20 |
| October 31, 2017 | $ 6.19 | $ 6.99 | $ 0.22 |
| Fiscal Year 2016 | |||
| Quarter Ended | Low Closing Price | High Closing Price | Distribution per Unit |
| January 31, 2016 | $ 5.89 | $ 9.99 | $ 0.16 |
| April 30, 2016 | $ 7.53 | $ 9.68 | $ 0.24 |
| July 31, 2016 | $ 8.15 | $ 9.75 | $ 0.15 |
| October 31, 2016 | $ 6.99 | $ 8.79 | $ 0.12 |
The quarterly distributions to unit owners represent their undivided interest in royalty payments from sales of gas, sulfur and oil during the previous quarter. Each unit owner is entitled to recover a portion of his or her investment in these royalty rights through a cost depletion percentage. The calculation of this cost depletion percentage is set forth in detail in Attachment B to the Cost Depletion Report attached as Exhibit 99.1 to this Form 10-K.
The Cost Depletion Report has been prepared by Graves & Co. using the limited information described in Item 2 of this Report to which reference is made. The Trustees believe that the calculations and assumptions used in the Cost Depletion Report are reasonable according to the facts and circumstances of available information. The cost depletion percentage recommended by the Trust's independent petroleum and natural gas consultants for calendar 2017 is 11.6635%. 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 2017 calendar year are included on special removable pages in the 2017 Annual Report. Additionally, the tax reporting information for 2017 is available on the Trust's website, www.neort.com, in the section marked Tax Letters contained within the Tax Information section.
The Trust does not maintain any compensation plans under which units are authorized for issuance. The Trust did not make any repurchases of Trust units during fiscal 2017, 2016 or 2015 and has never made such repurchases.
Item 6. Selected Financial Data.
| 2017 | 2016 | 2015 | 2014 | 2013 | |
| German gas, sulfur and oil royalties received | $ 7,762,225 | $ 6,960,961 | $ 12,390,575 | $ 18,927,005 | $ 21,546,298 |
| Net Income | $ 7,026,448 | $ 6,141,141 | $ 11,580,673 | $ 18,044,579 | $ 20,635,306 |
| Net Income per unit(a) | $ 0.76 | $ 0.67 | $ 1.26 | $ 1.96 | $ 2.25 |
| Units of beneficial interest outstanding at end of year(a) | 9,190,590 | 9,190,590 | 9,190,590 | 9,190,590 | 9,190,590 |
| Distributions per unit paid or to be paid to unit owners | $ 0.76 | $ 0.67 | $ 1.27 | $ 1.95 | $ 2.25 |
| Total assets at year end | $ 2,126,006 | $ 1,165,348 | $ 2,192,866 | $ 3,754,737 | $ 4,918,491 |
(a) Net income per unit was calculated based on the number of units outstanding at the end of the fiscal year.
Item 6. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Executive Summary
The Trust is a passive fixed investment trust which holds overriding royalty rights, receives income under those rights from certain operating companies, pays its expenses and distributes the remaining net funds to its unit owners. As mandated by the Trust Agreement, distributions of income are made on a quarterly basis. These distributions, as determined by the Trustees, constitute substantially all of the funds on hand after provision is made for Trust expenses then anticipated.
The Trust does not engage in any business or extractive operations of any kind in the areas over which it holds royalty rights and is precluded from engaging in such activities by the Trust Agreement. There are no requirements, therefore, for capital resources with which to make capital expenditures or investments in order to continue the receipt of royalty revenues by the Trust.
The properties of the Trust are described in Item 2. Properties of this Report. Of particular importance with respect to royalty income are the two royalty agreements, the Mobil Agreement and the OEG Agreement. The Mobil Agreement covers gas sales from the western part of the Oldenburg concession. Under the Mobil Agreement, the Trust has traditionally received the majority of its royalty income due to the higher royalty rate of 4%. The OEG Agreement covers gas sales from the entire Oldenburg concession but the royalty rate of 0.6667% is significantly lower and gas royalties have been correspondingly lower.
The operating companies pay monthly royalties to the Trust based on their sales of natural gas, sulfur and oil. Of these three products, natural gas provided approximately 96% of the total royalties in fiscal 2017. The amount of royalties paid to the Trust is primarily based on four factors: the amount of gas sold, the price of that gas, the area from which the gas is sold and the exchange rate.
On approximately the 25th of the months of January, April, July and October, the operating companies calculate the amount of gas sold during the previous calendar quarter and determine the amount of royalties that were payable to the Trust based on those sales. The pricing component to this royalty calculation no longer conforms to the same period. Due to the delay in the availability of the GBIP, the average GBIP for a three-month period ending two months prior to the end of the relevant calendar quarter is used. The average GBIP is increased by a percentage factor depending upon which royalty agreement forms the underlying basis for the royalty calculation. This timetable, the determination of the appropriate GBIP, and the percentage factor were set forth in the amendments to the Mobil and OEG Royalty Agreements signed on August 26, 2016. The respective royalty amount is divided into thirds and forms the monthly royalty payments to the Trust (payable on the 15th of each month) for the Trust's upcoming fiscal quarter. At the same time that the operating companies determine the actual amount of royalties that were payable for the prior calendar quarter, they look at the actual amount of royalties that were paid to the Trust for that period and calculate the difference between what was paid and what was payable. Additional amounts payable by the operating companies would be paid immediately and any overpayment would be deducted from the payment for the first month of the following fiscal quarter. In March of the following calendar year, an average GBIP for the prior calendar year (weighted on a monthly basis by the respective volume of imported gas) is published. In the succeeding calendar year, the operating companies make the final determination of any necessary royalty adjustments for the prior calendar year with a positive or negative adjustment made accordingly. Currently, the Trust's German accountants review the royalty calculations on a biennial basis.
There are two types of natural gas found within the Oldenburg concession, sweet gas and sour gas. Sweet gas has little or no contaminants and needs no treatment before it can be sold. Sour gas, in comparison, must be processed at the Grossenkneten desulfurization plant before it can be sold. The desulfurization process removes hydrogen sulfide and other contaminants. The hydrogen sulfide in gaseous form is converted to sulfur in a solid form and sold separately. As needed, EMPG, the operator of the Grossenkneten desulfurization plant, conducts maintenance on the plant, generally during the summer months when demand is lower. Historically, sour gas production capacity during the period of maintenance work has been reduced by approximately one-third. There was no maintenance conducted during 2016. Maintenance was conducted from March 2017 through mid-April 2017. The operating companies have informed the Trust that, to promote greater efficiency and cost effectiveness, the production capacity of Grossenkneten was reduced by approximately one-third through the retirement of Unit 3. Raw gas input capacity now stands at approximately 400 million cubic feet ("MMcf") per day.
Under the Mobil and OEG Agreements, the gas is sold in one of three ways: (1) directly on the spot market; (2) between Mobil Erdgas and BEB (intra-company sales); or (3) directly to various distributors under contracts (which delineate, among other provisions, the timing, manner, volume and price of the gas sold). While the operating companies will continue to sell gas in one of these three ways, the impact of the respective pricing involved is no longer applicable to the Trust because, under the amended royalty agreements, the price point, which is used as part of the basis for the royalty calculations, is now the average GBIP.
The Trust's accountants in Germany have begun their examination of the operating companies for 2015 and 2016, which will be performed in accordance with the provisions of the amended royalty agreements.
For unit owners, changes in the dollar value of the Euro have an immediate impact. This impact occurs at the time the royalties, which are paid to the Trust in Euros, are converted into U.S. dollars at the applicable exchange rate and transferred from Germany to the United States. In relation to the dollar, a stronger Euro would yield more dollars and a weaker Euro would yield less dollars.
Seasonal demand factors affect the income from the Trust's royalty rights insofar as they relate to energy demands and increases or decreases in prices, but on average they are generally not material to the annual income received under the Trust's royalty rights.
The Trust has no means of ensuring continued income from overriding royalty rights at their present level or otherwise. The Trust's consultant in Germany provides general information to the Trust on the German and European economies and energy markets. This information provides a context in which to evaluate the actions of the operating companies. The Trust's consultant receives reports from EMPG with respect to current and planned drilling and exploration efforts. However, EMPG and the operating companies continue to limit the information flow to that which is required by German law.
The low level of administrative expenses of the Trust limits the effect of inflation on costs. Sustained price inflation would be reflected in sales prices. Sales prices along with sales volumes form the basis on which the royalties paid to the Trust are computed.
Results: Fiscal 2017 versus Fiscal 2016
For fiscal 2017, the Trust's gross royalty income increased 11.51% to $7,762,225 from $6,960,961 in fiscal 2016. The increase in the amount of royalty income resulted in the higher distributions. The total distribution for fiscal 2017 was $0.76 per unit compared to $0.67 per unit for fiscal 2016. While gas prices under both royalty agreements increased, gas sales under both royalty agreements declined and average exchange rates were mixed. As a result, royalty income attributable to gas sales under the Mobil Agreement in fiscal 2017 declined by $175,099 as compared to fiscal 2016. Royalty income attributable to gas sales under the OEG Agreement in fiscal 2017 increased by $44,239 as compared to fiscal 2016.
The increase in royalty income for fiscal 2017 is primarily the result of positive adjustments in 2017 and negative adjustments in fiscal 2016. As in prior years, the Trust receives adjustments from the operating companies based on their final calculations of royalties payable during the previous periods. During fiscal 2017, the adjustments based on royalties payable for 2016 increased royalty income by $411,884, the equivalent of $0.0448 per unit. During fiscal 2016, the combination of positive and negative adjustments, including the year-end adjustments, reduced royalty income by $381,886, the equivalent of $0.0416 per unit. A similar situation occurred with respect to royalties paid under the Mobil Sulfur Agreement. In fiscal 2017, Mobil sulfur royalties totaled $43,932. In fiscal 2016 however, royalties under the Mobil Sulfur Agreement resulted in a net negative adjustment of $51,576 due to EMPG's incorrect inclusion in prior years of eastern sulfur sales in the royalty calculation.
Gas sales under the Mobil Agreement declined 5.90% to 23.566 Billion cubic feet ("Bcf") in fiscal 2017 from 25.043 Bcf in fiscal 2016. Since the Trust does not receive information about the decision-making process of the operating companies, it is impossible to determine to what extent, if any, which factors may have impacted gas sales. However, according to the Trust's consultant in Germany, it is likely that some portion of the decline in gas production is due to the normal reduction in well pressure that is experienced over time. The suspension of all drilling activities during the 2015-2017 period likely has also impacted gas sales.
| Quarterly and Yearly Gas Sales under the Mobil Agreement in Billion cubic feet | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Gas Sales | 2016 Gas Sales | Percentage change |
| First | 6.489 | 6.604 | - 1.74% |
| Second | 5.934 | 6.834 | -13.17% |
| Third | 5.500 | 4.917 | +11.86% |
| Fourth | 5.643 | 6.688 | -15.63% |
| Fiscal Year Total | 23.566 | 25.043 | - 5.90% |
Average prices for gas sold under the Mobil Agreement increased 3.35% to 1.6401 Euro cents per Killowatt hour ("Euro cents/kWh") in fiscal 2017 from 1.5870 Euro cents/kWh in fiscal 2016.
| Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour | |||
|---|---|---|---|
| Fiscal Quarter | 2017 Gas Sales | 2016 Gas Sales | Percentage change |
| First | 1.4789 | 1.8649 | - 20.70% |
| Second | 1.7434 | 1.5622 | + 11.60% |
| Third | 1.7406 | 1.5363 | + 13.30% |
| Fourth | 1.6197 | 1.3753 | + 17.77% |
| Fiscal Year Average | 1.6401 | 1.5870 | + 3.35% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $5.17 per thousand cubic feet ("Mcf"), a 2.58% decrease from fiscal 2016's average price of $5.04/Mcf. For fiscal 2017, royalties paid under the Mobil Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1038, a decrease of 0.41% from the average Euro/dollar exchange rate of $1.1083 for fiscal 2016.
| Average Euro Exchange Rate under the Mobil Agreement | |||
| Fiscal Quarter | 2017 Average Euro Exchange Rate | 2016 Average Euro Exchange Rate | Percentage change |
| First | 1.0582 | 1.0881 | - 2.75% |
| Second | 1.0625 | 1.1173 | - 4.90% |
| Third | 1.1175 | 1.1185 | - 0.09% |
| Fourth | 1.1806 | 1.1047 | + 6.87% |
| Fiscal Year Average | 1.1038 | 1.1083 | - 0.41% |
Excluding the effects of differences in prices and average exchange rates, the combination of royalty rates on gas sold from western Oldenburg results in an effective royalty rate approximately seven times higher than the royalty rate on gas sold from eastern Oldenburg. This is of particular significance to the Trust since gas sold from western Oldenburg provides the bulk of royalties paid to the Trust. For fiscal 2017, the volume of gas sold from western Oldenburg accounted for only 31.61% of the volume of all gas sales. However, western Oldenburg gas royalties provided approximately 78.79% or $5,845,817 out of a total of $7,419,509 in overall Oldenburg gas royalties.
Gas sales under the OEG Agreement decreased 3.46% to 74.544 Bcf in fiscal 2017 from 77.213 Bcf in fiscal 2016. Since the Trust does not receive information about the decision-making process of the operating companies, it is impossible to determine to what extent EMPG's decisions may have impacted gas sales. However, according to the Trust's consultant in Germany, it is likely that some portion of the decline in gas production is due to the normal reduction in well pressure that is experienced over time. The suspension of all drilling activities during the 2015-2017 period likely has also impacted gas sales.
| Quarterly and Yearly Gas Sales under the OEG Agreement in Billion cubic feet | |||
| Fiscal Quarter | 2017 Gas Sales | 2016 Gas Sales | Percentage change |
| First | 20.060 | 20.507 | - 2.18% |
| Second | 18.885 | 20.434 | - 7.58% |
| Third | 17.829 | 17.520 | + 1.76% |
| Fourth | 17.770 | 18.752 | - 5.24% |
| Fiscal Year Total | 74.544 | 77.213 | - 3.46% |
Average gas prices for gas sold under the OEG Agreement increased 2.96% to 1.6745 Euro cents/kWh in fiscal 2017 from 1.6264 Euro cents/kWh in fiscal 2016.
| Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour | |||
| Fiscal Quarter | 2017 Gas Prices | 2016 Gas Prices | Percentage change |
| First | 1.5081 | 1.9803 | - 23.84% |
| Second | 1.7779 | 1.5282 | + 16.34% |
| Third | 1.7750 | 1.5667 | + 13.30% |
| Fourth | 1.6517 | 1.4025 | + 17.77% |
| Fiscal Year Average | 1.6745 | 1.6264 | + 2.96% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $5.21/Mcf, a 3.37% increase from fiscal 2016's average price of $5.04/Mcf. For fiscal 2017, royalties paid under the OEG Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1101, an increase of 0.43% from the average Euro/dollar exchange rate of $1.1053 for fiscal 2016.
| Average Euro Exchange Rate under the OEG Agreement | |||
| Fiscal Quarter | 2017 Average Euro Exchange Rate | 2016 Average Euro Exchange Rate | Percentage change |
| First | 1.0590 | 1.0874 | - 2.61% |
| Second | 1.0630 | 1.1171 | - 4.84% |
| Third | 1.1175 | 1.1159 | + 0.14% |
| Fourth | 1.1788 | 1.1068 | + 6.51% |
| Fiscal Year Average | 1.1101 | 1.1053 | + 0.43% |
Interest income for fiscal 2017 of $4,352 declined slightly from interest income of $4,548 for fiscal 2016. Trust expenses decreased $84,239, or 10.22% to $740,129 in fiscal 2017 from $824,368 in fiscal 2016 due to lower legal expenses, both domestic and German. These lower legal expenses resulted from the completion in fiscal 2016 of the amendments to the Mobil and OEG Royalty Agreements. In addition, German accounting expenses were lower due to the completion in fiscal 2016 of the examination of the royalty companies for the 2013-2014 period.
Results: Fiscal 2016 versus Fiscal 2015
For fiscal 2016, the Trust's gross royalty income decreased 43.82% to $6,960,961 from $12,390,575 in fiscal 2015 continuing to reflect the disruption in the energy market and the uncertainty of the world economy. The decrease in royalty income is due to declines in gas sales, gas prices and average exchange rates under both royalty agreements. The decrease in the amount of royalty income resulted in the lower distributions. The total distribution for fiscal 2016 was $0.67 per unit compared to $1.27 per unit for fiscal 2015. As in prior years, the Trust receives adjustments from the operating companies based on their final calculations of royalties payable during the previous periods. During fiscal 2016, the combination of positive and negative adjustments reduced royalty income by $381,886, the equivalent of $0.0416 per unit. Due to the incorrect inclusion in prior years of eastern sulfur sales in the royalty calculation under the Mobil Sulfur Agreement, the combination of current year sulfur royalties and the negative adjustment from prior years resulted in a net negative adjustment for fiscal 2016 of $51,576, the equivalent of $0.0056 per unit. During fiscal 2015, the combination of positive and negative adjustments reduced royalty income by $592,626, the equivalent of $0.0645 per unit. Due to the incorrect inclusion in prior years of eastern sulfur sales in the royalty calculation under the Mobil Sulfur Agreement, the combination of current year sulfur royalties and the negative adjustment from prior years resulted in a net negative adjustment for fiscal 2015 of $215,348, the equivalent of $0.0234 per unit.
Gas sales under the Mobil Agreement declined 12.83% to 25.043 Bcf in fiscal 2016 from 28.729 Bcf in fiscal 2015. Gas sales in the first three quarters of fiscal 2016 showed a decline from the prior year's equivalent quarters. However, gas sales in the fourth quarter of fiscal 2016 were higher than the prior year's equivalent quarter. At least some of the increase in fourth quarter gas sales may be explained by the partial shutdown of the Grossenkneten desulfurization plant for a six-week period during the fourth quarter of fiscal 2015. Since the Trust does not receive information about the decision-making process of the operating companies, it is impossible to determine to what extent, if any, which factors may have impacted gas sales. However, according to the Trust's consultant in Germany, it is likely that some portion of the decline in gas production is due to the normal reduction in well pressure that is experienced over time. The suspension of all drilling activities during the 2015-2016 period likely has also impacted gas sales.
| Quarterly and Yearly Gas Sales under the Mobil Agreement in Billion cubic feet | |||
| Fiscal Quarter | 2016 Gas Sales | 2015 Gas Sales | Percentage change |
| First | 6.604 | 7.876 | - 16.15% |
| Second | 6.834 | 7.642 | - 10.57% |
| Third | 4.917 | 7.382 | - 33.39% |
| Fourth | 6.688 | 5.829 | + 14.74% |
| Fiscal Year Total | 25.043 | 28.729 | - 12.83% |
Average prices for gas sold under the Mobil Agreement decreased 28.39% to 1.5870 Euro cents/kWh in fiscal 2016 from 2.2162 Euro cents/kWh in fiscal 2015.
| Average Gas Prices under the Mobil Agreement in Euro cents per Kilowatt Hour | |||
| Fiscal Quarter | 2016 Gas Sales | 2015 Gas Sales | Percentage change |
| First | 1.8649 | 2.3538 | - 20.77% |
| Second | 1.5622 | 2.3212 | - 32.70% |
| Third | 1.5363 | 2.0017 | - 23.25% |
| Fourth | 1.3753 | 2.1662 | - 36.51% |
| Fiscal Year Average | 1.5870 | 2.2162 | - 28.39% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $5.04 per Mcf, a 30.19% decrease from fiscal 2015's average price of $7.22/Mcf. For fiscal 2016, royalties paid under the Mobil Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1083, a decrease of 2.12% from the average Euro/dollar exchange rate of $1.1323 for fiscal 2015.
| Average Euro Exchange Rate under the Mobil Agreement | |||
| Fiscal Quarter | 2016 Average Euro Exchange Rate | 2015 Average Euro Exchange Rate | Percentage change |
| First | 1.0881 | 1.2127 | - 10.27% |
| Second | 1.1173 | 1.0754 | + 3.90% |
| Third | 1.1185 | 1.1113 | + 0.65% |
| Fourth | 1.1047 | 1.1301 | - 2.25% |
| Fiscal Year Average | 1.1083 | 1.1323 | - 2.12% |
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 2016, the volume of gas sold from western Oldenburg accounted for only 32.43% of the volume of all gas sales. However, western Oldenburg gas royalties provided approximately 81.05% or $5,408,745 out of a total of $6,673,084 in overall Oldenburg gas royalties.
Gas sales under the OEG Agreement decreased 12.21% to 77.213 Bcf in fiscal 2016 from 87.952 Bcf in fiscal 2015. At least some portion of the decline in overall gas sales is likely a result of EMPG's decision to suspend all drilling activities during 2015-2016. Since the Trust does not receive information about the decision-making process of the operating companies, it is impossible to determine to what extent, if any, which factors may have impacted gas sales. However, according to the Trust's consultant in Germany, it is likely that some portion of the decline in gas production is due to the normal reduction in well pressure that is experienced over time.
| Quarterly and Yearly Gas Sales under the OEG Agreement in Billion cubic feet | |||
| Fiscal Quarter | 2016 Gas Sales | 2015 Gas Sales | Percentage change |
| First | 20.507 | 23.497 | - 12.73% |
| Second | 20.434 | 23.137 | - 11.68% |
| Third | 17.520 | 22.590 | - 22.44% |
| Fourth | 18.752 | 18.728 | + 0.13% |
| Fiscal Year Total | 77.213 | 87.952 | - 12.21% |
Average gas prices for gas sold under the OEG Agreement decreased 29.10% to 1.6264 Euro cents/kWh in fiscal 2016 from 2.2939 Euro cents/kWh in fiscal 2015.
| Average Gas Prices under the OEG Agreement in Euro cents per Kilowatt Hour | |||
| Fiscal Quarter | 2016 Gas Prices | 2015 Gas Prices | Percentage Change |
| First | 1.9803 | 2.4808 | - 20.17% |
| Second | 1.5282 | 2.4128 | - 36.66% |
| Third | 1.5667 | 2.0401 | - 23.20% |
| Fourth | 1.4025 | 2.2187 | - 36.79% |
| Fiscal Year Average | 1.6264 | 2.2939 | - 29.10% |
Converting gas prices into more familiar terms, using the average exchange rate, yielded a price of $5.04/Mcf, a 30.86% decrease from fiscal 2015's average price of $7.29/Mcf. For fiscal 2016, royalties paid under the OEG Agreement were converted and transferred at an average Euro/dollar exchange rate of $1.1053, a decrease of 2.11% from the average Euro/dollar exchange rate of $1.1291 for fiscal 2015.
| Average Euro Exchange Rate under the OEG Agreement | |||
|---|---|---|---|
| Fiscal Quarter | 2016 Average Euro Exchange Rate | 2015 Average Euro Exchange Rate | Percentage Change |
| First | 1.0874 | 1.1973 | - 9.18% |
| Second | 1.1171 | 1.0830 | + 3.15% |
| Third | 1.1159 | 1.1159 | - 0.00% |
| Fourth | 1.1068 | 1.1309 | - 2.13% |
| Fiscal Year Average | 1.1053 | 1.1291 | - 2.11% |
Interest income for fiscal 2016 decreased 51.82% to $4,548 as compared to $9,439 for fiscal 2015 reflecting the reduction in royalty receipts. Trust expenses increased 0.61% to $824,368 in fiscal 2016 from $819,341 in fiscal 2015 due to higher legal expenses, both domestic and German, and higher German accounting expenses relating to the amendments to the Mobil and OEG Royalty Agreements.
Report on Exploration and Drilling
The Trust's German consultant periodically contacts the representatives of the operating companies to inquire about their planned and proposed drilling and geophysical work and other general matters. The following represents a summary of the most recent information the Trust's German consultant received from representatives of EMPG. The Trust is not able to confirm the accuracy of any of the information supplied by the operating companies. In addition, the operating companies are not required to take any of the actions outlined and, if they change their plans with respect to any such actions, they are not obligated to inform the Trust.
EMPG has indicated that it plans to resume drilling in 2018, after having previously suspended all drilling activities for 2015 through 2017 due to the continuing difficulties caused by low energy prices worldwide and the uncertainties posed by ongoing changes in German regulations. If EMPG follows through with the drilling activities contained in its drilling schedule, 2018 will be a busy year including one workover and four horizontal deviations off existing wells. All the 2018 planned wells, Doetlingen Z-3A, as well as the multilateral wells, Brettorf Z-2b, Goldenstedt Z-12a M1, Goldenstedt Z-25a M1, are located in eastern Oldenburg and are intended to further develop the Zechstein zone through infill drilling. Multilateral wells take advantage of a single master well to draw from multiple sidetracks. The primary advantage is the cost saving in using a single borehole for more than one sidetrack. The 2018 workover is being attempted on a western Zechstein well, Visbek Z-16a. Visbek Z-16a suffered a severe casing collapse six months after it began production and was shut down in October 2013. Due to costs it is believed this work-over will be limited to an attempt to repair the original casing. We have no start dates nor estimated completion times for any of these wells or the workover.
The first well listed for 2019 is Hemmelte NW T-1 and is planned to develop a new area of the sweet gas Bunter zone in western Oldenburg. This well was initially planned as a dual purpose well tapping both the Bunter and the deeper Zechstein zones but, due to technical difficulties, was scaled back. An additional well to be sighted near the Hemmelte NW well and intended to access the Zechstein zone at a later date was initially mentioned but no further information has been forthcoming. The second well listed for 2019, Ahlhorn Z-3, is a sour gas well. The well will attempt to reactivate the Ahlhorn field which had been abandoned in 1997.
The only new well listed for 2020 is Jeddeloh Z-1. Jeddeloh Z-1 is the first well being drilled in the Oldenburg concession with Vermilion as the lead developer. The well is an exploration well tentatively located in the western portion of the area designated as Oldenburg-Land, the southernmost area of the three areas within the concession subject to Vermilion's Farm-In Agreement. Vermilion's well is intended to develop the Rotliegend (Red Sandstone) formation, a previously undeveloped productive zone within the concession. Oldenburg-Land is a relatively undeveloped area of the concession compared to the southern area of Muensterland-Cloppenburg-Vechta where the majority of the wells operated by EMPG are located. Our understanding of the terms of the original Farm-In Agreement would seem to indicate that there will have to be some further negotiations between Vermilion and EMPG to extend the original time frame. The Trust's consultant in Germany will continue to monitor this situation.
No firm dates have been announced for any of the wells described above. Information on wells that are not named or are in preliminary planning stages is not divulged by EMPG.
Critical Accounting Policies
The financial statements, appearing subsequently in this Report, present financial statement balances and financial results on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States ("GAAP basis"). Cash basis accounting is an accepted accounting method for royalty trusts such as the Trust. GAAP basis financial statements disclose income as earned and expenses as incurred, without regard to receipts or payments. The use of GAAP would require the Trust to accrue for expected royalty payments. This is exceedingly difficult since the Trust has very limited information on such payments until they are received and cannot accurately project such amounts. The Trust's cash basis financial statements disclose revenue when cash is received and expenses when cash is paid. The one modification of the cash basis of accounting is that the Trust accrues for distributions to be paid to unit owners (those distributions approved by the Trustees for the Trust). The Trust's distributable income represents royalty income received by the Trust during the period plus interest income less any expenses incurred by the Trust, all on a cash basis. In the opinion of the Trustees, the use of the modified cash basis provides a more meaningful presentation to unit owners of the results of operations of the Trust and presents to the unit owners a more accurate calculation of income and expenses for tax reporting purposes.
Off-Balance Sheet Arrangements
The Trust has no off-balance sheet arrangements.
Contractual Obligations
As shown below, the Trust had no contractual obligations as of October 31, 2017 other than the distribution announced on October 30, 2017 and payable to unit owners on November 29, 2017, as reflected in the statement of assets, liabilities and trust corpus.
| Payments Due by Period | |||||
|---|---|---|---|---|---|
| Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More than 5 Years | |
| Distributions payable to unit owners | $2,021,929 | $2,021,929 | $ 0 | $ 0 | $ 0 |
This Report on Form 10-K may contain forward-looking statements intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address future expectations and events or conditions concerning the Trust. Many of these statements are based on information provided to the Trust by the operating companies or by consultants using public information sources. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated in any forward-looking statements. These include:
• risks and uncertainties concerning levels of gas production and gas sale prices, general economic conditions and currency exchange rates;
• the ability or willingness of the operating companies to perform under their contractual obligations with the Trust;
• potential disputes with the operating companies and the resolution thereof; and
• the risk factors set forth above under Item 1A of this Report
All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and are generally beyond the control of the Trust. New factors emerge from time to time and it is not possible for the Trust to predict all such factors or to assess the impact of each such factor on the Trust. Any forward-looking statement speaks only as of the date on which such statement is made, and the Trust does not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made.
Item 7A. Quantitative and Qualitative Disclosure about Market Risk .
The Trust does not engage in any trading activities with respect to possible foreign exchange fluctuations. The Trust does not use any financial instruments to hedge against possible risks related to foreign exchange fluctuations. The market risk with respect to funds held in the Trust's bank account in Germany is negligible because standing instructions at the Trust's German bank require the bank to process conversions and transfers of royalty payments as soon as possible following their receipt. The Trust does not engage in any trading activities with respect to commodity price fluctuations.
Item 8. Financial Statements and Supplementary Data.
| Page Number | |
| Report of Independent Registered Public Accounting Firm | F-1 |
| Financial Statements: | |
| Statements of Assets, Liabilities and Trust Corpus as of October 31, 2017 and 2016 |
F-2 |
| Statements of Revenue Collected and
Expenses Paid for the Fiscal Years Ended October 31, 2017, 2016 and 2015 |
F-3 |
| Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2017, 2016 and 2015 |
F-4 |
| Statements of Changes in Cash and
Cash Equivalents for the Fiscal Years Ended October 31, 2017, 2016 and 2015 | F-5 |
| Notes to Financial Statements | F-6 - F-9 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and the Unit Owners of
North European Oil Royalty Trust
We have audited the accompanying statements of assets, liabilities and trust corpus of North European Oil Royalty Trust (the "Trust") as of October 31, 2017 and 2016, and the related statements of revenue collected and expenses paid, undistributed earnings, and changes in cash and cash equivalents for each of the three years in the period ended October 31, 2017. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
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 U.S. generally accepted accounting principles.
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, 2017 and 2016, its revenue collected and expenses paid, its undistributed earnings, and changes in its cash and cash equivalents for each of the three years in the period ended October 31, 2017, on the basis of accounting described in Note 1.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust's internal control over financial reporting as of October 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated December 28, 2017 expressed an unqualified opinion.
/s/Mazars USA LLP
New York, NY
December 28, 2017
F-1
| 2017 | 2016 | |
|---|---|---|
| ASSETS | ||
| Current assets -- Cash and cash equivalents | $ 2,126,005 | $ 1,165,347 |
| Producing gas and oil royalty rights, net of amortization (Notes 1 and 2) | 1 | 1 |
| Total Assets | $ 2,126,006 | $ 1,165,348 |
| LIABILITIES AND TRUST CORPUS | ||
| Current liabilities -- Distributions
to be paid to unit owners, paid November 2017 and 2016 |
$ 2,021,929 | $ 1,102,871 |
| Trust corpus (Notes 1 and 2) | 1 | 1 |
| Undistributed earnings | 104,076 | 62,476 |
| Total Liabilities and Trust Corpus | $ 2,126,006 | $ 1,165,348 |
The accompanying notes are an integral part of these financial statements.
F-2
| 2017 | 2016 | 2015 | |
|---|---|---|---|
| Gas, sulfur and oil royalties received | $ 7,762,225 | $ 6,960,961 | $ 12,390,575 |
| Interest income | 4,352 | 4,548 | 9,439 |
| Trust Income | 7,766,577 | 6,965,509 | 12,400,014 |
| Non-related party expenses | (669,965) | (715,404) | (732,209) |
| Related party expenses (Note 3) | (70,164) | (108,964) | (87,132) |
| Trust Expenses | (740,129) | (824,368) | (819,341) |
| Net Income | $ 7,026,448 | $ 6,141,141 | $ 11,580,673 |
| Net income per unit | $ 0.76 | $ 0.67 | $ 1.26 |
| Distributions per unit paid or to be paid to unit owners | $ 0.76 | $ 0.67 | $ 1.27 |
The accompanying notes are an integral part of these financial statements.
F-3
| 2017 | 2016 | 2015 | |
| Balance, beginning of period | $ 62,476 | $ 79,030 | $ 170,406 |
| Net income | 7,026,448 | 6,141,141 | 11,580,673 |
| 7,088,924 | 6,220,171 | 11,751,079 | |
| Less: | |||
| Current year distributions
paid or to be paid to unit owners |
6,984,848 | 6,157,695 | 11,672,049 |
| Balance, end of period | $ 104,076 | $ 62,476 | $ 79.030 |
The accompanying notes are an integral part of these financial statements.
F-4
| 2017 | 2016 | 2015 | |
| Sources of Cash and Cash Equivalents: | |||
| Gas, sulfur and oil royalties received | $ 7,762,225 | $6,960,961 | $12,390,575 |
| Interest income | 4,352 | 4,548 | 9,439 |
| 7,766,577 | 6,965,509 | 12,400,014 | |
| Uses of Cash and Cash Equivalents: | |||
| Payment of Trust expenses | 740,129 | 824,368 | 819,341 |
| Distributions paid | 6,065,790 | 7,168,659 | 13,142,544 |
| 6,805,919 | 7,993,027 | 13,961,885 | |
| Net increase (decrease) in cash and cash equivalents during the period |
960,658 | (1,027,518) | (1,561,871) |
| Cash and cash equivalents, beginning of period | 1,165,347 | 2,192,865 | 3,754,736 |
| Cash and cash equivalents, end of period | $ 2,126,005 | $ 1,165,347 | $ 2,192,865 |
The accompanying notes are an integral part of these financial statements.
F-5
(1) Summary of significant accounting policies:
Basis of accounting -
The accompanying financial statements of North European Oil Royalty Trust (the "Trust") are prepared in accordance with the rules and regulations of the SEC. Financial statement balances and financial results are presented on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States ("GAAP basis"). In the opinion of management, all adjustments that are considered necessary for a fair presentation of these financial statements, including adjustments of a normal, recurring nature, have been included.
On a modified cash basis, revenue is earned when cash is received and expenses are incurred when cash is paid. GAAP basis financial statements disclose revenue as earned and expenses as incurred, without regard to receipts or payments. The modified cash basis of accounting is utilized to permit the accrual for distributions to be paid to unit owners (those distributions approved by the Trustees for the Trust). The Trust's distributable income represents royalty income received by the Trust during the period plus interest income less any expenses incurred by the Trust, all on a cash basis. In the opinion of the Trustees, the use of the modified cash basis of accounting provides a more meaningful presentation to unit owners of the results of operations of the Trust.
Producing gas and oil royalty rights -
The rights to certain gas and oil royalties in Germany were transferred to the Trust at their net book value by North European Oil Company (the "Company") (see Note 2). The net book value of the royalty rights has been reduced to one dollar ($1) in view of the fact that the remaining net book value of royalty rights is de minimis relative to annual royalties received and distributed by the Trust and does not bear any meaningful relationship to the fair value of such rights or the actual amount of proved producing reserves.
Federal and state income taxes -
The Trust, as a grantor trust, is exempt from federal income taxes under a private letter ruling issued by the Internal Revenue Service. The Trust has no state income tax obligations.
F-6
Cash and cash equivalents -
Cash and cash equivalents are defined as amounts deposited in bank accounts and amounts invested in certificates of deposit and U. S. Treasury bills with original maturities generally of three months or less from the date of purchase. The investment options available to the Trust are limited in accordance with specific provisions of the Trust Agreement. As of October 31, 2017, the uninsured amounts held in the Trust's U.S. bank accounts were $1,878,125. In addition, the Trust held Euros 4,870, the equivalent of $5,695, in its German bank account at October 31, 2017.
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, 2017, 2016 and 2015, 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 space and services to the Trust at cost. For such office space and services, the Trust reimbursed the Managing Director $25,015, $28,559 and $25,729 in fiscal 2017, 2016 and 2015, respectively.
Lawrence A. Kobrin, a Trustee of the Trust, is a Senior Counsel at Cahill Gordon & Reindel LLP, which serves as counsel to the Trust. For legal services, the Trust paid Cahill Gordon & Reindel LLP $45,149, $80,405 and $61,403 in fiscal 2017, 2016 and 2015, respectively.
F-7
(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 2017, 2016 and 2015 calendar years.
(5) Quarterly results (unaudited):
The tables below summarize the quarterly results and distributions of the Trust for the fiscal years ended October 31, 2017 and 2016:
Fiscal 2017 by Quarter and Year
| First | Second | Third | Fourth | Year | |
| Royalties received | $ 1,724,686 | $ 1,918,830 | $ 1,974,441 | $ 2,144,268 | $ 7,762,225 |
| Net income | $ 1,475,017 | $ 1,699,909 | $ 1,840,694 | $ 2,010,828 | $ 7,026,448 |
| Net Income per unit | $ 0.16 | $ 0.18 | $ 0.20 | $ 0.22 | $ 0.76 |
| Distribution paid or to be paid |
$ 1,378,589 | $ 1,746,212 | $ 1,838,118 | $ 2,021,929 | $ 6,984,848 |
| Distribution per unit or to be paid to unit owners |
$ 0.15 | $ 0.19 | $ 0.20 | $ 0.22 | $ 0.76 |
Fiscal 2016 by Quarter and Year
| First | Second | Third | Fourth | Year | |
| Royalties received | $1,832,471 | $2,333,670 | $1,561,026 | $1,233,794 | $6,960,961 |
| Net income | $1,573,687 | $2,100,364 | $1,388,796 | $1,078,294 | $6,141,141 |
| Net Income per unit | $0.17 | $0.23 | $0.15 | $0.12 | $;0.67 |
| Distribution paid or to be paid |
$1,470,494 | $2,205,742 | $1,378,588 | $1,102,871 | $6,157,695 |
| Distribution per unit or to be paid to unit owners |
$0.16 | $0.24 | $0.15 | $0.12 | $0.67 |
Item 9. Changes in and
Disagreements with Accountants on
Accounting and Financial Disclosure.
None.
F-8
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, 2017. Based on that evaluation, the Managing Director concluded that the Trust's disclosure controls and procedures were effective as of October 31, 2017.
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, 2016. 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, 2017. Management's assessment of the effectiveness of our internal control over financial reporting as of October 31, 2017 has been audited by Mazars USA LLP, the Trust's independent auditor, as stated in their report which follows.
Part B. Attestation Report of Independent Registered Public Accounting Firm
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Trustees and the Unit Owners
of North European Oil Royalty Trust
We have audited North European Oil Royalty Trust's (the "Trust") internal control over financial reporting as of October 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Trust's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A trust's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A trust's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the trust are being made only in accordance with authorizations of management and trustees of the trust; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of October 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities and trust corpus as of October 31, 2017 and 2016, and the related statements of revenue collected and expenses paid, undistributed earnings and changes in cash and cash equivalents for each of the three years in the period ended October 31, 2017 and our report dated December 28, 2017 expressed an unqualified opinion thereon.
/s/ Mazars USA LLP
New York, NY
December 28, 2017
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 2017 that have materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting.
Item 9B. Other Information.
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Except as set forth below, the information required by this item will be contained in the Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to be held on February 20, 2018, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.
Code of Ethics
The Trustees have adopted a Code of Conduct and Business Ethics (the "Code") for the Trust's Trustees and employees, including the Managing Director. The Managing Director serves the roles of principal executive officer and principal financial and accounting officer. A copy of the Code is available without charge on request by writing to the Managing Director at the office of the Trust. The Code is also available on the Trust's website, www.neort.com.
All Trustees and employees of the Trust are required to read and sign a copy of the Code annually. No waivers or exceptions to the Code have been granted since the adoption of the Code. Any amendments or waivers to the Code, to the extent required, will be disclosed in a Form 8-K filing of the Trust after such amendment or waiver.
Item 11. Executive Compensation.
The information required by this item will be contained in the Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to be held on February 20, 2018, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.
Item 12. Security Ownership
of Certain Beneficial Owners and Management and Related
Stockholder Matters.
The information required by this item will be contained in the Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to be held on February 20, 2018, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item will be contained in the Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to be held on February 20, 2018, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services.
The information required by this item will be contained in the Trust's definitive Proxy Statement for its Annual Meeting of Unit Owners to be held on February 20, 2018, to be filed pursuant to Section 14 of the Securities Exchange Act of 1934, and is incorporated herein by reference.
Item 15. Exhibits and Financial Statement Schedules.
(a) The following is a list of the documents filed as part of this Report:
1. Financial Statements
Index to Financial Statements for the Fiscal Years Ended October 31, 2017, 2016 and 2015
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus as of October 31, 2017 and 2016
Statements of Revenue Collected and Expenses Paid for the Fiscal Years Ended October 31, 2017, 2016 and 2015
Statements of Undistributed Earnings for the Fiscal Years Ended October 31, 2017, 2016 and 2015
Statements of Changes in Cash and Cash Equivalents for the Fiscal Years Ended October 31, 2017, 2016 and 2015
Notes to Financial Statements
2. Exhibits
The Exhibit Index following the signature page lists all exhibits filed with this Report or incorporated by reference.
Item 16. Form 10-K Summary.
None.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Trust has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTH EUROPEAN OIL ROYALTY TRUST
| Dated: December 28, 2017 | /s/John R. Van Kirk |
| John R. Van Kirk, Managing Director | |
| and Principal Accounting Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
| Dated: December 28, 2017 | /s/Robert P. Adelman |
| Robert P. Adelman, Managing Trustee | |
| Dated: December 28, 2017 | /s/Ahron H.Haspel |
| Ahron H. Haspel, Trustee | |
| Dated: December 28, 2017 | /s/Lawrence A. Kobrin |
| Lawrence A. Kobrin, Trustee | |
| Dated: December 28, 2017 | /s/Willard B. Taylor |
| Willard B. Taylor, Trustee | |
| Dated: December 28, 2017 | /s/John R. Van Kirk |
| John R. Van Kirk, Managing Director | |
| and Principal Accounting Officer |
Exhibit Index
Exhibit 31
I, John R. Van Kirk, certify that:
/s/ John R. Van Kirk John R. Van Kirk Chief Executive Officer and Chief Financial Officer
Dated: December 28, 2017
Exhibit 31
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chapter 63, Title 18 U.S.C. Section 1350(a) and (b)), the undersigned hereby certifies that the Annual Report on Form 10-K for the period ended October 31, 2017 of North European Oil Royalty Trust ("Trust") fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that the information contained in such Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.
/s/ John R. Van Kirk John R. Van Kirk Chief Executive Officer and Chief Financial Officer
Dated: December 28, 2017
November 15, 2017
To Trustees of
North European Oil Royalty Trust
P. O. Box 456
Red Bank, New Jersey 07701
Ref: North European Oil Royalty Trust
Calculation of the Cost Depletion Percentage
For the Calendar Year 2017
Trustees:
In accordance with the request of the Trustees of North European Oil Royalty Trust ("Trustees"), the firm of Graves & Co. Consulting, LLC ("Graves") of Houston, Texas has performed the calculations necessary to derive the cost depletion percentage for the 2017 calendar year. The cost depletion percentage was prepared for use by unit owners of North European Oil Royalty Trust ("Trust") in filing Federal income tax returns. In order to calculate the cost depletion percentage we prepared a report of the estimated remaining proved producing reserves attributable to the overriding royalty interests of the Trust in the Northwest German Basin of the Federal Republic of Germany with an effective date of October 1, 2017.
We have reviewed all available information with respect to all of the Trust's proved developed properties used in the calculation of the cost depletion percentage as discussed later in this report. It is our opinion that these properties represent all of the Trust's assets that may be classified as proved for this purpose as per the Securities and Exchange Commission directives as detailed later in this report.
The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part 210-Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility Holding Company Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rules of General Application Section 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.
The proved producing reserves are as of October 1, 2017 and the reported sales are for the twelve month period ending September 30, 2017. The use of the period ending September 30, 2017 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 product is then averaged for the period to arrive at the unit price.
Based on the results of our calculation of estimated remaining proved producing reserves contained in the first part of this report, we have performed the calculations necessary to derive the cost depletion percentage for the 2017 calendar year. As detailed in Attachment B, the cost depletion percentage for the 2017 calendar year for Trust unit owners is equal to 11.6635% of the unit owner's cost basis as of January 1, 2017.
The scope of this study was to review limited information we were able to compile and to prepare an estimate of the proved producing reserves subject to the Trust's royalty interests from which the cost depletion percentage could be calculated. We prepared reserve estimates using acceptable evaluation principals for each source. These estimates were based in large part on the limited information supplied by the operator of the relevant properties.
The quantities presented herein are estimated reserves of oil, natural gas, natural gas liquids and sulfur that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty.
The Trust holds various overriding royalty rights on sales of gas, sulfur and oil from certain concessions and leases in the Federal Republic of Germany. The Oldenburg concession (1,386,000 acres), covering virtually the entire former Grand Duchy of Oldenburg and located in the federal state of Lower Saxony, is held by Oldenburgische Erdolgesellschaft ("OEG"). OEG in turn is owned by Mobil Erdgas-Erdol GmbH ("Mobil Erdgas"), the German subsidiary of ExxonMobil Corp. and by BEB Erdgas und Erdol GmbH ("BEB"), a joint venture of ExxonMobil Corp. and the Royal Dutch/Shell Group of Companies. As a result by direct and indirect ownership, ExxonMobil Corp. owns two-thirds of OEG and the Royal Dutch/Shell Group owns one-third of OEG.
The Oldenburg concession is currently the sole source of royalty income for the Trust. All proved producing reserves within the Oldenburg concession are covered by this report. Although the Trust has royalty interests in other areas, these areas are no longer used in the calculation of the annual cost depletion percentage because there is no current production from these areas.
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.
Oldenburg Area - Sales and Reserves
The Trust's royalty income currently comes exclusively from the Oldenburg area. Gas production accounts for the majority of the income; however, the hydrogen sulfide in much of the gas produced necessitates its removal before the gas can be sold. At the Grossenkneten desulfurization plant, the hydrogen sulfide in sour gas is removed. The plant's present input capacity stands at approximately 400 million cubic feet ("MMcf") per day following EMPG's retirement of Unit 3. The elimination of Unit 3 effectively reduces the input capacity by one third.
During the twelve months ending September 30, 2017, total sales for the Oldenburg area were as follows:
| |
|
|
|
|---|---|---|---|
| Gas Well Gas - MMCF | 23,530 | 50,967 | 74,497 |
| Oil Well Gas - MMCF | 43 | 25 | 68 |
| Oil & Condensate - Barrels | 91,337 | 35,491 | 126,828 |
| Sulfur - Short Tons | 103,342 | 354,568 | 457,910 |
Gross Reserves
Estimated gross remaining proved producing reserves attributable to the total Oldenburg area as of October 1, 2017 are as follows:
| |
|
|
|
|---|---|---|---|
| Gas Well Gas - MMCF | 213,634 | 321,588 | 535,222 |
| Oil Well Gas - MMCF | 431 | 77 | 508 |
| Oil & Condensate - Barrels | 941,765 | 110,229 | 1,051,994 |
| Sulfur - Short Tons | 927,427 | 2,700,817 | 3,628,244 |
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:
| |
|
||
|---|---|---|---|
| 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, 2017 and net sales for the twelve month period ending September 30, 2017 are as follows:
| |
|
|
|---|---|---|
| Gas Well Gas - MMCF | 9,936 | 1,330 |
| Oil Well Gas - MMCF | 20 | 2 |
| Oil & Condensate - Barrels | 43,487 | 4,210 |
| Sulfur - Short Tons | 40,231 | 4,665 |
A summary of net proved producing reserves by product and a five year history of net sales attributable to the royalty interests of the Trust are presented in Attachment A.
The reserves considered in this report are defined as proved producing reserves. Proved producing reserves are limited to those quantities which can be expected to be recoverable commercially from known reservoirs at current prices and costs, under existing regulatory practices and with existing conventional equipment and operating methods. Proved producing reserves do not include either proved developed non producing reserves or any class of probable reserves.
The estimate of reserves included in this report is based primarily upon production history or analogy with wells in the area producing from the same or similar formations. In addition to individual well production history, geological and well test information, when available, were utilized in the evaluation.
The reserves included in this report are estimates only and should not be construed as being exact quantities. The accuracy of the estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data. The quantities presented herein are estimated reserves of hydrocarbons and produced products that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty. Reserve estimates presented in this report are calculated using acceptable methods and procedures and are believed to be appropriate and reasonable; however, future reservoir performance may justify revision of these estimates.
For the purpose of this report, estimated reserves are scheduled for recovery primarily on the basis of actual producing rates or appropriate well test information. They were prepared giving consideration to engineering and geological data, anticipated producing mechanisms, the number and types of completions, as well as past performance of analogous reservoirs. Individual well production histories, when available, were analyzed and an appropriate daily producing rate was utilized for each individual well in the preparation of a forecast of future producing rates until an anticipated economic limit.
The estimates of reserves and the forecasted rates of production may be subject to regulation by various agencies, changes in market demand or other factors. Consequently, the volumes of reserves recovered and the actual rates of recovery may vary from the estimates included herein.
The Trust, as an overriding royalty interest owner, does not receive proprietary data from the various operators on producing wells. Data, such as logs, core analysis, reservoir tests, pressure tests, gas analyses, geologic maps, and individual well production histories on all of the wells which are used in volumetric and material balance type reserve estimates, are not available to the Trust. The lack of such data increases the inherent uncertainties of our reserve estimate.
The Trust receives quarterly statements from the operators that report production, sales and revenue data. Utilizing the same procedures as in prior years, this information plus published information received from W.E.G. (a German organization comparable to the American Petroleum Institute or the American Gas Association) has been used to prepare this annual report. In addition, the Trust retains a part-time consultant in Germany who is familiar with the German petroleum industry in general and the operating companies in particular. His periodic reports and communications were considered in the preparation of this report.
We believe that reserve estimates prepared using all the available data are appropriate and sufficient for the calculation of the cost depletion percentage. However, due to the limitations of available data, this estimate of reserves cannot have the same degree of accuracy that an estimate of reserves prepared using all pertinent data would have. Our experience in the evaluation of reserves using such limited data compensates somewhat for the limitations of available data.
The data in the reports received by the Trust is in metric tons and cubic meters. The following Metric to English Unit conversion factors were used:
| Gas: | 37.25 cubic feet per cubic meter at 14.7 psia and 60 degrees Fahrenheit |
| Oil: | 7.23 barrels per metric ton |
| Sulfur: | 1.1 short tons per metric ton |
Calculation of Cost Depletion Percentage
The categories of proved producing reserves considered in the calculation of the cost depletion percentage are oil, oil well gas, and gas well gas. Sulfur is a by-product of gas production and is not considered in the computation of total cost depletion percentage.
For each category of reserves, a product base was established for the Trust as of January 1, 1976. Through the use of these product bases, we can account for the relative size of each of these categories of reserves and the corresponding impact on the calculation of the cost depletion percentage. The product base for each category of proved producing reserves is reduced annually by an adjustment that is calculated by multiplying the product base at the beginning of the current year by the depletion factor for that category of reserves.
The depletion factor for each category of reserves is the ratio of the relevant net sales during the current year to the corresponding adjusted net proved producing reserves at the beginning of the current year.
Significant items in the cost depletion percentage calculation that appear on Attachment B as specific item numbers, shown in parentheses and their sources are as follows:
The adjusted estimated net proved producing reserves as of 10/1/16 Line (3) is obtained by adding the estimated remaining net proved producing reserves as of 10/1/16 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 10/1/16 Line (3). Therefore Line (6) = Line (4) / Line (3).
The product base for each category of proved producing reserves as of 1/1/16 Line (7) and the adjustment taken during 2016 Line (8) were obtained from the previous year's report. The product base as of 1/1/17 Line (9) forms the initial starting point for the calculation of the cost depletion percentage for the 2017 tax year. The product base for 1/1/16 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 1/1/17 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 1/1/17 [Sum Line (9)]. Therefore Line (11) = [Sum Line (10)] / [Sum Line (9)].
The cost depletion percentage represents the total allowable cost depletion for the 2017 calendar year for the Trust's unit owners, expressed as a percentage of their cost base as of January 1, 2017.
Neither Graves & Co. Consulting, LLC nor any of its employees have any interest in the subject properties and neither the employment to make this study and calculation nor our compensation is contingent on our estimate of reserves or the results of our calculation.
We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.
Sincerely yours,
GRAVES & CO. CONSULTING LLC Texas Registered Engineering Firm F - 19125
/s/ John L. Graves John L. Graves President
/s/ Kent B. Lina Kent B. Lina, P.E. Senior Reservoir Engineer
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| 2017 | ||||||
| 2016 | ||||||
| 2015 | ||||||
| 2014 | ||||||
| 2013 | ||||||
| OLDENBURG | |||
|---|---|---|---|
| NEORT NET RESERVES (Million Cubic Feet of Gas and Barrels of Oil) | |||
| 1. Estimated net proved producing reserves as of 10-1-16 | 12,214 | 14 | 33,371 |
| 2. Adjustment to reserves during period | -948 | 8 | 14,315 |
| 3. Adjusted est. net proved producing reserves as of 10-1-2016 | 11,266 | 22 | 47,686 |
| 4. Net sales from 10-1-16 to 9-30-17 | 1,330 | 2 | 4,210 |
| 5. Estimated remaining net proved producing reserves as of 10-1-2017 | 9,936 | 20 | 43,476 |
| RESERVE DEPLETION FACTOR | |||
| 6. Depletion factor | 0.11805 | 0.09091 | 0.08829 |
| NEORT WEIGHTED PRODUCT BASE ALLOCATION | |||
| 7. Product base as of 1-1-16 | 2.43449 | 0.00137 | 0.12198 |
| 8. Less adjustments taken during 2016 | 0.24907 | 0.00009 | 0.01371 |
| 9. Product base as of 1-1-17 | 2.18542 | 0.00128 | 0.10827 |
| 10. 2017 Adjustment to product base | 0.25800 | 0.00012 | 0.00956 |
| 11. Cost depletion percentage for 2017 calendar year for Trust unit owners is equal to 11.6635 percent of their 1-1-2017 cost base. |
Footnotes:
Line (1) from reserves review as of 10-1-16 Line (2) from reserves review as of 10-1-17 Line (3) = Line (1) + Line (2) Line (4) from BEB and Mobil Erdgas statements Line (5) from reserves review as of 10-1-17 Line (6) = Line (4) / Line (3) Line (7) from 2016 depletion calculations Line (8) from 2016 depletion calculations Line (9) = Line (7) - Line (8) Line (10) = Line (9) x Line (6) Line (11) = Sum Line (10) / Sum Line (9)
The following information is taken 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
Section 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.
Reserves 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 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.
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 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.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
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.
Additional Definitions:
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.
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.
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.