Permianville Royalty Trust - Annual Report: 2017 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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 December 31, 2017
or
o 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 001-35333
ENDURO ROYALTY TRUST
(Exact name of registrant as specified in its charter)
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Delaware |
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45-6259461 |
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(State or other jurisdiction of |
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(I.R.S. Employer |
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The Bank of New York Mellon Trust Company, N.A., Trustee |
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77002 |
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(Address of principal executive offices) |
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(Zip Code) |
Registrant’s telephone number, including area code: 1-512-236-6555
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class |
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Name of Each Exchange on Which Registered |
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Units of Beneficial Interest |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o 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 o 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 o
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
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):
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Accelerated filer |
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Non-accelerated filer |
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(Do not check if a smaller reporting company) |
Smaller reporting company |
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Emerging growth company |
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates (24,400,000 Units of Beneficial Interest) computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was $79,300,000.
As of March 6, 2018, 33,000,000 Units of Beneficial Interest of the Trust were outstanding.
Documents Incorporated By Reference: None
References to the “Trust” in this document refer to Enduro Royalty Trust, while references to “Enduro” in this document refer to Enduro Resource Partners LLC.
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-K, including without limitation the statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors,” regarding the financial position, business strategy, production and reserve growth, and other plans and objectives for the future operations of Enduro and regarding future matters relating to the Trust are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-K, could affect the future results of the energy industry in general, and Enduro and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:
· risks associated with the drilling and operation of oil and natural gas wells;
· the amount of future direct operating expenses and development expenses;
· the effect of existing and future laws and regulatory actions;
· the effect of changes in commodity prices or alternative fuel prices;
· the December 31, 2013 maturity of all hedge contracts previously entered into by Enduro related to the Underlying Properties and the prohibition on the Trust’s entry into any new hedging arrangements under the terms of the Conveyance;
· conditions in the capital markets;
· competition from others in the energy industry;
· uncertainty of estimates of oil and natural gas reserves and production; and
· cost inflation.
You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this Form 10-K. The Trust does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this Form 10-K or to reflect the occurrence of unanticipated events, unless the securities laws require the Trust to do so.
This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of Enduro and the Trust, including under the caption “Risk Factors.” All subsequent written and oral forward-looking statements attributable to Enduro or the Trust or persons acting on behalf of Enduro or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
In this Form 10-K the following terms have the meanings specified below.
Bbl—One barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.
Boe—One barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals approximately six Mcf of natural gas.
Btu—A British Thermal Unit, a common unit of energy measurement.
Completion—The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Development Well—A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential—The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.
Estimated future net revenues—Also referred to as “estimated future net cash flows.” The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.
Farm-in or farm-out agreement—An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
Field—An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
GAAP—Accounting principles generally accepted in the United States of America.
Gross acres or gross wells—The total acres or wells, as the case may be, in which a working interest is owned.
MBbl—One thousand barrels of crude oil or condensate.
MBoe—One thousand barrels of oil equivalent.
Mcf—One thousand cubic feet of natural gas.
MMBoe—One million barrels of oil equivalent.
MMBtu—One million British Thermal Units.
MMcf—One million cubic feet of natural gas.
Net acres or net wells—The sum of the fractional working interests owned in gross acres or wells, as the case may be.
Net profits interest—A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.
Net revenue interest—An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, Net Profits Interests, carried interests, reversionary interests and any other burdens to which the interest is subject.
Plugging and abandonment—Activities to remove production equipment and seal off a well at the end of a well’s economic life.
Proved developed reserves—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves—Under SEC rules, proved reserves are defined as:
Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved undeveloped reserves—Proved reserves 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.
PV-10— A non-GAAP financial measure of the present value of estimated future net revenues to be generated from the production of proved reserves, net of estimated future production and development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to income taxes, discounted at 10% per annum.
Recompletion—The completion for production of an existing wellbore in another formation from which that well has been previously completed.
Reservoir—A porous and permeable underground formation containing a natural accumulation of producible oil or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Working interest—The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Workover—Operations on a producing well to restore or increase production.
Enduro Royalty Trust (the “Trust”) is a Delaware statutory trust formed in May 2011 pursuant to a trust agreement dated May 3, 2011 (as amended and restated in November 2011 and September 2017, the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”), as trustor, The Bank of New York Mellon Trust Company, N.A. (the “Trustee”), as trustee, and Wilmington Trust Company (the “Delaware Trustee”), as Delaware Trustee.
The Trust was created to acquire and hold for the benefit of the Trust unitholders a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro as of the date of the conveyance of the net profits interest to the Trust (the “Net Profits Interest”). The properties in which the Trust holds the Net Profits Interest are referred to as the “Underlying Properties.” Enduro is a Delaware limited liability company engaged in the production and development of oil and natural gas from properties located in the Rockies, the Permian Basin of west Texas and southeastern New Mexico, and the Arklatex region of Texas and Louisiana.
In connection with the closing of the initial public offering of units of beneficial interest in the Trust (“Trust Units”) in November 2011, Enduro Operating LLC, a Texas limited liability company and a wholly owned subsidiary of Enduro (“Enduro Operating”), and Enduro Texas LLC, a Texas limited liability company and a wholly owned subsidiary of Enduro (“Enduro Texas”), merged, with each entity surviving the merger. By virtue of the merger, Enduro Texas retained all rights, title and interest to the Net Profits Interest. Enduro Operating and Enduro Texas entered into a Conveyance of Net Profits Interest, dated effective as of July 1, 2011 (as supplemented and amended to date, the “Conveyance”), to effect the transfer of the Net Profits Interest from Enduro Operating to Enduro Texas.
On November 8, 2011, Enduro Texas merged with and into the Trust (the “Trust Merger”) pursuant to an Agreement and Plan of Merger dated November 3, 2011 (the “Trust Merger Agreement”). Under the terms of the Trust Merger Agreement, the Trust continued as the surviving entity, and the limited liability company interest in Enduro Texas held by Enduro prior to the effective time of the Trust Merger converted into the right to receive 33,000,000 Trust Units. Further, by virtue of the Trust Merger, the Trust retained all right, title and interest to the Net Profits Interest (including the right to enforce the Conveyance against Enduro Operating, as grantor). On November 8, 2011, the Trust, Enduro Operating and Enduro Texas entered into a Supplement to Conveyance of Net Profits Interest to acknowledge that The Bank of New York Mellon Trust Company, N.A., as Trustee, is deemed the grantee under the Conveyance and a party thereto.
Immediately following the Trust Merger, Enduro completed an initial public offering of 13,200,000 Trust Units at a price to the public of $22 per unit.
In October 2013, Enduro completed a secondary offering of 11,200,000 Trust Units at a price to the public of $13.85 per unit. The Trust did not sell any Trust Units in the offering and did not receive any proceeds from the offering. After the completion of the secondary offering, Enduro owned 8,600,000 Trust Units, or 26% of the issued and outstanding Trust Units.
At a special meeting of Trust unitholders held on August 30, 2017, unitholders approved several proposals, including amendments to the Trust Agreement and Conveyance. In September 2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which amended certain provisions of the Trust Agreement to, among other things, allow Enduro to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust unitholders holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements of the Trust Agreement. This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding units of the Trust. To effect the same changes as those included in the amended Trust Agreement, Enduro, the Trustee and the Delaware Trustee also entered into the First Amendment to Conveyance of Net Profits Interest. As a result of the Trust unitholders approving amendments to the Trust Agreement and Conveyance and the approval of the divestiture of certain properties in the Permian Basin, Enduro and the Trustee entered into the Partial Release, Reconveyance and Termination Agreement (the “Partial Release”). Pursuant to the terms of the Partial Release, the Trustee, on behalf of the Trust, reconveyed, terminated and released to Enduro the Net Profits Interest with respect to certain of the Underlying Properties sold pursuant to eight letter agreements or purchase and sale agreements, as applicable, entered into between Enduro and eight separate counterparties.
The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the Underlying Properties during the term of the Trust. The Trust Agreement provides that the Trust’s business activities are limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the Conveyance. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interest.
The Trust has no employees. Administrative functions are performed by the Trustee pursuant to the Trust Agreement. The Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties. The duties of the Trustee are specified in the Trust Agreement and by the laws of the state of Delaware, except as modified by the Trust Agreement. The Trustee’s principal duties consist of:
· collecting cash attributable to the Net Profits Interest;
· paying expenses, charges and obligations of the Trust from the Trust’s assets;
· distributing distributable cash to the Trust unitholders;
· causing to be prepared and distributed a tax information report for each Trust unitholder and preparing and filing tax returns on behalf of the Trust;
· causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and by the rules of any securities exchange or quotation system on which the Trust Units are listed or admitted to trading;
· causing to be prepared and filed a reserve report by or for the Trust by independent reserve engineers as of December 31 of each year in accordance with criteria established by the Securities and Exchange Commission (the “SEC”);
· establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of the Sarbanes-Oxley Act of 2002;
· enforcing the Trust’s rights under certain agreements; and
· taking any action it deems necessary or advisable to best achieve the purposes of the Trust.
In connection with the formation of the Trust, the Trust entered into several agreements with Enduro that impose obligations upon Enduro, including the Conveyance and a Registration Rights Agreement. The Trustee has the power and authority under the Trust Agreement to enforce these agreements on behalf of the Trust. Additionally, the Trustee may from time to time supplement or amend the Conveyance and the Registration Rights Agreement without the approval of Trust unitholders in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the Trust unitholders, to comply with changes in applicable law or to change the name of the Trust. Such supplement or amendment, however, may not materially adversely affect the interests of the Trust unitholders.
The Trustee may create a cash reserve to pay for future liabilities of the Trust and may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed its cash on hand and available reserves. The Trustee may authorize the Trust to borrow from any person, including the Trustee, the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee nor any affiliate thereof intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the Trustee, Delaware Trustee or an affiliate thereof, would be similar to the terms that such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. Under the terms of the Trust Agreement, Enduro provided the Trust with a $1 million letter of credit to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses. If the Trust requires more than the $1 million under the letter of credit to pay administrative expenses, Enduro has agreed to loan funds to the Trust necessary to pay such expenses. If the Trust borrows funds or draws on the letter of credit, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid.
Each month, the Trustee pays Trust obligations and expenses and distributes to the Trust unitholders the remaining proceeds received from the Net Profits Interest. The cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date may be held in a noninterest-bearing account or may be invested in:
· interest-bearing obligations of the United States government;
· money market funds that invest only in United States government securities;
· repurchase agreements secured by interest-bearing obligations of the United States government; or
· bank certificates of deposit.
The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following:
· the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells the Net Profits Interest;
· the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years;
· the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution; or
· the Trust is judicially dissolved.
Upon dissolution of the Trust, the Trustee would sell all of the Trust’s assets, either by private sale or public auction, and, after payment or the making of reasonable provision for payment of all liabilities of the Trust, distribute the net proceeds of the sale to the Trust unitholders.
Marketing and Post-Production Services
Pursuant to the terms of the Conveyance, Enduro has the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interest in the Underlying Properties. The terms of the Conveyance restrict Enduro from charging any fee for marketing production attributable to the Net Profits Interest other than fees for marketing paid to non-affiliates. Accordingly, a marketing fee is not deducted (other than fees paid to non-affiliates) in the calculation of the Net Profits Interest’s share of net profits. The net profits to the Trust from the sales of oil and natural gas production from the Underlying Properties attributable to the Net Profits Interest is determined based on the same price that Enduro receives for sales of oil and natural gas production attributable to Enduro’s interest in the Underlying Properties. However, if the oil or natural gas is processed, the net profits receive the same processing upgrade or downgrade as Enduro.
The operators of the Underlying Properties sell the oil produced from the Underlying Properties to third-party crude oil purchasers. Oil production from the Underlying Properties is typically transported by truck from the field to the closest gathering facility or refinery. The operators sell the majority of the oil production from the Underlying Properties under contracts using market sensitive pricing. The price received by the operators for the oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon delivery location and oil quality. Natural gas produced by the operators is marketed and sold to third-party purchasers. The natural gas is sold pursuant to contracts with such third parties, and the sales contracts are in their secondary terms and are on a month-to-month basis. The contract prices are based on a published regional index price, after adjustments for Btu content, transportation and related charges.
The following purchasers individually accounted for ten percent or more of sales from the Underlying Properties that were included in calculating the Trust’s “Income from net profits interest” for the periods presented. The table provides the percentage represented by the purchasers during the periods presented:
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Year Ended December 31, |
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2017 |
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2016 |
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2015 |
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ConocoPhillips |
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32 |
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32 |
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30 |
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Occidental Petroleum |
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22 |
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19 |
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16 |
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Navajo Refining |
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12 |
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13 |
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12 |
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Pioneer Natural Resources |
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5 |
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6 |
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10 |
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Competition and Markets
The oil and natural gas industry is highly competitive. Enduro competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than Enduro, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. Because Enduro and the third party operators of the Underlying Properties are subject to competitive conditions in the oil and natural gas industry, the Trust’s Net Profits Interest is indirectly subject to those same competitive conditions.
Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Future prices for oil and natural gas will directly impact Trust distributions, estimates of reserves attributable to the Trust’s interests and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the Trust nor Enduro can make reliable predictions of future oil and natural gas supply and demand or future product prices. Nevertheless, lower product prices generally will result in lower distributions, lower estimates of reserves attributable to the Trust’s interests and lower estimated and actual future net revenues to the Trust.
All of the Trust’s assets are located in the United States. The operators of the Underlying Properties sell the oil and natural gas produced from the Underlying Properties to third-party purchasers in the United States. Demand for natural gas generally is higher in the winter months, but otherwise seasonal factors do not affect the Trust.
Description of Trust Units
Each Trust Unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. Each Trust unitholder has the same rights regarding his or her Trust Units as every other Trust unitholder has regarding his or her units. The Trust Units are in book-entry form only and are not represented by certificates. The Trust had 33,000,000 Trust Units outstanding as of March 6, 2018.
Distributions and Income Computations
Each month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s liabilities for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) are entitled to monthly distributions payable on or before the 10th business day after the record date. In the event that the net profits for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.
Unless otherwise advised by counsel or the Internal Revenue Service (“IRS”), the Trustee will treat the income and expenses of the Trust for each month as belonging to the Trust unitholders of record on the monthly record date. Trust unitholders generally will recognize income and expenses for tax purposes in the month the Trust receives or pays those amounts, rather than in the month the Trust distributes the cash to which such income or expenses (as applicable) relate. Minor variances may occur. For example, the Trustee could establish a reserve in one month that would not result in a tax deduction until a later month.
Transfer of Trust Units
Trust unitholders may transfer their Trust Units in accordance with the Trust Agreement. The Trustee will not require either the transferor or transferee to pay a service charge for any transfer of a Trust Unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Trust Unit as shown by its records as the owner of the Trust Unit. The Trustee will not be considered to know about any claim or demand on a Trust Unit by any party except the record owner. A person who acquires a Trust Unit after any monthly record date will not be entitled to the distribution relating to that monthly record date. Delaware law and the Trust Agreement govern all matters affecting the title, ownership or transfer of Trust Units.
Periodic Reports
The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders annual reports that Trust unitholders need to correctly report their share of the income and deductions of the Trust. The Trustee also causes to be prepared and filed reports that are required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust Units are listed or admitted to trading, and also causes the Trust to comply with the provisions of the Sarbanes-Oxley Act of 2002, including but not limited to, establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.
Each Trust unitholder and his or her representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee, subject to such restrictions as are set forth in the Trust Agreement.
Liability of Trust Unitholders
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. The courts in jurisdictions outside of Delaware, however, might not give effect to such limitation.
Voting Rights of Trust Unitholders
The Trustee or Trust unitholders owning at least 10% of the outstanding Trust Units may call meetings of Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders, unless such meeting is called by the Trust unitholders in which case the Trust unitholders are responsible for all costs associated with calling such meeting. Meetings must be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust Units outstanding must be present or represented to have a quorum. Each Trust unitholder is entitled to one vote for each Trust Unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.
Unless otherwise required by the Trust Agreement, a matter may be approved or disapproved by the affirmative vote of a majority of the Trust Units present in person or by proxy at a meeting where there is a quorum. This is true even if a majority of the total Trust Units did not approve it. The affirmative vote of the holders of at least 75% of the outstanding Trust Units is required to:
· dissolve the Trust;
· amend the Trust Agreement (except with respect to certain matters that do not adversely affect the rights of Trust unitholders in any material respect); or
· approve the sale of all the assets of the Trust (including the sale of the Net Profits Interest).
At the special meeting of Trust unitholders held on August 30, 2017, unitholders approved amendments to the Trust Agreement. In September 2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which amended certain provisions of the Trust Agreement to, among other things, allow Enduro to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust unitholders holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements of the Trust Agreement. This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding units of the Trust.
In addition, certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders.
Computation of Net Profits
The provisions of the Conveyance governing the computation of the net profits are detailed and extensive. The following information summarizes the material provisions of the Conveyance related to the computation of the net profits, but is qualified in its entirety by the text of the Conveyance, which is incorporated by reference as an exhibit to this Annual Report on Form 10-K.
Net Profits Interest
The amounts paid to the Trust for the Net Profits Interest are based on, among other things, the definitions of “gross profits” and “net profits” contained in the Conveyance and described below. Under the Conveyance, net profits are computed monthly, and 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties for each calendar month will be paid to the Trust on or before the end of the following month. Enduro will not pay to the Trust any interest on the net profits held by Enduro prior to payment to the Trust, provided that such payments are timely made.
“Gross profits” means the aggregate amount received by Enduro from and after July 1, 2011 from sales of oil and natural gas produced from the Underlying Properties that are not attributable to a production month that occurs prior to June 1, 2011 (after deducting the appropriate share of all royalties and any overriding royalties, production payments and other similar charges (in each case, in existence as of June 1, 2011) and other than certain excluded proceeds, as described in the Conveyance), including all proceeds and consideration received (i) directly or indirectly, for advance payments, (ii) directly or indirectly, under take-or-pay and similar provisions of production sales contracts (when credited against the price for delivery of production) and (iii) under balancing arrangements. Gross profits do not include consideration for the transfer or sale of any Underlying Property by Enduro or any subsequent owner to any new owner, unless the Net Profits Interest is released (as is permitted under certain circumstances). Gross profits also do not include any amount for oil or natural gas lost in production or marketing or used by the owner of the Underlying Properties in drilling, production and plant operations.
“Net profits” means, as more fully set forth in the Conveyance, gross profits less the following costs, expenses and, where applicable, losses, liabilities and damages all as actually incurred by Enduro and attributable to the Underlying Properties on or after July 1, 2011 but that are not attributable to a production month that occurs prior to July 1, 2011 (as such items are reduced by any offset amounts, as described in the Conveyance):
· with the exception of certain costs and expenses related to 20 wells located in the Haynesville Shale identified in the Conveyance, all costs for (i) drilling, development, production and abandonment operations, (ii) all direct labor and other services necessary for drilling, operating, producing and maintaining the Underlying Properties and workovers of any wells located on the Underlying Properties, (iii) treatment, dehydration, compression, separation and transportation, (iv) all materials purchased for use on, or in connection with, any of the Underlying Properties and (v) any other operations with respect to the exploration, development or operation of hydrocarbons from the Underlying Properties;
· all losses, costs, expenses, liabilities and damages with respect to the operation or maintenance of the Underlying Properties for (i) defending, prosecuting, handling, investigating or settling litigation, administrative proceedings, claims, damages, judgments, fines, penalties and other liabilities, (ii) the payment of certain judgments, penalties and other liabilities, (iii) the payment or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying with applicable local, state and federal statutes, ordinance, rules and regulations, (v) tax or royalty audits and (vi) any other loss, cost, expense, liability or damage with respect to the Underlying Properties not paid or reimbursed under insurance;
· all taxes, charges and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate, franchise and like taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying Properties;
· all insurance premiums attributable to the ownership or operation of the Underlying Properties for insurance actually carried with respect to the Underlying Properties, or any equipment located on any of the Underlying Properties, or incident to the operation or maintenance of the Underlying Properties;
· all amounts and other consideration for (i) rent and the use of or damage to the surface, (ii) delay rentals, shut-in well payments and similar payments and (iii) fees for renewal, extension, modification, amendment, replacement or supplementation of the leases included in the Underlying Properties;
· all amounts charged by the relevant operator as overhead, administrative or indirect charges specified in the applicable operating agreements or other arrangements covering the Underlying Properties or Enduro’s operations with respect thereto;
· to the extent that Enduro is the operator of certain of the Underlying Properties and there is no operating agreement covering such portion of the Underlying Properties, those overhead, administrative or indirect charges that are allocated by Enduro to such portion of the Underlying Properties;
· if, as a result of the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of hydrocarbons produced from the Underlying Properties, any amounts previously credited to the determination of the net profits are reclaimed from Enduro, then the amounts reclaimed;
· all costs and expenses for recording the Conveyance and, at the applicable times, terminations and/or releases thereof;
· amounts previously included in gross profits but subsequently paid as a refund, interest or penalty; and
· at the option of Enduro (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross profits when actually incurred).
As mentioned above, the costs deducted in the net profits determination will be reduced by certain offset amounts. The offset amounts are further described in the Conveyance, and include, among other things, certain net proceeds attributable to the treatment or processing of hydrocarbons produced from the Underlying Properties and certain non-production revenues, including salvage value for equipment related to plugged and abandoned wells. If the offset amounts exceed the costs during a monthly period, the ability to use such excess amounts to offset costs will be deferred and utilized as offsets in the next monthly period to the extent such amounts, plus accrued interest thereon, together with other offsets to costs, for the applicable month, are less than the costs arising in such month.
The Trust is not liable to the owners of the Underlying Properties or the operators for any operating capital or other costs or liabilities attributable to the Underlying Properties. The Trustee expects to make distributions to Trust unitholders monthly; however, in the event that the net profits for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.
The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties, multiplied by 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the Conveyance.
Additional Provisions
If a controversy arises as to the sales price of any production, then for purposes of determining gross profits:
· any proceeds that are withheld for any reason (other than at the request of Enduro) are not considered received until such time that the proceeds are actually collected;
· amounts received and promptly deposited with a non-affiliated escrow agent will not be considered to have been received until disbursed to Enduro by the escrow agent; and
· amounts received and not deposited with an escrow agent will be considered to have been received.
The Trustee is not obligated to return any cash received from the Net Profits Interest. Any overpayments made to the Trust by Enduro due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the Trust until Enduro recovers the overpayments plus interest at a prime rate (as described in the Conveyance).
The Conveyance generally permits Enduro to transfer without the consent or approval of the Trust unitholders all or any part of its interest in the Underlying Properties, subject to the Net Profits Interest. The Trust unitholders are not entitled to any proceeds of a sale or transfer of Enduro’s interest. Except in certain cases where the Net Profits Interest is released, following a sale or transfer, the Underlying Properties will continue to be subject to the Net Profits Interest, and the gross profits attributable to the transferred property will be calculated, paid and distributed by the transferee to the Trust. Enduro will have no further obligations, requirements or responsibilities with respect to any such transferred interests.
In addition, Enduro may, without the consent of the Trust unitholders, require the Trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months, provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by Enduro to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair value to the Trust of such Net Profits Interest being treated as an offset amount against costs and expenses. Enduro has not sold any of the Underlying Properties under this provision.
As the designated operator of a property included in the Underlying Properties, Enduro may enter into farm-out, operating, participation and other similar agreements to develop the property, but any transfers made in connection with such agreements will be made subject to the Net Profits Interest. Enduro may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.
Enduro has the right to release, surrender or abandon its interest in any Underlying Property that will no longer produce (or be capable of producing) hydrocarbons in paying quantities (determined without regard to the Net Profits Interest). Upon such release, surrender or abandonment, the portion of the Net Profits Interest relating to the affected property will also be released, surrendered or abandoned, as applicable. Enduro also has the right to abandon an interest in the Underlying Properties if (a) such abandonment is necessary for health, safety or environmental reasons or (b) the hydrocarbons that would have been produced from the abandoned portion of the Underlying Properties would reasonably be expected to be produced from wells located on the remaining portion of the Underlying Properties.
Enduro must maintain books and records sufficient to determine the amounts payable for the Net Profits Interest to the Trust. Monthly and annually, Enduro must deliver to the Trustee a statement of the computation of the net profits for each computation period. The Trustee has the right to inspect and review the books and records maintained by Enduro during normal business hours and upon reasonable notice. Enduro has further agreed to provide the Trust and Trustee with all information and services as are reasonably necessary to fulfill the purposes of the Trust, including such accounting, bookkeeping and informational services as may be necessary for the preparation of reports the Trust is required to prepare or file in accordance with applicable tax and securities laws, exchange listing rules and other requirements, including reserve reports and tax returns. Following the sale of all or any portion of the Underlying Properties, the purchaser will be bound by the obligations of Enduro under the Trust Agreement and the Conveyance with respect to the portion sold.
U.S. Federal Income Tax Matters
The following is a summary of certain U.S. federal income tax matters that may be relevant to the Trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Trust or the Trust unitholders.
The summary has limited application to non-U.S. persons and persons subject to special tax treatment such as, without limitation: banks, insurance companies or other financial institutions; Trust unitholders subject to the alternative minimum tax; tax-exempt organizations; dealers in securities or commodities; regulated investment companies; real estate investment trusts; traders in securities that elect to use a mark-to-market method of accounting for their securities holdings; non-U.S. Trust unitholders that are “controlled foreign corporations” or “passive foreign investment companies” persons that are S-corporations, partnerships or other pass-through entities; persons that own their interest in the Trust Units through S-corporations, partnerships or other pass-through entities; persons that at any time own more than 5% of the aggregate fair market value of the Trust Units; expatriates and certain former citizens or long-term residents of the United States; U.S. Trust unitholders whose functional currency is not the U.S. dollar; persons who hold the Trust Units as a position in a hedging transaction, “straddle”, “conversion transaction” or other risk reduction transaction; or persons deemed to sell the Trust Units under the constructive sale provisions of the Code. Each Trust unitholder should consult his own tax advisor with respect to his particular circumstances.
Classification and Taxation of the Trust
Tax counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, in its opinion, the Trust would be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the IRS or another taxing authority. The remainder of the discussion below is based on tax counsel’s opinion, at the time of formation, that the Trust will be classified as a grantor trust for U.S. federal income tax purposes. As a grantor trust, the Trust is not subject to U.S. federal income tax at the trust level. Rather, each Trust unitholder is considered for U.S. federal income tax purposes to own its proportionate share of the Trust’s assets directly as though no Trust were in existence. The income of the Trust is deemed to be received or accrued by the Trust unitholder at the time such income is received or accrued by the Trust, rather than when distributed by the Trust. Each Trust unitholder is subject to tax on its proportionate share of the income and gain attributable to the assets of the Trust and is entitled to claim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholder’s tax method of accounting and taxable year without regard to the taxable year or accounting method employed by the Trust.
The Trust files annual information returns, reporting to the Trust unitholders all items of income, gain, loss, deduction and credit. The Trust allocates these items of income, gain, loss, deduction and credit to Trust unitholders based on record ownership on the monthly record dates. It is possible that the IRS or another taxing authority could disagree with this allocation method and assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by this issue and result in an increase in the administrative expense of the Trust in subsequent periods.
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is generally 20%. Such marginal tax rates may be effectively increased due to the phaseout of personal exemptions and certain limitations and prohibitions on itemized deductions. The highest marginal U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.
Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts (and a reduced 1.4% tax on certain tax-exempt organizations). For these purposes, investment income generally will include a unitholder’s allocable share of the trust’s interest and royalty income plus the gain recognized from a sale of Trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s U.S. federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.
If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Code, the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The IRS likely will take the position that a unitholder must recapture depletion upon the disposition of a unit.
Classification of the Net Profits Interest
Tax counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, based upon the reserve report and representations made by the Trust regarding the expected economic life of the Underlying Properties and the expected duration of the Net Profits Interest, in its opinion the Net Profits Interest attributable to proved developed reserves will and the Net Profits Interest attributable to proved undeveloped reserves should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of production from the mineral interests they burden. No assurance can be given that the IRS or another taxing authority will not assert that the Net Profits Interest should be treated differently. Any such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in Trust Units.
Reporting Requirements for Widely-Held Fixed Investment Trusts
The Trustee assumes that some Trust Units are held by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and brokers holding an interest for a custodian street name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Houston, Texas 77002, telephone number 1-512-236-6545, is the representative of the Trust that will provide the tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units. Any generic tax information provided by the Trustee of the Trust is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.
Available Trust Tax Information
In compliance with the Treasury regulations reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns. This tax information booklet can be obtained at www.enduroroyaltytrust.com.
Environmental Matters and Regulation
General. For purposes of the discussion in this section, the oil and natural gas production operations conducted on the properties that are subject to the Net Profits Interest are referred to as “Enduro’s operations.” Enduro’s oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose significant obligations on Enduro’s operations, including requirements to:
· obtain permits to conduct regulated activities;
· limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
· restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling, completion and production activities;
· initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells; and
· apply specific health and safety criteria addressing worker protection.
Failure to comply with environmental laws and regulations may result in the assessment of significant administrative, civil and criminal sanctions, including monetary penalties, the imposition of joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of Enduro’s operations. Moreover, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Enduro has advised the Trustee that it believes that it is in substantial compliance with all existing environmental laws and regulations applicable to its current operations and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. While the Trump Administration has taken steps aimed at reducing federal regulatory burdens and costs for oil and natural gas production operations, the recent trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could have a material adverse effect on Enduro’s development expenses, results of operations and financial position. Enduro may be unable to pass on those increases to its customers. Moreover, accidental releases or spills may occur in the course of Enduro’s operations, and there can be no assurance that Enduro will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.
The following is a summary of certain existing environmental, health and safety laws and regulations to which Enduro’s business operations are subject.
Hazardous substance and wastes. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Enduro generates materials in the course of its operations that may be regulated as hazardous substances.
The Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, production and development of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes (“E&P Wastes”) now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA to request reconsideration of the exemption of E&P Wastes from regulation as hazardous waste under RCRA (which could also affect E&P Wastes’ regulation under other environmental laws, including CERCLA). In May 2016, several environmental groups sued the EPA for failing to update its rules for the management of wastes from oil and gas exploration and production under RCRA. In December 2016, the court entered a consent decree that resolved the litigation and under which EPA must propose, by no later than March 15, 2019, revisions to the rules for management of oil and gas exploration and production wastes, or sign a determination that a revision of the rules is not necessary. The consent decree further obligates EPA to take final action on any such proposed rule changes no later than July 15, 2021. Any such change could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the Trust unitholders. In addition, Enduro generates industrial wastes in the ordinary course of its operations that may be regulated as hazardous wastes.
The properties upon which Enduro conducts its operations have been used for oil and natural gas exploration and production for many years. Although Enduro may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released at or from the real properties upon which Enduro conducts its operations, or at or from other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, the properties upon which Enduro conducts its operations may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under Enduro’s control. These properties and the petroleum hydrocarbons and wastes disposed or released at or from these properties may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Enduro could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.
Water discharges. The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into “waters of the United States” is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The term “waters of the United States” has been broadly defined to include certain inland water bodies, including certain wetlands and intermittent streams. The EPA issued a final rule in May 2015 that attempts to clarify the federal jurisdictional reach over waters of the United States, but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In February 2017, President Trump issued an Executive Order directing the EPA Administrator to review the “waters of the United States” rule and to publish for notice and comment a proposed rule rescinding or revising the rule. EPA proposed to rescind the May 2015 rule in June 2017, and in February 2018, EPA promulgated a final rule that delays the implementation of the May 2015 rule until February 2020, to provide EPA and the Army Corps of Engineers time to reconsider the definition of “waters of the United States.” There is uncertainty regarding the fate of the “waters of the United States” rule, and the outcome of the rule may impact permitting and spill reporting requirements for Enduro’s business operations.
Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure (“SPCC”) plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. In June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities from sending wastewater directly to publicly owned treatment works (“POTWs”). Unconventional oil and gas extraction facilities can send wastewater to a private wastewater treatment facility that can either discharge treated wastewater or send it to a POTW. EPA is conducting a related study of treatment of oil and gas extraction wastewater at private wastewater treatment facilities. This restriction of disposal options for hydraulic fracturing waste and other changes to Clean Water Act requirements may result in increased costs to Enduro. In addition, naturally occurring radioactive material (“NORM”) is brought to the surface in connection with oil and gas production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM.
The Oil Pollution Act of 1990, as amended, or OPA, amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.
Hydraulic fracturing. Various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formation to stimulate production of oil and natural gas. The U.S. Congress has considered legislation to amend the federal Safe Drinking Water Act (“SDWA”) to subject hydraulic fracturing operations to regulation under the SDWA’s Underground Injection Control Program and to require the disclosure of chemicals used in the hydraulic fracturing process. Any such legislation could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against companies. In addition, the federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. The Secretary of Energy Advisory Board published their ninety-day report that included a number of recommendations. In December 2016, the EPA issued a final report on the potential impacts of hydraulic fracturing on drinking water resources. The report did not find widespread, systematic impacts to drinking water from hydraulic fracturing; at the same time, the report acknowledged information gaps that limited EPA’s ability to fully assess the potential impacts to drinking water resources. In addition, as noted above, the EPA in June 2016 issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities from sending wastewater directly to POTWs. EPA is conducting a related study of oil and gas extraction wastewater at private wastewater treatment facilities. In March 2015, the federal Bureau of Land Management (“BLM”) released a final rule establishing new or more stringent standards for performing hydraulic fracturing operations on federal and tribal lands. Several states, trade groups and companies have challenged the legality of the BLM rule in federal court. On September 30, 2015, the U.S. District Court for the District of Wyoming issued a preliminary injunction, blocking BLM from enforcing the new rules nationwide, and on June 21, 2016, the court issued a final ruling striking down the BLM rule. While the U.S. Department of Interior initially has appealed the decision to the Tenth Circuit Court of Appeals. BLM announced in March 2017 that it intended to rescind the rule. On December 29, 2017, BLM published a final rule that rescinded the 2015 hydraulic fracturing rule.
On August 16, 2012 the EPA published final rules that extend New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) to certain exploration and production operations. The final rule requires the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response to some of these challenges, the EPA amended the rule to extend compliance dates for certain storage vessels, and may issue additional revised rules in response to additional such requests in the future. Only a portion of these new rules appear to affect our operations at this time by requiring new air emissions controls, equipment modification, maintenance, monitoring, recordkeeping and reporting. Although these new requirements will increase our operating and capital expenditures and it is possible that the EPA will adopt further regulation that could further increase our operating and capital expenditures, we do not currently expect such existing and new regulations will have a material adverse impact on our operations or financial results.
Some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances, including the disclosure of information regarding the substances used in the hydraulic fracturing process. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is regulated at the federal level, Enduro’s and the third party operators’ fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. In December 2014, the Governor of New York announced that the state would maintain its moratorium on hydraulic fracturing in the state. Further, some local governments, including in Texas, have imposed moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the Underlying Properties are located.
Air emissions. The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting and regulatory programs and also impose various monitoring and reporting requirements. These laws and regulations may require Enduro to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air emissions permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. In January 2015, the White House announced a goal to reduce methane emissions from the oil and gas sector by 40-45% from 2012 emission levels by 2025. In May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. In May 2016, the EPA also finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and gas sector. The EPA also announced in March 2016 that it intended to reduce methane emissions from existing oil and gas sources, with a proposed rule expected in 2017; however, in March 2017, EPA Administrator Pruitt formally withdrew the Information Collection Request (ICR) that EPA had issued as the initial step in developing methane rules for existing oil and gas sources. In 2017, the EPA also announced that it would convene a proceeding to reconsider parts of the oil and gas methane rule that applies to new, modified, and reconstructed sources, and published a proposed rule seeking to delay the implementation of key requirements of the rule for a period of two years. In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on federal and tribal lands. However, the BLM in 2017 announced that it would revisit its 2016 methane rule, and in December 2017 published a final rule to delay the implementation of key requirements of its 2016 methane rule until January 2019, including requirements relating to venting, flaring, and fugitive emissions losses from oil and gas production activities. While there is uncertainty regarding the ultimate fate of these recent regulatory developments affecting oil and gas operations, these requirements could increase the costs of development and production, reducing the profits available to the Trust and potentially impairing the economic development of the Underlying Properties. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.
Climate change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs,” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. If ratified, the Paris Agreement will take effect in 2020. The United States ratified the Paris Agreement in September 2016; however, the country’s future participation in the Paris Agreement is uncertain. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but that it may enter into a future international agreement related to GHGs. In August 2017, the State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The United States’ adherence to the exit process, as well as the terms on which the United States may reenter the Paris Agreement or a separately negotiated international GHG agreement, are unknown at this time.
Both houses of Congress have actively considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. Although it is not possible at this time to predict when Congress may pass climate change legislation, any future federal or state laws that may be adopted to address GHG emissions could require Enduro to incur increased operating costs and could adversely affect demand for the oil and natural gas Enduro produces.
The EPA has also taken regulatory action aimed at reducing GHG emissions. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment, which has allowed the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. For example, the EPA adopted regulations under Prevention of Significant Deterioration (“PSD”) and Title V permitting programs for GHG emissions from certain large stationary sources. In June 2014, the U.S. Supreme Court held that GHG emissions alone cannot trigger an obligation to obtain a federal air permit, but the Court upheld EPA’s authority to regulate GHG emissions from major stationary sources where emissions of traditional criteria pollutants exceed federal permitting thresholds. In November 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. These requirements became applicable in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future. And, as noted above, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and gas sector in May 2016, though the EPA announced in 2017 that it would reconsider the oil and gas methane rule, and subsequently proposed to delay the implementation of the oil and gas methane rule for a period of two years.
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact Enduro’s operations. In addition to these regulatory developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase Enduro’s litigation risk for such claims. The adoption of any future regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the equipment and operations of Enduro could require Enduro to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with its operations, and such requirements also could adversely affect demand for the oil and natural gas that Enduro produces.
Legislation or regulations that may be adopted to address climate change could also affect the markets for Enduro’s products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with higher greenhouse gas emitting energy sources, Enduro’s products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. In August 2015, the EPA issued standards designed to limit GHG emissions from new power plants as well as the Clean Power Plan aimed at reducing GHG emissions from existing power plants. In February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending judicial review, and President Trump has been vocal in opposition to the Clean Power Plan. In October 2017, following a review directed by President Trump’s Energy Independence Executive Order, the EPA proposed to repeal the Clean Power Plan regulations. To the extent that its products are competing with lower greenhouse gas emitting energy, Enduro’s products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. Enduro cannot predict with any certainty at this time how these possibilities may affect its operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by Enduro or otherwise cause Enduro to incur significant costs in preparing for or responding to those effects.
National Environmental Policy Act. Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay the development of oil and natural gas projects.
Endangered Species Act. The federal Endangered Species Act restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause Enduro to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. For example, as a result of a settlement reached in 2011, the U.S. Fish and Wildlife Services has published a work plan for listing more than 450 species as endangered or threatened over the next several years.
Employee health and safety. The operations of Enduro are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.
Where You Can Find Other Information
We maintain a website at http://www.enduroroyaltytrust.com. The Trust’s filings under the Exchange Act are available at our website and are also available electronically from the website maintained by the SEC at http://www.sec.gov. In addition, the Trust will provide electronic copies of its recent filings free of charge to the Trust unitholders upon request to the Trustee.
Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the Trust and cash distributions to unitholders.
The Trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and Enduro. These factors include, among others:
· regional, domestic and foreign supply and perceptions of supply of oil and natural gas;
· the level of demand and perceptions of demand for oil and natural gas;
· political conditions or hostilities in oil and natural gas producing regions;
· anticipated future prices of oil and natural gas and other commodities;
· weather conditions and seasonal trends;
· technological advances affecting energy consumption and energy supply;
· U.S. and worldwide economic conditions;
· the price and availability of alternative fuels;
· the proximity, capacity, cost and availability of gathering and transportation facilities;
· the volatility and uncertainty of regional pricing differentials;
· governmental regulations and taxation;
· energy conservation and environmental measures; and
· acts of force majeure.
Lower oil and natural gas prices will reduce profits to which the Trust is entitled and may ultimately reduce the amount of oil and natural gas that is economically viable to produce from the Underlying Properties. As a result, the operators of the Underlying Properties could determine during periods of low commodity prices to shut-in or curtail production from wells on the Underlying Properties, or even plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, an operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the Net Profits Interest relating to the abandoned well or property.
The Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, decreasing commodity prices may cause the expenses of certain wells to exceed the well’s revenue, in which case the operator may decide to shut-in the well or plug and abandon the well. This scenario could reduce future cash distributions to Trust unitholders.
Enduro has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced, and the terms of the Conveyance of the Net Profits Interest prohibit Enduro from entering into new hedging arrangements burdening the Trust. As a result, all production in which the Trust has an interest is unhedged, and the amount of the cash distributions is subject to the possibility of greater fluctuations due to changes in oil and natural gas prices.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust Units.
The value of the Trust Units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the reserves and future production estimated to be attributable to the Trust’s interest in the Underlying Properties. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary both positively and negatively and in material amounts from estimates. Furthermore, direct operating expenses and development expenses relating to the Underlying Properties could be substantially higher than current estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:
· historical production from the area compared with production rates from other producing areas;
· oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and development expenses; and
· the assumed effect of expected governmental regulation and future tax rates.
Changes in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties may decrease in the future as a result of future decreases in the price of oil or natural gas.
The reserve report estimating the Trust’s proved reserves, future production and income attributable to the Trust’s interests in the Underlying Properties as of December 31, 2017 was prepared, in accordance with applicable regulations, using an average of the NYMEX first-day-of-the-month commodity price during the 12-month period ending on December 31, 2017 as required by the SEC. The applicable prices for 2017 were $51.34 per Bbl of oil and $2.98 per Mcf of natural gas.
Third party operators are the operators of substantially all of the wells on the Underlying Properties and, therefore, Enduro is not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
As of December 31, 2017, substantially all of the wells on the Underlying Properties were operated by third party operators. As a result, Enduro has limited ability to exercise influence over, and control the risks or costs associated with, the operations of these properties. The failure of a third party operator to adequately or efficiently perform operations, a third party operator’s breach of the applicable operating agreements or a third party operator’s failure to act in ways that are in Enduro’s or the Trust’s best interests could reduce production and revenues. Further, none of the third party operators of the Underlying Properties is obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. The success and timing of drilling and development activities on properties operated by the third party operators, therefore, depends on a number of factors that will be largely outside of Enduro’s control, including:
· the timing and amount of capital expenditures, which could be significantly more than anticipated;
· the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
· the third party operators’ expertise, operating efficiency and financial resources;
· approval of other participants in drilling wells;
· the selection of technology;
· the selection of counterparties for the sale of production; and
· the rate of production of the reserves.
The third party operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in capital expenditures and amounts available for distribution to Trust unitholders.
Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to Trust unitholders.
The process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous risks beyond the Trust’s, Enduro’s and the third party operators’ control, including risks that could delay the operators’ current drilling or production schedule and the risk that drilling will not result in commercially viable oil or natural gas production. The ability of the operators to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:
· reductions in oil or natural gas prices;
· delays imposed by or resulting from compliance with regulatory requirements, including permitting;
· unusual or unexpected geological formations;
· shortages of or delays in obtaining equipment and qualified personnel;
· lack of available gathering facilities or delays in construction of gathering facilities;
· lack of available capacity on interconnecting transmission pipelines;
· equipment malfunctions, failures or accidents;
· unexpected operational events and drilling conditions;
· market limitations for oil or natural gas;
· pipe or cement failures;
· casing collapses;
· lost or damaged drilling and service tools;
· loss of drilling fluid circulation;
· uncontrollable flows of oil and natural gas, inert gas, water or drilling fluids;
· fires and natural disasters;
· environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases;
· adverse weather conditions; and
· oil or natural gas property title problems.
If planned operations, including drilling of development wells, are delayed or cancelled, or if existing wells or development wells experience production below anticipated levels due to one or more of the foregoing factors or for any other reason, estimated future distributions to Trust unitholders may be reduced. If an operator incurs increased costs due to one or more of the foregoing factors or for any other reason and is unable to recover such costs from insurance, estimated future distributions to Trust unitholders may be reduced.
The Trust is passive in nature and neither the Trust nor the Trust unitholders have any ability to influence Enduro or control the operations or development of the Underlying Properties.
The Trust Units are a passive investment that entitles the Trust unitholder to only receive cash distributions from the Net Profits Interest. Trust unitholders have no voting rights with respect to Enduro and, therefore, have no managerial, contractual or other ability to influence Enduro’s or the third party operators’ activities or the operations of the Underlying Properties. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. Third party operators operate substantially all of the wells on the Underlying Properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property.
Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the Trust unitholders.
The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability of the operators of the Underlying Properties to conduct the operations which they currently have planned for the Underlying Properties, which would reduce the amount of cash received by the Trust and available for distribution to the Trust unitholders.
The Trust Units may lose value as a result of title deficiencies with respect to the Underlying Properties.
Enduro acquired the Underlying Properties through various acquisitions in late 2010 and early 2011. The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interest and the distributions to Trust unitholders. Enduro does not obtain title insurance covering mineral leaseholds, and Enduro’s failure to cure any title defects may cause Enduro to lose its rights to production from the Underlying Properties. In the event of any such material title problem, profits available for distribution to Trust unitholders and the value of the Trust Units may be reduced.
Enduro may transfer all or a portion of the Underlying Properties at any time without Trust unitholder consent, subject to specified limitations.
Enduro may at any time transfer all or part of the Underlying Properties, subject to and burdened by the Net Profits Interest, and may, along with the third party operators, abandon individual wells or properties reasonably believed to be not economically viable. Trust unitholders will not be entitled to vote on any transfer or abandonment of the Underlying Properties, and the Trust will not receive any profits from any such transfer, except in the limited circumstances when the Net Profits Interest is released in connection with such transfer, in which case the Trust will receive an amount equal to the fair market value (net of sales costs) of the Net Profits Interest released. Following any sale or transfer of any of the Underlying Properties, if the Net Profits Interest is not released in connection with such sale or transfer, the Net Profits Interest will continue to burden the transferred property and net profits attributable to such property will be calculated as part of the computation of net profits. Enduro may delegate to the transferee responsibility for all of Enduro’s obligations relating to the Net Profits Interest on the portion of the Underlying Properties transferred.
In addition, Enduro may, without the consent of the Trust unitholders, require the Trust to release the Net Profits Interest associated with any lease that accounts for 0.25% or less of the total production from the Underlying Properties in the prior 12 months and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by Enduro to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair market value of such Net Profits Interest being treated as an offset amount against costs and expenses. Enduro has not identified for sale any of the Underlying Properties.
The third party operators and Enduro may enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval of the Trustee or any Trust unitholder.
On January 12, 2018, Enduro launched a process to sell all its oil and natural gas assets, including the Underlying Properties and its Trust Units. The Underlying Properties are being sold subject to the Trust’s 80% Net Profits Interest. If the sales process relating to the Underlying Properties is successful, Enduro expects the new owner to assume Enduro’s obligations as the sponsor of the Trust. There can be no assurances that Enduro’s sales process will be successful, in whole or in part, or that the new owner of working interests in the Underlying Properties will perform its obligations as sponsor of the Trust in a manner comparable to Enduro.
The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the Trust and cash distributions to Trust unitholders will decrease over time.
The profits payable to the Trust attributable to the Net Profits Interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties will decline over time.
Future maintenance projects on the Underlying Properties may affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties. The timing and size of these projects will depend on, among other factors, the market prices of oil and natural gas. Neither Enduro nor, to Enduro’s knowledge, the third party operators have a contractual obligation to develop or otherwise pay development expenses on the Underlying Properties in the future. Furthermore, with respect to properties for which Enduro is not designated as the operator, Enduro has limited control over the timing or amount of those development expenses. Enduro also has the right to non-consent and not participate in the development expenses on properties for which it is not the operator, in which case Enduro and the Trust will not receive the production resulting from such development expenses. If the operators of the Underlying Properties do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by Enduro or estimated in the reserve report.
The Trust Agreement provides that the Trust’s activities are limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the Conveyance related to the Net Profits Interest. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the Net Profits Interest.
Because the net profits payable to the Trust are derived from the sale of depleting assets, the portion of the distributions to Trust unitholders attributable to depletion may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the Underlying Properties burdened by the Net Profits Interest may cease to produce in commercially paying quantities and the Trust may, therefore, cease to receive any distributions of net profits therefrom. At that point the value of the Trust Units should be expected to be $0.
An increase in the differential between the price realized by Enduro for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the profits to the Trust and, therefore, the cash distributions by the Trust and the value of Trust Units.
The prices received for Enduro’s oil and natural gas production usually fall below the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. Enduro cannot accurately predict oil or natural gas differentials. Increases in the differential between the realized price of oil and natural gas and the benchmark price for oil and natural gas could reduce the profits to the Trust, the cash distributions by the Trust and the value of the Trust Units.
The amount of cash available for distribution by the Trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the Trust.
The Trust will indirectly bear an 80% share of all costs and expenses related to the Underlying Properties, such as direct operating and development expenses, which will reduce the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Accordingly, higher costs and expenses related to the Underlying Properties will directly decrease the amount of cash received by the Trust in respect of its Net Profits Interest. Historical costs may not be indicative of future costs. For example, the third party operators may in the future propose additional drilling projects that significantly increase the capital expenditures associated with the Underlying Properties, which could reduce cash available for distribution by the Trust. In addition, cash available for distribution by the Trust will be further reduced by the Trust’s general and administrative expenses.
If direct operating and development expenses on the Underlying Properties together with the other costs exceed gross profits of production from the Underlying Properties, the Trust will not receive net profits from those properties until future gross profits from production exceed the total of the excess costs, plus accrued interest at the prime rate. If the Trust does not receive net profits pursuant to the Net Profits Interest, or if such net profits are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs.
The generation of profits for distribution by the Trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.
The amount of oil and natural gas that may be produced and sold from a well is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, the operators of the Underlying Properties are provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If the operators of the Underlying Properties are forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of profits from the sale of production.
The Trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.
The Trustee must sell the Net Profits Interest and dissolve the Trust if the holders of at least 75% of the outstanding Trust Units approve the sale or vote to dissolve the Trust. The Trustee must also sell the Net Profits Interest and dissolve the Trust if the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years. The net profits of any such sale will be distributed to the Trust unitholders.
Enduro may sell Trust Units in the public or private markets, and such sales could have an adverse impact on the trading price of the Trust Units.
Enduro holds an aggregate of 8,600,000 Trust Units. Enduro may sell Trust Units in the public or private markets, and any such sales could have an adverse impact on the price of the Trust Units. The Trust has granted registration rights to Enduro, which, if exercised, would facilitate sales of Trust Units by Enduro.
The trading price for the Trust Units may not reflect the value of the Net Profits Interest held by the Trust.
The trading price for publicly traded securities similar to the Trust Units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust will vary in response to numerous factors outside the control of the Trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development expenses. Consequently, the market price for the Trust Units may not necessarily be indicative of the value that the Trust would realize if it sold the Net Profits Interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid with respect to the Trust Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the Trust unitholder.
Conflicts of interest could arise between Enduro and its affiliates, on the one hand, and the Trust and the Trust unitholders, on the other hand.
As working interest owners in, and the operators of certain wells on, the Underlying Properties, Enduro and its affiliates could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
· Enduro’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the Underlying Properties for which Enduro acts as the operator. Enduro may also make decisions with respect to development expenses that adversely affect the Underlying Properties. These decisions include reducing development expenses on properties for which Enduro acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.
· Enduro may sell some or all of the Underlying Properties without taking into consideration the interests of the Trust unitholders. Such sales may not be in the best interests of the Trust unitholders. These purchasers may lack Enduro’s experience or its creditworthiness. Enduro also has the right, under certain circumstances, to cause the Trust to release all or a portion of the Net Profits Interest in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interest relates. In such an event, the Trust is entitled to receive the fair value (net of sales costs) of the Net Profits Interest released.
· Enduro may sell its Trust Units without considering the effects such sale may have on Trust Unit prices or on the Trust itself. Additionally, Enduro can vote its Trust Units in its sole discretion without considering the interests of the other Trust unitholders. Enduro is not a fiduciary with respect to the Trust unitholders or the Trust and does not owe any fiduciary duties or liabilities to the Trust unitholders or the Trust.
The Trust is administered by a Trustee who cannot be replaced except by a majority vote of the Trust unitholders at a special meeting which may make it difficult for Trust unitholders to remove or replace the Trustee.
The affairs of the Trust are administered by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the Trust Units present in person or by proxy at a meeting of such holders where a quorum is present, including Trust Units held by Enduro, called by either the Trustee or the holders of not less than 10% of the outstanding Trust Units. As a result, it will be difficult for public Trust unitholders to remove or replace the Trustee without the cooperation of holders of a significant percentage of total Trust Units.
Trust unitholders have limited ability to enforce provisions of the Net Profits Interest, and Enduro’s liability to the Trust is limited.
The Trust Agreement permits the Trustee to sue Enduro or any other future owner of the Underlying Properties to enforce the terms of the Conveyance creating the Net Profits Interest. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, Trust unitholders’ recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder’s ability to directly sue Enduro or any other third party other than the Trustee. As a result, Trust unitholders will not be able to sue Enduro or any future owner of the Underlying Properties to enforce these rights. Furthermore, the Conveyance provides that, except as set forth in the Conveyance, Enduro will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of corporations for profit under the General Corporation Law of the State of Delaware. The courts in jurisdictions outside of Delaware, however, might not give effect to such limitation.
The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.
The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that apply to the operations on the Underlying Properties, including the requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use; the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. For example, the EPA has published regulations that impose more stringent emissions control requirements for oil and gas development and production operations, which may require us, our operators, or third-party contractors to incur additional expenses to control air emissions from current operations and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other requirements. In January 2015, the White House announced a goal to reduce methane emissions from the oil and gas sector by 40-45% from 2012 emission levels by 2025. In May 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and gas sector. The EPA also announced in March 2016 that it intended to reduce methane emissions for existing sources. In 2017, however, the EPA signaled a different approach regarding methane emissions from oil and gas sources, withdrawing the Information Collection Request (ICR) that EPA had issued as the initial step in developing methane rules for existing oil and gas sources, announcing the reconsideration of the 2016 rule establishing methane standards for new, modified, and reconstructed oil and gas sources, and proposing a two-year delay in the implementation of the new source methane rule. In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on federal and tribal lands. In 2017, however, the BLM announced that it would revisit its 2016 methane rule, and then published a final rule that delays implementation of key emissions control requirements from its 2016 methane rule until January 2019. While there is uncertainty regarding the fate of the recent federal rules aimed at reducing emissions from oil and gas operations, oil and gas exploration and production activities remain subject to many federal, state, and local pollution control requirements. These requirements could increase the costs of development and production, reducing the profits available to the Trust and potentially impairing the economic development of the Underlying Properties. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often times requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and gas wastes, could impair the operators’ ability to produce oil and natural gas commercially from the Underlying Properties, which would reduce profits attributable to the Net Profits Interest.
There is inherent risk of incurring significant environmental costs and liabilities in the operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the operators could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether such operators were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the operators of the Underlying Properties to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations and could reduce the amount of cash available for distribution to Trust unitholders. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require the operators of the Underlying Properties to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.
The Trust will indirectly bear 80% of all costs and expenses paid by Enduro, including those related to environmental compliance and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to Enduro’s acquisition of the Underlying Properties unless such costs and expenses result from the operator’s negligence or misconduct. In addition, as a result of the increased cost of compliance, the operators of the Underlying Properties may decide to discontinue drilling.
Neither Enduro nor the Trust is generally entitled to, nor required to provide, indemnity to third party operators with respect to pollution liability and associated environmental remediation costs. However, Enduro may be required to provide, and may be entitled to, indemnity from third party operators with respect to such liabilities and costs in the event of the other party’s gross negligence or misconduct. In addition, Enduro has agreed to assume certain environmental liabilities of prior owners of the Underlying Properties in connection with the purchase thereof.
The amount of cash available for distribution by the Trust could be reduced by expenses caused by uninsured claims.
Enduro maintains insurance coverage against potential losses that it believes is customary in its industry. Enduro currently maintains general liability insurance and excess liability coverage. Enduro’s excess liability coverage and general liability insurance do not have deductibles. The general liability insurance covers Enduro and its subsidiaries for legal and contractual liabilities arising out of bodily injury or property damage, including any resulting loss of use to third parties, and for sudden and accidental pollution or environmental liability, while the excess liability coverage is in addition to and triggered if the general liability per occurrence limit is reached. In addition, Enduro maintains control of well insurance with per occurrence limits depending on the status of the well and deductibles consistent with industry standards. Enduro’s general liability insurance and excess liability policies do not provide coverage with respect to legal and contractual liabilities of the Trust, and the Trust does not maintain such coverage since it is passive in nature and does not have any ability to influence Enduro or control the operations or development of the Underlying Properties. However, the Trust unitholders may indirectly benefit from Enduro’s insurance coverage to the extent that insurance proceeds offset or reduce any costs or expenses that are deducted when calculating the net profits attributable to the Trust.
Enduro does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, Enduro believes its general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations in accordance with, and subject to, the terms of such policies. These policies may not cover fines, penalties or costs and expenses related to government-mandated cleanup of pollution. In addition, these policies do not provide coverage for all liabilities, and there can be no assurance that the insurance coverage will be adequate to cover claims that may arise or that Enduro will be able to maintain adequate insurance at rates it considers reasonable. The occurrence of an event not fully covered by insurance could result in a significant decrease in the amount of cash available for distribution by the Trust.
The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.
The production and development operations on the Underlying Properties are subject to complex and stringent laws and regulations. To conduct their operations in compliance with these laws and regulations, the operators of the Underlying Properties must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. The operators of the Underlying Properties may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, and the Trust will bear an 80% share of these costs. In addition, the operators’ costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to their operations. Such costs could have a material adverse effect on the operators’ business, financial condition and results of operations and reduce the amount of cash received by the Trust in respect of the Net Profits Interest. The operators of the Underlying Properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of the Underlying Properties are shippers on interstate pipelines, they must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity, and such compliance costs will be borne in part by the Trust.
Laws and regulations governing exploration and production may also affect production levels. The operators of the Underlying Properties are required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of the operators and third party downstream natural gas transporters. These and other laws and regulations can limit the amount of oil and natural gas the operators can produce from their wells, limit the number of wells they can drill, or limit the locations at which they can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.
New laws or regulations, or changes to existing laws or regulations, may unfavorably impact the operators of the Underlying Properties and result in increased operating costs or have a material adverse effect on their financial condition and results of operations and reduce the amount of cash received by the Trust. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations could increase the operating costs of the Underlying Properties, reduce the operators’ liquidity, delay the operators’ operations or otherwise alter the way the operators conduct their business, any of which could have a material adverse effect on the Trust and the amount of cash available for distribution to Trust unitholders.
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause them to incur significant costs in preparing for or responding to those effects.
The oil and gas industry is a direct source of certain greenhouse gas (“GHG”) emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact future operations on the Underlying Properties. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and other climate changes. Based on these findings, the agency has begun adopting and implementing regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted rules that regulate emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs.
On June 23, 2014, the U.S. Supreme Court held that greenhouse gas emissions alone cannot trigger an obligation to obtain an air permit. However, the Supreme Court upheld EPA’s authority to regulate GHG emissions from stationary sources, concluding sources that trigger air permitting requirements based on their traditional criteria pollutant emissions must include a limit for greenhouse gases in their permit. These EPA rules could affect the operations on the Underlying Properties or the ability of the operators of the Underlying Properties to obtain air permits for new or modified facilities.
In addition, in November 2010, the EPA published final regulations expanding the existing greenhouse gas monitoring and reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution facilities. These requirements became applicable in 2012 for emissions occurring in 2011. In early 2014, President Obama announced the “Climate Action Plan,” a broad-based plan designed to cut carbon pollution. A major focus of that plan is methane emission reductions. In January 2015, the White House announced a goal to reduce methane emissions from the oil and gas sector by 40-45% from 2012 emission levels by 2025. In May 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and gas sector. The EPA also announced in March 2016 that it intended to reduce methane emissions for existing sources. In 2017, however, the EPA signaled a different approach regarding methane emissions from oil and gas sources, withdrawing the Information Collection Request (ICR) that EPA had issued as the initial step in developing methane rules for existing oil and gas sources, announcing the reconsideration of the 2016 rule establishing methane standards for new, modified, and reconstructed oil and gas sources, and proposing a two-year delay in the implementation of the new source methane rule. In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on federal and tribal lands. In 2017, however, the BLM announced that it would revisit its 2016 methane rule, and then published a final rule that delays implementation of key emissions control requirements from its 2016 methane rule until January 2019. While there is uncertainty regarding the fate of the recent federal rules aimed at reducing emissions from oil and gas operations, oil and gas exploration and production activities, the Underlying Properties may be subject to these requirements or become subject to them in the future.
In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from the equipment or operations of the operators of the Underlying Properties could require the operators to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with their operations. Such requirements could also adversely affect demand for the oil and natural gas produced, all of which could reduce profits attributable to the Net Profits Interest and, as a result, the Trust’s cash available for distribution.
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact the operators of the Underlying Properties and the Trust.
Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the operators’ assets and operations and, consequently, may reduce profits attributable to the Net Profits Interest and, as a result, the Trust’s cash available for distribution.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing. In December 2016, the EPA issued a final report on the potential impacts of hydraulic fracturing on drinking water resources. The report did not find widespread, systematic impacts to drinking water from hydraulic fracturing; at the same time, the report acknowledged information gaps that limited EPA’s ability to fully assess the potential impacts to drinking water resources.
On August 16, 2012 the EPA published final rules that extend New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPs) to certain exploration and production operations. The final rule requires the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed or refractured after January 1, 2015. In response to some requests for reconsideration and challenges, EPA has amended the rule to extend compliance dates for certain storage vessels, and may issue additional revised rules in response to additional such requests in the future. In March 2015, the BLM released a final rule establishing new or more stringent standards for performing hydraulic fracturing operations on federal and tribal lands. Several states, trade groups and companies have challenged the legality of the BLM rule in federal court. On September 30, 2015, the U.S. District Court for the District of Wyoming issued a preliminary injunction, blocking BLM from enforcing the new rules nationwide, and on June 21, 2016, the court issued a final ruling striking down the BLM rule. While the U.S. Department of Interior initially appealed the decision to the Tenth Circuit Court of Appeals, BLM announced in March 2017 that it intended to rescind the rule. On December 29, 2017, BLM published a final rule that rescinded its 2015 hydraulic fracturing rule. While the ultimate fate of the recent EPA and BLM rules regulating hydraulic fracturing operations is unclear, it is possible that new requirements associated with the rules will increase operating and capital expenditures, and that the EPA or the BLM will adopt further regulation that could further increase operating and capital expenditures, it is not currently expected that such existing and new regulations will have a material adverse impact on operations or financial results.
Some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances, including the disclosure of information regarding the substances used in the hydraulic fracturing process. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is regulated at the federal level, Enduro’s and the third party operators’ fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. In December 2014, the Governor of New York announced that the state would maintain its moratorium on hydraulic fracturing in the state. Further, some local governments, including in Texas, have imposed moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. Similar measures might be considered or implemented in the jurisdictions in which the Underlying Properties are located.
If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in Texas, Louisiana or New Mexico, such legal requirements could make it more difficult or costly for Enduro or the third party operators to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that the operators are ultimately able to produce in commercially paying quantities from the Underlying Properties, and could increase the cycle times and costs to receive permits, delay or possibly preclude receipt of permits in certain areas, impact water usage and waste water disposal and require air emissions, water usage and chemical additives disclosures.
Enduro’s ability to perform its obligations to the Trust could be limited by restrictions under its debt agreements.
Enduro has various contractual obligations to the Trust under the Trust Agreement and Conveyance. Restrictions under Enduro’s debt agreements, including certain covenants, financial ratios and tests, could impair its ability to fulfill its obligations to the Trust. The requirement that Enduro comply with these restrictive covenants and financial ratios and tests may materially adversely affect its ability to react to changes in market conditions, take advantage of business opportunities it believes to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in its business which may, in turn, impair Enduro’s operations and its ability to perform its obligations to the Trust under the Trust Agreement and Conveyance. If Enduro is unable to perform its obligations to the Trust under the Trust Agreement or Conveyance, it could have a material adverse effect on the Trust.
The bankruptcy of Enduro or any of the third party operators could impede the operation of the wells and the development of the proved undeveloped reserves.
The value of the Net Profits Interest and the Trust’s ultimate cash available for distribution will be highly dependent on the financial condition of the operators of the Underlying Properties. None of the operators of the Underlying Properties, including Enduro, has agreed with the Trust to maintain a certain net worth or to be restricted by other similar covenants.
The ability to develop and operate the Underlying Properties depends on the future financial condition and economic performance and access to capital of the operators of those properties, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of Enduro and the third party operators. Enduro is not a reporting company and is not required to file periodic reports with the SEC pursuant to the Exchange Act. Therefore, as a Trust unitholder, you do not have access to financial information about Enduro.
In the event of the bankruptcy of an operator of the Underlying Properties, the working interest owners in the affected properties will have to seek a new party to perform the development and the operations of the affected wells. The working interest owners may not be able to find a replacement driller or operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time. As a result, such a bankruptcy may result in reduced production from the reserves and decreased distributions to Trust unitholders.
In the event of the bankruptcy of Enduro, if a court were to hold that the Net Profits Interest was part of the bankruptcy estate, the Trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico.
Enduro and the Trust believe that, in a bankruptcy of Enduro, the Net Profits Interest would be viewed as a separate property interest under Texas law and, as such, outside of Enduro’s bankruptcy estate. However, to the extent that were not the case, or to the extent Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of Enduro, in which case the Trust would be an unsecured creditor of Enduro at risk of losing the entire value of the Net Profits Interest to senior creditors.
Adverse developments in Texas, Louisiana or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to Trust unitholders.
The operations of the Underlying Properties are focused on the production and development of oil and natural gas within the states of Texas, Louisiana and New Mexico. As a result, the results of operations and cash flows of the Underlying Properties depend upon continuing operations in these areas. This concentration could disproportionately expose the Trust’s interests to operational and regulatory risk in these areas. Due to the lack of diversification in geographic location, adverse developments in exploration and production of oil and natural gas in any of these areas of operation could have a significantly greater impact on the results of operations and cash flows of the Underlying Properties than if the operations were more diversified.
TAX RISKS RELATED TO THE TRUST UNITS
The Trust has not requested a ruling from the IRS regarding the tax treatment of the Trust. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for U.S. federal income tax purposes, the Trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to Trust unitholders.
If the Trust were not treated as a grantor trust for U.S. federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to U.S. federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to Trust unitholders could be reduced as a result.
If the Trust were treated for U.S. federal income tax purposes as a partnership, it likely would be subject to new audit procedures that for taxable years beginning after December 31, 2017, alter the procedures for auditing large partnerships and also alter the procedures for assessing and collecting income taxes due (including applicable penalties and interest) as a result of an audit. These rules effectively would impose an entity level tax on the Trust, and unitholders may have to bear the expense of the adjustment even if they were not Trust unitholders during the audited taxable year.
Neither Enduro nor the Trustee has requested a ruling from the IRS regarding the tax status of the Trust, and neither Enduro nor the Trust can assure you that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.
Trust unitholders should be aware of the possible state tax implications of owning Trust Units.
You will be required to pay taxes on your share of the Trust’s income even if you do not receive any cash distributions from the Trust.
Trust unitholders are treated as if they own the Trust’s assets and receive the Trust’s income and are directly taxable thereon as if no Trust were in existence. Because the Trust will generate taxable income that could be different in amount than the cash the Trust distributes, unitholders will be required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust. Unitholders may not receive cash distributions from the Trust equal to their share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.
A portion of any tax gain on the disposition of the Trust Units could be taxed as ordinary income.
If a unitholder sells Trust Units, he or she will recognize a gain or loss equal to the difference between the amount realized and his or her tax basis in those Trust Units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture.
The Trust will allocate its items of income, gain, loss and deduction between transferors and transferees of the Trust Units each month based upon the ownership of the Trust Units on the monthly record date, instead of on the basis of the date a particular Trust Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust will generally allocate its items of income, gain, loss and deduction between transferors and transferees of the Trust Units each month based upon the ownership of the Trust Units on the monthly record date, instead of on the basis of the date a particular Trust Unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
Item 1B. Unresolved Staff Comments.
None.
Description of the Underlying Properties
The Underlying Properties consist of producing and non-producing interests in oil and natural gas units, wells and lands in Texas, Louisiana and New Mexico. The Underlying Properties include a portion of the assets in east Texas and north Louisiana acquired by Enduro from Denbury Resources Inc. in December 2010, and all of the assets in the Permian Basin of New Mexico and west Texas acquired by Enduro from Samson Investment Company and ConocoPhillips Company in January 2011 and February 2011, respectively. The Underlying Properties are divided into two geographic regions: the Permian Basin region and East Texas/North Louisiana region.
As of December 31, 2017, the Underlying Properties had proved reserves of 13.7 MMBoe and 99% of the volumes and PV-10 value were attributable to proved developed reserves. Substantially all of the 13.7 MMBoe of proved reserves, based on PV-10 value, were operated by third party operators.
Enduro’s interests in the Underlying Properties require Enduro to bear its proportionate share of the costs of development and operation of such properties. As of December 31, 2017, Enduro held average working interests of approximately 23% and 22% and average net revenue interests of approximately 20% and 16% in the Underlying Properties located in the Permian Basin and East Texas/North Louisiana regions, respectively. The Underlying Properties are also burdened by non-cost bearing interests owned by third parties consisting primarily of overriding royalty and royalty interests.
Reserves
Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), independent petroleum and geological engineers, estimated crude oil (including natural gas liquids) and natural gas proved reserves of the Underlying Properties’ full economic life and for the Trust life as of December 31, 2017. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates. In addition, the reserves and net revenues attributable to the Net Profits Interest include only 80% of the reserves attributable to the Underlying Properties that are expected to be produced within the term of the Net Profits Interest. The technical person primarily responsible for overseeing the preparation of the reserve estimates and the third party reserve reports is HC Lee, Enduro’s Director of Geology and Reservoir Engineering. Mr. Lee received a Bachelor of Science in Geological Oceanography from the University of Chinese Culture, Taipei, Taiwan and a Masters in Geology from the University of Arkansas. Mr. Lee has 35 years of experience in the energy industry with various responsibilities in exploration, operations, and acquisitions, including international experience in the Bohai Gulf and Jinhu Basin in China. He has structured transactions for farm-ins and joint ventures, and he was previously the joint owner of a company focused in the Delaware and Midland Basins of the Permian. Mr. Lee consults with Cawley Gillespie during the reserve estimation process to review properties, assumptions, and relevant data.
The independent petroleum engineer’s report as to the proved oil and natural gas reserves as of December 31, 2017 was prepared by Cawley Gillespie. Cawley Gillespie, whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical person at Cawley Gillespie primarily responsible for overseeing the reserve estimates with respect to the Underlying Properties and the Net Profits Interest attributable to the Trust is W. Todd Brooker. Mr. Brooker has been a petroleum consultant for Cawley Gillespie since 1992 and is currently the Senior Vice President. He is a registered professional engineer in the State of Texas (license no. 83462) and a graduate of the University of Texas with a Bachelor of Science in Petroleum Engineering.
Information concerning changes in net proved reserves attributable to the Trust, and the calculation of the standardized measure of the related discounted future net revenues is contained in the notes to the financial statements of the Trust included in this Form 10-K. Enduro has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.
The following table summarizes the estimated proved reserve quantities and PV-10 attributable to the Trust and Underlying Properties as of December 31, 2017 and 2016:
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Trust Net Profits Interest |
|
Underlying Properties |
| ||||||||||||||
|
|
|
Oil(1) |
|
Natural |
|
Total(2) |
|
PV-10(3) |
|
Oil(1) |
|
Natural |
|
Total(2) |
|
PV-10(3) |
| ||
|
|
|
(MBbls) |
|
(MMcf) |
|
(MBoe) |
|
(in thousands) |
|
(MBbls) |
|
(MMcf) |
|
(MBoe) |
|
(in |
| ||
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
Proved Developed Producing |
|
3,055 |
|
6,936 |
|
4,211 |
|
$ |
66,094 |
|
9,882 |
|
21,422 |
|
13,453 |
|
$ |
82,619 |
|
|
Proved Developed Non-Producing |
|
— |
|
14 |
|
2 |
|
30 |
|
1 |
|
38 |
|
7 |
|
37 |
| ||
|
Proved Undeveloped |
|
42 |
|
82 |
|
56 |
|
818 |
|
148 |
|
290 |
|
196 |
|
1,022 |
| ||
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
Proved Developed Producing |
|
2,515 |
|
5,694 |
|
3,464 |
|
$ |
43,860 |
|
7,452 |
|
16,197 |
|
10,152 |
|
$ |
54,826 |
|
|
Proved Developed Non-Producing |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
| ||
|
Proved Undeveloped |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
| ||
|
(1) |
Reserves for natural gas liquids are immaterial and included as a component of oil reserves. |
|
(2) |
Boe represents an approximate energy equivalent basis such that one Bbl of crude oil equals approximately six Mcf of natural gas. However, the value of oil and natural gas fluctuate and the value of reserve volumes of oil and natural gas are often substantially different than the amount implied by the Boe ratio. |
|
(3) |
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices, after adjustment for differentials in location and quality, for each of the preceding twelve months. An estimate of PV-10 is provided because it provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. PV-10 is considered relevant and useful for evaluating the relative monetary significance of oil and natural gas reserves. PV-10 is not intended to represent the current market value of the estimated reserves of the Underlying Properties. PV-10 differs from standardized measure of discounted future net cash flows because it does not include the effect of future income taxes. Please refer to the notes to the financial statements of the Trust included in this Form 10-K. |
Reserve quantities and revenues for the Net Profits Interest were estimated from projections of reserves and revenues attributable to the Underlying Properties. Since the Trust has a defined Net Profits Interest, the Trust does not own a specific percentage of the oil and natural gas reserve quantities. Accordingly, reserves allocated to the Trust pertaining to its 80% Net Profits Interest in the Underlying Properties have effectively been reduced to reflect recovery of the Trust’s 80% portion of applicable production and development costs. Because Trust reserve quantities are determined using an allocation formula, any changes in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the Net Profits Interest.
Estimates of proved reserves were prepared in accordance with guidelines prescribed by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the NYMEX first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements. Prices used in estimating reserves were as follows:
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Oil (per Bbl) |
|
$ |
51.34 |
|
$ |
42.75 |
|
$ |
50.28 |
|
|
Natural gas (per Mcf) |
|
$ |
2.98 |
|
$ |
2.48 |
|
$ |
2.59 |
|
Changes in Proved Undeveloped Reserves
During the year ended December 31, 2017, proved undeveloped reserves of the Underlying Properties increased 196 MBoe due to ongoing development in the Pecos Valley field in the Permian Basin of west Texas. During 2017, 3 gross (0.7 net) wells were drilled and as a result of an ongoing development program, 5 gross (1.2 net) wells were added as proved undeveloped reserves at December 31, 2017. The following is a summary of the changes in quantities of proved undeveloped reserves for the Underlying Properties during the year ended December 31, 2017:
|
|
|
Underlying Properties |
| ||||
|
|
|
Oil(1) |
|
Natural Gas |
|
Total |
|
|
|
|
(MBbls) |
|
(MMcf) |
|
(MBoe) |
|
|
Balance — December 31, 2016 |
|
— |
|
— |
|
— |
|
|
Development |
|
148 |
|
290 |
|
196 |
|
|
Revisions and Other |
|
— |
|
— |
|
— |
|
|
Balance — December 31, 2017 |
|
148 |
|
290 |
|
196 |
|
(1) Reserves for natural gas liquids are immaterial and included as a component of oil reserves.
Producing Acreage and Well Counts
For the following data, “gross” refers to the total number of wells or acres in the Underlying Properties and “net” refers to gross wells or acres multiplied by the percentage working interest owned by Enduro and in turn attributable to the Underlying Properties. All of the acreage comprising the Underlying Properties is held by production. Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.
The Underlying Properties are interests in properties located in the Permian Basin of west Texas and New Mexico and in the East Texas/North Louisiana region. The following is a summary of the approximate acreage of the Underlying Properties at December 31, 2017:
|
|
|
Acres |
| ||
|
|
|
Gross |
|
Net |
|
|
Permian Basin |
|
123,367 |
|
36,580 |
|
|
East Texas/North Louisiana |
|
12,629 |
|
4,899 |
|
|
Total |
|
135,996 |
|
41,479 |
|
The following is a summary of the producing wells on the Underlying Properties as of December 31, 2017:
|
|
|
Oil |
|
Natural Gas |
| ||||
|
|
|
Gross Wells(1) |
|
Net Wells |
|
Gross Wells(1) |
|
Net Wells |
|
|
Permian Basin |
|
3,489 |
|
326 |
|
80 |
|
10 |
|
|
East Texas/North Louisiana |
|
— |
|
— |
|
318 |
|
68 |
|
|
Total |
|
3,489 |
|
326 |
|
398 |
|
78 |
|
(1) Enduro’s total producing wells include 17 operated wells and 3,870 non-operated wells. At December 31, 2017, 155 of Enduro’s producing wells had multiple completions.
The following is a summary of the number of development and exploratory wells drilled on the Underlying Properties located in the Permian Basin and East Texas/North Louisiana during the last three years:
|
|
|
Year Ended December 31, |
| ||||||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| ||||||
|
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
|
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
8 |
|
1.3 |
|
9 |
|
0.9 |
|
2 |
|
0.1 |
|
|
Dry holes |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
|
|
8 |
|
1.3 |
|
9 |
|
0.9 |
|
2 |
|
0.1 |
|
|
Exploratory Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
Dry holes |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
|
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
8 |
|
1.3 |
|
9 |
|
0.9 |
|
2 |
|
0.1 |
|
|
Dry holes |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
|
|
8 |
|
1.3 |
|
9 |
|
0.9 |
|
2 |
|
0.1 |
|
|
|
|
Year Ended December 31, |
| ||||||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| ||||||
|
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
|
East Texas/North Louisiana |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
6 |
|
0.5 |
|
— |
|
— |
|
— |
|
— |
|
|
Dry holes |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
|
|
6 |
|
0.5 |
|
— |
|
— |
|
— |
|
— |
|
|
Exploratory Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
Dry holes |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
|
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
6 |
|
0.5 |
|
— |
|
— |
|
— |
|
— |
|
|
Dry holes |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
|
|
6 |
|
0.5 |
|
— |
|
— |
|
— |
|
— |
|
Major Producing Areas
Substantially all of the Underlying Properties are located in mature oil fields that are characterized by long production histories. Based on the reserve reports, approximately 73% of the future production from the Underlying Properties is expected to be oil and approximately 27% is expected to be natural gas.
Permian Basin Region
The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States. The Underlying Properties in the Permian Basin contain 123,367 gross (36,580 net) acres in Texas and New Mexico.
The largest fields in the Underlying Properties are located primarily in the Permian Basin (measured by Boe reserves at December 31, 2017). Each of the following fields individually account for more than 15 percent of the Underlying Properties reserves as of December 31, 2017.
· The largest field area in the Permian Basin region is the Eunice Monument field, which primarily consists of the North Monument Grayburg Unit. The North Monument Grayburg Unit was discovered in 1929. Proved reserves attributable to the Underlying Properties in the Eunice Monument area were 2.5 MMBoe as of December 31, 2017. The operators of the Eunice Monument area are Apache Corporation and XTO Energy.
· The second largest field in the Permian Basin region is the Lost Tank field operated by Occidental Petroleum. This unit produces from the Brushy Canyon and Wolfcamp formations at depths up to 8,500 feet. Proved reserves attributable to the Underlying Properties in the Lost Tank field were 2.3 MMBoe as of December 31, 2017.
The following table shows the average sales price and lease operating expenses for any field that individually accounted for more than 15 percent of the Underlying Properties’ reserves as of the end of the respective period. The figures presented for the largest fields in the Permian Basin of west Texas and New Mexico below relate to the amounts included in the net profits calculation for the distributions paid during the years ended December 31, 2017, 2016 and 2015.
|
|
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Eunice Monument Area |
|
Oil Average Sales Price per Bbl |
|
$ |
46.09 |
|
$ |
38.94 |
|
$ |
57.08 |
|
|
|
|
Natural Gas Average Sales Price per Mcf |
|
$ |
3.28 |
|
$ |
2.65 |
|
$ |
3.63 |
|
|
|
|
Average Lease Operating Expense per Boe |
|
$ |
17.86 |
|
$ |
18.53 |
|
$ |
19.43 |
|
|
|
|
|
|
|
|
|
|
|
| |||
|
Lost Tank |
|
Oil Average Sales Price per Bbl |
|
$ |
48.21 |
|
$ |
37.57 |
|
$ |
54.66 |
|
|
|
|
Natural Gas Average Sales Price per Mcf |
|
$ |
2.72 |
|
$ |
1.93 |
|
$ |
2.73 |
|
|
|
|
Average Lease Operating Expense per Boe |
|
$ |
4.46 |
|
$ |
4.72 |
|
$ |
4.42 |
|
East Texas/North Louisiana Region
The Underlying Properties contain interests in 12,629 gross (4,899 net) acres in the East Texas/North Louisiana region across three fields: the Elm Grove field, operated primarily by Aethon Energy Operating, LLC and BHP Billiton Ltd.; the Kingston field, operated by EXCO Resources and Indigo Resources, LLC; and the Stockman field, operated by Enduro. Substantially all proved reserves attributable to the Underlying Properties in the East Texas/North Louisiana region are located in the Haynesville, Cotton Valley, and Hosston reservoirs of the Elm Grove and Kingston fields. Proved reserves attributable to the Underlying Properties in the Elm Grove and Kingston fields were 1.6 MMBoe and 0.07 MMBoe, respectively, as of December 31, 2017.
Production and Reserves
The following table shows the net production, average sales price, average lease operating expense, and proved reserves as of year-end for the Underlying Properties located in the Permian Basin of west Texas and New Mexico and in the East Texas/North Louisiana region, which relates to the amounts included in the net profits calculation for the distributions paid during the years ended December 31, 2017, 2016 and 2015.
|
|
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Permian Basin |
|
Oil Sales Volumes (Bbls) |
|
617,894 |
|
791,459 |
|
891,320 |
| |||
|
|
|
Natural Gas(1) Sales Volumes (Mcf) |
|
1,865,321 |
|
2,503,998 |
|
2,613,003 |
| |||
|
|
|
Total Sales Volumes (Boe) |
|
928,781 |
|
1,208,792 |
|
1,326,820 |
| |||
|
|
|
Oil Average Sales Price per Bbl |
|
$ |
46.30 |
|
$ |
38.41 |
|
$ |
57.05 |
|
|
|
|
Natural Gas Average Sales Price per Mcf |
|
$ |
2.78 |
|
$ |
2.04 |
|
$ |
3.02 |
|
|
|
|
Average Lease Operating Expense per Boe |
|
$ |
19.06 |
|
$ |
16.59 |
|
$ |
19.62 |
|
|
|
|
Proved Reserves (MBoe) |
|
11,979 |
|
9,480 |
|
14,533 |
| |||
|
|
|
|
|
|
|
|
|
|
| |||
|
East Texas/North Louisiana |
|
Oil Sales Volumes (Bbls) |
|
3,922 |
|
4,937 |
|
6,078 |
| |||
|
|
|
Natural Gas(1) Sales Volumes (Mcf) |
|
1,320,851 |
|
1,993,351 |
|
2,289,232 |
| |||
|
|
|
Total Sales Volumes (Boe) |
|
224,064 |
|
337,162 |
|
387,617 |
| |||
|
|
|
Oil Average Sales Price per Bbl |
|
$ |
45.84 |
|
$ |
37.23 |
|
$ |
58.05 |
|
|
|
|
Natural Gas Average Sales Price per Mcf |
|
$ |
2.74 |
|
$ |
2.10 |
|
$ |
3.13 |
|
|
|
|
Average Lease Operating Expense per Boe |
|
$ |
8.40 |
|
$ |
7.03 |
|
$ |
9.69 |
|
|
|
|
Proved Reserves (MBoe) |
|
1,677 |
|
672 |
|
747 |
| |||
|
|
|
|
|
|
|
|
|
|
| |||
|
Total |
|
Oil Sales Volumes (Bbls) |
|
621,816 |
|
796,396 |
|
897,398 |
| |||
|
|
|
Natural Gas(1) Sales Volumes (Mcf) |
|
3,186,172 |
|
4,497,349 |
|
4,902,235 |
| |||
|
|
|
Total Sales Volumes (Boe) |
|
1,152,845 |
|
1,545,954 |
|
1,714,437 |
| |||
|
|
|
Oil Average Sales Price per Bbl |
|
$ |
46.29 |
|
$ |
38.40 |
|
$ |
57.06 |
|
|
|
|
Natural Gas Average Sales Price per Mcf |
|
$ |
2.76 |
|
$ |
2.07 |
|
$ |
3.07 |
|
|
|
|
Average Lease Operating Expense per Boe |
|
$ |
16.98 |
|
$ |
14.50 |
|
$ |
17.37 |
|
|
|
|
Proved Reserves (MBoe) |
|
13,656 |
|
10,152 |
|
15,281 |
| |||
(1) Production of natural gas liquids is immaterial and included as a component of natural gas production.
Abandonment and Sale of Underlying Properties
Each of the operators of the Underlying Properties or any transferee has the right to abandon its interest in any well or property if it reasonably believes a well or property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, the portion of the Net Profits Interest relating to the abandoned property will be extinguished.
Enduro generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interest, without the consent of the Trust unitholders. Following the sale of all or any portion of the Underlying Properties, the purchaser will be bound by the obligations of Enduro under the Trust Agreement and the Conveyance with respect to the portion sold. In addition, Enduro may, without the consent of the Trust unitholders, require the Trust to release the Net Profits Interest associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by Enduro to a non-affiliate of the relevant Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such Net Profits Interest. Enduro has not identified for sale any of the Underlying Properties.
Title to Properties
The properties comprising the Underlying Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens and obligations affect Enduro’s rights to production or the value of production from the Underlying Properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties.
Enduro’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject to one or more of the following:
· royalties and other burdens, express and implied, under oil and natural gas leases and other arrangements;
· overriding royalties, production payments and similar interests and other burdens created by Enduro’s predecessors in title;
· a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title;
· liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;
· pooling, unitization and communitization agreements, declarations and orders;
· easements, restrictions, rights-of-way and other matters that commonly affect property;
· conventional rights of reassignment that obligate Enduro to reassign all or part of a property to a third party if Enduro intends to release or abandon such property;
· preferential rights to purchase or similar agreements and required third party consents to assignments or similar agreements;
· obligations or duties affecting the Underlying Properties to any municipality or public authority with respect to any franchise, grant, license or permit, and all applicable laws, rules, regulations and orders of any governmental authority; and
· rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and also the interests held therein, including Enduro’s interests and the Net Profits Interest.
Enduro has informed the Trustee that Enduro believes the burdens and obligations affecting the properties comprising the Underlying Properties are conventional in the industry for similar properties. Enduro has also informed the Trustee that Enduro believes the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the Net Profits Interest or its value.
To give third parties notice of the Net Profits Interest, Enduro recorded the Conveyance in Texas, Louisiana and New Mexico in the real property records in each Texas, Louisiana or New Mexico county in which the Underlying Properties are located, or in such other public records of those states as required under applicable law to place third parties on notice of the Conveyance.
In a bankruptcy of Enduro, to the extent Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of Enduro, in which case the Trust would be an unsecured creditor of Enduro at risk of losing the entire value of the Net Profits Interest to senior creditors. See “Risk Factors—In the event of the bankruptcy of Enduro, if a court were to hold that the Net Profits Interest was part of the bankruptcy estate, the Trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico” in Item 1A of this Form10-K.
Enduro believes that its title to the Underlying Properties and the Trust’s title to the Net Profits Interest are each good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such Underlying Properties or Net Profits Interest. Under the terms of the Conveyance creating the Net Profits Interest, Enduro has provided a special warranty of title with respect to the Net Profits Interest, subject to the burdens and obligations described in this section. Please see “Risk Factors—The Trust Units may lose value as a result of title deficiencies with respect to the Underlying Properties” in Item 1A of this Form 10-K.
Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject. The foregoing does not address any legal proceedings to which Enduro or any of the third party operators may be a party or subject or that may otherwise relate to or affect any of the Underlying Properties or the operations of any of the operators of the Underlying Properties.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Market for Registrant’s Trust Units, Related Unitholder Matters and Issuer Purchases of Trust Units.
The Trust Units trade on the New York Stock Exchange under the symbol “NDRO.” The high and low sales prices and aggregate monthly distributions paid per unit for each quarter in 2017 and 2016 were as follows:
|
|
|
Price Range |
|
Distributions |
| |||||
|
Quarter |
|
High |
|
Low |
|
Paid |
| |||
|
2017 |
|
|
|
|
|
|
| |||
|
First Quarter |
|
$ |
3.98 |
|
$ |
3.20 |
|
$ |
0.067516 |
|
|
Second Quarter |
|
$ |
3.65 |
|
$ |
3.05 |
|
$ |
0.099122 |
|
|
Third Quarter |
|
$ |
4.45 |
|
$ |
3.20 |
|
$ |
0.035594 |
|
|
Fourth Quarter |
|
$ |
4.35 |
|
$ |
2.75 |
|
$ |
1.153649 |
|
|
2016 |
|
|
|
|
|
|
| |||
|
First Quarter |
|
$ |
3.79 |
|
$ |
1.77 |
|
$ |
0.083331 |
|
|
Second Quarter |
|
$ |
4.06 |
|
$ |
2.37 |
|
$ |
0.018150 |
|
|
Third Quarter |
|
$ |
3.83 |
|
$ |
3.19 |
|
$ |
0.058876 |
|
|
Fourth Quarter |
|
$ |
4.55 |
|
$ |
3.25 |
|
$ |
0.096803 |
|
At December 31, 2017, there were 33,000,000 Trust Units outstanding. On March 6, 2018, the closing sales price of the Trust Units as reported by the NYSE was $3.45 per unit, and there were four unitholders of record. This number does not include owners for whom Trust Units may be held in “street” name.
Distributions
Each month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s incurred expenses for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) are entitled to monthly distributions payable on or before the 10th business day after the record date (or the next succeeding business day). For further information on distributions to unitholders, see Note 7 of the Notes to Financial Statements in Item 8 of this Form 10-K.
Equity Compensation Plans
The Trust does not have any employees and does not maintain any equity compensation plans.
Recent Sales of Unregistered Securities
There were no equity securities sold by the Trust during the year ended December 31, 2017.
Purchases of Equity Securities
There were no purchases of Trust Units by the Trust or any affiliated purchaser during the fourth quarter of 2017.
Item 6. Selected Financial Data.
The following table sets forth selected financial data for the Trust for the years ended December 31, 2017, 2016 and 2015 and as of December 31, 2017, 2016 and 2015.
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Income from Net Profits Interest |
|
$ |
7,643,960 |
|
$ |
9,216,320 |
|
$ |
14,478,775 |
|
|
Income from sale of Net Profits Interest on undeveloped acreage |
|
$ |
36,300,165 |
|
$ |
— |
|
$ |
— |
|
|
Income from sale of Net Profits Interest on producing properties |
|
$ |
1,650,000 |
|
$ |
— |
|
$ |
— |
|
|
Distributable income |
|
$ |
44,744,073 |
|
$ |
8,486,280 |
|
$ |
13,768,821 |
|
|
Distributable income per unit |
|
$ |
1.355881 |
|
$ |
0.257160 |
|
$ |
0.417237 |
|
|
|
|
December 31, 2017 |
|
December 31, 2016 |
|
December 31, 2015 |
| |||
|
Trust corpus |
|
$ |
94,099,933 |
|
$ |
107,324,542 |
|
$ |
121,009,502 |
|
|
Trust Units outstanding |
|
33,000,000 |
|
33,000,000 |
|
33,000,000 |
| |||
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This discussion contains forward-looking statements. Please refer to “Forward-Looking Statements” for an explanation of these types of statements.
Overview
Enduro Royalty Trust, a statutory trust created in May 2011, completed its initial public offering in November 2011. The Trust’s only asset and source of income is the Net Profits Interest, which entitles the Trust to receive 80% of the net profits from oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties. Additionally, third parties operate substantially all of the wells on the Underlying Properties and, therefore, Enduro is not in a position to control the timing of development efforts, associated costs, or the rate of production of the reserves.
The Trust is required to make monthly cash distributions of substantially all of its monthly cash receipts, after deducting the Trust’s administrative expenses, to holders of record (generally the last business day of each calendar month) on or before the 10 th business day after the record date. The Net Profits Interest is entitled to a share of the profits from and after July 1, 2011 attributable to production occurring on or after June 1, 2011. The amount of Trust revenues and cash distributions to Trust unitholders depends on, among other things:
· oil and natural gas sales prices;
· volumes of oil and natural gas produced and sold attributable to the Underlying Properties;
· production and development costs;
· price differentials;
· potential reductions or suspensions of production;
· the amount and timing of Trust administrative expenses; and
· the establishment, increase, or decrease of reserves for approved development expenses or future liabilities of the Trust.
Generally, Enduro receives cash payment for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced.
2017 Recap and 2018 Outlook
Oil and natural gas prices declined significantly in the second half of 2014 and have remained lower than during the early life of the Trust, negatively impacting the fair value of the Net Profits Interest as well as revenues and distributable income available to unitholders. Further, depressed commodity pricing reduced development activity in 2015 and 2016, thereby hindering the ability to abate natural production declines on the Underlying Properties.
The average NYMEX oil price for the production months included in 2017 distributions increased 19% from the prior year, increasing oil revenues in 2017. Although NYMEX oil prices have increased to over $55 per Bbl, the continued depressed commodity price environment has and will continue to negatively affect the amount of cash flow available for distribution to the Trust unitholders in 2018.
As further discussed in Note 4 of the Notes to Financial Statements, in September 2017, Enduro completed the sale of certain properties in the Permian Basin and, in connection with the sale, the Trust released its 80% Net Profits Interest in the properties in exchange for 80% of the net proceeds of the sales. As a result of the divestiture, the Trust received $38.0 million in net proceeds and made a special distribution of $1.150005 per unit to Trust unitholders in October 2017. The proceeds received by the Trust from the divestitures primarily related to undeveloped acreage. Therefore, total proved reserves related to the Divestiture Properties were approximately 2.5% of the Trust’s total proved reserves as of December 31, 2016.
In 2017, development activity on the Underlying Properties was focused on the East Texas / North Louisiana area. Operators have enhanced completion technology on Haynesville wells, resulting in improved economics. Over 50% of the capital expenditures incurred in 2017 were focused on the East Texas / North Louisiana area, with six gross (0.5 net) wells drilled during 2017.
The operators of the properties underlying the Trust continue to evaluate planned capital expenditures during 2018, but based on currently available information, Enduro anticipates 2018 capital expenditures to range from $4 million to $6 million attributable to the properties in which the Trust owns a net profits interest, or $3 million to $5 million net to the Trust’s 80% net profits interest.
On January 12, 2018, Enduro launched a process to sell all its oil and natural gas assets, including the Underlying Properties and its Trust Units. The Underlying Properties are being sold subject to the Trust’s 80% Net Profits Interest. If the sales process relating to the Underlying Properties is successful, Enduro expects the new owner to assume Enduro’s obligations as the sponsor of the Trust. There can be no assurances that Enduro’s sales process will be successful, in whole or in part, or that the new owner of working interests in the Underlying Properties will perform its obligations as sponsor of the Trust in a manner comparable to Enduro.
Results of Operations
The following table displays oil and natural gas sales volumes and average prices from the Underlying Properties, representing the amounts included in the net profits calculation for the distributions paid during the years ended December 31, 2017, 2016 and 2015.
|
|
|
Underlying Properties Sales Volumes |
|
Average Price |
| ||||||
|
Month of Distribution |
|
Oil |
|
Natural Gas |
|
Oil |
|
Natural Gas |
| ||
|
2017: |
|
|
|
|
|
|
|
|
| ||
|
January |
|
61,130 |
|
257,711 |
|
$ |
41.10 |
|
$ |
2.41 |
|
|
February |
|
63,737 |
|
261,379 |
|
$ |
45.04 |
|
$ |
2.63 |
|
|
March |
|
60,632 |
|
471,853 |
|
$ |
42.85 |
|
$ |
2.61 |
|
|
April |
|
74,925 |
|
308,189 |
|
$ |
51.25 |
|
$ |
2.50 |
|
|
May |
|
62,978 |
|
306,811 |
|
$ |
49.07 |
|
$ |
3.05 |
|
|
June |
|
57,714 |
|
305,783 |
|
$ |
50.05 |
|
$ |
3.48 |
|
|
July |
|
63,106 |
|
291,314 |
|
$ |
47.42 |
|
$ |
3.01 |
|
|
August |
|
59,930 |
|
309,909 |
|
$ |
47.45 |
|
$ |
2.48 |
|
|
September |
|
59,033 |
|
358,085 |
|
$ |
45.11 |
|
$ |
2.71 |
|
|
October |
|
58,631 |
|
315,138 |
|
$ |
42.40 |
|
$ |
2.78 |
|
|
Total—2017(1) |
|
621,816 |
|
3,186,172 |
|
$ |
46.29 |
|
$ |
2.76 |
|
|
2016: |
|
|
|
|
|
|
|
|
| ||
|
January |
|
70,206 |
|
406,853 |
|
$ |
44.37 |
|
$ |
2.44 |
|
|
February |
|
70,104 |
|
415,239 |
|
$ |
45.03 |
|
$ |
2.33 |
|
|
March |
|
68,223 |
|
486,540 |
|
$ |
40.28 |
|
$ |
2.55 |
|
|
April |
|
66,130 |
|
365,158 |
|
$ |
33.55 |
|
$ |
1.88 |
|
|
May |
|
69,156 |
|
392,316 |
|
$ |
29.06 |
|
$ |
1.85 |
|
|
June |
|
64,393 |
|
361,611 |
|
$ |
27.89 |
|
$ |
1.87 |
|
|
July |
|
69,118 |
|
337,869 |
|
$ |
33.32 |
|
$ |
1.81 |
|
|
August |
|
65,679 |
|
357,235 |
|
$ |
36.44 |
|
$ |
1.56 |
|
|
September |
|
65,223 |
|
311,904 |
|
$ |
42.20 |
|
$ |
1.90 |
|
|
October |
|
63,325 |
|
378,239 |
|
$ |
45.24 |
|
$ |
1.85 |
|
|
November |
|
63,585 |
|
349,412 |
|
$ |
41.83 |
|
$ |
2.04 |
|
|
December |
|
61,254 |
|
334,973 |
|
$ |
41.85 |
|
$ |
2.47 |
|
|
Total—2016 |
|
796,396 |
|
4,497,349 |
|
$ |
38.40 |
|
$ |
2.07 |
|
|
2015: |
|
|
|
|
|
|
|
|
| ||
|
January |
|
82,474 |
|
432,652 |
|
$ |
84.91 |
|
$ |
4.16 |
|
|
February |
|
81,868 |
|
428,266 |
|
$ |
76.79 |
|
$ |
4.17 |
|
|
March |
|
78,027 |
|
432,627 |
|
$ |
69.92 |
|
$ |
3.94 |
|
|
April |
|
79,802 |
|
318,830 |
|
$ |
57.49 |
|
$ |
3.54 |
|
|
May |
|
74,315 |
|
365,039 |
|
$ |
45.40 |
|
$ |
3.37 |
|
|
June |
|
65,848 |
|
499,735 |
|
$ |
45.37 |
|
$ |
2.79 |
|
|
July |
|
84,478 |
|
383,647 |
|
$ |
46.15 |
|
$ |
2.60 |
|
|
August |
|
63,058 |
|
379,199 |
|
$ |
46.18 |
|
$ |
2.52 |
|
|
September |
|
73,967 |
|
417,505 |
|
$ |
54.85 |
|
$ |
2.37 |
|
|
October |
|
72,290 |
|
440,374 |
|
$ |
56.29 |
|
$ |
2.37 |
|
|
November |
|
71,875 |
|
394,272 |
|
$ |
50.38 |
|
$ |
2.47 |
|
|
December |
|
69,396 |
|
410,089 |
|
$ |
42.51 |
|
$ |
2.60 |
|
|
Total—2015 |
|
897,398 |
|
4,902,235 |
|
$ |
57.06 |
|
$ |
3.07 |
|
(1) The year ended December 31, 2017 does not include sales volumes for November and December as the Trust did not pay a distribution in those months as the net profits interest calculation for such periods was negative.
Computation of Income from Net Profits Interest Received by the Trust
In connection with the closing of the initial public offering in November 2011, Enduro contributed the Net Profits Interest to the Trust in exchange for 33,000,000 newly issued Trust Units. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale and production of oil and natural gas attributable to the Underlying Properties that are produced during the term of the Conveyance, which commenced on July 1, 2011. The Trust’s Income from Net Profits Interest consists of monthly net profits attributable to the Income from Net Profits Interest. Net profits income for the years ended December 31, 2017, 2016, and 2015 was determined as shown in the following table:
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Gross profits: |
|
|
|
|
|
|
| |||
|
Oil sales |
|
$ |
28,785,847 |
|
$ |
30,581,617 |
|
$ |
51,202,046 |
|
|
Natural gas sales |
|
8,801,104 |
|
9,288,783 |
|
15,058,423 |
| |||
|
Total |
|
37,586,951 |
|
39,870,400 |
|
66,260,469 |
| |||
|
Costs: |
|
|
|
|
|
|
| |||
|
Direct operating expenses: |
|
|
|
|
|
|
| |||
|
Lease operating expenses |
|
19,580,000 |
|
22,422,000 |
|
29,788,000 |
| |||
|
Compression, gathering and transportation |
|
2,026,000 |
|
3,179,000 |
|
2,391,000 |
| |||
|
Production, ad valorem and other taxes |
|
2,707,000 |
|
2,953,000 |
|
5,365,000 |
| |||
|
Development expenses |
|
3,844,000 |
|
(329,000 |
) |
10,618,000 |
| |||
|
Total |
|
28,157,000 |
|
28,225,000 |
|
48,162,000 |
| |||
|
Net profits |
|
$ |
9,429,251 |
|
$ |
11,645,400 |
|
$ |
18,098,469 |
|
|
Percentage allocable to Net Profits Interest |
|
80 |
% |
80 |
% |
80 |
% | |||
|
Net profits allocable to Net Profits Interest |
|
$ |
7,543,960 |
|
$ |
9,316,320 |
|
$ |
14,478,775 |
|
|
Enduro reserve for approved development expenses released (withheld), net |
|
100,000 |
|
(100,000 |
) |
— |
| |||
|
Income from Net Profits Interest |
|
7,643,960 |
|
9,216,320 |
|
14,478,775 |
| |||
|
Less: Trust general and administrative expenses and cash withheld for expenses |
|
(850,052 |
) |
(730,040 |
) |
(709,954 |
) | |||
|
Distributable income generated by properties prior to divestiture |
|
$ |
6,793,908 |
|
$ |
8,486,280 |
|
$ |
13,768,821 |
|
|
Income from sale of Net Profits Interest |
|
37,950,165 |
|
— |
|
— |
| |||
|
Distributable income |
|
$ |
44,744,073 |
|
$ |
8,486,280 |
|
$ |
13,768,821 |
|
In 2017, there were two months in which direct operating and development expenses exceeded revenues, thereby causing net profits on the Underlying Properties to be negative. As a result, there were no distributions to Trust unitholders in November or December 2017 and the aggregate shortfall in net profits was carried forward to be reduced from net profits generated by the Underlying Properties in 2018. As the net profits for the two periods was negative and there was no distribution paid to unitholders, revenues and the associated direct operating and development expenses are excluded from the calculation of distributable income detailed in the table above as well as the related sales volumes detailed below.
The following table displays oil and natural gas sales volumes and average prices from the Underlying Properties, representing the amounts included in the net profits calculation for distributions paid during the years ended December 31, 2017, 2016, and 2015:
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Underlying Properties Sales Volumes: |
|
|
|
|
|
|
| |||
|
Oil (Bbls) |
|
621,816 |
|
796,396 |
|
897,398 |
| |||
|
Natural Gas (Mcf) |
|
3,186,172 |
|
4,497,349 |
|
4,902,235 |
| |||
|
Combined (Boe) |
|
1,152,845 |
|
1,545,954 |
|
1,714,437 |
| |||
|
|
|
|
|
|
|
|
| |||
|
Average Prices: |
|
|
|
|
|
|
| |||
|
Oil — NYMEX (September-August) ($/Bbl) |
|
$ |
49.35 |
|
$ |
41.63 |
|
$ |
60.57 |
|
|
Differential |
|
$ |
(3.06 |
) |
$ |
(3.23 |
) |
$ |
(3.51 |
) |
|
Oil prices realized ($/Bbl) |
|
$ |
46.29 |
|
$ |
38.40 |
|
$ |
57.06 |
|
|
|
|
|
|
|
|
|
| |||
|
Natural gas — NYMEX (August-July) ($/Mcf) |
|
$ |
3.08 |
|
$ |
2.30 |
|
$ |
3.23 |
|
|
Differential |
|
$ |
(0.32 |
) |
$ |
(0.23 |
) |
$ |
(0.16 |
) |
|
Natural gas prices realized ($/Mcf) |
|
$ |
2.76 |
|
$ |
2.07 |
|
$ |
3.07 |
|
Years Ended December 31, 2017 and 2016
Net profits attributable to the Underlying Properties for the year ended December 31, 2017 is calculated from the following:
· oil sales related to oil produced from the Underlying Properties primarily from September 2016 through June 2017;
· natural gas sales related to natural gas produced from the Underlying Properties primarily from August 2016 through May 2017; and
· direct operating and development expenses related to expenses and capital incurred primarily from October 2016 to July 2017.
Net profits attributable to the Underlying Properties for the year ended December 31, 2017 were $9.4 million compared to $11.6 million for the year ended December 31, 2016. As a result of direct operating expenses and development expenses exceeding oil and natural gas sales for the last two months of 2017, the Trust did not pay a distribution to unitholders for the last two months of the year. Under the modified cash basis of accounting, as there was no distribution, the oil and natural gas sales, direct operating expenses and development expenses for such periods are not included in the table above or this analysis of net profits attributable to the Underlying Properties for the year ended December 31, 2017 versus the year ended December 31, 2016. Therefore, several variances between years are due to the year ended December 31, 2017 including ten months of results compared to twelve months for the year ended December 31, 2016. The $2.2 million decrease from 2016 to 2017 was primarily due to the following items:
· Oil sales decreased $1.8 million, primarily due to lower sales volumes, which decreased oil sales by $6.7 million. The offsetting $4.9 million increase in oil sales was due to higher realized prices. The average oil price received increased 21% as a result of the corresponding increase in the average NYMEX oil price for the relevant production months. Oil sales volumes decreased 22% primarily due to the year ended December 31, 2017 including only ten months of oil sales volumes. Offsetting the declines were volume increases in the Permian Basin relating to multiple months of production from two wells for which previously delayed payments were made during the second quarter of 2017. Although these two wells reached payout in mid-2013, the operator had not been paying Enduro for production from the wells. Oil cash receipts for these wells during the year ended 2017 that related to prior periods totaled $0.8 million, representing over four years of revenues, and oil volumes of approximately 12,000 Bbls. Excluding the accumulated receipts for these wells received in the second quarter of 2017, oil cash receipts and volumes would have been $28.0 million and approximately 609,900 Bbls, respectively, for the year ended December 31, 2017.
· Natural gas sales decreased $0.5 million due to lower sales volumes, which had a $2.7 million negative impact on natural gas sales. The decrease in realized sales volumes is offset by higher realized prices, which had a $2.2 million impact on natural gas sales. The average natural gas price received increased 34% as a result of the corresponding increases in the average NYMEX gas price for the relevant production months. Natural gas volumes decreased 29% primarily due to the year ended December 31, 2017 including only ten months of natural gas sales volumes. In addition, payment timing differences and natural production declines in the Elm Grove field of the East Texas / North Louisiana region accounted for 489,400 Mcf, or 37%, of the decline in natural gas volumes. Additionally, natural gas sales volumes in the year ended December 31, 2017 were lower due to the recoupment of previously paid volumes as described in Note 10 of the Notes to Financial Statements. The recoupment period began in the second quarter of 2016 and reduced volumes by approximately 65,500 Mcf more in the year ended December 31, 2017 as compared to the year ended December 31, 2016.
· Compression, gathering and transportation (“CGT”) expenses decreased from $3.2 million in 2016 to $2.0 million in 2017. The decreases in CGT expenses is primarily attributable to a difference in the number of months included in the respective periods. In addition, in 2016, CGT expenses were higher than usual due to unused firm capacity reservation fees that were retroactively charged by an operator in the Elm Grove field of North Louisiana for several years beginning with the January 2012 production month. The retroactively charged firm capacity reservation fees included in CGT expenses for the year ended December 31, 2016 totaled $0.3 million.
· Lease operating expenses decreased $2.8 million primarily due to the two months of expenses not included in the 2017 period.
· Production, ad valorem and other taxes decreased $0.2 million primarily due to a $2.3 million decrease in total sales revenues. As a percentage of revenues, production, ad valorem and other taxes remained relatively consistent, with 2017 at 7.2% compared to 7.4% for the year ended December 31, 2016.
· Development expenses increased $4.2 million as a result of increased capital projects in the Permian Basin as well as capital development projects in the Elm Grove field of North Louisiana. During the year ended December 31, 2017, six gross (0.5 net) wells in North Louisiana commenced drilling, which increased capital expenditures by $2.0 million. The increased capital expenditures related to the Haynesville drilling program in North Louisiana caused expenses to exceed revenues for the last two months of 2017, resulting in a negative net profits interest for the respective periods. During the year ended December 31, 2016, the low commodity price environment led to a lack of capital projects and capital adjustments were recorded that resulted from projects where actual costs incurred were less than projected. Those adjustments more than offset capital expenditures incurred and increased net profits by $0.3 million.
During the year ended December 31, 2016, Enduro established a total reserve of $850,000 for approved 2016 development expenses and released $750,000 during the year as discussed in Note 8 of the Notes to Financial Statements in Item 8 of this Form 10-K. At December 31, 2016, $100,000 remained in the reserve for approved capital expenditures. In the distribution paid in January 2017, Enduro released the final $100,000 reserve. Enduro no longer maintains any reserve for development expenses
The Trust withheld $0.9 million and paid $0.7 million for general and administrative expenses during the year ended December 31, 2017. Expenses paid during the period primarily consisted of fees for the preparation of 2016 tax information for unitholders, preparation of the Trust’s 2016 reserve report and Annual Report on Form 10-K, 2016 and 2017 financial statement audit fees, preparation of the Trust’s 2017 monthly press releases and Quarterly Reports on Form 10-Q, Trustee fees, and New York Stock Exchange listing fees. For the year ended December 31, 2016, the Trust withheld $0.7 million and paid $0.7 million for general and administrative expenses.
Years Ended December 31, 2016 and 2015
Income from Net Profits Interest for the year ended December 31, 2016 is calculated from the following:
· oil sales related to oil produced from the Underlying Properties primarily from September 2015 through August 2016;
· natural gas sales related to natural gas produced from the Underlying Properties primarily from August 2015 through July 2016; and
· direct operating and development expenses related to expenses and capital incurred primarily from October 2015 to September 2016.
Net profits attributable to the Underlying Properties for the year ended December 31, 2016 were $11.6 million compared to $18.1 million for the year ended December 31, 2015. The $6.5 million decrease from 2015 to 2016 was primarily due to the following items:
· Oil sales decreased $20.6 million, primarily due to lower realized prices, which caused oil sales to decline by $14.9 million. The remaining $5.7 million decrease in oil sales was due to reduced sales volumes. The average oil price received decreased 33% as a result of the corresponding decrease in the average NYMEX oil price for the relevant production months. Oil sales volumes decreased 11% as a result of natural production declines, which included high initial rates of decline on new wells in the Permian Basin. Production from wells drilled as part of the 2014 Rocker B drilling program declined approximately 46,600 Bbls from approximately 77,400 Bbls included in distributions paid during 2015 to approximately 30,800 Bbls included in distributions paid during 2016.
· Natural gas sales decreased $5.8 million due to lower realized prices, which reduced natural gas sales by $4.5 million, and reduced sales volumes, which decreased natural gas sales by $1.3 million. The average natural gas price received decreased 33% due to a 29% decrease in the average NYMEX natural gas price and reduced sales price realizations for the relevant production months. Sales price realizations during 2016 were impacted by a reduction in natural gas liquids (“NGLs”) pricing, which is included as part of the natural gas pricing on non-operated properties. During periods of higher oil prices, natural gas differentials were positive due to the impact of NGL pricing upgrades as certain NGL pricing correlates with oil prices. Natural gas sales volumes decreased 8% primarily as a result of natural production declines.
· Lease operating expenses decreased $7.4 million ($2.87 per Boe) primarily due to decreases in workover and maintenance activity on mature fields in the Permian Basin, the costs of oilfield goods and services and reduced plugging and abandonment costs.
· Production, ad valorem and other taxes decreased $2.4 million primarily due to a $26.4 million decrease in total sales revenues. In addition, during 2016, ad valorem expenses were $1.1 million lower as a result of lower than expected actual ad valorem expenses in 2015. As a percentage of revenues, production, ad valorem and other taxes were 7.4% for 2016 compared to 8.1% for 2015.
· Development expenses decreased $10.9 million primarily due to a lack of capital projects and development activity in the low commodity price environment. For distributions paid during the year ended December 31, 2016, capital adjustments, resulting from projects where actual costs incurred were less than projected, more than offset capital expenditures incurred and increased net profits by $0.3 million.
During the year ended December 31, 2016, Enduro established a total reserve of $850,000 for approved 2016 development expenses and released $750,000 during the year as discussed in Note 8 of the Notes to Financial Statements in Item 8 of this Form 10-K. At December 31, 2016, $100,000 remained in the reserve for approved capital expenditures.
The Trust withheld $0.7 million and paid $0.7 million for general and administrative expenses during the year ended December 31, 2016. Expenses paid during the period primarily consisted of fees for the preparation of 2015 tax information for unitholders, preparation of the Trust’s 2015 reserve report and Annual Report on Form 10-K, 2015 and 2016 financial statement audit fees, preparation of the Trust’s 2016 monthly press releases and Quarterly Reports on Form 10-Q, Trustee fees, and New York Stock Exchange listing fees. For the year ended December 31, 2015, the Trust withheld $0.7 million and paid $0.9 million for general and administrative expenses.
Liquidity and Capital Resources
The Trust’s principal sources of liquidity are cash flow generated from the Net Profits Interest and borrowing capacity under the letter of credit described below. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) in any given month, over the Trust’s expenses paid for that month. Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses.
The Trustee may create a cash reserve to pay for future liabilities of the Trust. If the Trustee determines that the cash on hand and the cash to be received are, or will be, insufficient to cover the Trust’s liabilities, the Trustee may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from any person, including the Trustee or the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee or any affiliate thereof intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were to be loaned by the entity serving as Trustee or Delaware Trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. In addition, Enduro has provided the Trust with a $1 million letter of credit to be used by the Trust if its cash on hand (including available cash reserves) is insufficient to pay ordinary course administrative expenses. Further, if the Trust requires more than the $1 million under the letter of credit to pay administrative expenses, Enduro has agreed to loan funds to the Trust necessary to pay such expenses. Any loan made by Enduro to the Trust would be evidenced by a written promissory note, be on an unsecured basis, and have terms that are no less favorable to Enduro than those that would be obtained in an arm’s length transaction between Enduro and an unaffiliated third party. If the Trust borrows funds or draws on the letter of credit, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid. Except for the foregoing, the Trust has no source of liquidity or capital resources. The Trustee has no current plans to authorize the Trust to borrow money. At December 31, 2017 and 2016, the Trust held cash reserves of $366,773 and $184,331, respectively, for future Trust expenses. Since its formation, the Trust has not borrowed any funds and no amounts have been drawn on the letter of credit.
In February 2016, Enduro established a $750,000 reserve from that month’s net profits interest calculation for approved 2016 development expenses. The Trust, in its discretion, also withheld $250,000 for anticipated future liabilities of the Trust. In March 2016, Enduro withheld an additional $100,000 to increase the previously established reserve for approved development expenses, a total reserve of $850,000. As a result of lower than anticipated expenditures during the year, over the course of the remaining 2016 distributions Enduro released $750,000 of the established reserve, thereby increasing the net profits attributable to the Trust. In the distribution paid in January 2017, Enduro released the final $100,000 reserve. Enduro no longer maintains any reserve for development expenses.
Cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date may be held in a noninterest-bearing account or may be invested in:
· interest-bearing obligations of the United States government;
· money market funds that invest only in United States government securities;
· repurchase agreements secured by interest-bearing obligations of the United States government; or
· bank certificates of deposit.
In prior periods, the amounts received by Enduro from hedge contract counterparties upon settlement of the hedge contracts reduced the operating expenses related to the Underlying Properties in calculating income from the Net Profits Interest in the first and second quarters of 2014. Enduro has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced after 2013 and the terms of the Conveyance prohibit Enduro from entering into new hedging arrangements burdening the Trust.
The Trust pays the Trustee an administrative fee of $200,000 per year. The Trust pays the Delaware Trustee an annual fee of $2,000. The Trust also incurs, either directly or as a reimbursement to the Trustee, legal, accounting, tax and engineering fees, printing costs and other expenses that are deducted by the Trust before distributions are made to Trust unitholders. The Trust also is responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to Trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees.
The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.
Off-Balance Sheet Arrangements
The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.
Contractual Obligations
A summary of the Trust’s contractual obligations as of December 31, 2017 is provided in the following table:
|
|
|
Payments Due by Year | ||||||||||||||||||
|
|
|
2018 |
|
2019 |
|
2020 |
|
2021 |
|
2022 |
|
After 2022 |
|
Total |
| |||||
|
|
|
(in thousands) | ||||||||||||||||||
|
Trustee Administrative fee |
|
200 |
|
200 |
|
200 |
|
200 |
|
200 |
|
|
(a) |
|
(a) | |||||
|
Delaware Trustee fee |
|
2 |
|
2 |
|
2 |
|
2 |
|
2 |
|
|
(a) |
|
(a) | |||||
|
Total |
|
$ |
202 |
|
$ |
202 |
|
$ |
202 |
|
$ |
202 |
|
$ |
202 |
|
|
(a) |
|
(a) |
(a) Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee and $2,000 to the Delaware Trustee. Because the term of the Net Profits Interest and the Trust are not limited, the aggregate amounts of future payments cannot be calculated.
New Accounting Pronouncements
As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.
Critical Accounting Policies and Estimates
The Trust uses the modified cash basis of accounting to report Trust receipts of income from the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties plus any payments made or net payments received in connection with the settlement of certain hedge contracts, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received by the Trust pursuant to terms of the conveyance creating the Net Profits Interest.
Under the terms of the Conveyance, the monthly Net Profits Interest calculation includes oil and natural gas revenues received as well as cash settlements for applicable hedge contracts received by Enduro during the relevant month for periods during which hedges were in place. Monthly operating expenses and capital expenditures represent incurred expenses, and as a result, represent accrued expenses as well as expenses paid during the period.
The financial statements of the Trust are prepared on the following basis:
(a) Income from Net Profits Interest is recorded when distributions are received by the Trust;
(b) Distributions to Trust unitholders are recorded when paid by the Trust;
(c) Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid;
(d) Cash reserves for Trust expenses may be established by the Trustee for certain future expenditures that would not be recorded as contingent liabilities under accounting principles generally accepted in the United States of America (“GAAP”);
(e) Amortization of the Net Profits Interest in oil and natural gas properties is calculated on a unit-of-production basis and is charged directly to the Trust corpus. Such amortization does not affect cash earnings of the Trust; and
(f) The Net Profits Interest in oil and natural gas properties is periodically assessed whenever events or circumstances indicate that the aggregate value may have been impaired below its total capitalized cost based on the Underlying Properties. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows of the Net Profits Interest, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value determined using discounted cash flows.
The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; general and administrative expenses are recorded when paid instead of when incurred; and amortization of the net profits interest calculated on a unit-of-production basis is charged directly to trust corpus instead of as an expense. While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts.
This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Oil and Natural Gas Reserves. The proved oil and natural gas reserves for the Underlying Properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.
The Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and natural gas reserves. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.
Amortization of Net Profits Interest. The Trust calculates amortization of the Net Profits Interest in oil and natural gas properties on a unit-of-production basis based on the Underlying Properties’ production and reserves. The reserves upon which the amortization rate is based are quantity estimates which are subject to numerous uncertainties inherent in the estimation of proved reserves. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. These estimates are expected to change as additional information becomes available in the future. Downward revisions in proved reserves may result in an increased rate of amortization. Amortization is recorded on sales volumes paid by the Trust during the relevant period and is charged directly to the Trust corpus balance. As a result, amortization does not affect the cash earnings of the Trust.
Impairment of Net Profits Interest. The Net Profits Interest in oil and natural gas properties is periodically assessed for impairment whenever events or circumstances indicate that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the Net Profits Interest. During the year ended December 31, 2015, the Trust recognized a $367.3 million impairment of the Net Profits Interest. The impairment resulted in a non-cash charge to Trust corpus and did not affect distributable income. Future downward revisions in actual production volumes relative to current forecasts, higher than expected operating costs, or lower than anticipated market pricing could result in recognition of impairment in future periods. For further information, see “Note 5. Fair Value Measurements” of the Notes to Financial Statements in Item 8 of this Form 10-K. The Trust did not realize any impairment during the years ended December 31, 2017 or 2016.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Trust’s only asset and source of income is the Net Profits Interest, which entitles the Trust to receive 80% of the net profits from oil and natural gas production from the Underlying Properties. Commodity prices affect the amount of cash flow available for distribution to Trust unitholders, and lower prices may reduce the amount of oil and natural gas that Enduro and its third party operators can economically produce. Consequently, the Trust is exposed to market risk from fluctuations in oil and natural gas prices.
The terms of the Net Profits Interest prohibit Enduro from entering into hedging arrangements burdening the Trust, excluding the hedges that existed prior to the date of the Conveyance. All hedge contracts in effect prior to the date of the Conveyance had matured as of December 31, 2013. Accordingly, the Trust is no longer subject to risks related to derivative contracts, and therefore the amount of future cash distributions will be subject to the full impact of fluctuations due to changes in oil and natural gas prices as noted above.
The Trust is a passive entity, and the Trust’s ability to engage in borrowing transactions is limited to funds necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust. Since its formation, the Trust has not borrowed any funds. In addition, the terms of the Net Profits Interest prohibit the Trust from entering into any investments other than investing cash on hand in specific short-term cash investments. Due to the limited nature of its borrowing and investing activities, the Trust is not subject to material interest rate market risk.
Item 8. Financial Statements and Supplementary Data.
Report of Independent Registered Public Accounting Firm
To the Trustee and Unitholders of Enduro Royalty Trust
Opinion on the Financial Statements
We have audited the accompanying statements of assets, liabilities, and trust corpus of Enduro Royalty Trust (the Trust) as of December 31, 2017 and 2016, the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Trust at December 31, 2017 and 2016, and its distributable income for each of the three years in the period ended December 31, 2017, in conformity with the modified cash basis of accounting, as described in Note 2, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Trust’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 12, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
|
/s/ Ernst & Young LLP |
|
|
|
|
|
We have served as the Trust’s auditor since 2011. |
|
|
|
|
|
Fort Worth, Texas |
|
|
March 12, 2018 |
|
ENDURO ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
|
|
|
December 31, |
| ||||
|
|
|
2017 |
|
2016 |
| ||
|
ASSETS |
|
|
|
|
| ||
|
Cash and cash equivalents |
|
$ |
366,773 |
|
$ |
184,331 |
|
|
Net profits interest in oil and natural gas properties, net |
|
93,733,160 |
|
107,140,211 |
| ||
|
Total assets |
|
$ |
94,099,933 |
|
$ |
107,324,542 |
|
|
LIABILITIES AND TRUST CORPUS |
|
|
|
|
| ||
|
Trust corpus (33,000,000 units issued and outstanding) |
|
$ |
94,099,933 |
|
$ |
107,324,542 |
|
|
Total liabilities and Trust corpus |
|
$ |
94,099,933 |
|
$ |
107,324,542 |
|
The accompanying notes to financial statements are an integral part of these statements.
ENDURO ROYALTY TRUST
Statements of Distributable Income
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Income from net profits interest |
|
$ |
7,643,960 |
|
$ |
9,216,320 |
|
$ |
14,478,775 |
|
|
Income from sale of net profits interest on undeveloped acreage |
|
36,300,165 |
|
— |
|
— |
| |||
|
Income from sale of net profits interest on producing properties |
|
1,650,000 |
|
— |
|
— |
| |||
|
Interest and investment income |
|
15,328 |
|
572 |
|
7 |
| |||
|
General and administrative expenses |
|
(682,938 |
) |
(654,132 |
) |
(851,178 |
) | |||
|
Cash reserves used (withheld) for Trust expenses |
|
(182,442 |
) |
(76,480 |
) |
141,217 |
| |||
|
Distributable income |
|
$ |
44,744,073 |
|
$ |
8,486,280 |
|
$ |
13,768,821 |
|
|
Distributable income per unit (33,000,000 units) |
|
$ |
1.355881 |
|
$ |
0.257160 |
|
$ |
0.417237 |
|
The accompanying notes to financial statements are an integral part of these statements.
ENDURO ROYALTY TRUST
Statements of Changes in Trust Corpus
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Trust corpus, beginning of period |
|
$ |
107,324,542 |
|
$ |
121,009,502 |
|
$ |
528,372,769 |
|
|
Sale of net profits interest on producing properties |
|
(1,650,000 |
) |
— |
|
— |
| |||
|
Cash reserves (used) withheld for Trust expenses |
|
182,442 |
|
76,480 |
|
(141,217 |
) | |||
|
Distributable income |
|
44,744,073 |
|
8,486,280 |
|
13,768,821 |
| |||
|
Distributions to unitholders |
|
(44,744,073 |
) |
(8,486,280 |
) |
(13,768,821 |
) | |||
|
Impairment of net profits interest |
|
— |
|
— |
|
(367,258,842 |
) | |||
|
Amortization of net profits interest |
|
(11,757,051 |
) |
(13,761,440 |
) |
(39,963,208 |
) | |||
|
Trust corpus, end of year |
|
$ |
94,099,933 |
|
$ |
107,324,542 |
|
$ |
121,009,502 |
|
The accompanying notes to financial statements are an integral part of these statements.
ENDURO ROYALTY TRUST
1. TRUST ORGANIZATION AND PROVISIONS
Enduro Royalty Trust (the “Trust”) is a Delaware statutory trust formed in May 2011 pursuant to a trust agreement (the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”), as trustor, The Bank of New York Mellon Trust Company, N.A. (the “Trustee”), as trustee, and Wilmington Trust Company (the “Delaware Trustee”), as Delaware Trustee.
The Trust was created to acquire and hold for the benefit of the Trust unitholders a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro as of the date of the conveyance of the net profits interest to the Trust (the “Net Profits Interest”). The properties in which the Trust holds the Net Profits Interest are referred to as the “Underlying Properties.”
In connection with the closing of the initial public offering in November 2011, Enduro contributed the Net Profits Interest to the Trust in exchange for 33,000,000 units of beneficial interest in the Trust (the “Trust Units”). Through the initial public offering in 2011 and a secondary offering in 2013, Enduro has sold a total of 24,400,000 Trust Units. As of December 31, 2017 and 2016, Enduro owned 8,600,000 Trust Units, or 26% of the issued and outstanding Trust Units.
At a special meeting of Trust unitholders held on August 30, 2017, unitholders approved several proposals, including amendments to the Trust Agreement. In September 2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which amended certain provisions of the Trust Agreement to, among other things, allow Enduro to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust unitholders holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements of the Trust Agreement. This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding units of the Trust.
The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties. The Trust Agreement provides, among other provisions, that:
· the Trust’s business activities are limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the Conveyance of Net Profits Interest, dated effective as of July 1, 2011 (as supplemented and amended to date, the “Conveyance”). As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interest;
· the Trust may dispose of all or any material part of the assets of the Trust (including the sale of the Net Profits Interests) if approved by at least 75% of the outstanding Trust Units;
· Enduro may sell a divided or undivided portion of its interests in the Underlying Properties, free from and unburdened by the Net Profits Interest, if approved by at least 50% of the outstanding Trust Units at a meeting of Trust unitholders;
· the Trustee will make monthly cash distributions to unitholders (Note 7);
· the Trustee may create a cash reserve to pay for future liabilities of the Trust;
· the Trustee may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed its cash on hand and available reserves. No further distributions will be made to Trust unitholders until such amounts borrowed are repaid; and
· the Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following:
· the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells the Net Profits Interest;
· the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years;
· the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution; or
· the Trust is judicially dissolved.
ENDURO ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—Continued
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Accounting
The Trust uses the modified cash basis of accounting to report Trust receipts of income from the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (including lease operating expenses and production and property taxes) and development expenses of the Underlying Properties, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received by the Trust from Enduro pursuant to terms of the Conveyance creating the Net Profits Interest.
Under the terms of the Conveyance, the monthly Net Profits Interest calculation includes oil and natural gas revenues received by Enduro during the relevant month. Monthly operating expenses and capital expenditures represent estimated incurred expenses, and as a result, represent accrued expenses as well as expenses paid during the period.
The financial statements of the Trust are prepared on the following basis:
(a) Income from Net Profits Interest is recorded when distributions are received by the Trust;
(b) Distributions to Trust unitholders are recorded when paid by the Trust;
(c) Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid;
(d) Cash reserves for Trust expenses may be established by the Trustee for certain future expenditures that would not be recorded as contingent liabilities under accounting principles generally accepted in the United States of America (“GAAP”);
(e) Amortization of the Net Profits Interest in oil and natural gas properties is calculated on a unit-of-production basis and is charged directly to the Trust corpus; and
(f) The Net Profits Interest in oil and natural gas properties is periodically assessed whenever events or circumstances indicate that the aggregate value may have been impaired below its total capitalized cost based on the Underlying Properties. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows of the Net Profits Interest, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value determined using discounted cash flows.
The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; general and administrative expenses are recorded when paid instead of when incurred; and amortization of the net profits interest calculated on a unit-of-production basis is charged directly to trust corpus instead of as an expense. While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts.
This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (“SEC”) as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
Use of Estimates
The preparation of financial statements in conformity with the basis of accounting described above requires the Trust to make estimates and assumptions that affect reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Significant estimates affecting these financial statements include estimates of proved oil and natural gas reserves, which are used to compute the Trust’s amortization of net profits interest and its impairment assessments. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less.
Impairment
The Net Profits Interest in oil and natural gas properties is periodically assessed for impairment whenever events or circumstances indicate that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the Net Profits Interest. While the Trust did not record an impairment during the years ended December 31, 2017 or 2016, future downward revisions in actual production volumes relative to current forecasts, higher than expected operating costs, or lower than anticipated commodity prices could result in recognition of impairment in future periods. During the year ended December 31, 2015, the Trust recognized a $367,258,842 impairment of the Net Profits Interest. The impairment resulted in a non-cash charge to Trust corpus, which did not affect distributable income. For further information on the impairment recognized in 2015, see “Note 5. Fair Value Measurements.”
New Accounting Pronouncements
As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.
ENDURO ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—Continued
3. NET PROFITS INTEREST IN OIL AND NATURAL GAS PROPERTIES
The Net Profits Interest in oil and natural gas properties was recorded at its fair value on the date of conveyance. Amortization of the Net Profits Interest in oil and natural gas properties is calculated on a unit-of-production basis based on the Underlying Properties’ production and reserves. As the Trust uses the modified cash basis of accounting, amortization is recognized only in those months for which income from net profits interest exceeds capital expenditures. The reserves upon which the amortization rate is based are quantity estimates which are subject to numerous uncertainties inherent in the estimation of proved reserves. The volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. These estimates are expected to change as additional information becomes available in the future. Downward revisions in proved reserves may result in an increased rate of amortization. Amortization is charged directly to the Trust corpus balance and does not affect the distributable income of the Trust. Accumulated amortization as of December 31, 2017 and 2016 was $263,357,998 and $251,600,947, respectively.
The Net Profits Interest is periodically assessed for impairment whenever events or circumstances indicate that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the Net Profits Interest. While the Trust did not record an impairment during the years ended December 31, 2017 or 2016, future downward revisions in actual production volumes relative to current forecasts, higher than expected operating costs, or lower than anticipated commodity prices could result in recognition of impairment in future periods. During the year ended December 31, 2015, the Trust recognized a $367,258,842 impairment of the Net Profits Interest. The impairment resulted in a non-cash charge to Trust corpus but did not affect distributable income. For further information, see “Note 5. Fair Value Measurements.”
As further discussed in “Note 4. Divestiture of Net Profits Interest in Certain Permian Basin Properties,” in September 2017, Enduro completed the sale of certain properties in the Permian Basin and, in connection with the sale, the Trust released its 80% Net Profits Interest in the properties in exchange for 80% of the net proceeds of the sales. As a result of the divestiture, and concurrent with the distribution of cash to the Trust that occurred in October, the Trust reduced the carrying value of the Net Profits Interest reflected on the accompanying Statement of Assets, Liabilities and Trust Corpus by $1,650,000, which was the portion of the net sales proceeds allocated to producing properties. The remainder of the net sales proceeds, totaling $36,300,165, was attributed to the sale of the net profits interest on undeveloped acreage and not reflected in the carrying value of the Net Profits Interest. See “Note 5. Fair Value Measurements” for further discussion of the fair value of the divested properties, which was the basis for allocating net proceeds between producing properties and undeveloped acreage.
4. DIVESTITURE OF NET PROFITS INTEREST IN CERTAIN PERMIAN BASIN PROPERTIES
In June 2017, Enduro notified the Trustee that Enduro had entered into eight separate purchase and sale agreements to divest certain acreage and associated production in the Permian Basin (the “Divestiture Properties”) that constituted part of the Underlying Properties and were therefore burdened by the Trust’s Net Profits Interest. On August 30, 2017, at a special meeting of Trust unitholders, the unitholders approved (i) the eight transactions pursuant to which Enduro would sell the Divestiture Properties, (ii) the release of the Trust’s 80% Net Profits Interest in the Divestiture Properties, and (iii) the related proposals to effect the sale transactions in exchange for the Trust receiving 80% of the net proceeds from the sale of the Divestiture Properties.
In September 2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which amended certain provisions of the Trust Agreement to, among other things, allow Enduro to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust unitholders holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements of the Trust Agreement. This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding units of the Trust. To effect the same changes as those included in the amended Trust Agreement, Enduro, the Trustee and the Delaware Trustee also entered into the First Amendment to Conveyance of Net Profits Interest. As a result of the Trust unitholders approving amendments to the Trust Agreement and Conveyance and the approval of the divestiture of the Divestiture Properties, Enduro and the Trustee entered into the Partial Release, Reconveyance and Termination Agreement (the “Partial Release”). Pursuant to the terms of the Partial Release, the Trustee, on behalf of the Trust, reconveyed, terminated and released to Enduro the Net Profits Interest with respect to the Divestiture Properties sold pursuant to eight letter agreements or purchase and sale agreements, as applicable, entered into between Enduro and eight separate counterparties.
In September 2017, Enduro completed the sale of the Divestiture Properties. The following table displays the aggregate net proceeds from the sale of the Divestiture Properties and the aggregate net proceeds allocable to Trust unitholders:
|
Proceeds to Enduro from sale of Divestiture Properties |
|
$ |
49,141,943 |
|
|
Less: Transaction expenses |
|
(766,737 |
) | |
|
Net proceeds from sale of Divestiture Properties |
|
48,375,206 |
| |
|
Percentage allocable to Trust’s Net Profits Interest |
|
80 |
% | |
|
Net proceeds allocable to the Trust |
|
38,700,165 |
| |
|
Indemnity holdback |
|
(750,000 |
) | |
|
Cash distributed to Trust unitholders from divestiture of Net Profits Interest |
|
$ |
37,950,165 |
|
|
Number of Trust Units |
|
33,000,000 |
| |
|
Special distribution per Trust Unit |
|
$ |
1.150005 |
|
Total proceeds received by Enduro from the sale of the Divestiture Properties, after preliminary closing adjustments, were approximately $49.1 million. After deducting transaction expenses of $766,737, net proceeds to Enduro were $48.4 million, of which the proceeds allocable to the Trust were $38.7 million in accordance with its 80% Net Profits Interest. Pursuant to an agreement between Enduro and the Trust, Enduro withheld $750,000 of the net proceeds allocable to the Trust to cover possible indemnification obligations under the purchase and sale agreements. Any remaining amount held after payment for any indemnities contained in the purchase and sale agreements will be released and included in the regular monthly distribution to Trust unitholders within 25 months of the closing of the transactions, or by the end of October 2019. As a result of these transactions, a special distribution of $1.150005 per unit was paid on October 20, 2017 to Trust unitholders.
As discussed in “Note 5. Fair Value Measurements,” the cash distributed to Trust unitholders as a result of the divestitures of the Net Profits Interest was allocated between producing properties and undeveloped acreage based on the fair value of the Divestiture Properties. The $1,650,000 allocated to producing properties reduced the carrying value of the “Net profits interest in oil and natural gas properties, net” line item on the Statement of Assets, Liabilities and Trust Corpus and is shown as “Income from sale of net profits interest on producing properties” on the Statement of Distributable Income. The remaining amount was allocated to undeveloped acreage and is reflected in the Statement of Distributable Income as “Income from sale of net profits interest on undeveloped acreage.” As the proceeds received from the sale of the Divestiture Properties were primarily attributable to undeveloped acreage, the net profits generated from the Divestiture Properties have been insignificant to the Trust historically.
ENDURO ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—Continued
5. FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The three approaches for measuring the fair value of assets and liabilities are the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset, often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
· Level 1 — Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
· Level 2 — Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
· Level 3 — Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Fair Values—Non-recurring
Divestiture of Net Profits Interest
In connection with the divestiture of the Net Profits Interest as discussed in Note 4, the fair value of the producing properties sold in relation to the fair value of the Underlying Properties was evaluated utilizing an undiscounted cash flow model as of the date of sale. This fair value measurement using an income approach was based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. Internal price estimates were developed based on third-party longer-term commodity futures price outlooks. Based on this analysis, the expected future net cash flows of the producing properties sold discounted at an annual rate of 10 percent was approximately $2.2 million, representing approximately 1.7% of the total expected future net cash flows of the Underlying Properties discounted at an annual rate of 10 percent.
Due to the impairment of the Net Profits Interest recognized during the third quarter of 2015, the carrying value of the Net Profits Interest was reduced to reflect the Trust’s interest in the value of producing properties within the Underlying Properties. As the producing properties sold by Enduro represented 1.7% of the fair value of the Underlying Properties, the Trust reduced the carrying value of the Net Profits Interest reflected on its financial statements by 1.7%, or approximately $1.7 million, in October 2017.
Impairment of Net Profits Interest
Due to continued declines in commodity prices and the resulting effect on estimated future cash flows of the Net Profits Interest, and on the reserves attributable to the Trust’s interest in the Underlying Properties, there were indications during the third quarter of 2015 that the carrying value of the Net Profits Interest may be impaired. As a result, an undiscounted cash flow calculation was performed which demonstrated that expected future net cash flows of the Net Profits Interest were below its carrying value. Fair value was subsequently measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. Internal price estimates were developed based on third-party longer-term commodity futures price outlooks, and future cash flows were calculated using an estimated average realized oil price of $66.26 per Bbl and natural gas price of $2.99 per Mcf. The expected future net cash flows were discounted using an annual rate of 15 percent to determine fair value.
As a result of the fair value assessment, the Trust recorded an impairment charge during the year ended December 31, 2015 of $367,258,842. The following table presents the value of the Net Profits Interest measured at fair value on a non-recurring basis at the time impairment was recorded in the third quarter of 2015:
|
Carrying Value |
|
$ |
491,491,642 |
|
|
Impairment |
|
(367,258,842 |
) | |
|
Fair Value |
|
$ |
124,232,800 |
|
Although the Trust did not record an impairment during the years ended December 31, 2017 or 2016, it is reasonably possible that the estimates of undiscounted future net cash flows attributable to the Underlying Properties may change in the future resulting in the need to further impair the carrying value of the Net Profits Interest. The primary factors that may affect estimates of future cash flows include: revisions, both positive and negative, to estimates of oil and natural gas reserves; changes in estimated average realized oil and natural gas prices; and results of future drilling activities.
ENDURO ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—Continued
6. INCOME TAXES
Federal Income Taxes
For federal income tax purposes, the Trust is a grantor trust and therefore is not subject to tax at the trust level. Trust unitholders are treated as owning a direct interest in the assets of the Trust, and each Trust unitholder is taxed directly on his or her pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his or her pro rata share of the deductions and expenses attributable to the assets of the Trust. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.
The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each unitholder is entitled to depletion deductions because the Net Profits Interest constitutes “economic interests” in oil and natural gas properties for federal income tax purposes. Each unitholder is entitled to amortize the cost of the Trust Units through cost depletion over the life of the Net Profits Interest or, if greater, through percentage depletion. Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the Trust Units. Rather, a unitholder could be entitled to percentage depletion as long as the applicable Underlying Properties generate net income.
Some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 601 Travis, 16th Floor, Houston, Texas 77002, telephone number (512) 236-6545, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.enduroroyaltytrust.com. Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.
The tax consequences to a unitholder of ownership of Trust Units will depend in part on the unitholder’s tax circumstances. Unitholders should consult their tax advisors about the federal tax consequences relating to owning the Trust Units.
State Taxes
The Trust’s revenues are from sources in the states of Louisiana, New Mexico and Texas. Because it distributes all of its net income to unitholders, the Trust is not taxed at the trust level in Louisiana or New Mexico. Although the Trust does not owe tax, the Trustee is required to file a return with Louisiana reflecting the income and deductions of the Trust attributable to properties located in that state. Louisiana and New Mexico presently have income taxes which tax income of nonresidents from real property located within that state. Louisiana and New Mexico also impose a corporate income tax which may apply to unitholders organized as corporations.
Texas imposes a franchise tax at a rate of 0.75% on gross revenues less certain deductions for returns originally due on or after January 1, 2016, as specifically set forth in the Texas franchise tax statutes. Entities subject to tax generally include trusts unless otherwise exempt. Trusts that receive at least 90% of their federal gross income from designated passive sources, including royalties from mineral properties and other income from other non-operating mineral interests, and do not receive more than 10% of their income from operating an active trade or business, generally are exempt from the Texas franchise tax as “passive entities.” Although the Trust is intended to be exempt from Texas franchise tax at the trust level as a passive entity, each unitholder that is considered a taxable entity under the Texas franchise tax would generally be required to include its portion of Trust net income in its own Texas franchise tax computation.
Each unitholder should consult his or her own tax advisor regarding state tax requirements, if any, applicable to such person’s ownership of Trust Units.
ENDURO ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—Continued
7. DISTRIBUTIONS TO UNITHOLDERS
Each month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s liabilities for that month, subject to adjustments for changes made by the Trustee during the month in any cash reserves established for future liabilities of the Trust. Distributions are made to the holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) and are payable on or before the 10th business day after the record date.
The following table provides information regarding the Trust’s distributions paid during the periods indicated:
|
Declaration Date |
|
Record Date |
|
Payment Date |
|
Distribution per Unit |
| |
|
2017: |
|
|
|
|
|
|
| |
|
December 19, 2016 |
|
December 30, 2016 |
|
January 17, 2017 |
|
$ |
0.013980 |
|
|
January 20, 2017 |
|
January 31, 2017 |
|
February 14, 2017 |
|
$ |
0.036205 |
|
|
February 17, 2017 |
|
February 28, 2017 |
|
March 14, 2017 |
|
$ |
0.017331 |
|
|
March 21, 2017 |
|
March 31, 2017 |
|
April 14, 2017 |
|
$ |
0.040901 |
|
|
April 18, 2017 |
|
April 28, 2017 |
|
May 12, 2017 |
|
$ |
0.035220 |
|
|
May 19, 2017 |
|
May 31, 2017 |
|
June 14, 2017 |
|
$ |
0.023001 |
|
|
June 20, 2017 |
|
June 30, 2017 |
|
July 17, 2017 |
|
$ |
0.015040 |
|
|
July 21, 2017 |
|
July 31, 2017 |
|
August 14, 2017 |
|
$ |
0.011227 |
|
|
August 21, 2017 |
|
August 31, 2017 |
|
September 15, 2017 |
|
$ |
0.009327 |
|
|
September 19, 2017 |
|
September 29, 2017 |
|
October 16, 2017 |
|
$ |
0.003644 |
|
|
September 25, 2017 — Special Distribution |
|
October 5, 2017 |
|
October 20, 2017 |
|
$ |
1.150005 |
|
|
Total—2017 |
|
|
|
|
|
$ |
1.355881 |
|
|
2016: |
|
|
|
|
|
|
| |
|
December 18, 2015 |
|
December 31, 2015 |
|
January 15, 2016 |
|
$ |
0.029187 |
|
|
January 19, 2016 |
|
January 29, 2016 |
|
February 12, 2016 |
|
$ |
0.029839 |
|
|
February 19, 2016 |
|
February 29, 2016 |
|
March 14, 2016 |
|
$ |
0.024305 |
|
|
March 21, 2016 |
|
March 31, 2016 |
|
April 14, 2016 |
|
$ |
0.009855 |
|
|
April 19, 2016 |
|
April 29, 2016 |
|
May 13, 2016 |
|
$ |
0.007279 |
|
|
May 20, 2016 |
|
May 31, 2016 |
|
June 14, 2016 |
|
$ |
0.001016 |
|
|
June 20, 2016 |
|
June 30, 2016 |
|
July 15, 2016 |
|
$ |
0.013353 |
|
|
July 19, 2016 |
|
July 29, 2016 |
|
August 12, 2016 |
|
$ |
0.015600 |
|
|
August 19, 2016 |
|
August 31, 2016 |
|
September 15, 2016 |
|
$ |
0.029923 |
|
|
September 20, 2016 |
|
September 30, 2016 |
|
October 17, 2016 |
|
$ |
0.036876 |
|
|
October 21, 2016 |
|
October 31, 2016 |
|
November 15, 2016 |
|
$ |
0.031870 |
|
|
November 18, 2016 |
|
November 30, 2016 |
|
December 14, 2016 |
|
$ |
0.028057 |
|
|
Total—2016 |
|
|
|
|
|
$ |
0.257160 |
|
|
2015: |
|
|
|
|
|
|
| |
|
December 19, 2014 |
|
December 31, 2014 |
|
January 15, 2015 |
|
$ |
0.065822 |
|
|
January 20, 2015 |
|
January 30, 2015 |
|
February 13, 2015 |
|
$ |
0.006598 |
|
|
February 17, 2015 |
|
February 27, 2015 |
|
March 13, 2015 |
|
$ |
0.015796 |
|
|
March 20, 2015 |
|
March 31, 2015 |
|
April 14, 2015 |
|
$ |
0.037109 |
|
|
April 20, 2015 |
|
April 30, 2015 |
|
May 14, 2015 |
|
$ |
0.017598 |
|
|
May 18, 2015 |
|
May 29, 2015 |
|
June 12, 2015 |
|
$ |
0.023686 |
|
|
June 19, 2015 |
|
June 30, 2015 |
|
July 14, 2015 |
|
$ |
0.028013 |
|
|
July 21, 2015 |
|
July 31, 2015 |
|
August 14, 2015 |
|
$ |
0.020142 |
|
|
August 21, 2015 |
|
August 31, 2015 |
|
September 15, 2015 |
|
$ |
0.072243 |
|
|
September 18, 2015 |
|
September 30, 2015 |
|
October 15, 2015 |
|
$ |
0.055579 |
|
|
October 20, 2015 |
|
October 30, 2015 |
|
November 16, 2015 |
|
$ |
0.042364 |
|
|
November 19, 2015 |
|
November 30, 2015 |
|
December 14, 2015 |
|
$ |
0.032287 |
|
|
Total—2015 |
|
|
|
|
|
$ |
0.417237 |
|
8. DEVELOPMENT EXPENSE RESERVE
During the first quarter of 2016, Enduro established a reserve of $750,000 from the calculated net profits interest for approved 2016 development expenses, which was held by Enduro. During the second quarter of 2016, Enduro increased the previously established reserve by $100,000, for a total of $850,000 withheld for approved 2016 development expenses. During the year ended December 31, 2016, no development expenses were applied against the reserve. However, as a result of lower than anticipated capital expenditures, Enduro released $750,000 of the reserve during the second half of 2016, which increased the income from net profits interest for that period. During the first three months of 2017, Enduro released the remaining $100,000 of the reserve. Prior to 2016, Enduro had not established a reserve for development expenses.
ENDURO ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS—Continued
9. TRUSTEE FEES AND RELATED PARTY TRANSACTIONS
Trustee Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee and $2,000 to the Delaware Trustee. During the year ended December 31, 2017, the Trust paid $200,997 to the Trustee and $2,000 to the Delaware Trustee pursuant to the terms of the Trust Agreement. During the years ended December 31, 2016 and 2015, the Trust paid $201,032 and $200,100, respectively, to the Trustee and $0 and $2,000, respectively, to the Delaware Trustee.
Agreement with Enduro Resource Partners LLC. The Trust and Enduro are parties to a Registration Rights Agreement, as amended, whereby Enduro, its affiliates and certain permitted transferees holding registrable Trust Units are entitled, upon receipt by the Trustee of written notice from holders of a majority of the then outstanding registrable Trust Units, to demand that the Trust effect the registration of the registrable Trust Units. The holders of the registrable Trust Units are entitled to demand a maximum of five such registrations. In connection with the preparation and filing of any registration statement, Enduro will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust. Any underwriting discounts and commissions will be borne by the seller of the Trust Units.
10. PERMIAN BASIN OPERATOR ADJUSTMENT AND IMPACT ON FUTURE DISTRIBUTIONS
As previously disclosed, Enduro received a letter in July 2015 from one of its operators in the Permian Basin pertaining to 480,000 Mcf of natural gas for which the operator had paid Enduro on the Underlying Properties but for which Enduro had only produced 240,000 Mcf. Subsequently, the operator and Enduro agreed that the value of the overpaid production, totaling $1.1 million to the Underlying Properties, would be recouped with proceeds from future production.
During the recoupment period, which began during the second quarter of 2016, Enduro will not receive any revenue payments and future distribution calculations will not include any volumes or revenues from any of the operator’s properties until the $1.1 million is fully recovered. For the year ended December 31, 2017, these properties would have contributed approximately 5,900 Bbls, amounting to $0.2 million in oil receipts, and 191,200 Mcf, amounting to $0.5 million in natural gas receipts. After deducting $0.3 million in revenue deductions for taxes and transportation expenses, a total of $0.5 million has been withheld by the operator for the year ended December 31, 2017. For the year ended December 31, 2016, the properties would have contributed approximately 4,200 Bbls, amounting to $0.2 million in oil receipts, and 95,500 Mcf, amounting to $0.2 million in natural gas receipts. After deducting $0.1 million in revenue deductions for taxes and transportation expenses, a total of $0.3 million was withheld by the operator from the Underlying Properties in the year ended December 31, 2016.
Since the beginning of the recoupment period, these properties would have contributed approximately 10,100 Bbls, amounting to $0.4 million in oil receipts, and 286,700 Mcf, amounting to $0.7 million in natural gas receipts. After deducting $0.3 million in revenue deductions for taxes and transportation expenses, a total of $0.8 million has been withheld by the operator and, as a result, $0.4 million remains to be recouped in subsequent periods.
11. SUBSEQUENT EVENTS
Enduro Sale Process
On January 12, 2018, Enduro launched a process to sell all its oil and natural gas assets, including the Underlying Properties and its Trust Units. The Underlying Properties are being sold subject to the Trust’s 80% Net Profits Interest. If the sales process relating to the Underlying Properties is successful, Enduro expects the new owner to assume Enduro’s obligations as the sponsor of the Trust. There can be no assurances that Enduro’s sales process will be successful, in whole or in part, or that the new owner of working interests in the Underlying Properties will perform its obligations as sponsor of the Trust in a manner comparable to Enduro.
Distributions Paid or Declared
On January 16, 2018, the distribution of $0.016359 per Trust Unit, which was declared on December 18, 2017, was paid to Trust unitholders owning Trust Units as of December 29, 2017. The distribution consisted of net profits allocable to the Trust of $1,011,202, less a cumulative previous net profits shortfall of $421,367 for the prior two distribution periods and less cash reserves withheld for future Trust expenses of approximately $50,000.
Subsequent to December 31, 2017, the Trust declared the following distributions:
|
Declaration Date |
|
Record Date |
|
Payment Date |
|
Distribution per Unit |
| |
|
January 19, 2018 |
|
January 31, 2018 |
|
February 14, 2018 |
|
$ |
0.018433 |
|
|
February 16, 2018 |
|
February 28, 2018 |
|
March 14, 2018 |
|
$ |
0.037125 |
|
ENDURO ROYALTY TRUST
UNAUDITED SUPPLEMENTARY INFORMATION
Oil and Natural Gas Producing Activities
Oil and Natural Gas Reserve Quantities
Estimates of proved reserves attributable to the Trust and the related valuations were based 100% on reports prepared by the Trust’s independent petroleum engineers, Cawley, Gillespie & Associates, Inc. Estimates were prepared in accordance with guidelines prescribed by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements. Prices used in estimating reserves were as follows:
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Oil (per Bbl) |
|
$ |
51.34 |
|
$ |
42.75 |
|
$ |
50.28 |
|
|
Natural gas (per Mcf) |
|
$ |
2.98 |
|
$ |
2.48 |
|
$ |
2.59 |
|
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The process of estimating quantities of oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, these estimates are expected to change as additional information becomes available in the future.
As of December 31, 2017, 2016, and 2015, all of the Underlying Properties’ oil and natural gas reserves were attributable to properties within the United States. Proved reserves attributable to the Trust and related standardized measure valuations are prepared on an accrual basis, which is the basis on which Enduro and the Underlying Properties maintain their production records and is different from the basis on which the Trust production records are computed. The following is a summary of the changes in quantities of proved oil and natural gas reserves attributable to the Trust for the periods indicated:
|
|
|
Trust Net Profits Interest | |||||
|
|
|
Oil (1) |
|
Natural |
|
Total |
|
|
Balance—January 1, 2015 |
|
7,100 |
|
24,413 |
|
11,169 |
|
|
Extensions and discoveries |
|
25 |
|
26 |
|
29 |
|
|
Revisions of previous estimates |
|
(3,214 |
) |
(16,670 |
) |
(5,992 |
) |
|
Income from Net Profits Interest |
|
(191 |
) |
(961 |
) |
(351 |
) |
|
Balance—December 31, 2015 |
|
3,720 |
|
6,808 |
|
4,855 |
|
|
Extensions and discoveries |
|
5 |
|
5 |
|
6 |
|
|
Revisions of previous estimates |
|
(1,102 |
) |
699 |
|
(986 |
) |
|
Income from Net Profits Interest |
|
(108 |
) |
(1,818 |
) |
(411 |
) |
|
Balance—December 31, 2016 |
|
2,515 |
|
5,694 |
|
3,464 |
|
|
Extensions and discoveries |
|
92 |
|
2,638 |
|
531 |
|
|
Revisions of previous estimates |
|
624 |
|
167 |
|
652 |
|
|
Sales of Net Profits Interest |
|
(45 |
) |
(373 |
) |
(107 |
) |
|
Income from Net Profits Interest |
|
(89 |
) |
(1,094 |
) |
(271 |
) |
|
Balance—December 31, 2017 |
|
3,097 |
|
7,032 |
|
4,269 |
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
December 31, 2015 |
|
3,720 |
|
6,808 |
|
4,855 |
|
|
December 31, 2016 |
|
2,515 |
|
5,694 |
|
3,464 |
|
|
December 31, 2017 |
|
3,055 |
|
6,950 |
|
4,213 |
|
|
Proved undeveloped reserves: |
|
|
|
|
|
|
|
|
December 31, 2015 |
|
— |
|
— |
|
— |
|
|
December 31, 2016 |
|
— |
|
— |
|
— |
|
|
December 31, 2017 |
|
42 |
|
82 |
|
56 |
|
(1) Reserves for natural gas liquids are immaterial and included as a component of oil reserves.
Extensions and discoveries. During the year ended December 31, 2017, extensions and discoveries were primarily related to development activity in the Haynesville Shale in north Louisiana and the Pecos Valley field in west Texas. In 2017, six gross (0.5 net) wells were drilled in the Haynesville Shale and included as extensions. In addition, 3 gross (0.7 net) wells were drilled in the Pecos Valley field during the year, and those wells in addition to 5 gross (1.2 net) Pecos Valley locations added as proved undeveloped reserves are included as extensions. During the years ended December 31, 2016 and 2015, capital development activity on the Underlying Properties was limited and, as a result, there were minimal extensions and discoveries.
Revisions of previous estimates. During the year ended December 31, 2017, revisions of previous estimates increased oil reserves by 25%, primarily due to an increase in the average oil price used to estimate future net reserves. The NYMEX average oil price of $51.34 per Bbl used to determine reserves as of December 31, 2017 was 20% higher than the $42.75 per Bbl average NYMEX oil price as of December 31, 2016.
During the year ended December 31, 2016, revisions of previous estimates decreased oil reserves by 30%, primarily as a result of a decrease in the average oil price used to determine estimated future net reserves. The NYMEX average oil price of $42.75 per Bbl used to determine reserves as of December 31, 2016 was 15% lower than the $50.28 per Bbl average NYMEX oil price as of December 31, 2015. In addition to shortening the estimated lives of wells included in the Underlying Properties, this average oil price caused certain fields to not be economic, thereby further decreasing reserves quantities.
ENDURO ROYALTY TRUST
UNAUDITED SUPPLEMENTARY INFORMATION—Continued
During the year ended December 31, 2015, revisions of previous estimates decreased oil reserves by 45%, primarily due to price revisions as the average oil price used to determine estimated future net reserves decreased by $44.71 per Bbl, or 47%, from $94.99 per Bbl at December 31, 2014 to $50.28 per Bbl at December 31, 2015. Revisions of previous estimates for natural gas decreased natural gas reserves by 68% in 2015 primarily due to price revisions as the average natural gas price used to determine estimated future net reserves decreased by $1.76 per Mcf from $4.35 per Mcf at December 31, 2014 to $2.59 per Mcf at December 31, 2015.
Sales of net profits interest. As discussed in Note 4 of the Notes to Financial Statements, during the year ended December 31, 2017, the Trust divested of its Net Profits Interest in certain oil and natural gas properties in the Permian Basin. As a result of this divestiture, the proved reserves associated with the producing properties reduced the Trust’s total proved reserves on a BOE basis by approximately 3%.
Income from net profits interest. Income from net profits interest represents the reduction in total proved reserves as a result of net profits allocable to the Trust from the Underlying Properties during the applicable year, expressed as oil and natural gas reserve volumes. During the year ended December 31, 2017, as a result of increased capital development activity, net profits allocable to the Trust were reduced compared to the prior year, thereby reducing the income from net profits expressed as reserves.
During the year ended December 31, 2016, the reduction in oil reserves as a result of the realized income from net profits interest declined from the prior year due to reduced oil revenues. This decline was the result of decreased commodity pricing, thereby reducing the oil net profits attributable to the Trust. The reduction in natural gas volumes due to the realized income from net profits increased from the prior year as a result of reduced direct operating expenses. A reduction in direct operating expenses caused the net profit interest attributable to the Trust from natural gas to increase, thereby increasing the deduction.
During the year ended December 31, 2015, the decline in income from net profits interest was primarily related to the decline in oil and natural gas prices, partially offset by a decrease in development expenditures and production costs.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future cash inflows were computed by applying the commodity prices utilized in determining proved reserves to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. As the Trust is not subject to federal income taxes, future income taxes have been excluded.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves attributable to the Trust was as follows as of the dates indicated:
|
|
|
December 31, |
| |||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
|
|
(in thousands) |
| |||||||
|
Future cash inflows |
|
$ |
148,063 |
|
$ |
98,223 |
|
$ |
175,868 |
|
|
Future production taxes |
|
(12,081 |
) |
(8,127 |
) |
(14,630 |
) | |||
|
Future net cash flows |
|
$ |
135,982 |
|
$ |
90,096 |
|
$ |
161,238 |
|
|
10% annual discount for estimated timing of cash flows |
|
(69,041 |
) |
(46,236 |
) |
(82,858 |
) | |||
|
Standardized measure of discounted future net cash flows |
|
$ |
66,941 |
|
$ |
43,860 |
|
$ |
78,380 |
|
The changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves attributable to the Trust for the periods indicated were as follows (in thousands):
|
|
|
Year Ended December 31, |
| |||||||
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Extensions, discoveries, and other additions |
|
$ |
5,088 |
|
$ |
205 |
|
$ |
810 |
|
|
Sales of Net Profits Interest |
|
(980 |
) |
— |
|
— |
| |||
|
Accretion of discount |
|
4,386 |
|
7,838 |
|
28,716 |
| |||
|
Revisions of previous estimates and other |
|
22,257 |
|
(33,139 |
) |
(226,295 |
) | |||
|
Income from Net Profits Interest |
|
(7,670 |
) |
(9,424 |
) |
(12,008 |
) | |||
|
Change in present value of future net revenues |
|
23,081 |
|
(34,520 |
) |
(208,777 |
) | |||
|
Balance, beginning of period |
|
43,860 |
|
78,380 |
|
287,157 |
| |||
|
Balance, end of year |
|
$ |
66,941 |
|
$ |
43,860 |
|
$ |
78,380 |
|
Selected Quarterly Financial Data
The following table provides selected quarterly financial data for the periods indicated:
|
|
|
Quarter |
| ||||||||||
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
| ||||
|
Year Ended December 31, 2017: |
|
|
|
|
|
|
|
|
| ||||
|
Income from Net Profits Interest |
|
$ |
2,378,074 |
|
$ |
3,546,015 |
|
$ |
1,549,611 |
|
$ |
170,260 |
|
|
Income from sale of Net Profits Interest on undeveloped acreage |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
36,300,165 |
|
|
Income from sale of Net Profits Interest on producing properties |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
1,650,000 |
|
|
Distributable income |
|
$ |
2,228,028 |
|
$ |
3,271,026 |
|
$ |
1,174,602 |
|
$ |
38,070,417 |
|
|
Distributions per unit |
|
$ |
0.067516 |
|
$ |
0.099122 |
|
$ |
0.035594 |
|
$ |
1.153649 |
|
|
Year Ended December 31, 2016: |
|
|
|
|
|
|
|
|
| ||||
|
Income from Net Profits Interest |
|
$ |
3,169,942 |
|
$ |
708,982 |
|
$ |
1,992,888 |
|
$ |
3,344,508 |
|
|
Distributable income |
|
$ |
2,749,923 |
|
$ |
598,950 |
|
$ |
1,942,908 |
|
$ |
3,194,499 |
|
|
Distributions per unit |
|
$ |
0.083331 |
|
$ |
0.018150 |
|
$ |
0.058876 |
|
$ |
0.096803 |
|
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures (as defined in Rules 13a-15 and 15d-15 under the Exchange Act). Based on this evaluation, the Trustee has concluded that the disclosure controls and procedures of the Trust were effective, as of the end of the period covered by this report, in ensuring that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure.
Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the Trust Agreement and (ii) the Conveyance, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by Enduro, including information relating to results of operations, the costs and revenues attributable to the Trust’s interest under the Conveyance and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Net Profits Interest, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.
Changes in Internal Control over Financial Reporting. During the quarter ended December 31, 2017, there were no changes in the Trust’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Enduro.
TRUSTEE’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with the modified cash basis of accounting. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control—Integrated Framework (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2017. The independent registered public accounting firm of Ernst & Young LLP, the independent registered accounting firm that audited the financial statements of the Trust in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2017, which is included in this Item 9A.
Report of Independent Registered Public Accounting Firm
To the Trustee and Unitholders of Enduro Royalty Trust
Opinion on Internal Control over Financial Reporting
We have audited Enduro Royalty Trust’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Enduro Royalty Trust (the Trust) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the statements of assets, liabilities, and trust corpus of Enduro Royalty Trust as of December 31, 2017 and 2016, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2017, and the related notes and our report dated March 12, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
The Trustee 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 Trustee’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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
An entity’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. An entity’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 entity; (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 entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’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.
/s/ Ernst & Young LLP
Fort Worth, Texas
March 12, 2018
None.
Item 10. Directors, Executive Officers and Corporate Governance.
The Trust has no directors or executive officers. The Trustee is a corporate Trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust Units at a meeting at which a quorum is present.
Section 16(a) Beneficial Ownership Reporting Compliance
The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust’s units are required to file with the SEC initial reports of ownership of units and reports of changes in such ownership pursuant to Section 16 under the Exchange Act. Based solely on a review of these reports and any such reports furnished to the Trustee, the Trustee is not aware of any person having failed to file on a timely basis the reports required by Section 16(a) of the Exchange Act during the most recent fiscal year.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and has not adopted a code of ethics applicable to such persons.
Item 11. Executive Compensation.
Pursuant to the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee. During the year ended December 31, 2017, the Trustee received $200,997 in administrative fees and reimbursable expenses from the Trust. During the years ended December 31, 2016 and 2015, the Trustee received $201,032 and $200,100, respectively, in administrative fees and reimbursable expenses from the Trust. The Trust does not have any executive officers, directors or employees. The Trust does not have a board of directors, and it does not have a compensation committee.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
(a) Security Ownership of Certain Beneficial Owners.
Based on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the units as of March 6, 2018 except as set forth below. The following information has been obtained from public filings with the SEC.
|
Beneficial Owner |
|
Trust Units |
|
Percent of |
|
|
Enduro Resource Partners LLC |
|
8,600,000 |
(1) |
26.1 |
% |
|
Enduro Resource Holdings LLC |
|
8,600,000 |
(2) |
26.1 |
% |
|
R/C IV Enduro Holdings, L.P. |
|
8,600,000 |
(3) |
26.1 |
% |
|
Riverstone/Carlyle Energy Partners IV, L.P |
|
8,600,000 |
(4) |
26.1 |
% |
|
R/C Energy GP IV, LLC |
|
8,600,000 |
(5) |
26.1 |
% |
|
Jerry Roger Kent |
|
1,892,238 |
(6) |
5.7 |
% |
(1) Reference is hereby made to the Schedule 13D filed by the reporting person on October 11, 2013 for additional information regarding the beneficial ownership of the reporting person.
(2) Reference is hereby made to the Schedule 13D filed by the reporting person on October 11, 2013 for additional information regarding the beneficial ownership of the reporting person. Enduro Resource Holdings LLC does not directly own any Trust Units. By virtue of being the sole member of Enduro Resource Partners LLC, Enduro Resource Holdings LLC may be deemed to possess shared voting and dispositive powers with respect to the 8,600,000 Trust Units held by Enduro Resource Partners LLC.
(3) Reference is hereby made to the Schedule 13D filed by the reporting person on October 11, 2013 for additional information regarding the beneficial ownership of the reporting person. R/C IV Enduro Holdings, L.P. does not directly own any Trust Units. By virtue of owning 92.7% of the limited liability company interests in Enduro Resource Holdings LLC, R/C IV Enduro Holdings, L.P. may be deemed to possess shared voting and dispositive powers with respect to the 8,600,000 Trust Units held by Enduro Resource Partners LLC.
(4) Reference is hereby made to the Schedule 13D filed by the reporting person on October 11, 2013 for additional information regarding the beneficial ownership of the reporting person. Riverstone/Carlyle Energy Partners IV, L.P. does not directly own any Trust Units. By virtue of being the sole general partner of R/C IV Enduro Holdings, L.P., Riverstone/Carlyle Energy Partners IV, L.P. may be deemed to possess shared voting and dispositive powers with respect to the 8,600,000 Trust Units held by Enduro Resource Partners LLC.
(5) Reference is hereby made to the Schedule 13D filed by the reporting person on October 11, 2013 for additional information regarding the beneficial ownership of the reporting person. R/C Energy GP IV, LLC does not directly own any Trust Units. By virtue of being the sole general partner of Riverstone/Carlyle Energy Partners IV, L.P, R/C Energy GP IV, LLC may be deemed to possess shared voting and dispositive powers with respect to the 8,600,000 Trust Units held by Enduro Resource Partners LLC.
(6) Reference is hereby made to the Schedule 13G/A filed by the reporting person on February 12, 2018 for additional information regarding the beneficial ownership of the reporting person.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant. See “Certain Relationships and Related Transactions, and Director Independence—Registration Rights Agreement” in Item 13 of this Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Trustee Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee and $2,000 to the Delaware Trustee.
Registration Rights Agreement. The Trust and Enduro are parties to a Registration Rights Agreement, as amended, whereby Enduro, its affiliates and certain permitted transferees holding registrable Trust Units are entitled, upon receipt by the Trustee of written notice from holders of a majority of the then outstanding registrable Trust Units, to demand that the Trust effect the registration of the registrable Trust Units. The holders of the registrable Trust Units are entitled to demand a maximum of five such registrations. In connection with the preparation and filing of any registration statement, Enduro will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust. Any underwriting discounts and commissions will be borne by the seller of the Trust Units. The foregoing description of the Registration Rights Agreement is qualified in its entirety by the terms of the Registration Rights Agreement, and Amendment No. 1 thereto, copies of which are incorporated by reference as exhibits to this Form 10-K.
Director Independence
The Trust does not have a board of directors.
Item 14. Principal Accounting Fees and Services.
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee. During the years ended December 31, 2017, 2016 and 2015, Ernst & Young, LLP served as the Trust’s independent registered public accounting firm. The Trustee also has appointed Ernst & Young, LLP as the independent registered public accounting firm to audit the Trust’s financial statements for the fiscal year ending December 31, 2018.
The following table presents the aggregate fees billed to the Trust for the years ended December 31, 2017, 2016 and 2015 by Ernst & Young, LLP:
|
|
|
2017 |
|
2016 |
|
2015 |
| |||
|
Audit fees(1) |
|
$ |
181,367 |
|
$ |
137,516 |
|
$ |
183,091 |
|
|
Audit-related fees |
|
— |
|
— |
|
— |
| |||
|
Tax fees |
|
— |
|
— |
|
— |
| |||
|
All other fees |
|
— |
|
— |
|
— |
| |||
|
Total fees |
|
$ |
181,367 |
|
$ |
137,516 |
|
$ |
183,091 |
|
(1) Fees billed for professional services rendered for the integrated audit of the Trust’s financial statements and reviews of the financial statements included in the Trust’s quarterly reports.
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements
The following financial statements are set forth under “Financial Statements and Supplementary Data” in Item 8 of this Form 10-K on the pages indicated:
|
|
|
Page in this |
|
|
Enduro Royalty Trust |
|
|
|
|
|
37 |
| |
|
|
38 |
| |
|
|
39 |
| |
|
|
40 |
| |
|
|
41 |
| |
|
|
48 |
|
(a)(2) Schedules
Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
(a)(3) Exhibits
See Index to Exhibits.
None.
INDEX TO EXHIBITS
|
Exhibit |
|
Description |
|
|
|
|
|
2.1* |
|
|
|
|
|
|
|
3.1* |
|
|
|
|
|
|
|
3.2* |
|
|
|
|
|
|
|
3.3* |
|
|
|
|
|
|
|
4.1* |
|
|
|
|
|
|
|
4.2* |
|
|
|
|
|
|
|
10.1* |
|
|
|
|
|
|
|
10.2* |
|
|
|
|
|
|
|
10.3* |
|
|
|
|
|
|
|
10.4* |
|
|
|
|
|
|
|
23.1 |
|
|
|
|
|
|
|
31.1 |
|
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
|
|
|
|
32.1 |
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
|
|
99.1 |
|
* Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
Date: March 12, 2018 |
ENDURO ROYALTY TRUST | ||
|
|
| ||
|
|
By: |
THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., AS TRUSTEE | |
|
|
By: |
/s/ SARAH NEWELL | |
|
|
|
Name: |
Sarah Newell |
|
|
Title: |
Vice President | |
The Registrant, Enduro Royalty Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust Agreement under which it serves.