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EX-99.1 - EX-99.1 - Permianville Royalty Trustd504442dex991.htm
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Table of Contents

 

 

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, 2012

or

 

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

For the transition period from                      to                     

Commission File Number 001-35333

 

 

ENDURO ROYALTY TRUST

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   45-6259461

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

The Bank of New York Mellon Trust Company, N.A., Trustee

Global Corporate Trust

919 Congress Avenue, Suite 500

Austin, Texas

  78701
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (800) 852-1422

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

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Units of Beneficial Interest   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  ¨    No  x.

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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

 

Large accelerated filer   ¨      Accelerated filer   x
Non-accelerated filer   ¨   (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates (13,200,000 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 $217,140,000.

As of March 14, 2013, 33,000,000 Units of Beneficial Interest of the Trust were outstanding.

 

 

Documents Incorporated By Reference: None

 

 

 


Table of Contents

TABLE OF CONTENTS

 

Forward-Looking Statements

    1   

Glossary of Certain Oil and Natural Gas Terms

    2   
PART I   

Item 1.

 

Business

    5   

Item 1A.

 

Risk Factors

    21   

Item 1B.

 

Unresolved Staff Comments

    35   

Item 2.

 

Properties

    36   

Item 3.

 

Legal Proceedings

    41   

Item 4.

 

Mine Safety Disclosures

    41   
PART II   

Item 5.

 

Market for Registrant’s Trust Units, Related Unitholder Matters and Issuer Purchases of Trust Units

    42   

Item 6.

 

Selected Financial Data

    43   

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

    44   

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

    52   

Item 8.

 

Financial Statements and Supplementary Data

    54   

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    90   

Item 9A.

 

Controls and Procedures

    90   

Item 9B.

 

Other Information

    92   
PART III   

Item 10.

 

Directors, Executive Officers and Corporate Governance

    92   

Item 11.

 

Executive Compensation

    92   

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

    92   

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    93   

Item 14.

 

Principal Accounting Fees and Services

    93   
PART IV   

Item 15.

 

Exhibits, Financial Statement Schedules

    94   

SIGNATURES

    95   

Appendix A

 

Reserve Summary Report of Cawley, Gillespie & Associates, Inc. dated January 18, 2013

    A-1   

 

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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.

FORWARD-LOOKING STATEMENTS

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 any statements 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 impact of hedge contracts;

 

   

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 us 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.

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this Form 10-K the following terms have the meanings specified below.

Bbl—One stock tank barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.

Boe—One stock tank 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.

Gross acres or gross wells—The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal well—A well that starts off being drilled vertically but which is eventually curved to become horizontal (or near horizontal) in order to parallel a particular geologic formation.

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.

 

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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 person’s 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 for fiscal years ending on or after December 31, 2009, 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—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 well bore in another formation from which that well has been previously completed.

 

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Reservoir—A porous and permeable underground formation containing a natural accumulation of producible oil and/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, 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.

 

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PART I

 

Item 1. Business.

Enduro Royalty Trust (the “Trust”) is a Delaware statutory trust formed in May 2011 (“Inception”) pursuant to a trust agreement dated May 3, 2011 (as amended and restated on November 3, 2011, 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, east Texas and north Louisiana.

In connection with the closing of the initial public offering of units of beneficial interest in the Trust (“Trust Units”) on November 8, 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 80% of the net profits from the sale of oil and natural gas production from certain properties in Texas, Louisiana and New Mexico. Enduro Operating and Enduro Texas entered into a Conveyance of Net Profits Interest, dated effective as of July 1, 2011 (the “Conveyance”), to effect the transfer of the Net Profits Interest from Enduro Operating to Enduro Texas.

On November 8, 2011, the merger (the “Trust Merger”) of Enduro Texas with and into the Trust pursuant to an Agreement and Plan of Merger dated November 3, 2011 (the “Trust Merger Agreement”), became effective. 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 (the “Conveyance Supplement”) 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 Conveyance, Enduro completed an initial public offering of 13,200,000 Trust Units at a price to the public of $22 per unit.

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

 

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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”); and

 

   

enforcing the Trust’s rights under certain agreements.

In connection with the formation of the Trust, the Trust entered into several agreements with Enduro that impose obligations upon Enduro that are enforceable by the Trustee on behalf of the Trust, 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 to which the Trust is a party 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 or any affiliate of either of them 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 entity serving as Trustee, 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. 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, draws on the letter of credit or Enduro loans funds to the Trust, 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 must 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.

 

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Alternatively, cash held for distribution at the next distribution date may be held in a noninterest-bearing account.

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 will not be 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 will be 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, in the event that the oil or natural gas is processed, the net profits will 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. Enduro does not believe that the loss of any of these parties as a purchaser of crude oil production from the Underlying Properties would have a material impact on the business or operations of Enduro or the Underlying Properties because of the competitive marketing conditions in Texas, Louisiana and New Mexico.

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 percentage of a published regional index price, after adjustments for Btu content, transportation and related charges.

For the year ended December 31, 2012, ConocoPhillips, Occidental Petroleum Corporation, and Navajo Refining accounted for approximately 30%, 21%, and 10%, respectively, of sales from the Underlying Properties. ConocoPhillips and Occidental Petroleum Corporation accounted for approximately 35% and 18%, respectively, of sales from the Underlying Properties that were included in calculating the Trust’s Net Profits Interest from Inception through December 31, 2011.

 

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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 price fluctuations 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, future product prices or the effect of future product prices on 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.

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 14, 2013.

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.

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

 

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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 governs 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, 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. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will 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 or any material part of the assets of the Trust (including the sale of the Net Profits Interest).

In addition, certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders.

 

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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 included 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. The Trustee expects to make distributions to Trust unitholders monthly.

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;

 

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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;

 

   

all administrative hedge costs paid from and after July 1, 2011 (in respect of hedges existing prior to the date of the Conveyance, as further described in the Conveyance);

 

   

all hedge settlement costs paid from and after July 1, 2011 (in respect of hedges existing prior to the date of the Conveyance, as further described in the Conveyance);

 

   

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, all of the hedge payments received by Enduro from and after July 1, 2011 from hedge contract counterparties upon settlement of hedge contracts and certain other 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. 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.

 

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Gross profits and net profits are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.

Commodity Hedges

The Trust is exposed to fluctuations in energy prices in the normal course of business due to the Net Profits Interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that Enduro and its third party operators can economically produce. To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the Trust and to achieve more predictable cash flow, Enduro entered into hedge contracts with respect to approximately 41% and 67% of expected oil and natural gas production, respectively, for 2013 from the total proved reserves attributable to the Underlying Properties as of December 31, 2012. These hedge contracts include a combination of fixed price swaps, collars and floors. These contracts reduce the exposure of the revenues from oil and natural gas production from the Underlying Properties; however, these contracts also limit the amount of cash available for distribution if prices increase above the fixed hedge price. After the production month of December 31, 2013, none of the production attributable to the Underlying Properties will be hedged. As a result, the amount of the cash distributions will be subject to the possibility of greater fluctuations after 2013 due to changes in oil and natural gas prices.

The following table sets forth the volumes of Enduro’s natural gas commodity derivative contracts related to the Underlying Properties, the weighted average contractual prices per Mcf, and the weighted average NYMEX equivalent prices per Mcf as of December 31, 2012:

 

     Put Contracts      Swap Contracts  
Period    Daily
Volumes
     Average
Contractual
Price
     Average
NYMEX
Equivalent
Price(1)
     Daily
Volumes
     Average
Contractual
Price
     Average
NYMEX
Equivalent
Price(1)
 
     (Mcf)      ($/Mcf)      ($/Mcf)      (Mcf)      ($/Mcf)      ($/Mcf)  

2013

     8,000       $ 4.90       $ 5.01         4,000       $ 5.00       $ 5.09   

 

(1) 

Enduro’s natural gas derivative contracts related to the Underlying Properties are comprised of contracts entered into at local basis points, such as Centerpoint and El Paso Permian, as well as NYMEX-based contracts. For presentation purposes and for comparability among the various contracts, the contract prices were converted to NYMEX equivalent prices using estimated basis differentials in the over-the-counter futures market.

The following table sets forth the volumes of Enduro’s oil commodity derivative contracts related to the Underlying Properties and the weighted average NYMEX prices per Bbl as of December 31, 2012:

 

     Three-Way Collars         
Period    Daily
Volumes
     Average
Sub-
Floor
Price
     Average
Floor
Price
     Average
Cap
Price
     Daily
Swap
Volumes
     Average
Swap
Price
 
     (Bbls)      ($/Bbl)      ($/Bbl)      ($/Bbl)      (Bbls)      ($/Bbl)  

2013

     500       $ 67.50       $ 90.00       $ 110.00         510       $ 102.97   

The amounts received by Enduro from the hedge contract counterparty upon settlement of the hedge contracts will reduce the operating expenses related to the Underlying Properties in calculating net profits. In addition, the aggregate amounts paid by Enduro on settlement of the hedge contracts related to the Underlying Properties will reduce the amount of net profits paid to the Trust. See “Computation of Net Profits—Net Profits Interest.”

 

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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 nonaffiliated 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 identified for sale any of the Underlying Properties.

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

 

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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.

Federal Income Tax Matters

The following is a summary of certain U.S. 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 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 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 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 39.6%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains

 

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(generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Such marginal tax rates may be effectively increased by up to 1.2% due to the phaseout of personal exemptions and the limitations on itemized deductions. The highest marginal U.S. federal income tax rate applicable to corporations is 35%, 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 for taxable years beginning after December 31, 2012. 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 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 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., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, 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.

 

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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. 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. However, the clear 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

 

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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). 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 and hydraulic fracturing. 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. 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. 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.

 

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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.

It is customary to recover oil and natural gas from deep shale and tight sand formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. In addition, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with a progress report released in late 2012 and a final draft report expected to be released for public comment and peer review in late 2014. The results of this study could spur further action toward federal legislation and regulation of hydraulic fracturing activities. The EPA has also asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Safe Drinking Water Act’s Underground Injection Control Program and has released draft guidance documents regarding the process for obtaining a permit for hydraulic fracturing involving diesel fuel, and the U.S. Bureau of Land Management has proposed rules that would impose new requirements on hydraulic fracturing operations conducted on public lands. Also some states, including states in which Enduro operates, have adopted, or 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. Disclosures of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for Enduro or the third party operators to perform hydraulic fracturing activities.

Air emissions. The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting 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. 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 Enduro, its 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. While these rules remain in effect, the EPA has announced that it will reexamine and reissue the rules over the next several years. 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. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels.

 

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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.

In addition, on December 15, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted regulations that limit emissions of GHGs from motor vehicles beginning with the 2012 model year. On June 3, 2010, the EPA also published regulations to address the permitting of GHG emissions from stationary sources under Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. On June 26, 2012, the U.S. Circuit Court for the District of Columbia upheld the EPA’s GHG regulations; a petition for review by the U.S. Supreme Court has not yet been filed and would be due in late March 2013. In addition, on November 30, 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, but industry groups have filed suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. The Underlying Properties may be subject to these requirements or become subject to them in the future.

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. 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

 

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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 (“ESA”) 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. While some of Enduro’s facilities or leased acreage may be located in areas that are or will be designated as habitat for endangered or threatened species, Enduro believes that it is in substantial compliance with the ESA.

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, or “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. Enduro believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

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 SEC at http://www.sec.gov. In addition, the Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.

 

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Item 1A. Risk Factors.

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. Prices of oil and natural gas 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 prices of oil and natural gas 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. In addition, the operators could determine during periods of low commodity prices to 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. If this scenario were to occur, 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 entered into hedge contracts with respect to approximately 41% and 67% of expected production of oil and natural gas production, respectively, for 2013 from the total proved reserves attributable to the Underlying Properties in the reserve report as of December 31, 2012. The hedge contracts are intended to reduce exposure of the revenues from oil and natural gas production from the Underlying Properties to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Some of the hedge contracts could limit the benefit to the Trust of any increase in oil or natural gas prices through 2013. The Trust will be required to bear its share of the hedge payments regardless of whether the

 

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corresponding quantities of oil and natural gas are produced or sold. Furthermore, 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 of the Net Profits Interest prohibit Enduro from entering into new hedging arrangements burdening the Trust. As a result, the amount of the cash distributions will be subject to the possibility of greater fluctuations after 2013 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 third party operators are the operators of approximately 99% 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, 2012, approximately 99% of the wells on the Underlying Properties were operated by the 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 are 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;

 

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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:

 

   

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;

 

   

reductions in oil or natural gas prices;

 

   

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.

In the event that planned operations, including drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, estimated future distributions to Trust unitholders may be reduced. In

 

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the event an operator incurs increased costs due to one or more of the above factors or for any other reason and is not able to recover such costs from insurance, the estimated future distributions to Trust unitholders may be reduced.

The Trust is passive in nature and neither the Trust nor the Trust unitholders will 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, will 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. The third party operators operate approximately 99% 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 since December 2010. 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

 

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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 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.

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.

 

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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 expenses, development expenses and hedge 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 expenses, development expenses and hedge 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

 

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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 19,800,000 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 has registration rights and can 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.

 

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The Trust is managed 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 managed 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 Enduro so long as it holds 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 Net Profits Interest 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. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will 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. These

 

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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 with limits of $1 million and $20 million per occurrence, respectively, and $2 million and $20 million in the aggregate, respectively. Enduro’s excess liability coverage has a deductible of $10,000 per occurrence, while there is no deductible on the general liability insurance. The general liability insurance covers Enduro and its

 

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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 ranging from $5 million to $20 million and deductibles ranging from $100,000 to $200,000 depending on the status of the well. 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. In order 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.

 

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New laws or regulations, or changes to existing laws or regulations, may unfavorably impact the operators of the Underlying Properties, could 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. On December 15, 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, according to the EPA, 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 require a reduction in emissions of GHGs from motor vehicles as well as 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 26, 2012, the U.S. Circuit Court for the District of Columbia upheld the EPA’s GHG regulations. A petition for review by the U.S. Supreme Court has not yet been filed and would be due in late March 2013. 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, on November 30, 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, although industry groups have filed suit challenging certain provisions of the rules and are engaged in settlement negotiations to amend and correct the rules. 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.

 

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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, 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, 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, particularly natural gas, 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 involving diesel fuel under the Safe Drinking Water Act’s Underground Injection Control Program and has released draft guidance documents regarding the process for obtaining a permit for hydraulic fracturing involving diesel fuel. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with a progress report released in late 2012 and a final draft report expected to be released for public comment and peer review in late 2014. The U.S. Bureau of Land Management has also proposed rules that would impose new requirements on hydraulic fracturing operations conducted on public lands. Also, 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. Further, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities, while some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered or imposed temporary moratoria on drilling operations using hydraulic fracturing until further study of the potential environmental and human health impacts by the EPA or the relevant agencies are completed. 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. 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.

 

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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 Securities Exchange Act of 1934, as amended (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 held 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.

It is well-established under Texas law that the conveyance of a net profits interest constitutes the conveyance of a presently vested, non-possessory interest in real property. Therefore, 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. Likewise, Enduro and the Trust believe that the Net Profits Interest would be viewed as a separate property interest under the laws of Louisiana and outside of Enduro’s bankruptcy estate. Since enactment of the Louisiana Mineral Code in 1975, Louisiana courts have classified an overriding royalty interest as a real right and an incorporeal immovable (similar to a real property interest). Although there are no reported Louisiana court cases addressing whether a net profits interest, carved out of the interest of a mineral lessee under an oil and gas lease, should be similarly classified as a real right and an incorporeal immovable, a 1972 Colorado federal court applying Louisiana law did conclude that such a net profits interest was comparable to an overriding royalty interest and, thus, was properly so classified. Similarly, Enduro and the Trust believe that a New Mexico court would rule that the conveyance of a net profits interest constitutes a conveyance of a real property interest. While no New Mexico case has clearly defined the nature of a “net profits interest” independent of the creating instrument, New Mexico case law has held that an overriding royalty interest in a mineral lease is a real property interest under New Mexico law. The 10th Circuit Court of Appeals has held that a net profits interest is “similar to” an overriding royalty interest. Given that the Conveyance contains a provision stating that it is the express intent of the parties that the Conveyance constitutes a conveyance of a royalty interest in real property, in the event of a bankruptcy on the part of Enduro, under New Mexico law, the Net Profits Interest would likely not be treated as part of Enduro’s bankruptcy estate. Further, it is relevant that Enduro and the Trust have structured the Net Profits Interest as an overriding royalty interest in gross production payable on the basis of net profits. Nevertheless, the outcome is not certain given that there are not any dispositive Louisiana or New Mexico Supreme Court cases directly concluding that a conveyance of a Net Profits Interest: (i) in the case of Louisiana, constitutes the conveyance of a real right and an incorporeal immovable (similar to a real property interest) or (ii) in the case of New Mexico, constitutes the conveyance of a real property interest. As such, in a bankruptcy of Enduro, to the extent Louisiana or New Mexico law were held to be applicable, the Net Profits Interest

 

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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.

The receipt of payments by Enduro based on the hedge contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the Trust unitholders.

Payments from hedge contract counterparties to Enduro are intended to offset costs and thus have the effect of providing additional cash to the Trust during periods of lower crude oil and natural gas prices. In the event that any of the counterparties to the hedge contracts default on their obligations to make payments to Enduro under the hedge contracts, the cash distributions to the Trust unitholders could be materially reduced. Enduro does not have any security interest from its hedge counterparties against which it could recover in the event of a default by any such counterparty.

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 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 federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to 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.

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.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

In recent years, the Obama administration’s budget proposals and other proposed legislation have included elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these provisions would eliminate certain tax preferences

 

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applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to the repeal of the percentage depletion allowance for oil and gas properties. It is unclear whether any such changes will be enacted and, if so, when any such changes would become effective.

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 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.

 

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Item 2. Properties.

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, 2012, the Underlying Properties had proved reserves of 21.4 MMBoe. As of December 31, 2012, approximately 90% of the volumes and substantially all of the PV-10 value of the proved reserves associated with the Underlying Properties were attributable to proved developed reserves. As of December 31, 2012, substantially all of the proved reserves attributable to the Underlying Properties, 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, 2012, Enduro held average working interests of approximately 15% and 21% and average net revenue interest of approximately 13% 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, 2012. 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 John W. Arms, Enduro’s Executive Vice President and Chief Operating Officer. Mr. Arms received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1991. Prior to co-founding Enduro, Mr. Arms was Senior Vice President of Acquisitions for Encore Acquisition Company. Mr. Arms has over 20 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Arms consults regularly 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, 2012 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 estimate with respect to the Underlying Properties and the Net Profits Interest attributable to the Trust is Robert D. Ravnaas. Mr. Ravnaas has been a petroleum consultant for Cawley Gillespie since 1983, and became Executive Vice President in 1999. He is a registered professional engineer in the State of Texas (license no. 61304) and a graduate of the University of Texas with an M.S. in Petroleum Engineering. In addition, Mr. Ravnaas received a B.Sc. with special honors in Chemical Engineering from the University of Colorado.

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

 

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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, 2012:

 

    Trust Net Profits Interest     Underlying Properties  
    Oil     Natural Gas     Total     PV-10     Oil     Natural Gas     Total     PV-10  
    (MBbls)     (MMcf)     (MBOE)     (in thousands)     (MBbls)     (MMcf)     (MBOE)     (in thousands)  

Proved Developed Producing

    5,307        19,264        8,518      $ 239,739        12,139        41,698        19,089      $ 299,673   

Proved Developed Non-Producing

    17        15        19        802        29        27        33        1,003   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved Developed

    5,324        19,279        8,537        240,541        12,168        41,725        19,122        300,676   

Proved Undeveloped

    —         1,050        175        (2,750     —         13,402        2,234        (3,436
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Proved

    5,324        20,329        8,712      $ 237,791        12,168        55,127        21,356      $ 297,240   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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 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 gas reserves.

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, 2012
    May 3, 2011
(Inception) through
December 31, 2011
 
     (in thousands)  

Conveyance of Net Profits Interest by Enduro

   $ —        $ 290,665   

Extensions, discoveries, and other additions

     802        4,202   

Accretion of discount

     29,054        4,844   

Revisions of previous estimates and other

     (29,709     —    

Net profits income

     (52,898     (9,169
  

 

 

   

 

 

 

Change in present value of future net revenues

     (52,751     290,542   

Balance, beginning of period

     290,542        —    
  

 

 

   

 

 

 

Balance, end of year

   $ 237,791      $ 290,542   
  

 

 

   

 

 

 

The following average oil and natural gas prices were used to determine the estimated future net revenues from the Underlying Properties for the periods indicated.

 

     2012      2011  

Oil (per Bbl)

   $ 94.71       $ 96.19   

Natural gas (per Mcf)

   $ 2.75       $ 4.11   

The estimates are for proved reserves only and do not include any probable or possible reserves nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.

 

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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, 2012.

 

     Acres  
     Gross      Net  

Permian Basin

     142,684         32,419   

East Texas/North Louisiana

     13,380         4,994   
  

 

 

    

 

 

 

Total

     156,064         37,413   
  

 

 

    

 

 

 

The following is a summary of the producing wells on the Underlying Properties as of December 31, 2012:

 

     Oil      Natural Gas  
     Gross  Wells(1)      Net Wells      Gross  Wells(1)      Net Wells  

Permian Basin

     3,551         338         124         16   

East Texas/North Louisiana

     —          —          410         85   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     3,551         338         534         101   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Enduro’s total wells include 17 operated wells and 4,068 non-operated wells. At December 31, 2012, 183 of Enduro’s wells had multiple completions.

The following is a summary of the number of development and exploratory wells drilled on the Underlying Properties during the last three years.

 

     Year Ended December 31,  
     2012      2011      2010  
     Gross      Net      Gross      Net      Gross      Net  

Permian Basin

                 

Development Wells:

                 

Productive

     18         2.6         16         4.2         55         10.9   

Dry holes

     1         0.5         —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     19         3.1         16         4.2         55         10.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Exploratory Wells:

                 

Productive

     —          —          —          —          —          —    

Dry holes

     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total:

                 

Productive

     18         2.6         16         4.2         55         10.9   

Dry holes

     1         0.5         —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     19         3.1         16         4.2         55         10.9   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Table of Contents
     Year Ended December 31,  
      2012      2011      2010  
     Gross      Net      Gross      Net      Gross      Net  

East Texas/North Louisiana

                 

Development Wells:

                 

Productive

     —          —          28         2.7         3         0.3   

Dry holes

     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     —          —          28         2.7         3         0.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Exploratory Wells:

                 

Productive

     —          —          —          —          8         0.7   

Dry holes

     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     —          —          —          —          8         0.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total:

                 

Productive

     —          —          28         2.7         11         1   

Dry holes

     —          —          —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
     —          —          28         2.7         11         1   

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 57% of the future production from the Underlying Properties is expected to be oil and approximately 43% 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 142,684 gross (32,419 net) acres in Texas and New Mexico.

Four of the largest fields in the Permian Basin region of the Underlying Properties are the following (measured by PV-10 value):

 

   

The largest field in the Permian Basin region is the Apache operated North Central Levelland Unit discovered in 1937. This unit is a waterflood property and produces from the San Andres formation at a depth of approximately 4,900 feet. Proved reserves attributable to the Underlying Properties in the North Central Levelland Unit were 2.5 MMBoe as of December 31, 2012.

 

   

The second largest field in the Permian Basin region is the Apache operated North Monument Grayburg Unit discovered in 1929. Proved reserves attributable to the Underlying Properties in the North Monument Grayburg Unit were 2.4 MMBoe as of December 31, 2012.

 

   

The third 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 1.8 MMBoe as of December 31, 2012.

 

   

The fourth largest field in the Permian Basin region is the North Cowden Unit discovered in 1930. The North Cowden Unit is undergoing both waterflood and CO2 recovery processes. This unit produces from the Grayburg formation at a depth of 4,500 feet. Proved reserves attributable to the Underlying Properties in the North Cowden field were 2.0 MMBoe as of December 31, 2012. The operator of the North Cowden field is Occidental.

 

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Table of Contents

East Texas/North Louisiana Region

The Underlying Properties contain interests in 13,380 gross (4,994 net) acres in the East Texas/North Louisiana region across three fields: the Elm Grove Field, operated by Petrohawk, the Kingston Field, operated by EXCO Resources, Inc., and the Stockman Field, operated by Enduro. In the Kingston Field, EXCO Resources has drilled wells on 80-acre well spacing. The proved reserves associated with the Underlying Properties in the East Texas/North Louisiana region do not include reserves attributable to 80-acre well spacing nor are there any reserves from the Bossier, Cotton Valley Lime or Smackover formations. However, the Underlying Properties include the economic rights to production from these formations on Enduro’s acreage position in the event that production is generated from them. Enduro will not be able to influence development activities in the non-operated fields, and no assurance can be given that such down spacing will continue or that the referenced additional formations will be produced.

Abandonment and Sale of Underlying Properties

The operators of the Underlying Properties or any transferee will have 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, in one degree or another, 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;

 

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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 that 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 that 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.

In order to give third parties notice of the Net Profits Interest, Enduro recorded the Conveyance of the Net Profits Interest 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 held 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 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.”

 

Item 3. Legal Proceedings.

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.

 

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Table of Contents

PART II

 

Item 5. Market for Registrant’s Trust Units, Related Unitholder Matters and Issuer Purchases of Trust Units.

The Trust Units commenced trading on the New York Stock Exchange on November 3, 2011 under the symbol “NDRO.” Prior to November 3, 2011, there was no established public trading market for the Trust Units. The high and low sales prices per unit for each quarter in 2012 and from 2011 were as follows:

 

     Price Range     

Distributions
Paid

 
Quarter    High      Low     

2012

        

First Quarter

   $ 22.02       $ 18.95       $ 0.430885   

Second Quarter

   $ 21.73       $ 15.01       $ 0.450216   

Third Quarter

   $ 19.73       $ 16.37       $ 0.434369   

Fourth Quarter

   $ 19.51       $ 15.25       $ 0.443662   

2011

        

Fourth Quarter (November 3, 2011 through December 31, 2011)

   $ 21.85       $ 18.01       $ 0.314703   

At December 31, 2012, there were 33,000,000 Trust Units outstanding. On March 6, 2013, the closing sales price of the Trust Units as reported by the NYSE was $15.50 per unit, and there were two 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).

On November 18, 2011, the Trust announced the Trust’s first distribution, which was related to net profits generated during the calculation period from July 1, 2011 through September 30, 2011 as provided in the Conveyance. The distribution primarily represented oil and natural gas production during the months of June and July 2011 and a portion of oil production related to August 2011, while expenses were included for the full three months in the calculation period. The following table provides information regarding the Trust’s distributions paid during the periods indicated:

 

Declaration Date

  

            Record Date             

  

            Payment Date             

   Distribution per Unit  

2012:

        

December 19, 2011

   December 30, 2011    January 17, 2012    $ 0.148113   

January 20, 2012

   January 31, 2012    February 14, 2012    $ 0.140337   

February 17, 2012

   February 29, 2012    March 14, 2012    $ 0.142435   

March 20, 2012

   March 30, 2012    April 13, 2012    $ 0.155529   

April 20, 2012

   April 30, 2012    May 14, 2012    $ 0.148038   

May 18, 2012

   May 31, 2012    June 14, 2012    $ 0.146649   

June 19, 2012

   June 29, 2012    July 16, 2012    $ 0.145842   

July 20, 2012

   July 31, 2012    August 14, 2012    $ 0.150535   

August 21, 2012

   August 31, 2012    September 17, 2012    $ 0.137992   

September 18, 2012

   September 28, 2012    October 15, 2012    $ 0.142001   

October 19, 2012

   October 31, 2012    November 15, 2012    $ 0.140765   

November 19, 2012

   November 30, 2012    December 14, 2012    $ 0.160896   

2011:

        

November 18, 2011

   November 30, 2011    December 14, 2011    $ 0.314703   

 

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On December 20, 2012, the Trust declared a distribution of $0.139439 per Trust Unit to unitholders of record as of December 31, 2012. The distribution was paid on January 15, 2013.

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, 2012.

Purchases of Equity Securities

There were no purchases of Trust Units by the Trust or any affiliated purchaser during the fourth quarter of 2012.

 

Item 6. Selected Financial Data.

The Trust was formed in May 2011. The conveyance of the Net Profits Interest, however, did not occur until November 8, 2011. As a result, the Trust did not recognize any income or make any distributions during the first ten months of 2011.

On November 18, 2011, the Trust announced the Trust’s first distribution, which was related to net profits generated during the calculation period from July 1, 2011 through September 30, 2011 as provided in the Conveyance. The distribution primarily represented oil and natural gas production during the months of June and July 2011 and a portion of oil production related to August 2011, while expenses were included for the full three months in the calculation period.

The following table sets forth selected data for the Trust for the year ended December 31, 2012 and the period from May 3, 2011 (Inception) through December 31, 2011 and as of December 31, 2012 and 2011.

 

     Year ended
December 31, 2012
     May 3, 2011
(Inception) through
December 31, 2011
 

Income from net profits interest

   $ 59,101,312       $ 10,535,206   

Distributable income

   $ 58,051,356       $ 10,385,199   

Distributable income per unit

   $ 1.759132       $ 0.314703   

 

     December 31, 2012      December 31, 2011  

Trust corpus

   $ 637,845,277       $ 713,723,835   

Trust Units outstanding

     33,000,000         33,000,000   

 

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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

The Trust is a statutory trust created under the Delaware Statutory Trust Act in May 2011. The business and affairs of the Trust are managed by the Trustee. 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 Delaware Trustee has only minimal rights and duties that are necessary to satisfy the requirements of the Delaware Statutory Trust Act.

In connection with the closing of the initial public offering, on November 8, 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 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: (1) the Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells the Net Profits Interest, (2) 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, (3) the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution or (4) the Trust is judicially dissolved.

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 10th business day after the record date. The Net Profits Interest will be entitled to a share of the profits from and after July 1, 2011 attributable to production occurring on or after June 1, 2011. During 2011, the Trust paid one distribution, which was announced on November 18, 2011. The Trust’s first distribution related to net profits generated during the calculation period from July 1, 2011 through September 30, 2011 as provided in the Conveyance. The distribution primarily represented oil and natural gas production during the months of June and July 2011 and a portion of oil production related to August 2011, while expenses were included for the full three months in the calculation period.

The amount of Trust revenues and cash distributions to Trust unitholders depends on, among other things:

 

   

oil and 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; and

 

   

the amount and timing of Trust administrative expenses.

Results of Operations

Year Ended December 31, 2012 and Period from Inception through December 31, 2011

The Trust was formed in May 2011. In connection with the closing of the initial public offering, on November 8, 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

 

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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.

For the year ended December 31, 2012, net profits income received by the Trust amounted to $59,101,312 compared to $10,535,206 in 2011. As the Trust was not formed until May 3, 2011 and the conveyance of the Net Profits Interest was not completed until November 8, 2011, the Trust did not receive or disburse funds during the first ten months of 2011.

The following table displays oil and natural gas sales, volumes and average prices (excluding the effects of the hedging arrangements discussed in Note 4 of the Notes to Financial Statements) from the Underlying Properties, representing the amounts included in the net profits calculation for the distributions paid during the year ended December 31, 2012 and for the period from Inception through December 31, 2011.

 

     Underlying Sales Volumes      Average Price  
Month of Distribution    Oil
(Bbls)
     Natural Gas
(Mcf)
     Oil
(per Bbl)
     Natural Gas
(per Mcf)
 

2012:

           

January

     90,717         755,809       $ 82.77       $ 4.74   

February

     91,431         817,344       $ 83.24       $ 4.11   

March

     83,844         950,978       $ 93.99       $ 3.93   

April

     86,314         843,318       $ 94.88       $ 3.75   

May

     83,735         799,759       $ 97.30       $ 3.51   

June

     79,914         819,095       $ 98.62       $ 3.31   

July

     81,730         665,676       $ 101.11       $ 3.03   

August

     73,609         753,823       $ 101.36       $ 2.77   

September

     83,302         762,632       $ 87.80       $ 2.53   

October

     77,410         1,336,036       $ 76.17       $ 2.41   

November

     79,184         918,802       $ 81.62       $ 2.49   

December

     83,573         927,143       $ 86.24       $ 2.85   
  

 

 

    

 

 

       

Total—2012

     994,763         10,350,415       $ 90.29       $ 3.24   
  

 

 

    

 

 

       

2011:

           

December

     220,481         1,413,458       $ 89.39       $ 4.63   
  

 

 

    

 

 

       

Total—2011

     220,481         1,413,458       $ 89.39       $ 4.63   
  

 

 

    

 

 

       

The average received price of oil was $90.29 per Bbl for the year ended December 31, 2012 compared to an average NYMEX oil price of approximately $94.88 for the relevant production months, while the average received price of natural gas was $3.24 per Mcf during 2012 compared to an average NYMEX natural gas price of approximately $3.04 for the relevant production months.

The average received price of oil was $89.39 per Bbl from Inception through December 31, 2011 compared to an average NYMEX oil price of approximately $93.09 for the relevant production months, while the average received price of natural gas was $4.63 per Mcf from Inception through December 31, 2011 compared to an average NYMEX natural gas price of approximately $4.34 for the relevant production months.

 

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Computation of Net Profits Income Received by the Trust

The Trust’s net profits income consists of monthly net profits attributable to the Net Profits Interest. Net profits income for the year ended December 31, 2012 and the period from Inception through December 31, 2011 was determined as shown in the following table:

 

     Year Ended
December 31,
2012
    Inception (May 3, 2011)
through

December 31,
2011
 

Gross profits:

    

Oil sales

   $ 89,821,176      $ 19,709,665   

Natural gas sales

     33,543,537        6,545,667   
  

 

 

   

 

 

 

Total

     123,364,713        26,255,332   
  

 

 

   

 

 

 

Costs:

    

Direct operating expenses:

    

Lease operating expenses

     31,228,716        7,471,202   

Compression, gathering and transportation

     4,428,270        849,042   

Production, ad valorem and other taxes

     9,334,989        2,275,000   

Development expenses

     16,334,354        3,223,358   
  

 

 

   

 

 

 

Total

     61,326,329        13,818,602   
  

 

 

   

 

 

 

Settlement of hedge contracts

     11,838,256        732,278   
  

 

 

   

 

 

 

Net profits

   $ 73,876,640      $ 13,169,008   

Percentage allocable to Net Profits Interest

     80     80
  

 

 

   

 

 

 

Income from Net Profits Interest

   $ 59,101,312      $ 10,535,206   

Trust general and administrative expenses and cash withheld for expenses

     (1,049,956     (150,007
  

 

 

   

 

 

 

Distributable income

   $ 58,051,356      $ 10,385,199   
  

 

 

   

 

 

 

Excess of revenues over direct operating expenses and development expenses from the Underlying Properties was approximately $73.9 million in 2012. This amount includes settlements of approximately $11.8 million related to hedge contracts. Applying the net profits interest percentage of 80% to the excess of revenues over direct operating expenses and development expenses results in income from the Net Profits Interest to the Trust (prior to Trust general and administrative expenses and cash withheld for expenses) of approximately $59.1 million for the year ended December 31, 2012.

Excess of revenues over direct operating expenses and development expenses from the Underlying Properties was approximately $13.2 million from Inception through December 31, 2011. This amount includes settlements of approximately $0.7 million related to hedge contracts. Applying the net profits interest percentage of 80% to the excess of revenues over direct operating expenses and development expenses results in income from the Net Profits Interest to the Trust (prior to Trust general and administrative expenses and cash withheld for expenses) of approximately $10.5 million for the period. As the Trust was not formed until May 3, 2011 and the conveyance of the Net Profits Interest was not completed until November 8, 2011, the Trust did not receive or disburse funds during the first ten months of 2011.

Total capital expenditures included in the net profits calculation during the year ended December 31, 2012 were approximately $16.3 million as compared to capital expenditures of $3.2 million during the period from Inception through December 31, 2011. The 2011 period represented capital expenditures incurred during one quarter in 2011. Capital expenditures increased during 2012 as a result of the full year of the net profits calculation but also due to certain capital expenditures that were excluded from the 2011 period for development drilling projects in the Haynesville Shale. Per the Conveyance, Enduro agreed to pay for up to $9.1 million of

 

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estimated development expenses related to certain projects in the Haynesville Shale, thereby reducing the Trust’s share of development expenses. During the 2011 period, capital totaling approximately $6.6 million was incurred related to these projects that is not reflected in the calculation.

Total lease operating expenses included in the net profits calculation during the twelve months ended December 31, 2012 were approximately $31.2 million ($11.48 per Boe). For the period from Inception through December 31, 2011, total lease operating expenses were approximately $7.5 million.

Production, ad valorem and other taxes included in the net profits calculation during the twelve months ended December 31, 2012 were approximately $9.3 million, or 7.6% of revenues. For the period from Inception through December 31, 2011, production, ad valorem and other taxes were $2.3 million, or 8.7% of revenues. As a percentage of revenues, production, ad valorem and other taxes were higher during the 2011 period as the 2011 period only included revenues from 2 months of oil and natural gas receipts, while expenses were included for three months, resulting in a higher percentage.

The Trust paid general and administrative expenses of $1.0 million during the year ended December 31, 2012. Expenses paid during the period primarily consisted of fees for the preparation of 2011 tax information for unitholders, preparation of the Trust’s reserve report and Annual Report on Form 10-K for 2011, 2011 financial statement audit fees, Trustee fees, and New York Stock Exchange listing fees. Due to the limited period of activity during 2011, the Trustee paid general and administrative expenses of $37,261 from Inception through December 31, 2011. During the 2011 period, the Trust withheld $0.2 million for general and administrative expenses.

2013 Outlook

In 2013, Enduro expects capital to range from $22-$24 million ($18-$19 million net to the Trust’s 80% NPI), focused on projects in the Permian Basin. This capital primarily relates to four Permian Basin oil wells being drilled in the Lost Tank field in southeastern New Mexico, in which Enduro owns a 50% working interest. Two of the Lost Tank wells were spud in December 2012 and are expected to be completed and producing in early 2013. These projects are anticipated to grow oil production during the year.

Discussion and Analysis of Historical Results of the Underlying Properties

The following table sets forth revenues, direct operating expenses and the excess of revenues over direct operating expenses relating to the Underlying Properties for the six months ended June 30, 2011 and for the year ended December 31, 2010 derived from the historical revenues and direct operating expenses of the Underlying Properties included elsewhere in this Annual Report on Form 10-K.

 

     Six Months
Ended June 30,
2011
     Year Ended
December 31,
2010
 
    

(Unaudited)

(In thousands)

 

Revenues:

     

Oil

   $ 42,908       $ 70,033   

Natural gas

     16,464         33,787   
  

 

 

    

 

 

 

Total revenues

   $ 59,372       $ 103,820   
  

 

 

    

 

 

 

Direct operating expenses:

     

Lease operating

   $ 13,245       $ 24,579   

Gathering and processing

     1,091         1,977   

Production and other taxes

     4,317         8,069   
  

 

 

    

 

 

 

Total direct operating expenses

   $ 18,653       $ 34,625   
  

 

 

    

 

 

 

Excess of revenues over direct operating expenses

   $ 40,719       $ 69,195   
  

 

 

    

 

 

 

 

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The following table provides oil and natural gas sales volumes, average sales prices, average costs per Boe and capital expenditures relating to the Underlying Properties for the six months ended June 30, 2011 and for the year ended December 31, 2010.

 

     Six Months
Ended June 30,
2011
     Year Ended
December 31,
2010
 
     (Unaudited)  

Operating data:

     

Permian Basin

     

Sales volumes:

     

Oil (MBbls)

     455         921   

Natural gas (MMcf)

     969         2,195   

Total sales (MBoe)

     616         1,287   

Average sales prices:

     

Oil (per Bbl)

   $ 93.03       $ 74.58   

Natural gas (per Mcf)

   $ 6.14       $ 5.77   

Average costs per Boe:

     

Lease operating

   $ 17.22       $ 15.62   

Gathering and processing

   $ 0.33       $ 0.35   

Production and other taxes

   $ 6.13       $ 5.20   

Capital expenditures (in thousands):

     

Property development costs

   $ 16,610       $ 18,225   

East Texas/North Louisiana

     

Sales volumes:

     

Oil (MBbls)

     7         18   

Natural gas (MMcf)

     2,595         4,976   

Total sales (MBoe)

     440         847   

Average sales prices:

     

Oil (per Bbl)

   $ 96.29       $ 74.72   

Natural gas (per Mcf)

   $ 4.05       $ 4.24   

Average costs per Boe:

     

Lease operating

   $ 5.99       $ 5.29   

Gathering and processing

   $ 2.01       $ 1.80   

Production and other taxes

   $ 1.23       $ 1.62   

Capital expenditures (in thousands):

     

Property development costs

   $ 15,509       $ 7,779   

Total Underlying Properties

     

Sales volumes:

     

Oil (MBbls)

     462         939   

Natural gas (MMcf)

     3,564         7,171   

Total sales (MBoe)

     1,056         2,134   

Average sales prices:

     

Oil (per Bbl)

   $ 92.87       $ 74.58   

Natural gas (per Mcf)

   $ 4.62       $ 4.71   

Average costs per Boe:

     

Lease operating

   $ 12.54       $ 11.52   

Gathering and processing

   $ 1.03       $ 0.93   

Production and other taxes

   $ 4.09       $ 3.78   

Capital expenditures (in thousands):

     

Property development costs

   $ 32,119       $ 26,004   

 

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Discussion and Analysis of Pro Forma Combined Historical Results of the Underlying Properties

Pro Forma Combined Historical Results for the Year Ended December 31, 2010

Excess of revenues over direct operating expenses for the Underlying Properties was $69.2 million for the year ended December 31, 2010 as a result of an increase in the average price received for the oil and natural gas sold.

Revenues. Revenues from oil and natural gas sales were $103.8 million as a result of an increase in the average price received for crude oil sold to $74.58 per Bbl for the year ended December 31, 2010. In addition, the average price received for natural gas sold was $4.71 per Mcf for the year ended December 31, 2010.

Lease operating expenses. Lease operating expenses were $24.6 million for the year ended December 31, 2010, which represented an $0.87 per Boe increase in the lease operating expense rate from the prior year.

Gathering and processing expenses. Gathering and processing expenses were $2.0 million for the year ended December 31, 2010.

Production and other taxes. Production and other taxes were $8.1 million based on the increase in revenues from oil and natural gas sales on which these taxes are based.

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 that month, over the Trust’s expenses paid for that month. Available funds are reduced by any cash the Trustee decides 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 the any person, including the Trustee or the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee or any affiliate of either of them 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 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 agreed to provide 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. 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. If the Trust borrows funds, draws on the letter of credit or Enduro loans funds to the Trust, 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. During the year ended December 31, 2012, the Trust increased its cash reserve for future Trust expenses by $81,782 to $194,538. At December 31, 2011, the Trust had withheld $112,746 as cash reserves 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.

 

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Cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date must 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.

Alternatively, cash held for distribution at the next distribution date may be held in a noninterest-bearing account.

As substantially all of the Underlying Properties are located in mature fields, Enduro does not expect future costs for the Underlying Properties to change significantly as compared to recent historical costs other than changes due to fluctuations in the cost of oilfield services generally.

The amounts received by Enduro from the hedge contract counterparty upon settlement of the hedge contracts will reduce the operating expenses related to the Underlying Properties in calculating the net profits. However, if the hedge payments received by Enduro under the hedge contracts and other non-production revenue exceed operating expenses during a period, the ability to use such excess amounts to offset operating expenses will be deferred, with interest accruing on such amounts at the prevailing prime rate, until the next period where the hedge payments and the other non-production revenue are less than such expenses. In addition, the aggregate amounts paid by Enduro on settlement of the hedge contracts will reduce the amount of net profits paid to the Trust.

The Trust pays the Trustee an administrative fee of $200,000 per year. The Trust pays the Delaware Trustee a fee of $2,000 per year. 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 other than the commodity hedge contracts disclosed in the section “Quantitative and Qualitative Disclosures About Market Risk.”

Contractual Obligations

A summary of the Trust’s contractual obligations as of December 31, 2012 is provided in the following table:

 

     Payments Due by Year  
     2013      2014      2015      2016      2017      After 2017     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
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

      

 

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(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; therefore, 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 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 of payments received in connection with the settlement of certain hedge contracts, 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 creating the Net Profits Interest.

The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:

(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 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 investment in Net Profits Interest is calculated on a unit-of-production basis and is charged directly to 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.

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 as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

 

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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 Gas Reserves. The proved oil and 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 gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The standardized measure of discounted future net cash flows is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using year-end oil and gas prices and year-end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. 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 amortizes the investment in Net Profits Interest using the units-of-production method. The rate of recording amortization is dependent upon estimates of total proved reserves, which incorporate various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which we record amortization expense may increase, reducing Trust corpus. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic conditions.

Impairment of Investment in Net Profits Interest. Investment in the Net Profits Interest is periodically assessed to determine whether its aggregate value has 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.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Hedge Contracts

The Trust is exposed to fluctuations in energy prices in the normal course of business due to the Net Profits Interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that Enduro and its third party operators can economically produce. To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the Trust and to achieve more predictable cash flows, Enduro entered into hedge contracts with respect to approximately 62% and 51% of expected oil and natural gas production for 2012 and 2013, respectively, from the total proved reserves attributable to the Underlying Properties. These hedge contracts include a combination of fixed price swaps, collars and floors. These contracts reduce the exposure of the revenues from oil and natural gas production from the Underlying Properties; however, these contracts also limit the amount of cash available for distribution if

 

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prices increase above the fixed hedge price. After December 31, 2013, none of the production attributable to the Underlying Properties will be hedged. As a result, the amount of the cash distributions will be subject to the possibility of greater fluctuations after 2013 due to changes in oil and natural gas prices.

The following table sets forth the volumes of Enduro’s natural gas commodity derivative contracts related to the Underlying Properties, the weighted average contractual prices per Mcf, and the weighted average NYMEX equivalent prices per Mcf as of December 31, 2012:

 

     Put Contracts      Swap Contracts  
Period    Daily
Volumes
     Average
Contractual
Price
     Average
NYMEX
Equivalent
Price(1)
     Daily
Volumes
     Average
Contractual
Price
     Average
NYMEX
Equivalent
Price(1)
 
     (Mcf)      ($/Mcf)      ($/Mcf)      (Mcf)      ($/Mcf)      ($/Mcf)  

2013

     8,000       $ 4.90       $ 5.01         4,000       $ 5.00       $ 5.09   

 

(1) 

Enduro’s natural gas derivative contracts related to the Underlying Properties are comprised of contracts entered into at local basis points, such as Centerpoint and El Paso Permian, as well as NYMEX-based contracts. For presentation purposes and for comparability among the various contracts, the contract prices were converted to NYMEX equivalent prices using estimated basis differentials in the over-the-counter futures market.

The following table sets forth the volumes of Enduro’s oil commodity derivative contracts related to the Underlying Properties and the weighted average NYMEX prices per Bbl as of December 31, 2012:

 

     Three-Way Collars         
Period    Daily
Volumes
     Average
Sub-Floor
Price
     Average
Floor
Price
     Average
Cap
Price
     Daily
Swap
Volumes
     Average
Swap
Price
 
     (Bbls)      ($/Bbl)      ($/Bbl)      ($/Bbl)      (Bbls)      ($/Bbl)  

2013

     500       $ 67.50       $ 90.00       $ 110.00         510       $ 102.97   

The amounts received by Enduro from the hedge contract counterparty upon settlement of the hedge contracts will reduce the operating expenses related to the Underlying Properties in calculating net profits. In addition, the aggregate amounts paid by Enduro on settlement of the hedge contracts related to the Underlying Properties will reduce the amount of net profits paid to the Trust.

 

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Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

To the Trustee and Unitholders of

Enduro Royalty Trust

We have audited the accompanying statements of assets, liabilities, and trust corpus of Enduro Royalty Trust as of December 31, 2012 and 2011, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2012 and the period from May 3, 2011 (Inception) to December 31, 2011. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 2, the financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Enduro Royalty Trust as of December 31, 2012 and 2011, and its distributable income for the year ended December 31, 2012 and the period from May 3, 2011 (Inception) to December 31, 2011, in conformity with the basis of accounting described in Note 2.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Enduro Royalty Trust’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 18, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

March 18, 2013

 

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ENDURO ROYALTY TRUST

Statements of Assets, Liabilities and Trust Corpus

 

     December 31,
2012
     December 31,
2011
 

ASSETS

     

Cash and cash equivalents

   $ 194,538       $ 112,756   

Net profits interest in oil and natural gas properties, net

     637,650,739         713,611,079   
  

 

 

    

 

 

 

Total assets

   $ 637,845,277       $ 713,723,835   
  

 

 

    

 

 

 

LIABILITIES AND TRUST CORPUS

     

Trust corpus (33,000,000 units issued and outstanding)

   $ 637,845,277       $ 713,723,835   
  

 

 

    

 

 

 

Total liabilities and Trust corpus

   $ 637,845,277       $ 713,723,835   
  

 

 

    

 

 

 

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

 

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ENDURO ROYALTY TRUST

Statements of Distributable Income

 

     Year Ended
December 31, 2012
    May 3, 2011
(Inception)
through
December 31, 2011
 

Income from net profits interest

   $ 59,101,312      $ 10,535,206   

Interest and investment income

     606        —     

General and administrative expenses

     (968,780     (37,261

Cash reserves withheld for Trust expenses

     (81,782     (112,746
  

 

 

   

 

 

 

Distributable income

   $ 58,051,356      $ 10,385,199   
  

 

 

   

 

 

 

Distributable income per unit (33,000,000 units)

   $ 1.759132      $ 0.314703   
  

 

 

   

 

 

 

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

 

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ENDURO ROYALTY TRUST

Statements of Changes in Trust Corpus

 

     Year Ended
December 31, 2012
    May 3, 2011
(Inception)
through
December 31, 2011
 

Trust corpus, beginning of period

   $ 713,723,835      $ 10   

Investment in net profits interest

     —          726,000,000   

Cash reserves withheld for Trust expenses

     81,782        112,746   

Distributable income

     58,051,356        10,385,199   

Distributions to unitholders

     (58,051,356     (10,385,199

Amortization of net profits interest

     (75,960,340     (12,388,921
  

 

 

   

 

 

 

Trust corpus, end of year

   $ 637,845,277      $ 713,723,835   
  

 

 

   

 

 

 

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

 

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ENDURO ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

 

1. ORGANIZATION OF THE TRUST

Formation of the Trust and Provisions

Enduro Royalty Trust (the “Trust”) is a Delaware statutory trust formed in May 2011 (“Inception”) 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.” 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, east Texas and north Louisiana.

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 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.

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. At December 31, 2012 the Trust had $194,538 of cash and cash equivalents, an increase of $81,782 from the December 31, 2011 cash and cash equivalents balance of $112,756. 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 or any affiliate of either of them 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 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. Under the terms of the Trust Agreement, Enduro provided the Trust with a $1.0 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 $1.0 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, draws on the letter of credit or Enduro loans funds to the Trust, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid. Since its formation, the Trust has not borrowed any funds and no amounts have been drawn on the letter of credit.

 

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Each month, the Trustee pays Trust obligations and expenses and distributes to 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 must 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.

Alternatively, cash held for distribution at the next distribution date may be held in a noninterest-bearing account. At December 31, 2012 and December 31, 2011, the Trust did not have any cash on hand related to future distributions.

Net Profits Interest Conveyance and Initial Public Offering

On November 8, 2011, Enduro conveyed to the Trust, through the merger of a wholly owned subsidiary of Enduro with the Trust, the Net Profits Interest in exchange for 33,000,000 units of beneficial interest in the Trust (the “Trust Units”). Immediately following the conveyance, Enduro completed an initial public offering of 13,200,000 Trust Units. After the completion of the initial public offering and as of December 31, 2012 and 2011, Enduro owned 19,800,000 Trust Units, or 60% of the issued and outstanding Trust Units.

 

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

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 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. 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”);

 

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(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 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; 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 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 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. As of December 31, 2012, the Trust’s Net Profits Interest asset was not impaired.

 

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Concentration of Credit Risk

Oil and natural gas production from the Underlying Properties is principally sold to end users, marketers and other purchasers that have access to nearby pipeline facilities. 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” for the periods presented. The table provides the percentage represented by the purchasers during the periods presented:

 

     Year Ended
December 31, 2012
    May 3, 2011
(Inception) through
December 31, 2011
 

ConocoPhillips

     30     35

Occidental Petroleum

     21     18

Navajo Refining

     10     (1 ) 

 

(1) 

Sales to this customer were less than 10% for the period presented.

As there is significant competition among purchasers of oil and natural gas in the areas of the Underlying Properties, the loss of one or both of these purchasers does not present a significant risk. If one or both of the largest purchasers were lost, several entities could purchase the oil and natural gas produced from the Underlying Properties with little or no interruption to the business.

Enduro entered into certain hedge contacts related to the Underlying Properties through December 31, 2013, for which settlements are included in the Net Profits Interest calculation. The hedge contracts are with two counterparties, Merrill Lynch Commodities, Inc. and BNP Paribas.

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.

 

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. Accumulated amortization as of December 31, 2012 and 2011 was $88,349,261 and $12,388,921, respectively.

 

4. COMMODITY HEDGES

The Trust is exposed to fluctuations in energy prices in the normal course of business due to the Net Profits Interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that Enduro and its third party operators can economically produce. To mitigate the negative effects of a possible decline in oil and natural gas prices on distributable income to the Trust and to achieve more predictable cash flows, Enduro entered into hedge contracts with respect to approximately 41% and 67% of expected oil and natural gas production, respectively, for 2013 from the total proved reserves attributable to the Underlying Properties as of December 31, 2012. These hedge contracts include a combination of fixed price swaps, collars and floors. These contracts reduce the exposure of the revenues from oil and natural gas

 

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production from the Underlying Properties; however, these contracts also limit the amount of cash available for distribution if prices increase above the fixed hedge price. After the production month of December 31, 2013, none of the production attributable to the Underlying Properties will be hedged.

The following table sets forth the volumes of Enduro’s natural gas commodity derivative contracts related to the Underlying Properties, the weighted average contractual prices per Mcf, and the weighted average NYMEX equivalent prices per Mcf as of December 31, 2012:

 

     Put Contracts      Swap Contracts  
Period    Daily
Volumes
     Average
Contractual
Price
     Average
NYMEX
Equivalent
Price(1)
     Daily
Volumes
     Average
Contractual
Price
     Average
NYMEX
Equivalent
Price(1)
 
     (Mcf)      ($/Mcf)      ($/Mcf)      (Mcf)      ($/Mcf)      ($/Mcf)  

2013

     8,000       $ 4.90       $ 5.01         4,000       $ 5.00       $ 5.09   

 

(1) 

Enduro’s natural gas derivative contracts related to the Underlying Properties are comprised of contracts entered into at local basis points, such as Centerpoint and El Paso Permian, as well as NYMEX-based contracts. For presentation purposes and for comparability among the various contracts, the contract prices were converted to NYMEX equivalent prices using estimated basis differentials in the over-the-counter futures market.

The following table sets forth the volumes of Enduro’s oil commodity derivative contracts related to the Underlying Properties and the weighted average NYMEX prices per Bbl as of December 31, 2012:

 

     Three-Way Collars         
Period    Daily
Volumes
     Average
Sub-
Floor
Price
     Average
Floor
Price
     Average
Cap
Price
     Daily
Swap
Volumes
     Average
Swap
Price
 
     (Bbls)      ($/Bbl)      ($/Bbl)      ($/Bbl)      (Bbls)      ($/Bbl)  

2013

     500       $ 67.50       $ 90.00       $ 110.00         510       $ 102.97   

The amounts received by Enduro from the hedge contract counterparty upon settlement of the hedge contracts reduce the operating expenses related to the Underlying Properties in calculating net profits. In addition, the aggregate amounts paid by Enduro on settlement of the hedge contracts related to the Underlying Properties reduce the amount of net profits paid to the Trust.

 

5. 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 pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his 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 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

 

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depletion. Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the Trust Units. Rather, a unitholder is entitled to percentage depletion as long as the applicable Underlying Properties generate gross 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. (“Trustee”), 919 Congress Avenue, Austin, Texas 78701, 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 should not be taxed at the trust level in Louisiana or New Mexico. While the Trust should 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. Texas does not impose a state income tax, so the Trust’s income will not be subject to income tax at the trust level in Texas. Louisiana and New Mexico presently have income taxes which tax income of nonresidents from real property located within that state. Louisiana and New Mexico tax nonresidents on royalty income from the royalties located in 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 1% on gross revenues less certain deductions, 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.” While 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.

 

6. 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

 

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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 twelve months ended December 31, 2012 and from Inception through December 31, 2011:

 

Declaration Date

   Record Date    Payment Date    Distribution per Unit  

2012:

        

December 19, 2011

   December 30, 2011    January 17, 2012    $ 0.148113   

January 20, 2012

   January 31, 2012    February 14, 2012    $ 0.140337   

February 17, 2012

   February 29, 2012    March 14, 2012    $ 0.142435   

March 20, 2012

   March 30, 2012    April 13, 2012    $ 0.155529   

April 20, 2012

   April 30, 2012    May 14, 2012    $ 0.148038   

May 18, 2012

   May 31, 2012    June 14, 2012    $ 0.146649   

June 19, 2012

   June 29, 2012    July 16, 2012    $ 0.145842   

July 20, 2012

   July 31, 2012    August 14, 2012    $ 0.150535   

August 21, 2012

   August 31, 2012    September 17, 2012    $ 0.137992   

September 18, 2012

   September 28, 2012    October 15, 2012    $ 0.142001   

October 19, 2012

   October 31, 2012    November 15, 2012    $ 0.140765   

November 19, 2012

   November 30, 2012    December 14, 2012    $ 0.160896   

2011:

        

November 18, 2011

   November 30, 2011    December 14, 2011    $ 0.314703   

 

7. 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. In addition, the Trust paid an initial acceptance fee of $10,000 to the Trustee and $1,500 to the Delaware Trustee for the first year of service. During the year ended December 31, 2012, the Trust paid $213,202 to the Trustee and $5,500 to the Delaware Trustee pursuant to the terms of the Trust Agreement. The amounts paid to the Delaware Trustee during 2012 represented fees for both 2012 and 2013. During the period from Inception through December 31, 2011, the Trust did not pay any amounts to the Trustee or the Delaware Trustee.

Agreement with Enduro Resource Partners LLC. The Trust entered into a registration rights agreement with Enduro in November 2011 in connection with Enduro’s conveyance to the Trust of the Net Profits Interest. Under the registration rights agreement, the Trust agrees, for the benefit of Enduro and any transferee of Enduro’s Trust Units, to register the Trust Units they hold.

 

8. SUBSEQUENT EVENTS

On January 15, 2013, the distribution of $0.139439 per Trust Unit, which was declared on December 20, 2012, was paid to Trust unitholders owning Trust Units as of December 31, 2012. The distribution consisted of net profits allocable to the Trust of $4,651,483, less cash reserves withheld for future Trust expenses of approximately $50,000.

Subsequent to December 31, 2012, the Trust declared the following distributions:

 

Declaration Date

   Record Date    Payment Date    Distribution per Unit  

January 18, 2013

   January 31, 2013    February 14, 2013    $ 0.125276   

February 15, 2013

   February 28, 2013    March 14, 2013    $ 0.070519   

March 18, 2013

   March 28, 2013    April 12, 2013    $
0.056553
  

 

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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 United States Securities and Exchange Commission 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:

 

     2012      2011  

Oil (per Bbl)

   $ 94.71       $ 96.19   

Natural gas (per Mcf)

   $ 2.75       $ 4.11   

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, 2012 and 2011, all of the Underlying Properties’ oil and 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:

 

     Oil
(MBbls)
    Natural
Gas
(MMcf)
    Total
(MBOE)
 

Balance at Inception—May 3, 2011

     —          —          —     

Conveyance of Net Profits Interest by Enduro

     5,769        31,143        10,959   

Extensions and discoveries

     2        2,934        491   

Revisions of previous estimates

     —          —          —     

Production

     (82     (373     (144
  

 

 

   

 

 

   

 

 

 

Balance—December 31, 2011

     5,689        33,704        11,306   

Extensions and discoveries

     2        407        70   

Revisions of previous estimates

     60        (8,914     (1,426

Production

     (427     (4,868     (1,238
  

 

 

   

 

 

   

 

 

 

Balance—December 31, 2012

     5,324        20,329        8,712   
  

 

 

   

 

 

   

 

 

 

Proved developed reserves:

      

December 31, 2011

     5,689        25,230        9,894   
  

 

 

   

 

 

   

 

 

 

December 31, 2012

     5,324        19,279        8,537   
  

 

 

   

 

 

   

 

 

 

Proved undeveloped reserves:

      

December 31, 2011

     —          8,474        1,412   
  

 

 

   

 

 

   

 

 

 

December 31, 2012

     —          1,050        175   
  

 

 

   

 

 

   

 

 

 

 

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UNAUDITED SUPPLEMENTARY INFORMATION—Continued

 

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,  
     2012     2011  
     (in thousands)  

Future cash inflows

   $ 530,038      $ 660,423   

Future production taxes

     (44,941     (52,618
  

 

 

   

 

 

 

Future net cash flows

   $ 485,097      $ 607,805   

10% annual discount for estimated timing of cash flows

     (247,306     (317,263
  

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 237,791      $ 290,542   
  

 

 

   

 

 

 

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, 2012
    May 3, 2011
(Inception) through
December 31, 2011
 
     (in thousands)  

Conveyance of Net Profits Interest by Enduro

   $ —        $ 290,665   

Extensions, discoveries, and other additions

     802        4,202   

Accretion of discount

     29,054        4,844   

Revisions of previous estimates and other

     (29,709     —     

Net profits income

     (52,898     (9,169
  

 

 

   

 

 

 

Change in present value of future net revenues

     (52,751     290,542   

Balance, beginning of period

     290,542        —     
  

 

 

   

 

 

 

Balance, end of year

   $ 237,791      $ 290,542   
  

 

 

   

 

 

 

 

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UNAUDITED SUPPLEMENTARY INFORMATION—Continued

 

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, 2012:

           

Income from Net Profits Interest

   $ 14,469,220       $ 15,232,110       $ 14,459,162       $ 14,940,820   

Distributable income

   $ 14,219,205       $ 14,857,128       $ 14,334,177       $ 14,640,846   

Distributions per unit

   $ 0.430885       $ 0.450216       $ 0.434369       $ 0.443662   

May 3, 2011 (Inception) through December 31, 2011:

           

Income from Net Profits Interest

   $ —         $ —         $ —         $ 10,535,206   

Distributable income

   $ —         $ —         $ —         $ 10,385,199   

Distributions per unit

   $ —         $ —         $ —         $ 0.314703   

 

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UNDERLYING PROPERTIES

HISTORICAL FINANCIAL INFORMATION

INDEX TO FINANCIAL STATEMENTS

 

PREDECESSOR UNDERLYING PROPERTIES:

  

Unaudited Statement of Revenues and Direct Operating Expenses for the Six Months Ended June 30, 2011

     69   

Notes to Unaudited Statement of Revenues and Direct Operating Expenses

     70   

Report of Independent Registered Public Accounting Firm

     71   

Statement of Revenues and Direct Operating Expenses for the Year Ended December 31, 2010

     72   

Notes to Statement of Revenues and Direct Operating Expenses

     73   

SAMSON PERMIAN BASIN ASSETS:

  

Unaudited Statement of Revenues and Direct Operating Expenses for the Six Months Ended June 30, 2011

     76   

Notes to Unaudited Statement of Revenues and Direct Operating Expenses

     77   

Report of Independent Registered Public Accounting Firm

     78   

Statement of Revenues and Direct Operating Expenses for the Year Ended December 31, 2010

     79   

Notes to Statement of Revenues and Direct Operating Expenses

     80   

CONOCOPHILLIPS PERMIAN BASIN ASSETS:

  

Unaudited Statement of Revenues and Direct Operating Expenses for the Six Months Ended June 30, 2011

     83   

Notes to Unaudited Statement of Revenues and Direct Operating Expenses

     84   

Report of Independent Registered Public Accounting Firm

     85   

Statement of Revenues and Direct Operating Expenses for the Year Ended December 31, 2010

     86   

Notes to Statement of Revenues and Direct Operating Expenses

     87   

 

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PREDECESSOR UNDERLYING PROPERTIES

UNAUDITED STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

SIX MONTHS ENDED JUNE 30, 2011

(in thousands)

 

Revenues:

  

Oil

   $ 674   

Natural gas

     10,518   
  

 

 

 

Total revenues

     11,192   
  

 

 

 

Direct operating expenses:

  

Lease operating

     2,635   

Gathering and processing

     885   

Production and other taxes

     542   
  

 

 

 

Total direct operating expenses

     4,062   
  

 

 

 

Excess of revenues over direct operating expenses

   $ 7,130   
  

 

 

 

The accompanying notes are an integral part of this statement.

 

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PREDECESSOR UNDERLYING PROPERTIES

NOTES TO UNAUDITED STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

On December 1, 2010 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in East Texas and North Louisiana from Denbury Resources Inc. (“Denbury”) for a cash purchase price of approximately $217.4 million. These assets were acquired by Denbury on March 9, 2010 in connection with Denbury’s acquisition of Encore Acquisition Company (“Encore”). These properties are collectively referred to herein as the “Predecessor Underlying Properties.”

The accompanying unaudited statement of revenues and direct operating expenses is presented on the accrual basis of accounting and was derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Denbury and Encore for their respective ownership periods prior to the Acquisition Date.

During the period presented, the Predecessor Underlying Properties were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statement of revenues and direct operating expenses is not indicative of the financial condition or results of operations of the Predecessor Underlying Properties and such amounts may not be representative of future operations.

The unaudited statement of revenues and direct operating expenses does not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Predecessor Underlying Properties. In the opinion of management, the accompanying unaudited statement of revenues and direct operating expenses includes all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.

2. Contingencies

The activities of the Predecessor Underlying Properties are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Predecessor Underlying Properties.

3. Cash Flow Information

Capital expenditures relating to the Predecessor Underlying Properties were approximately $15.5 million for the six months ended June 30, 2011. Other cash flow information is not available on a stand-alone basis for the Predecessor Underlying Properties.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Managers and Members of Enduro Resource Partners LLC:

We have audited the accompanying statement of revenues and direct operating expenses of the Predecessor Underlying Properties, described in Note 1, for the year ended December 31, 2010. This statement is the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on this statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement is free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the Predecessor Underlying Properties. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statement. We believe that our audit provides a reasonable basis for our opinion.

The accompanying statement reflects the revenues and direct operating expenses of the Predecessor Underlying Properties, as described in Note 1, and is not intended to be a complete presentation of the Predecessor Underlying Properties’ revenues and expenses.

In our opinion, the statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Predecessor Underlying Properties for the year ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Fort Worth, Texas

May 11, 2011

 

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PREDECESSOR UNDERLYING PROPERTIES

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

YEAR ENDED DECEMBER 31, 2010

(in thousands)

 

Revenues:

  

Oil

   $ 1,345   

Natural gas

     21,112   
  

 

 

 

Total revenues

     22,457   
  

 

 

 

Direct operating expenses:

  

Lease operating

     4,484   

Gathering and processing

     1,522   

Production and other taxes

     1,373   
  

 

 

 

Total direct operating expenses

     7,379   
  

 

 

 

Excess of revenues over direct operating expenses

   $ 15,078   
  

 

 

 

The accompanying notes are an integral part of this statement.

 

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PREDECESSOR UNDERLYING PROPERTIES

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

On December 1, 2010 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in East Texas and North Louisiana from Denbury Resources Inc. (“Denbury”) for a cash purchase price of approximately $213.8 million, subject to post-closing adjustments. These assets were acquired by Denbury on March 9, 2010 in connection with Denbury’s acquisition of Encore Acquisition Company (“Encore”). The portion of these properties Enduro expects to contribute to Enduro Royalty Trust are collectively referred to herein as the “Predecessor Underlying Properties.”

The accompanying statement of revenues and direct operating expenses is presented on the accrual basis of accounting and was derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Denbury for the period prior to the Acquisition Date.

During the period presented, the Predecessor Underlying Properties were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statement of revenues and direct operating expenses is not indicative of the financial condition or results of operations of the Predecessor Underlying Properties and such amounts may not be representative of future operations.

Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statement of revenues and direct operating expenses of the Predecessor Underlying Properties are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).

2. Significant Accounting Policies

(a) Use of Estimates

Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual balances and results could be different from those estimates.

(b) Revenue Recognition

Oil and natural gas revenues are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Revenues are reported net of royalties and other amounts due to third parties.

(c) Direct Operating Expenses

Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Predecessor Underlying Properties. Direct operating expenses include lease operating, gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and field expenses. Gathering and processing expenses include

 

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the costs of oil and/or natural gas taken in-kind for the use of gas processing facilities as well as maintenance, repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.

3. Contingencies

The activities of the Predecessor Underlying Properties are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Predecessor Underlying Properties.

4. Cash Flow Information

Capital expenditures relating to the Predecessor Underlying Properties were approximately $7.8 million for the year ended December 31, 2010. Other cash flow information is not available on a stand-alone basis for the Predecessor Underlying Properties.

5. Supplemental Oil and Natural Gas Disclosures (Unaudited)

The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities—Oil and Gas (“ASC 932”). The following unaudited supplemental information has been presented in accordance with the revised reserve estimation and disclosure rules.

Oil and Natural Gas Reserve Quantities

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 gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the Predecessor Underlying Properties and changes therein for the year ended December 31, 2010.

 

     Oil
(MBbls)
    Natural Gas
(MMcf)
    Total
(MBOE)
 

January 1, 2010

     104        54,609        9,205   

Revisions of previous estimates

     (61     11,128        1,794   

Production

     (18     (4,976     (847
  

 

 

   

 

 

   

 

 

 

December 31, 2010

     25        60,761        10,152   
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2010

     25        30,294        5,074   

Proved undeveloped reserves as of:

      

December 31, 2010

     —          30,467        5,078   

 

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Standardized Measure of Discounted Future Net Cash Flows

Estimated discounted future net cash flows and changes therein were determined for the Predecessor Underlying Properties in accordance with ASC 932. Future cash inflows were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows.

The prices per unit used for the Predecessor Underlying Properties’ proved reserves and future net revenues are as follows:

 

Oil (per Bbl)

   $ 79.43   

Natural gas (per Mcf)

   $ 4.37   

Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves based on period-end costs assuming continuation of existing economic conditions. No future income tax expense was computed as taxable income arising from the operations of the properties accrues to the owner. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.

Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the Predecessor Underlying Properties’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table presents the estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the year ended December 31, 2010 (in thousands).

 

Future cash inflows

   $ 249,277   

Future production costs

     (56,146

Future development costs

     (51,674
  

 

 

 

Future net cash flows

     141,457   

10% discount for estimating timing of cash flows

     (72,263
  

 

 

 

Standardized measure of discounted future net cash flows

   $ 69,194   
  

 

 

 

The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the year ended December 31, 2010 (in thousands).

 

Sales of oil and natural gas produced, net of production costs

   $ (15,078

Net changes in prices and production costs

     25,650   

Revisions of previous quantity estimates

     17,808   

Development costs incurred during the period

     7,779   

Accretion of discount

     4,567   

Change in estimated future development costs

     (17,147

Timing and other

     (60
  

 

 

 

Net change in standardized measure

     23,519   

Standardized measure, beginning of year

     45,675   
  

 

 

 

Standardized measure, end of year

   $ 69,194   
  

 

 

 

 

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SAMSON PERMIAN BASIN ASSETS

UNAUDITED STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

SIX MONTHS ENDED JUNE 30, 2011

(in thousands)

 

Revenues:

  

Oil

   $ 8,975   

Natural gas

     2,637   
  

 

 

 

Total revenues

     11,612   
  

 

 

 

Direct operating expenses:

  

Lease operating

     1,777   

Gathering and processing

     108   

Production and other taxes

     789   
  

 

 

 

Total direct operating expenses

     2,674   
  

 

 

 

Excess of revenues over direct operating expenses

   $ 8,938   
  

 

 

 

The accompanying notes are an integral part of this statement.

 

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SAMSON PERMIAN BASIN ASSETS

NOTES TO UNAUDITED STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

On January 5, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “Samson Permian Basin Assets”) from Samson Investment Company and related subsidiaries (collectively, “Samson”) for a cash purchase price of approximately $133.8 million, subject to post-closing adjustments.

The accompanying unaudited statement of revenues and direct operating expenses is presented on the accrual basis of accounting and was derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of Samson for periods prior to the Acquisition Date.

During the periods presented, the Samson Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statement of revenues and direct operating expenses is not indicative of the financial condition or results of operations of the Samson Permian Basin Assets and such amounts may not be representative of future operations.

The unaudited statement of revenues and direct operating expenses does not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the Samson Permian Basin Assets. In the opinion of management, the accompanying unaudited statement of revenues and direct operating expenses includes all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.

2. Contingencies

The activities of the Samson Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Samson Permian Basin Assets.

3. Cash Flow Information

Capital expenditures relating to the Samson Permian Basin Assets were approximately $350,000 for the six months ended June 30, 2011. Other cash flow information is not available on a stand-alone basis for the Samson Permian Basin Assets.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Managers and Members of Enduro Resource Partners LLC:

We have audited the accompanying statement of revenues and direct operating expenses of the Samson Permian Basin Assets, described in Note 1, for the year ended December 31, 2010. This statement is the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on these statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement is free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the Samson Permian Basin Assets. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statement. We believe that our audit provides a reasonable basis for our opinion.

The accompanying statement reflects the revenues and direct operating expenses of the Samson Permian Basin Assets, as described in Note 1, and is not intended to be a complete presentation of the Samson Permian Basin Assets’ revenues and expenses.

In our opinion, the statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Samson Permian Basin Assets for the year ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

May 9, 2011

 

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SAMSON PERMIAN BASIN ASSETS

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

YEAR ENDED DECEMBER 31, 2010

(in thousands)

 

Revenues:

  

Oil

   $ 16,626   

Natural gas

     5,650   
  

 

 

 

Total revenues

     22,276   
  

 

 

 

Direct operating expenses:

  

Lease operating

     3,438   

Gathering and processing

     212   

Production and other taxes

     1,702   
  

 

 

 

Total direct operating expenses

     5,352   
  

 

 

 

Excess of revenues over direct operating expenses

   $ 16,924   
  

 

 

 

The accompanying notes are an integral part of this statement.

 

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SAMSON PERMIAN BASIN ASSETS

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

On January 5, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “Samson Permian Basin Assets”) from Samson Investment Company and related subsidiaries (collectively, “Samson”) for a cash purchase price of approximately $133.8 million, subject to post-closing adjustments.

The accompanying statement of revenues and direct operating expenses is presented on the accrual basis of accounting and was derived from the historical accounting records of Samson for periods prior to the Acquisition Date.

During the period presented, the Samson Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Samson Permian Basin Assets and such amounts may not be representative of future operations.

Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statement of revenues and direct operating expenses of the Samson Permian Basin Assets are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).

2. Significant Accounting Policies

(a) Use of Estimates

Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual balances and results could be different from those estimates.

(b) Revenue Recognition

Oil and natural gas revenues are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Revenues are reported net of royalties and other amounts due to third parties.

(c) Direct Operating Expenses

Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Samson Permian Basin Assets. Direct operating expenses include lease operating, gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and field expenses. Gathering and processing expenses include

 

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the costs of oil and/or natural gas taken in-kind for the use of gas processing facilities as well as maintenance, repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.

3. Contingencies

The activities of the Samson Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the Samson Permian Basin Assets.

4. Cash Flow Information (Unaudited)

Capital expenditures relating to the Samson Permian Basin Assets were approximately $799,000 for the year ended December 31, 2010. Other cash flow information is not available on a stand-alone basis for the Samson Permian Basin Assets.

5. Supplemental Oil and Natural Gas Disclosures (Unaudited)

The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities—Oil and Gas (“ASC 932”). The following unaudited supplemental information has been presented in accordance with the revised reserve estimation and disclosure rules.

Oil and Natural Gas Reserve Quantities

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 gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the Samson Permian Basin Assets and changes therein, for the year ended December 31, 2010.

 

     Oil
(MBbls)
    Natural Gas
(MMcf)
    Total
(MBOE)
 

January 1, 2010

     3,144        11,458        5,054   

Revisions of previous estimates

     120        379        183   

Production

     (216     (1,056     (392
  

 

 

   

 

 

   

 

 

 

December 31, 2010

     3,048        10,781        4,845   
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2010

     3,048        10,781        4,845   

 

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Standardized Measure of Discounted Future Net Cash Flows

Estimated discounted future net cash flows and changes therein were determined for the Samson Permian Basin Assets in accordance with ASC 932. Future cash inflows were computed by applying the average prices of oil and natural gas during the 12-month period to the period-end quantities of those proved reserves (with consideration of price changes only to the extent provided by contractual arrangements). The average prices were determined using the arithmetic average of the prices in effect on the first day of the month for each month within the period. This same 12-month average price was also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows.

The prices per unit used for the Samson Permian Basin Assets’ proved reserves and future net revenues are as follows:

 

Oil (per Bbl)

   $ 79.43   

Natural gas (per Mcf)

   $ 4.37   

Future development and production costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves based on period-end costs assuming continuation of existing economic conditions. No future income tax expense was computed as taxable income arising from the operations of the properties accrues to the owner. An annual discount rate of 10% was used to reflect the timing of the future net cash flows.

Discounted future cash flow estimates like those shown below are not intended to present, nor should they be interpreted to present, the fair value of the Samson Permian Basin Assets’ oil and natural gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table presents the estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas for the year ended December 31, 2010 (in thousands).

 

Future cash inflows

   $ 292,253   

Future production costs

     (107,372
  

 

 

 

Future net cash flows

     184,881   

10% discount for estimating timing of cash flows

     (99,927
  

 

 

 

Standardized measure of discounted future net cash flows

   $ 84,954   
  

 

 

 

The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the year ended December 31, 2010 (in thousands).

 

Sales of oil and natural gas produced, net of production costs

   $ (16,924

Net changes in prices and production costs

     25,022   

Revisions of previous quantity estimates

     3,361   

Accretion of discount

     6,888   

Timing and other

     (2,276
  

 

 

 

Net change in standardized measure

     16,071   

Standardized measure, beginning of year

     68,883   
  

 

 

 

Standardized measure, end of year

   $ 84,954   
  

 

 

 

 

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CONOCOPHILLIPS PERMIAN BASIN ASSETS

UNAUDITED STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

SIX MONTHS ENDED JUNE 30, 2011

(in thousands)

 

Revenues:

  

Oil

   $ 33,259   

Natural gas

     3,309   
  

 

 

 

Total revenues

     36,568   
  

 

 

 

Direct operating expenses:

  

Lease operating

     8,833   

Gathering and processing

     98   

Production and other taxes

     2,986   
  

 

 

 

Total direct operating expenses

     11,917   
  

 

 

 

Excess of revenues over direct operating expenses

   $ 24,651   
  

 

 

 

The accompanying notes are an integral part of this statement.

 

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CONOCOPHILLIPS PERMIAN BASIN ASSETS

NOTES TO UNAUDITED STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

On February 28, 2011 (the “Acquisition Date”), Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “ConocoPhillips Permian Basin Assets”) from ConocoPhillips Company and a related subsidiary (collectively, “ConocoPhillips”) for a cash purchase price of approximately $314.2 million, subject to post-closing adjustments.

The accompanying unaudited statement of revenues and direct operating expenses is presented on the accrual basis of accounting and was derived from the historical accounting records of Enduro for periods subsequent to the Acquisition Date and of ConocoPhillips for periods prior to the Acquisition Date.

During the periods presented, the ConocoPhillips Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying unaudited statement of revenues and direct operating expenses is not indicative of the financial condition or results of operations of the ConocoPhillips Permian Basin Assets and such amounts may not be representative of future operations.

The unaudited statement of revenues and direct operating expenses does not represent a complete set of financial statements reflecting the financial position, results of operations, shareholders’ equity, and cash flows of the ConocoPhillips Permian Basin Assets. In the opinion of management, the accompanying unaudited statement of revenues and direct operating expenses includes all adjustments considered necessary for fair presentation on the basis described above. All adjustments are of a normal recurring nature.

2. Contingencies

The activities of the ConocoPhillips Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the ConocoPhillips Permian Basin Assets.

3. Cash Flow Information

Capital expenditures relating to the ConocoPhillips Permian Basin Assets were approximately $16.3 million for the six months ended June 30, 2011. Other cash flow information is not available on a stand-alone basis for the ConocoPhillips Permian Basin Assets.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Managers and Members of Enduro Resource Partners LLC:

We have audited the accompanying statement of revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets, described in Note 1, for the year ended December 31, 2010. This statement is the responsibility of Enduro Resource Partners LLC’s management. Our responsibility is to express an opinion on this statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement is free of material misstatement. We were not engaged to perform an audit of the internal controls over financial reporting of the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statement. We believe that our audit provides a reasonable basis for our opinion.

The accompanying statement reflects the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets, as described in Note 1, and is not intended to be a complete presentation of the ConocoPhillips Permian Basin Assets’ revenues and expenses.

In our opinion, the statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets for the year ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

May 9, 2011

 

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CONOCOPHILLIPS PERMIAN BASIN ASSETS

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

YEAR ENDED DECEMBER 31, 2010

(in thousands)

 

Revenues:

  

Oil

   $ 52,062   

Natural gas

     7,025   
  

 

 

 

Total revenues

     59,087   
  

 

 

 

Direct operating expenses:

  

Lease operating

     16,657   

Gathering and processing

     243   

Production and other taxes

     4,994   
  

 

 

 

Total direct operating expenses

     21,894   
  

 

 

 

Excess of revenues over direct operating expenses

   $ 37,193   
  

 

 

 

The accompanying notes are an integral part of this statement.

 

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CONOCOPHILLIPS PERMIAN BASIN ASSETS

NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

1. Basis of Presentation

On February 28, 2011, Enduro Resource Partners LLC (“Enduro”) completed the acquisition of certain oil and natural gas properties located in the Permian Basin in Texas and New Mexico (the “ConocoPhillips Permian Basin Assets”) from ConocoPhillips Company and a related subsidiary (collectively, “ConocoPhillips”) for a cash purchase price of approximately $314.2 million, subject to post-closing adjustments.

The accompanying statement of revenues and direct operating expenses is presented on the accrual basis of accounting and was derived from the historical accounting records of ConocoPhillips.

During the period presented, the ConocoPhillips Permian Basin Assets were not accounted for as a separate division and therefore certain costs such as depletion, depreciation, and amortization, accretion of asset retirement obligations, general and administrative expenses, interest, income taxes, and other expenses of an indirect nature were not allocated to the individual properties. Any attempt to allocate such indirect expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by Enduro. As a result of the exclusion of these various expenses, the accompanying statement of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the ConocoPhillips Permian Basin Assets and such amounts may not be representative of future operations.

Full separate financial statements prepared in accordance with generally accepted accounting principles are not presented as the information necessary to prepare such statements is neither readily available on an individual property basis nor practicable to obtain in these circumstances. Accordingly, the statement of revenues and direct operating expenses of the ConocoPhillips Permian Basin Assets are presented in lieu of the financial statements otherwise required under Rules 3-01 and 3-02 of Regulation S-X by the Securities and Exchange Commission (“SEC”).

2. Significant Accounting Policies

(a) Use of Estimates

Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual balances and results could be different from those estimates.

(b) Revenue Recognition

Oil and natural gas revenues are recognized when such products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibilities of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Revenues are reported net of royalties and other amounts due to third parties.

(c) Direct Operating Expenses

Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the ConocoPhillips Permian Basin Assets. Direct operating expenses include lease operating, gathering, processing, and production and other tax expenses. Lease operating expenses include the costs of maintaining and operating property and equipment on producing oil and natural gas leases and include field labor, insurance, maintenance, repairs, utilities and supplies, and well workover and field expenses. Gathering and processing expenses include the costs of oil and/or natural gas taken in- kind for the use of gas processing facilities as well as maintenance,

 

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repair, and other operating costs incurred in gathering the production. Production and other taxes consist of severance and ad valorem taxes. Production taxes are recorded at the time transfer of title occurs. Such taxes represent a fixed percentage of production and are calculated and paid to the state governments in accordance with applicable regulations.

3. Contingencies

The activities of the ConocoPhillips Permian Basin Assets are subject to potential claims and litigation in the normal course of operations. Enduro’s management does not believe that any liability resulting from any pending or threatened litigation will have a materially adverse effect on the operations or financial results of the ConocoPhillips Permian Basin Assets.

4. Cash Flow Information (Unaudited)

Capital expenditures relating to the ConocoPhillips Permian Basin Assets were approximately $17.4 million for the year ended December 31, 2010. Other cash flow information is not available on a stand-alone basis for the ConocoPhillips Permian Basin Assets.

5. Supplemental Oil and Natural Gas Disclosures (Unaudited)

The following unaudited supplemental oil and natural gas disclosures were derived from reserve reports which were prepared by Enduro’s reserve engineers and are presented in accordance with the Financial Accounting Standards Board ASC Topic 932, Extractive Activities—Oil and Gas (“ASC 932”). The following unaudited supplemental information has been presented in accordance with the revised reserve estimation and disclosure rules.

Oil and Natural Gas Reserve Quantities

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 gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reserve. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following table presents the estimated remaining net proved and proved developed oil and natural gas reserves of the ConocoPhillips Permian Basin Assets and changes therein, for the year ended December 31, 2010.

 

     Oil
(MBbls)
    Natural Gas
(MMcf)
    Total
(MBOE)
 

January 1, 2010

     8,921        10,055        10,597   

Revisions of previous estimates

     1,477        1,784        1,774   

Production

     (705     (1,139     (895
  

 

 

   

 

 

   

 

 

 

December 31, 2010

     9,693        10,700        11,476   
  

 

 

   

 

 

   

 

 

 

Proved developed reserves as of:

      

December 31, 2010

     9,314        9,407        10,882   

Proved undeveloped reserves as of:

      

December 31, 2010

     379        1,293