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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









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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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##### Table of Contents

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 |  | DailyVolumes  |       |  | AverageContractualPrice |   |      | AverageNYMEXEquivalentPrice(1) |  |   | DailyVolumes |  |  | AverageContractualPrice |       |  | AverageNYMEXEquivalentPrice(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 |  | DailyVolumes      |     |  | AverageSub-FloorPrice |   |       | AverageFloorPrice |  |   | AverageCapPrice |  |  | DailySwapVolumes |        |  | AverageSwapPrice | 
|       |  | (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



36



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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 EndedDecember 31, 2012 |         |   | May 3,
2011(Inception) throughDecember 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.



37



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##### Table of Contents

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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|                           |  |                         |   |  |      |  |   |       |  |  |     |  |  |       |     |  |     |  |    |  |  |  |     | 
|-------------------------- |  | ----------------------- | - |  | ---- |  | - | ----- |  |  | --- |  |  | ----- | --- |  | --- |  | -- |  |  |  | --- | 
|                           |  | 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 CO2recovery 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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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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



40



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##### Table of Contents

| |  |  | 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 |       |  | DistributionsPaid |  
|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 10thbusiness 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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##### Table of Contents

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 endedDecember 31, 2012 |            |  | May 3, 2011(Inception) throughDecember 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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##### Table of Contents

|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 10thbusiness 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



44



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##### Table of Contents

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.



45



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##### Table of Contents

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 EndedDecember 31,2012 |             |   | Inception (May 3, 2011)throughDecember 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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##### Table of Contents

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 MonthsEnded June 30,2011 |        |  | Year EndedDecember 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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##### Table of Contents

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 MonthsEnded June 30,2011 |        |  | Year EndedDecember 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 |  | DailyVolumes  |       |  | AverageContractualPrice |   |      | AverageNYMEXEquivalentPrice(1) |  |   | DailyVolumes |  |  | AverageContractualPrice |       |  | AverageNYMEXEquivalentPrice(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 |  | DailyVolumes      |     |  | AverageSub-FloorPrice |   |       | AverageFloorPrice |  |   | AverageCapPrice |  |  | DailySwapVolumes |        |  | AverageSwapPrice | 
|       |  | (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 EndedDecember 31, 2012 |            |   | May 3, 2011(Inception)throughDecember 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 EndedDecember 31, 2012 |             |   | May 3, 2011(Inception)throughDecember 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
EndedDecember 31, 2012 |    |   | May 3,
2011(Inception) throughDecember 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 |  | DailyVolumes  |       |  | AverageContractualPrice |   |      | AverageNYMEXEquivalentPrice(1) |  |   | DailyVolumes |  |  | AverageContractualPrice |       |  | AverageNYMEXEquivalentPrice(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 |  | DailyVolumes      |     |  | AverageSub-FloorPrice |   |       | AverageFloorPrice |  |   | AverageCapPrice |  |  | DailySwapVolumes |        |  | AverageSwapPrice | 
|       |  | (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) |       |   | NaturalGas(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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ENDURO ROYALTY TRUST

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 EndedDecember 31, 2012 |         |   | May 3,
2011(Inception) throughDecember 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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ENDURO ROYALTY TRUST

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  |             |  |  | 594    |  



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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 ConocoPhillips 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 ConocoPhillips 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 ConocoPhillips 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                                      |  | $ | 788,822  |  
|Future production costs                                  |  |   | (407,974 | )
|Future development costs                                 |  |   | (6,000   | )
|Future net cash flows                                    |  |   | 374,848  |  
|                                                         |  |   |          |  
|10% discount for estimating timing of cash flows         |  |   | (179,827 | )
|                                                         |  |   |          |  
|Standardized measure of discounted future net cash flows |  | $ | 195,021  |  
|                                                         |  |   |          |  

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).



|                                                               |  |   |         |  
|-------------------------------------------------------------- |  | - | ------- | -
|Extensions and discoveries, net of future development costs    |  | $ | 11,065  |  
|Sales of oil and natural gas produced, net of production costs |  |   | (37,193 | )
|Net changes in prices and production costs                     |  |   | 69,967  |  
|Revisions of previous quantity estimates                       |  |   | 21,549  |  
|Accretion of discount                                          |  |   | 12,741  |  
|Change in estimated future development costs                   |  |   | (5,721  | )
|Timing and other                                               |  |   | (4,793  | )
|                                                               |  |   |         |  
|Net change in standardized measure                             |  |   | 67,615  |  
|Standardized measure, beginning of year                        |  |   | 127,406 |  
|                                                               |  |   |         |  
|Standardized measure, end of year                              |  | $ | 195,021 |  
|                                                               |  |   |         |  



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|Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
|------- | -------------------------------------------------------------------------------------

None.



|Item 9A. | Controls and Procedures.
|-------- | ------------------------

Evaluation of Disclosure Controls and Procedures. The Trustee conducted an evaluation of the Trusts disclosure controls and procedures (as defined in Rules 13a-15 and 15d-15 under the
Exchange Act). Based on this evaluation, the Trustee has concluded that the disclosure controls and procedures of the Trust were effective, as of the end of the period covered by this report, in ensuring that information required to be disclosed by
the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure.

Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created,
including the provisions of (i) the Trust Agreement and (ii) the Conveyance of the Net Profits Interest, the Trustees disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by
Enduro, including information relating to results of operations, the costs and revenues attributable to the Trusts interest under the Conveyance and other operating and historical data, plans for future operating and capital expenditures,
reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Net Profits Interest, and (B) conclusions and reports regarding
reserves by the Trusts independent reserve engineers.

Changes in Internal Control over Financial
Reporting.During the quarter ended December 31, 2012, there were no changes in the Trusts internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the
Trusts internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of Enduro.

TRUSTEES REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined
in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in
accordance with the modified cash basis of accounting. The Trustee conducted an evaluation of the effectiveness of the Trusts internal control over financial reporting based on the criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustees evaluation under the framework in Internal ControlIntegrated Framework, the Trustee concluded that the
Trusts internal control over financial reporting was effective as of December 31, 2012. The independent registered public accounting firm of Ernst & Young LLP, as auditors of the statements of assets, liabilities, and trust
corpus, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2012, has issued an attestation report on the Trusts internal control over financial reporting, which is included
herein.



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Report of Independent Registered Public Accounting Firm

To the Trustee and Unitholders of

Enduro
Royalty Trust

We have audited 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 (the COSO criteria). The Trustee of Enduro Royalty Trust is responsible for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustees Report on Internal Control Over Financial Reporting. Our
responsibility is to express an opinion on the Trusts internal control over financial reporting based on our audit.

We conducted our
audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A trusts internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles as described in
Note 2 to the Trusts financial statements. A trusts internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with a modified cash basis of
accounting, and that receipts and expenditures of the trust are being made only in accordance with the authorizations of the trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,
use, or disposition of the trusts assets that could have a material effect on the financial statements.

Because of its inherent
limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Enduro Royalty Trust
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 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 for the period from May 3, 2011 (Inception) to December 31, 2011 of Enduro
Royalty Trust, 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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|Item 9B. | Other Information.
|-------- | ------------------

None.

PART III



|Item 10. | Directors, Executive Officers and Corporate Governance.
|-------- | -------------------------------------------------------

The Trust has no directors or executive officers. The Trustee is a corporate Trustee that may be removed by the affirmative vote of the
holders of not less than a majority of the outstanding Trust Units at a meeting at which a quorum is present.

Section 16(a)
Beneficial Ownership Reporting Compliance

The Trust has no directors or officers. Accordingly, only holders of more than
10% of the Trusts units are required to file with the SEC initial reports of ownership of units and reports of changes in such ownership pursuant to Section 16 under the Securities Exchange Act of 1934. Based solely on a review of these
reports and any such reports furnished to the Trustee, the Trustee is not aware of any person having failed to file on a timely basis the reports required by Section 16(a) of the Exchange Act during the most recent fiscal year.

Audit Committee and Nominating Committee

Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

Code of Ethics

The
Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and has not adopted a code of ethics applicable to such persons.



|Item 11. | Executive Compensation.
|-------- | -----------------------

Pursuant to the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee. The Net Profits Interest was conveyed to the Trust on November 8, 2011. During the year ended
December 31, 2012, the Trustee received $213,202 in administrative fees from the Trust. During the period from Inception through December 31, 2011, the Trustee did not receive any administrative fees from the Trust. The Trust does not have
any executive officers, directors or employees. The Trust does not have a board of directors, and it does not have a compensation committee.



|Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
|-------- | ----------------------------------------------------------------------------------------------



|(a) | Security Ownership of Certain Beneficial Owners.
|--- | ------------------------------------------------

Based on filings with the SEC, the Trustee is not aware of any holders of 5% or more of the units except as set forth below. The following information has been obtained from public filings with the SEC.



|                                 |  |                              |            |     |                 |  |      |  
|-------------------------------- |  | ---------------------------- | ---------- | --- | --------------- |  | ---- | -
|Beneficial Owner                 |  | Trust UnitsBeneficiallyOwned |            |     | Percent ofClass | 
|Enduro Resource Partners LLC     |  |                              | 19,800,000 | (1) |                 |  | 60.0 | %
|Carlyle Group Management, L.L.C. |  |                              | 19,800,000 | (2) |                 |  | 60.0 | %



|(1) | Reference is hereby made to the Schedule 13D filed by the reporting person on November 18, 2011 for additional information regarding the
beneficial ownership of the reporting person.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Reference is hereby made to the Form 3 filed by the reporting person on May 11, 2012 for additional information regarding the beneficial ownership
of the reporting person.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|(b) | Security Ownership of Management.
|--- | ---------------------------------

Not applicable.



|(c) | Changes in Control.
|--- | -------------------

The
registrant knows of no arrangement, including any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result in a change of control of the registrant. See Certain
Relationships and Related Transactions, and Director IndependenceRegistration Rights.



|Item 13. | Certain Relationships and Related Transactions, and Director Independence.
|-------- | --------------------------------------------------------------------------

Trustee Administrative Fee.Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the
Trustee and $2,000 to the Delaware Trustee.

Registration Rights Agreement.The Trust entered into a Registration
Rights Agreement with Enduro dated as of November 8, 2011 and amended by Amendment No. 1 on November 8, 2012 in connection with the initial public offering of Trust Units and Enduros conveyance to the Trust of the Net Profits
Interest whereby Enduro, its affiliates and certain permitted transferees holding registrable Trust Units are entitled, 180 days after the effectiveness of the Registration Rights Agreement and upon receipt by the Trustee of written notice from
holders of a majority of the then outstanding registrable Trust Units, to demand that the Trust effect the registration of the registrable Trust Units. The holders of the registrable Trust Units are entitled to demand a maximum of five such
registrations. In connection with the preparation and filing of any registration statement, Enduro will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by
the Trust. Any underwriting discounts and commissions will be borne by the seller of the Trust Units. The foregoing description of the Registration Rights Agreement is qualified in its entirety by the terms of the Registration Rights Agreement, and
Amendment No. 1 thereto, copies of which are filed as exhibits to this report.

Director Independence

The Trust does not have a board of directors.



|Item 14. | Principal Accounting Fees and Services.
|-------- | ---------------------------------------

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the
Trustee. During the year ended December 31, 2012 and for the period from Inception through December 31, 2011, Ernst & Young, LLP served as the Trusts independent registered public accounting firm. The Trustee also has
appointed Ernst & Young, LLP as the independent registered public accounting firm to audit the Trusts financial statements for the fiscal year ending December 31, 2013.

The following table presents the aggregate fees billed to the Trust for the year ended December 31, 2012 and for the period from
Inception through December 31, 2011 by Ernst & Young, LLP:



|                   |  |      |         |  |      |   |         | 
|------------------ |  | ---- | ------- |  | ---- | - | ------- | 
|                   |  | 2012 |         |  | 2011 |  
|Audit fees(1)      |  | $    | 130,000 |  |      | $ | 125,000 | 
|Audit-related fees |  |      |        |  |      |   |        | 
|Tax fees           |  |      |        |  |      |   |        | 
|All other fees     |  |      |        |  |      |   |        | 
|                   |  |      |         |  |      |   |         | 
|Total fees         |  | $    | 130,000 |  |      | $ | 125,000 | 
|                   |  |      |         |  |      |   |         | 



|(1) | Fees for audit services consisted of the audit of the Trusts financial statements.
|--- | -----------------------------------------------------------------------------------



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PART IV



|Item 15. | Exhibits, Financial Statement Schedules.
|-------- | ----------------------------------------

(a)(1) Financial Statements

The following financial statements are
set forth under Financial Statements and Supplementary Data of this Form 10-K on the pages indicated:



|                                                                                                     |  |                       |    | 
|---------------------------------------------------------------------------------------------------- |  | --------------------- | -- | 
|                                                                                                     |  | Page in thisForm 10-K |   
|Enduro Royalty Trust                                                                                 |  |                       |    | 
|Report of Independent Registered Public Accounting Firm                                              |  |                       | 54 | 
|Statements of Assets, Liabilities and Trust Corpus                                                   |  |                       | 55 | 
|Statements of Distributable Income                                                                   |  |                       | 56 | 
|Statements of Changes in Trust Corpus                                                                |  |                       | 57 | 
|Notes to Financial Statements                                                                        |  |                       | 58 | 
|Unaudited Supplementary Information                                                                  |  |                       | 65 | 
|                                                                                                     | 
|Underlying Properties Historical Financial Information                                               |  |                       |    | 
|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 | 

(a)(2) Schedules

Schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.

(a)(3) Exhibits

See Exhibit Index.



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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.



ENDURO ROYALTY TRUSTBy

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.By:

/s/    MIKE
ULRICHMike UlrichVice President


March 18, 2013

The Registrant, Enduro Royalty Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are
available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that such function exists pursuant to the terms of the Trust Agreement under which it serves.



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Appendix A



LOGO

January 18, 2013

Mr. Mike Ulrich

Enduro Royalty Trust

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

919 Congress Avenue, Suite 500

Austin, TX 78701



|    |  |                                                                                                                                                                                                                                                                  |  |                                                                                                                             
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------------------------------------------------------------------------------------
|Re: |  | EvaluationTotal Proved Reserves Enduro Royalty TrustNet Profit Interests Derived From Enduro Resource Partners
LLC Underlying Properties Total Controlled Interests Texas, Louisiana and New Mexico Properties Using Yearend SEC Prices as of December 31,
2012 |  | Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and
Future Net Revenue

Dear Mr. Ulrich:

As requested, this report was prepared on January 18, 2013 for Enduro Royalty Trust (Trust) for the purpose of submitting our estimates of total proved reserves and forecasts of economics
attributable to the Trust net profits interests. We evaluated 100% of the Trust reserves, which are made up of oil and gas properties in Texas, Louisiana and New Mexico controlled by Enduro Resource Partners (Company). This evaluation
utilized an effective date of December 31, 2012, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). Composite summaries of
the proved reserves for both the total controlled interests and the net profits interests are presented below.

Total
Controlled Interests



|                            |  |        |  |                          |             |  |                              |  |         |                   |  |  |             |  |  |  |             | 
|--------------------------- |  | ------ |  | ------------------------ | ----------- |  | ---------------------------- |  | ------- | ----------------- |  |  | ----------- |  |  |  | ----------- | 
|                            |  |        |  | ProvedDevelopedProducing |             |  | ProvedDevelopedNon-Producing |  |         | ProvedUndeveloped |  |  | TotalProved | 
|Net Reserves                |  |        |  |                          |             |  |                              |  |         |                   |  |  |             |  |  |  |             | 
|Oil                         |  |  Mbbl |  |                          | 12,138.9    |  |                              |  | 28.8    |                   |  |  | 0.0         |  |  |  | 12,167.7    | 
|Gas                         |  |  MMcf |  |                          | 41,698.3    |  |                              |  | 27.0    |                   |  |  | 13,402.1    |  |  |  | 55,127.4    | 
|Revenue                     |  |        |  |                          |             |  |                              |  |         |                   |  |  |             |  |  |  |             | 
|Oil                         |  |  M$   |  |                          | 1,037,886.1 |  |                              |  | 2,392.6 |                   |  |  | 0.0         |  |  |  | 1,040,278.8 | 
|Gas                         |  |  M$   |  |                          | 158,935.2   |  |                              |  | 63.2    |                   |  |  | 33,932.0    |  |  |  | 192,930.5   | 
|Net Taxes                   |  |  M$   |  |                          | 100,667.8   |  |                              |  | 216.4   |                   |  |  | 1,963.7     |  |  |  | 102,847.9   | 
|Operating Expenses          |  |  M$   |  |                          | 494,013.2   |  |                              |  | 606.0   |                   |  |  | 11,116.6    |  |  |  | 505,735.8   | 
|Investments                 |  |  M$   |  |                          | 0.0         |  |                              |  | 0.0     |                   |  |  | 18,250.6    |  |  |  | 18,250.6    | 
|Net Operating Income (BFIT) |  |  M$   |  |                          | 602,140.6   |  |                              |  | 1,633.4 |                   |  |  | 2,601.1     |  |  |  | 606,374.9   | 
|Discounted at 10%           |  |  M$   |  |                          | 299,673.3   |  |                              |  | 1,003.0 |                   |  |  | -3,436.1    |  |  |  | 297,240.2   | 



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Enduro Royalty Trust

January 18, 2013

Page
 2



Net Profits Interests



|                            |  |        |  |                          |           |  |                              |  |         |                   |  |  |             |  |  |  |           | 
|--------------------------- |  | ------ |  | ------------------------ | --------- |  | ---------------------------- |  | ------- | ----------------- |  |  | ----------- |  |  |  | --------- | 
|                            |  |        |  | ProvedDevelopedProducing |           |  | ProvedDevelopedNon-Producing |  |         | ProvedUndeveloped |  |  | TotalProved | 
|Net Reserves                |  |        |  |                          |           |  |                              |  |         |                   |  |  |             |  |  |  |           | 
|Oil                         |  |  Mbbl |  |                          | 5,307.0   |  |                              |  | 17.0    |                   |  |  | 0.0         |  |  |  | 5,324.0   | 
|Gas                         |  |  MMcf |  |                          | 19,264.0  |  |                              |  | 15.0    |                   |  |  | 1,050.0     |  |  |  | 20,329.0  | 
|Revenue                     |  |        |  |                          |           |  |                              |  |         |                   |  |  |             |  |  |  |           | 
|Oil                         |  |  M$   |  |                          | 453,385.0 |  |                              |  | 1,397.0 |                   |  |  | 0.0         |  |  |  | 454,782.0 | 
|Gas                         |  |  M$   |  |                          | 72,560.0  |  |                              |  | 36.0    |                   |  |  | 2,658.0     |  |  |  | 75,253.0  | 
|Net Taxes                   |  |  M$   |  |                          | 44,235.0  |  |                              |  | 127.0   |                   |  |  | 579.0       |  |  |  | 44,941.0  | 
|Operating Expenses          |  |  M$   |  |                          | 0.0       |  |                              |  | 0.0     |                   |  |  | 0.0         |  |  |  | 0.0       | 
|Investments                 |  |  M$   |  |                          | 0.0       |  |                              |  | 0.0     |                   |  |  | 0.0         |  |  |  | 0.0       | 
|Net Operating Income (BFIT) |  |  M$   |  |                          | 481,711.0 |  |                              |  | 1,307.0 |                   |  |  | 2,078.0     |  |  |  | 485,097.0 | 
|Discounted at 10%           |  |  M$   |  |                          | 239,739.0 |  |                              |  | 802.0   |                   |  |  | -2,750.0    |  |  |  | 237,791.0 | 

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is
after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine
its present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in
thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Our 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.

Net Profit Calculation

The net profits interests entitle the Trust
to receive 80% of the net proceeds attributable to the Company interest from the sale of production from the underlying properties.

Hydrocarbon Pricing

The base SEC oil and gas prices calculated for December 31, 2012 were $94.71/bbl and $2.75/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2012 and the base gas price
is based upon Henry Hub spot prices (EIA) during 2012.

The base prices were adjusted for differentials on a per-property
basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of
the proved properties was estimated to be $85.50 per barrel for oil and $3.50 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.



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Enduro Royalty Trust

January 18, 2013

Page
 3



Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, lease operating expenses
(LOE), workover expenses, overhead expenses and investments were calculated and prepared by Company and were thoroughly reviewed by us for accuracy and completeness. LOE (column 22) was determined at the well level using averages determined from
historical lease operating statements. All economic parameters, including expenses and investments, were held constant (not escalated) throughout the life of these properties.

Severance tax rates were applied at normal state percentages of oil and gas revenue. Ad valorem taxes were applied to each property as provided by your office.

Possible Effects of Federal and State Legislation

Federal, state and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved
reserves for this report. However, the impact of possible changes to legislation or regulations to future operating expenses and investment costs have not been included in the evaluation. These possible changes could have an effect on the reserves
and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

SEC Conformance and Regulations

The reserve classifications and the
economic considerations used herein for the SEC pricing scenario conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws,
taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not
anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 13 proved undeveloped locations based in various fields in Louisiana. Each of these drilling locations proposed as part of the Companys development plan conforms to the
proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have every intent to complete this development plan within the next five years. Furthermore, the Company has demonstrated that they have the proper
company staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority
of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of
accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either
volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of
their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.



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Enduro Royalty Trust

January 18, 2013

Page
 4



General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent
information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause
us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and
geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their
related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and
the salvage value of equipment at abandonment have not been included as part of the workover expenses described previously.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered
professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. This evaluation was supervised by Robert D. Ravnaas, President at Cawley, Gillespie & Associates, Inc. and
a State of Texas Licensed Professional Engineer (License #61304). We do not own an interest in the properties or Enduro Resource Partners LLC or Enduro Royalty Trust and are not employed on a contingent basis. We have used all methods and procedures
that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. We consent to the filing of this report as an exhibit to the
Annual Report on Form 10-K of Enduro Royalty Trust for the year end December 31, 2012.



Yours very truly,LOGO

LOGORobert D. Ravnaas, P.E.PresidentCAWLEY, GILLESPIE & ASSOCIATES, INC.Texas Registered Engineering Firm (F-693)




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INDEX TO EXHIBITS



|               |  |                                                                                                                                                                                                                                                                                                                                                                                                                          
|-------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit
Number |  | Description                                                                                                                                                                                                                                                                                                                                                                                                              
|               | 
|2.1*           |  | Agreement and Plan of Merger of Enduro Royalty Trust and Enduro Texas LLC, dated as of November 3, 2011 by and between the Bank of New York Mellon Trust Company, N.A. as Trustee of
Enduro Royalty Trust and Enduro Texas LLC. (Incorporated herein by reference to Exhibit 1.2 to our Current Report on Form 8-K filed on November 8, 2011 (File No. 1-35333))                                                         
|               | 
|3.1*           |  | Certificate of Trust of Enduro Royalty Trust. (Incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-1, filed on May 16, 2011
(Registration No. 333-174225))                                                                                                                                                                                                                           
|               | 
|3.2*           |  | Trust Agreement of Enduro Royalty Trust, dated as of May 3, 2011 by and between the Bank of New York Mellon Trust Company, N.A. as Trustee of Enduro Royalty Trust and Enduro
Texas LLC. (Incorporated herein by reference to Exhibit 3.4 to the Registration Statement on Form S-1, filed on May 16, 2011 (Registration No. 333-174225))                                                                                
|               | 
|3.3*           |  | Amended and Restated Trust Agreement of Enduro Royalty Trust, dated November 3, 2011, among Enduro Resource Partners LLC, The Bank of New York Mellon Trust Company, N.A. as Trustee
of Enduro Royalty Trust, and Wilmington Trust Company, as Delaware Trustee of Enduro Royalty Trust. (Incorporated herein by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on November 8, 2011 (File
No. 1-35333))
|               | 
|4.1*           |  | Registration Rights Agreement, dated as of November 8, 2011, by and between Enduro Resource Partners LLC and Enduro Royalty Trust. (Incorporated herein by reference to
Exhibit 10.3 to our Current Report on Form 8-K filed on November 8, 2011 (File No. 1-35333))                                                                                                                                                     
|               | 
|4.2            |  | Amendment No. 1 to Registration Rights Agreement, dated as of November 8, 2012, by and between Enduro Resource Partners LLC and Enduro Royalty Trust                                                                                                                                                                                                                                                                     
|               | 
|10.1*          |  | Conveyance of Net Profits Interest, dated November 8, 2011, by and between Enduro Operating LLC and Enduro Texas LLC. (Incorporated herein by reference to Exhibit 10.1 to our
Current Report on Form 8-K filed on November 8, 2011 (File No. 1-35333))                                                                                                                                                                  
|               | 
|10.2*          |  | Supplement to Conveyance of Net Profits Interest, dated November 8, 2011, from Enduro Operating LLC, Enduro Texas LLC and the Bank of New York Mellon Trust Company, N.A. as Trustee
of Enduro Royalty Trust. (Incorporated herein by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on November 8, 2011 (File No. 1-35333))                                                                          
|               | 
|23.1           |  | Consent of Cawley, Gillespie & Associates, Inc.                                                                                                                                                                                                                                                                                                                                                                          
|               | 
|31.1           |  | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                                                                                                  
|               | 
|32.1           |  | Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                                                                                                                                  
|               | 
|99.1           |  | Report of Cawley, Gillespie & Associates, Inc.                                                                                                                                                                                                                                                                                                                                                                           



|* | Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.
|- | ----------------------------------------------------------------------------------------------