Exhibit 99.1



LOGO

January 22, 2014

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 Trust Net 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, 2013 |  | 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 22, 2014 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, 2013, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of theSecurities 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 |  |                          | 13,169.1    |  |                              |  | 394.1    |                   |  |  | 378.9       |  |  |  | 13,942.0    | 
|Gas                         |  |  MMcf |  |                          | 40,801.8    |  |                              |  | 1,615.7  |                   |  |  | 13,981.9    |  |  |  | 56,399.4    | 
|Revenue                     |  |        |  |                          |             |  |                              |  |          |                   |  |  |             |  |  |  |             | 
|Oil                         |  |  M$   |  |                          | 1,193,641.0 |  |                              |  | 37,566.8 |                   |  |  | 25,556.7    |  |  |  | 1,256,764.4 | 
|Gas                         |  |  M$   |  |                          | 156,453.1   |  |                              |  | 5,034.7  |                   |  |  | 50,605.8    |  |  |  | 212,093.7   | 
|Net Taxes                   |  |  M$   |  |                          | 109,910.5   |  |                              |  | 2,531.0  |                   |  |  | 3,845.7     |  |  |  | 116,287.2   | 
|Operating Expenses          |  |  M$   |  |                          | 550,531.2   |  |                              |  | 3,250.1  |                   |  |  | 12,272.7    |  |  |  | 566,054.0   | 
|Investments                 |  |  M$   |  |                          | 0.0         |  |                              |  | 441.0    |                   |  |  | 20,214.4    |  |  |  | 20,655.4    | 
|Net Operating Income (BFIT) |  |  M$   |  |                          | 689,652.3   |  |                              |  | 36,379.5 |                   |  |  | 39,829.6    |  |  |  | 765,861.2   | 
|Discounted at 10%           |  |  M$   |  |                          | 319,556.5   |  |                              |  | 23,370.6 |                   |  |  | 16,439.9    |  |  |  | 359,367.1   | 



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Enduro Royalty Trust

January 22, 2014

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Net Profits Interests



|                            |  |        |  |                          |           |  |                              |  |          |                   |  |  |             |  |  |  |           | 
|--------------------------- |  | ------ |  | ------------------------ | --------- |  | ---------------------------- |  | -------- | ----------------- |  |  | ----------- |  |  |  | --------- | 
|                            |  |        |  | ProvedDevelopedProducing |           |  | ProvedDevelopedNon-Producing |  |          | ProvedUndeveloped |  |  | TotalProved | 
|Net Reserves                |  |        |  |                          |           |  |                              |  |          |                   |  |  |             |  |  |  |           | 
|Oil                         |  |  Mbbl |  |                          | 5,825.0   |  |                              |  | 286.0    |                   |  |  | 147.0       |  |  |  | 6,259.0   | 
|Gas                         |  |  MMcf |  |                          | 19,307.0  |  |                              |  | 1,172.0  |                   |  |  | 6,569.0     |  |  |  | 27,048.0  | 
|Revenue                     |  |        |  |                          |           |  |                              |  |          |                   |  |  |             |  |  |  |           | 
|Oil                         |  |  M$   |  |                          | 526,746.0 |  |                              |  | 27,284.0 |                   |  |  | 9,880.0     |  |  |  | 563,910.0 | 
|Gas                         |  |  M$   |  |                          | 73,784.0  |  |                              |  | 3,658.0  |                   |  |  | 23,771.0    |  |  |  | 101,213.0 | 
|Net Taxes                   |  |  M$   |  |                          | 48,812.0  |  |                              |  | 1,838.0  |                   |  |  | 1,786.0     |  |  |  | 52,436.0  | 
|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$   |  |                          | 551,721.0 |  |                              |  | 29,102.0 |                   |  |  | 31,864.0    |  |  |  | 612,687.0 | 
|Discounted at 10%           |  |  M$   |  |                          | 255,645.0 |  |                              |  | 18,697.0 |                   |  |  | 13,154.0    |  |  |  | 287,495.0 | 

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, 2013 were $96.78/bbl and $3.67/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 2013 and the base gas price is based upon Henry Hub spot prices
(EIA) during 2013.

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 $90.14
per barrel for oil and $3.76 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.



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Enduro Royalty Trust

January 22, 2014

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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 19 proved undeveloped locations based in various fields in Louisiana and Texas.
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 22, 2014

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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, 2013.



|     |                                           |                  
|---- | ----------------------------------------- | -----------------
|     |                                           | Yours very truly,
|     |                                          
|LOGO |                                           | LOGO             
|     | Robert D. Ravnaas, P.E.                  
|     | President                                
|     | CAWLEY, GILLESPIE & ASSOCIATES, INC.     
|     | Texas Registered Engineering Firm (F-693)



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APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material
balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of
the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the
quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as
well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application
of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief
discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have
controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of
rates versus time or cumulative production. This procedure is referred to as decline curve analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various
production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise
that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method
requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on
the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for
other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates
obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of
hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible
to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric
calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be
relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations
and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are
generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself
arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and
new information is obtained about well and reservoir performance.



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APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and
January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

(22) Proved oil and gas
reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable
time.

(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid
contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and
engineering data.

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

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

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to,
fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in
the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for
development by all necessary parties and entities, including governmental entities.

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

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:

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

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

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

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

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

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



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

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

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

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

(iv) See
also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

(17) Possible reserves.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

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

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

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

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

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

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

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that a
registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation SK. This is relevant in that Instruction 2 to paragraph (a)(2) states: The registrant is permitted, but
not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be
economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue
interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those
reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir,
or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).



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| |  | Cawley, Gillespie & Associates, Inc. |  | Appendix
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