Attached files

file filename
EX-23.2 - EX-23.2 - CONSENT OF ERNST & YOUNG LLP - WildHorse Resource Development Corpwrd-ex232_8.htm
10-K - 10-K - WildHorse Resource Development Corpwrd-10k_20171231.htm
EX-32.1 - EX-32.1 - CERTIFICATIONS OF CEO AND CFO - WildHorse Resource Development Corpwrd-ex321_39.htm
EX-31.2 - EX-31.2 - CERTIFICATION OF CHIEF FINANCIAL OFFICER - WildHorse Resource Development Corpwrd-ex312_38.htm
EX-31.1 - EX-31.1- CERTIFICATION OF CHIEF EXECUTIVE OFFICER - WildHorse Resource Development Corpwrd-ex311_40.htm
EX-23.3 - EX-23.3 - CONSENT OF CAWLEY, GILLESPIE AND ASSOCIATES, INC. - WildHorse Resource Development Corpwrd-ex233_10.htm
EX-23.1 - EX-23.1 - CONSENT OF KPMG - WildHorse Resource Development Corpwrd-ex231_6.htm
EX-21.1 - EX-21.1 - SUBSIDIARIES OF WILDHORSE RESOURCE DEVELOPMENT CORPORATION - WildHorse Resource Development Corpwrd-ex211_7.htm
EX-4.6 - EX-4.6 - SECOND SUPPLEMENTAL INDENTURE - WildHorse Resource Development Corpwrd-ex46_52.htm

Exhibit 99.1




13640 BRIARWICK DRIVE, SUITE 100306 WEST SEVENTH STREET, SUITE 3021000 LOUISIANA STREET, SUITE 1900 AUSTIN, TEXAS 78729-1707FORT WORTH, TEXAS 76102-4987HOUSTON, TEXAS 77002-5008 512-249-7000817- 336-2461713-651-9944


January 23, 2018


Mr. Jason Pearce

Senior Vice President, Reserves

WildHorse Resource Development Corporation 9805 Katy Freeway, Suite 400

Houston, TX 77024









Dear Mr. Pearce:




Re:Reserve Audit – SEC Pricing

WildHorse Resource Development Corporation

Total Proved Reserves As of December 31, 2017

Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and

Future Net Revenue


At your request, Cawley, Gillespie & Associates, Inc. (“CG&A”) prepared this report on January 23, 2018 for WildHorse Resource Development Corporation (“WildHorse”) for the purpose of confirming WildHorse’s in-house estimates of the proved reserves and future revenue, as of December 31, 2017, attributable to WildHorse’s interest in certain oil and gas properties in East Texas and North Louisiana. It is our understanding that the proved reserves   estimated in this report constitute all of the proved reserves owned by WildHorse, which are located in various oil and gas properties in East Texas and North Louisiana. This report was prepared for public disclosure by WildHorse or its affiliates in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. This evaluation, effective December 31, 2017, 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).  In CG&A’s opinion,   the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purposes.

A composite summary of the results of this audit are presented in the table below with respect to the total proved reserves of the interests of WildHorse:















Net Reserves







- Mbbl






- MMcf






Net Revenue

- Mbbl






- M$






- M$






- M$





Severance Taxes

- M$





Ad Valorem Taxes

- M$





Operating Expenses

- M$





3rd Party COPAS

- M$





Other Deductions

- M$






- M$





Future Net Cash Flow

- M$





Discounted @ 10%

- M$






WildHorse Resource Development Corporation – SEC Pricing

January 23, 2018

Page 2



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.


Hydrocarbon Pricing

In this audit, the base oil and gas prices calculated for December 31, 2017 were $51.34/BBL and $2.976/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 during 2017 and the base gas price is based upon Henry Hub spot prices during 2017. Prices were not escalated.


The base prices were adjusted for differentials on a by area 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 $49.80 per barrel for oil, $16.27 per barrel for NGL, and $2.849 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.


Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials,  gas shrinkage, ad valorem taxes, lease operating expenses and investments were calculated and prepared by WildHorse and were accepted as furnished. All economic parameters, including lease operating expenses and investments, were  held constant (not escalated) throughout the life of these properties.


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.


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 offset 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 WildHorse’s  properties.  The  assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.


WildHorse Resource Development Corporation – SEC Pricing

January 23, 2018

Page 3



General Discussion

Please be advised that, based upon the foregoing, in our opinion the above-described estimates of the direct interests of WildHorse’s proved reserves are, in the aggregate,  reasonable  and  have  been prepared in accordance  with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. In aggregate, CG&A reserve estimates are within 10% of WildHorse’s in-house reserve estimates shown in the tables above for WildHorses’s properties. The estimates shown herein are for proved reserves. WildHorse’s estimates do not include probable or possible reserves that exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.


It should be understood that our above-described audit does not constitute a complete reserve study of the audited WildHorse oil and gas properties. The estimates and forecasts were based upon interpretations of data furnished by WildHorse and available from our files. 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 nor have the mechanical  operation  or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated or considered. The estimated net cost of plugging and the salvage value of equipment at abandonment has been included.


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. The lead evaluator preparing this report was W. Todd Brooker, P.E., President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or WildHorse 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.


This letter is for the use of WildHorse Resource Development Corporation. This letter should not be used, circulated, or quoted for any other purpose without the express written consent of Cawley, Gillespie & Associates, Inc. or except as required by law.







W. Todd Brooker, P.E. President

Yours very truly,











Robert P. Bergeron, Jr., P.E Senior Reservoir Engineer





Explanatory Comments for Individual Tables











Table Number Effective Date of the Evaluation

Identity of Interest Evaluated

Reserve Classification and Development Status Operator – Property Name

Field (Reservoir) Names – County, State







(11) (21)Calendar or Fiscal years/months commencing on effective date.



(3) (4)Gross Production (8/8th) for the years/months which are economical.         These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative  production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.



(5) (6) (7)

Net  Production  accruable  to  evaluated  interest  is  calculated  by  multiplying  the  revenue  interest  times the gross production.  These values take into account changes in interest and gas shrinkage.




Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.



Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.



Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.



Revenue derived from oil sales -- column (5) times column (8).



Revenue derived from gas sales -- column (6) times column (9).



Revenue derived from NGL sales -- column (7) times column (10).



Revenue derived from hedge positions.



Revenue not derived from column (12) through column (15); may include electrical sales revenue and saltwater disposal revenue.




Total Revenue – sum of column (12) through column (16).



Production-Severance taxes deducted from gross oil, gas and NGL revenue.



Ad Valorem taxes.



$/BOE6 is the total of column (22), column (25), column (26), and column (27) divided by Barrels of Oil Equivalent (“BOE”). BOE is net oil production column (5) plus net gas production column (6) converted to oil at six Mcf gas per one bbl oil plus net NGL production column (7) converted to oil at one bbl NGL per 0.65 bbls of oil.




Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed  rate administrative overhead charges for operated oil and gas producers known as COPAS.




Average gross wells.



Average net wells are gross wells times working interest.



Work-over Expenses are non-direct operating expenses and may include maintenance, well  service,  compressor, tubing, and pump repair.




3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.



Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.



Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.




(30)Future Net Cash Flow is column (17) less the total of column (18), column (19), column (22), column (25), column (26), column (27), and column (28). The data in column (29) are accumulated in column (30). Federal income taxes have not been considered.


(31)Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.





DCF Profile

•   The cumulative cash flow discounted at six different interest rates are shown at the bottom of columns (30-31).     Interest has been compounded monthly. The DCF’s for the “Without Hedge” case may be shown to the left of the main DCF profile.




•   The economic life of the appraised property is noted in the lower right-hand corner of the table. Footnotes•   Comments regarding the evaluation may be shown in the lower left-hand footnotes.


Price Deck A table of oil and gas prices, price caps and escalation rates may be shown in the lower middle footnotes.





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 a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. 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.




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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Cawley, Gillespie & Associates, Inc.



"(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).








Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable


“(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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