Exhibit 99.4















ALTA MESA HOLDINGS, L.P.











Estimated



Future Reserves



Attributable to Certain



Leasehold and Royalty Interests







OKLAHOMA PROPERTIES











NYMEX Pricing Case











As of



December 31, 2016















RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

 

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January 26, 2017







Tim J. Turner

VP Corporate Planning and Reserves

Alta Mesa Holdings, L.P.

15021 Katy Freeway, Suite 400

Houston, Texas 77094



Dear Mr. Turner:



At the request of Alta Mesa Holdings, LP.  (AMH), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by AMH’s engineering and geological staff based on the definitions and disclosure guidelines contained in the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (SPE-PRMS) based on varying price and unescalated cost parameters (SPE-PRMS forecast case), provided by AMH.   The income data which were not reviewed by Ryder Scott were estimated using AMH’s future price and cost parameters as noted herein.  The results of our reserves audit, completed on January 19, 2017, are presented herein.   



The estimated reserves shown herein represent AMH’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by AMH and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2016.    The properties reviewed by Ryder Scott incorporate 395 reserve determinations and are located in the state of Oklahoma. 



The properties reviewed by Ryder Scott account for a portion of AMH’s total net proved reserves located in the state of Oklahoma as of December 31, 2016.  Based on the estimates of total net proved reserves prepared by AMH for their Oklahoma properties, the reserves audit conducted by Ryder Scott addresses 99 percent of the total proved developed net liquid hydrocarbon reserves, 99 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 100 percent of the total proved undeveloped net gas reserves of AMH.



The properties reviewed by Ryder Scott account for a portion of AMH’s total proved discounted future net income using NYMEX price parameters described herein as of December 31, 2016.  Although it was not included in our scope of study to review the economic analysis prepared by AMH, the income projections for the reserves reviewed by Ryder Scott account for 99 percent of the total proved developed discounted future net income at 10 percent and 100 percent of the total proved undeveloped discounted future net income at 10 percent of AMH’s Oklahoma properties.  



As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”



Based on our review, including the data, technical processes and interpretations presented by AMH, it is our opinion that the overall procedures and methodologies utilized by AMH in preparing their

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estimates of the proved reserves as of December 31, 2016 comply with the current SPE-PRMS definitions and guidelines and that the overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate on a barrel of oil equivalent basis, reasonable within the established audit tolerance guidelines set forth in the SPE auditing standards.  Barrel of oil equivalents are determined by adding oil and plant products on a barrel for barrel basis and natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.   



The estimated reserves presented in this report, as of December 31, 2016, are related to hydrocarbon prices, based on varying price parameters provided by AMH.  Actual future prices may vary significantly from the prices assumed in this report; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The net reserves as estimated by AMH attributable to AMH's interest in properties that we reviewed and for those that we did not review are summarized as follows:





NYMEX PRICING CASE

Estimated Net Reserves 

Certain Leasehold and Royalty Interests of

Alta Mesa Holdings, L.P.

OKLAHOMA PROPERTIES







Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels).  All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.  The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent.  MBOE means thousand barrels of oil equivalent. 



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The plant products in our review are based on AMH’s calculations of estimated plant product recovery yields to gas production, which are anticipated to be recovered as the result of the installation of a new and more efficient natural gas processing facility in Oklahoma.  This new facility began processing the last week of May 2016, and has not yet reached full capacity.  It is our understanding that Kingfisher Midstream, a gas gatherer and processor, is currently processing less than 40 MMcfd, and as volumes ramp up, efficiencies will increase and the current NGL yield assumption of 75 barrels/MMcf will be achieved. We have reviewed such yields for reasonableness; however, we have not conducted an independent verification of the data furnished by AMH.  Such yields are dependent on the ability of AMH to obtain access to natural gas processing capacity capable of achieving these yields.  The plant product volumes in our review are based on these facilities achieving the designed product recoveries.



In certain instances where natural gas is processed in a third party plant, the title to the gas is transferred before the processing plant.  The income received for the gas delivered is determined by a contractually determined volume of a portion of the plant residue sales gas and of the plant products (natural gas liquids) extracted from the natural gas.  AMH has shown this incremental income from plant products as equivalent plant product volumes in order to provide transparency to investors, banks, and financial institutions regarding specific sources of forecasted income.



As stated previously, AMH did not request Ryder Scott to conduct an economic analysis of the net economic benefit from the production of the above reserves volumes.  AMH’s estimates of future net income may not capture all the new and revised gas gathering, processing, compression, and other fees and expenses and potential revenue enhancements resulting from the aforementioned processing facilities located in Oklahoma.  Thus, the user of this report is cautioned that AMH’s estimates of the future net income ultimately may or may not be within the 10 percent tolerance.  The total future net income discounted at 10 percent prepared by AMH (which Ryder Scott did not review) attributable to AMH's interest in properties that we reviewed and those properties that we did not review are summarized below:



NYMEX PRICING CASE

Discounted Future Net Income

Certain Leasehold and Royalty Interests of

Alta Mesa Holdings, L.P.

OKLAHOMA PROPERTIES





The discounted future net income shown above is presented at AMH’s request for your information and should not be construed as an estimate of fair market value.  The term $M denotes thousands of dollars.



Reserves Included in This Report



The proved reserves presented herein conform to the definitions of reserves sponsored and approved by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the

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American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE) as set forth in the 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System (SPE-PRMS).  An abridged version of the SPE/WPC/AAPG/SPEE reserves terms and definitions used herein are included as attachments to this report and entitled “Petroleum Reserves Definitions.”  



The various reserve development and production status categories are defined in the attachment to this report entitled “Petroleum Reserves Status Definitions and Guidelines.” 



No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.  The gas volumes presented herein do not include volumes of gas consumed in operations as reserves. 



Recoverable petroleum resources may be classified according to the SPE-PRMS into one of three principal resource classifications: prospective resources, contingent resources, or reserves.  Discovered petroleum resources may be classified as either contingent resources or as reserves depending on the chance that if a project is implemented it will reach commercial producing status (i.e. chance of commerciality).  The distinction between various “classifications” of resources and reserves relates to their discovery status and increasing chance of commerciality.  Commerciality is not solely determined based on the economic status of a project which refers to the situation where the income from an operation exceeds the expenses involved in, or attributable to, that operation.  Conditions addressed in the determination of commerciality also include technological, economic, legal, environmental, social, and governmental factors.  While economic factors are generally related to costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms and taxes.  At AMH’s request, this report addresses only the reserves attributable to the properties reviewed herein and not the resources (if any).



All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  Estimates will generally be revised only as additional geologic or engineering data becomes available or as economic conditions change.



Reserves are “those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.”  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. 



Proved oil and gas reserves are “those quantities of petroleum which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.”



Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Probable reserves are “those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves.”  For probable reserves, it is “equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves” (cumulative 2P volumes).  Possible reserves are “those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than probable reserves.”  For

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possible reserves, the “total quantities ultimately recovered from the project have a low probability to exceed the sum of the proved plus probable plus possible reserves” (cumulative 3P volumes). At AMH’s request, this report addresses only the proved reserves attributable to the properties reviewed herein and not the unproved reserves (if any). 



The reserves included herein were estimated using deterministic methods and presented as incremental quantities.  Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. 



Estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks.  As a result, the estimates of oil and gas reserves have an intrinsic uncertainty.  The reserves included in this report are therefore estimates only and should not be construed as being exact quantities.  They may or may not be actually recovered, and if recovered, could be more or less than the estimated amounts.



Audit Data, Methodology, Procedure and Assumptions



The estimation of reserve quantities involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities.  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy.  These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves.  Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property. 



In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of recoverable hydrocarbons is identified, the evaluator must determine the uncertainty associated with the incremental quantities of those recoverable hydrocarbons. If the quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity is addressed by the reserve category assigned by the evaluator.  Therefore, it is the categorization of incremental recoverable quantities that addresses the inherent uncertainty in the estimated quantities reported.

Estimates of reserve quantities and their associated categories or classifications may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of the recoverable quantities and their associated categories or classifications may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.



The proved reserves, prepared by AMH,  for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods.  Approximately 100 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods.  These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December 2016, in those cases where such data were

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considered to be definitive.  The data utilized in this analysis were furnished to Ryder Scott by AMH or obtained from public data sources and were considered sufficient for the purpose thereof. 



Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by a combination of the analogy and volumetric methods.   The data utilized from the analogues were considered sufficient for the purpose thereof. 



Horizontal wells and locations which Ryder Scott audited, essentially all of which are located in the Meramec, Osage, and Oswego plays in Oklahoma, represent 97 percent of AMH’s liquids reserves and 97 percent of AMH’s gas reserves.  Seventy-six  percent of liquids reserves and 77 percent of gas reserves associated with horizontal drilling are proved undeveloped.  The remainder are producing.



To estimate recoverable oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on the cost and price assumptions as noted herein, and forecasts of future production rates.  Under the SPE-PRMS Section 2.2.2 and Table 3, proved reserves must be demonstrated to be commercially recoverable under defined economic conditions, operating methods and governmental regulations from a given date forward.  



As stated previously, proved reserves must be demonstrated to be commercially recoverable under defined conditions, operating methods and governmental regulations from a given date forward.  To confirm that the proved reserves reviewed by us meet the SPE-PRMS guidelines to be commercially recoverable, we have reviewed certain primary economic data utilized by AMH relating to hydrocarbon prices and costs as noted herein.    



AMH furnished us with product prices for the properties reviewed by us.  The future hydrocarbon price parameters used by AMH are summarized in the following table.







Product prices which were actually used for each property reviewed by us reflect adjustments for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by AMH.  The term MMBtu represents million of British thermal units 



The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in AMH’s individual property evaluations.



Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed.  The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.



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Operating costs furnished by AMH are based on the operating expense reports of AMH and include only those costs directly applicable to the leases or wells for the properties reviewed by us.   The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.  The operating costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH.   No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.



Development costs furnished by AMH are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished by AMH were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by AMH.  The estimated net cost of abandonment after salvage was included by AMH for properties where abandonment costs net of salvage were significant.  AMH’s estimates of the net abandonment costs were accepted without independent verification.    



Because of the direct relationship between volumes of undeveloped reserves and development plans, we include in the undeveloped category for the properties we reviewed only reserves assigned to undeveloped locations that we have been assured will definitely be drilled.   AMH has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans.



Current costs used by AMH were held constant throughout the life of the properties.



AMH’s forecasts of future production rates are based on historical performance from wells currently on production.  If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.  An estimated rate of decline was then applied to depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates. 



Test data and other related information were used by AMH to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by AMH.  Wells or locations that are not currently producing may start producing earlier or later than anticipated in AMH’s estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 



The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. 



AMH’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons,  drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

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The estimates of reserves presented herein were based upon a review of the properties in which AMH owns an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by AMH for potential liabilities to restore and clean up damages, if any, caused by past operating practices.



Certain technical personnel of AMH are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties.  These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner.  We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.



AMH has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In performing our audit of AMH’s forecast of future proved production, we have relied upon data furnished by AMH with respect to property interests owned, production and well tests from examined wells, plant product yields, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by AMH.  The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved.  We consider the factual data furnished to us by AMH to be appropriate and sufficient for the purpose of our review of AMH’s estimates of reserves.  In summary, we consider the assumptions, data, methods and analytical procedures used by AMH and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.



Audit Opinion



In our opinion, AMH's estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves as set forth in the Society of Petroleum Engineers’ Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information, and we found no bias in the utilization and analysis of data in estimates for these properties.

The overall proved reserves for the reviewed properties as estimated by AMH are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.



We were in reasonable agreement with AMH's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between AMH's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to AMH when its reserve estimates were prepared.  However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by AMH.



Other Properties

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Other properties, as used herein, are those Oklahoma properties of AMH which we did not review.  The proved net reserves attributable to the other properties account for less than one percent of the total proved net liquid hydrocarbon reserves, less than one percent of the total proved net gas reserves, and less than one percent  of the total proved discounted future net income discounted at 10 percent based on estimates prepared by AMH as of December 31, 2016. 



The same technical personnel of AMH were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.



Standards of Independence and Professional Qualification



Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937.  Ryder Scott is employee-owned and maintains offices in Houston,  Texas;  Denver,  Colorado; and Calgary,  Alberta,  Canada.  We have over eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately owned or publicly traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.



Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.    We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.



Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.



We are independent petroleum engineers with respect to AMH.  Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical persons primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.



Terms of Usage



This report was prepared for the exclusive use and sole benefit of Alta Mesa Holdings, L.P. and may not be put to other use without our prior written consent for such use.  The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.



RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

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/s/ Michael F. Stell



Michael F. Stell, P.E.

TBPE License No. 56416

Advising Senior Vice President





/s/ Beau Utley



Beau Utley

Petroleum Engineer



 

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Professional Qualifications of Primary Technical Person



The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.



Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions.  For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.



Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California,  Berkeley, in 1981.  He is a licensed Professional Engineer in the State of Texas.  He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.



In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills.  As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13 hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register.  Mr. Stell attended an additional 15 hours of formalized in-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.  As part of his 2010 continuing education hours, Mr. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training.  For each year starting 2011 through 2016, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.



Based on his educational background, professional training and over 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.







 

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PETROLEUM RESERVES DEFINITIONS



As Adapted From:

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE),

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)







PREAMBLE



Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward under defined conditions.  All reserve estimates involve some degree of uncertainty.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. 

Estimation of reserves is done under conditions of uncertainty.  The method of estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data.  The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities.  Identifying reserves as proved, probable, and possible has been the most frequent classification method and gives an indication of the probability of recovery.  Because of the differences in uncertainty, caution should be exercised when aggregating reserves of different classifications.



Reserves estimates will generally be revised as additional geologic or engineering data becomes available or as economic conditions change. 



Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.



Reserves may be attributed to either conventional or unconventional petroleum accumulations under the SPE-PRMS.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.  Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.  The SPE-PRMS acknowledges unconventional petroleum accumulations as reserves regardless of their in-place characteristics, the extraction method applied, or the degree of processing required.

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Reserves do not include quantities of petroleum being held in inventory and may be reduced for usage, processing losses and/or non-hydrocarbons that must be removed prior to sale.





SPE-PRMS RESERVES DEFINITIONS



In March 2007, the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE) jointly approved the “Petroleum Resources Management System” (“SPE-PRMS”).  The SPE-PRMS consolidates, builds on, and replaces guidance previously contained in the 2000 “Petroleum Resources Classification and Definitions” and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources” publications.



The intent of the SPE, WPC, AAPG and SPEE in approving additional classifications beyond proved reserves is to facilitate consistency among professionals using such terms.  In presenting these definitions, none of these organizations are recommending public disclosure of reserves classified as unproved.  Public disclosure of the quantities classified as unproved reserves is left to the discretion of the countries or companies involved and should not be construed as replacing guidelines for public disclosures under the guidelines established by regulatory and/or other governmental agencies.



Reference should be made to the full SPE-PRMS for the complete definitions and guidelines as the following definitions, descriptions and explanations rely wholly or in part on excerpts from the SPE-PRMS document (direct passages excerpted from the SPE-PRMS document are denoted in italics herein).





RESERVES (SPE-PRMS DEFINITIONS)



The SPE-PRMS Section 1.1 and Table 1 define reserves as follows:



Reserves.  Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.  Reserves must satisfy four criteria: they must be discovered, recoverable, commercial and remaining based on the development project(s) applied.  Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status.





ADDITIONAL TERMS USED IN RESERVES EVALUATIONS (SPE-PRMS DEFINITIONS)



The SPE-PRMS Sections 2.3, 2.3.4, 2.4 and Appendix A define the following terms as follows:



Improved recovery.  Improved Recovery is the extraction of additional petroleum, beyond Primary Recovery, from naturally occurring reservoirs by supplementing the natural forces in the reservoir.  It includes waterflooding and gas injection for pressure maintenance, secondary processes, tertiary processes and any other means of supplementing natural reservoir recovery processes.  Improved recovery also includes thermal and chemical processes to improve the in-situ mobility of viscous forms of petroleum.  (Also called Enhanced Recovery.)



Improved recovery projects must meet the same Reserves commerciality criteria as primary recovery projects.  There should be an expectation that the project will be economic and that the entity has committed to implement the project in a reasonable time frame (generally within 5 years; further

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delays should be clearly justified).  If there is significant project risk, forecast incremental recoveries may be similarly categorized but should be classified as Contingent Resources.



The judgment on commerciality is based on pilot testing within the subject reservoir or by comparison to a reservoir with analogous rock and fluid properties and where a similar established improved recovery project has been successfully applied.



Incremental recoveries through improved recovery methods that have yet to be established through routine, commercially successful applications are included as Reserves only after a favorable production response from the subject reservoir from either (a) a representative pilot or (b) an installed program, where the response provides support for the analysis on which the project is based.



Similar to improved recovery projects applied to conventional reservoirs, successful pilots or operating projects in the subject reservoir or successful projects in analogous reservoirs may be required to establish a distribution of recovery efficiencies for non-conventional accumulations.  Such pilot projects may evaluate both the extraction efficiency and the efficiency of unconventional processing facilities to derive sales products prior to custody transfer.



These incremental recoveries in commercial projects are categorized into Proved, Probable, and Possible Reserves based on certainty derived from engineering analysis and analogous applications in similar reservoirs.



Commercial.  When a project is commercial, this implies that the essential social, environmental and economic conditions are met, including political, legal, regulatory and contractual conditions.  In addition, a project is commercial if the degree of commitment is such that the accumulation is expected to be developed and placed on production within a reasonable time frame.  While 5 years is recommended as a benchmark, a longer time frame could be applied where for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives.  In all cases, the justification for classification as Reserves should be clearly documented.





PROVED RESERVES (SPE-PRMS DEFINITIONS)



The SPE-PRMS Section 2.2.2 and Table 3 define proved oil and gas reserves as follows:



Proved oil and gas reserves.  Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs under defined economic conditions, operating methods, and government regulations.  If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.



The area of the reservoir considered as Proved includes:



(1) the area delineated by drilling and defined by fluid contacts, if any, and



(2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.



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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 otherwise indicated by definitive geoscience, engineering, or performance data.  Such definitive information may include pressure gradient analysis and seismic indicators.  Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines”, Chapter 8).



Reserves in undeveloped locations may be classified as Proved provided that:





For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.









 

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PETROLEUM RESERVES STATUS DEFINITIONS and GUIDELINES



As Adapted From:

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE),

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)







Reserves status categories define the development and producing status of wells and reservoirs.  The SPE-PRMS Table 2 define the reserves status categories as follows:





DEVELOPED RESERVES (SPE-PRMS DEFINITIONS)



Developed Reserves are expected quantities to be recovered from existing wells and facilities.



Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well.  Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped.  Developed Reserves may be further sub-classified as Producing or Non-Producing.



Developed Producing

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.



Improved recovery reserves are considered producing only after the improved recovery project is in operation.



Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.



Shut-In

Shut-in Reserves are expected to be recovered from:



Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. 



In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.





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UNDEVELOPED RESERVES (SPE-PRMS DEFINITIONS)



Undeveloped Reserves are quantities expected to be recovered through future investments.



Undeveloped Reserves are expected to be recovered from:

(a)  recomplete an existing well; or

(b) install production or transportation facilities for primary or improved recovery projects.











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