Exhibit 99.1



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|LOGO |  | FAX (303) 623-4258

621
SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE 303) 623-9147

March 28, 2011

PrimeEnergy Corporation

One Landmark Square

Stamford, Connecticut 06901

Dear
Ms. Beverly A. Cummings:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved
reserves, future production, and income attributable to certain leasehold and royalty interests of PrimeEnergy Corporation and 100% of its Partnership Interests (PrimeEnergy) as of December 31, 2010. The subject properties are located in
the states of Colorado, Kansas, Louisiana, Montana, Mississippi, New Mexico, Oklahoma, Texas, West Virginia and Wyoming and in the federal waters offshore Louisiana and Texas. The reserves and income data were estimated based on the definitions and
disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC
regulations). Our third party study was prepared for public disclosure by PrimeEnergy Corporation in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The results of our third party study,
completed on March 28, 2011, are presented herein. The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of PrimeEnergy as of
December 31, 2010.

The estimated reserves and future net income amounts presented in this report, as of
December 31, 2010 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report,
determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices
may vary significantly from the prices required by SEC regulations; 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
results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

PrimeEnergy Corporation and
100% of Partnership Interests

As of December 31, 2010





|                         |  |           |             |  |               |   |            |                 |  |   |             |  |  |   |             |   |  |   |             |  |  | 
|------------------------ |  | --------- | ----------- |  | ------------- | - | ---------- | --------------- |  | - | ----------- |  |  | - | ----------- | - |  | - | ----------- |  |  | 
|                         |  | Proved    |            
|                         |  | Developed |             |  |               |   |            | OtherDeductions |  |   | TotalProved | 
|                         |  | Producing |             |  | Non-Producing |   |            | Undeveloped     |  |   |            
|Net Remaining Reserves   |  |           |             |  |               |   |            |                 |  |   |             |  |  |   |             |   |  |   |             | 
|Oil/Condensate  Barrels |  |           | 4,773,665   |  |               |   | 459,400    |                 |  |   | 2,652,258   |  |  |   | 0           |   |  |   | 7,885,323   | 
|Gas  MMCF               |  |           | 37,754      |  |               |   | 4,192      |                 |  |   | 11,400      |  |  |   | 0           |   |  |   | 53,346      | 
|                         |  |           |             |  |              
|Income Data              |  |           |             |  |               |   |            |                 |  |   |             |  |  |   |             |   |  |   |             | 
|Future Gross Revenue     |  | $         | 566,032,948 |  |               | $ | 62,115,311 |                 |  | $ | 278,993,873 |  |  | $ | 0           |   |  | $ | 907,142,132 | 
|Deductions               |  |           | 299,917,484 |  |               |   | 25,981,261 |                 |  |   | 178,060,013 |  |  |   | 20,245,339  |   |  |   | 524,204,097 | 
|                         |  |           |             |  |               |   |            |                 |  |   |             |  |  |   |             |   |  |   |             |  |  | 
|Future Net Income (FNI)  |  | $         | 266,115,464 |  |               | $ | 36,134,050 |                 |  | $ | 100,933,860 |  |  | $ | (20,245,339 | ) |  | $ | 382,938,035 | 
|                         |  |           |             |  |              
|Discounted FNI @ 10%     |  | $         | 155,270,587 |  |               | $ | 19,094,038 |                 |  | $ | 26,696,281  |  |  | $ | (6,270,043  | ) |  | $ | 194,790,863 | 



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PrimeEnergy Corporation

March 28, 2011

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Liquid hydrocarbons are expressed in standard 42 gallon barrels. 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 estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic
software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used at the request of PrimeEnergy. Ryder Scott has found this program to be generally acceptable, but notes that certain
summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties,
also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of
production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. Other Deductions incorporate abandonment costs net of salvage and contractual net
cash flow adjustments. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash
on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 63 percent and gas reserves account for the remaining 37 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.

The results shown above are presented for your information and should not be construed as our estimate of fair marker value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commissions Regulations Part 210.4-10(a). An abridged version of the SEC reserves
definitions from 210.4-10(a) entitled Petroleum Reserves Definitions is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled Petroleum Reserves Definitions in this
report. The proved developed non-producing reserves included herein consist of the shut in and behind pipe categories.

No
attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as 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. 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. The relative
degree of uncertainty may be conveyed by placing reserves into one of two



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COMPANY    PETROLEUM CONSULTANTS



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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. At PrimeEnergys request, this report addresses only the proved reserves attributable to the properties evaluated herein.

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. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved
reserves as a high degree of confidence that the quantities will be recovered.

Proved reserve estimates will
generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that as changes due to increased availability of geoscience (geological, geophysical,
and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. Moreover, estimates of proved reserves
may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact
quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

PrimeEnergy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.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PrimeEnergy 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 for potential liabilities to restore and clean
up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves 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 in accordance with the definitions set forth by the Securities and Exchange Commissions Regulations
Part 210.4-10(a). 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 singularly 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



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COMPANY    PETROLEUM CONSULTANTS



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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 reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the
reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is
the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the
quantities actually recovered are much more likely than not to be achieved. The SEC states that 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. The SEC states that possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a
project have a low probability of exceeding proved plus probable plus possible reserves. All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or
engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories 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 for the
properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 97 percent of the proved producing reserves attributable to producing wells and/or reservoirs 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 2010 in those cases
where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by PrimeEnergy or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 3 percent of
the proved producing reserves were estimated by the volumetric method. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for
the reserve estimates was considered to be inappropriate.

Approximately 80 percent of the proved developed non-producing and
undeveloped reserves included herein were estimated by analogy. The data utilized in this analysis were considered sufficient for the purpose thereof. Approximately 20 percent of the proved developed non-producing and undeveloped reserves included
herein were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by PrimeEnergy or which we have obtained from public data sources that were available through December, 2010.
The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters
derived from geological, geophysical and engineering data that cannot be measured



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directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves
must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be
anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with
rules adopted by the SEC, omitted from consideration in making this evaluation.

PrimeEnergy 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 preparing our forecast of future proved production and income, we have relied upon data furnished by
PrimeEnergy with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, ad valorem and production taxes, recompletion and development costs, abandonment costs after
salvage, product prices based on the SEC regulations, 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 PrimeEnergy. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and
future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this
report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance
with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the SEC Regulations. In
our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our
forecasts of future production rates are based on historical performance data. 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 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 PrimeEnergy. Wells or locations that are not currently producing may start producing earlier or later than
anticipated in our 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



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lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the
ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For
hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the
12-month unweighted arithmetic average as previously described.

PrimeEnergy furnished us with the above mentioned average
prices in effect on December 31, 2010. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark
prices are prior to the adjustments for differentials as described herein. The table below summarizes the benchmark prices and price reference used for the geographic areas included in the report. In certain geographic areas,
the price reference and benchmark prices may be defined by contractual arrangements

The product prices that were actually
used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and gathering and transportation fees, and/or distance from market, referred to herein as
differentials. The differentials used in the preparation of this report were furnished to us by PrimeEnergy.

In
addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the average realized prices. The average realized prices shown in the table below were determined from the
total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.



|                |  |                |  |                 |  |                          |  |                       
|--------------- |  | -------------- |  | --------------- |  | ------------------------ |  | ----------------------
|Geographic Area |  | Product        |  | Price
Reference |  | Average
Benchmark
Prices |  | AverageRealized
Prices
|North America   |  |                |  |                 |  |                          |  |                       
|United States   |  | Oil/Condensate |  | WTI Cushing     |  | $79.43Bbl                |  | $76.11/Bbl            
|                |  |                |  |                
|                |  | Gas            |  | Henry Hub       |  | $4.38/MMBTU              |  | $6.73/MCF             

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

Costs

Operating
costs for the leases and wells in this report are based on the operating expense reports of PrimeEnergy and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative
costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general



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administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating
agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PrimeEnergy. 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 were furnished to us by PrimeEnergy and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were
accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs
net of salvage were significant. The estimates of the net abandonment costs furnished by PrimeEnergy were accepted without independent verification.

The proved non-producing and undeveloped reserves in this report have been incorporated herein in accordance with PrimeEnergys plans to develop these reserves as of December 31, 2010. The
implementation of PrimeEnergys development plans as presented to us and incorporated herein is subject to the approval process adopted by PrimeEnergys management. As the result of our inquires during the course of preparing this report,
PrimeEnergy has informed us that the development activities included herein have been subjected to and received the internal approvals required by PrimeEnergys management at the appropriate local, regional and/or corporate level. In addition
to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PrimeEnergy. Additionally,
PrimeEnergy has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

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

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 for over seventy years. 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



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equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to PrimeEnergy. Neither we nor any of our employees have any 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 study,
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 evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of
Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the
disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PrimeEnergy.

We have provided PrimeEnergy with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by
PrimeEnergy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

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.



Very truly yours,RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580/s/ Richard J. MarshallRichard J. Marshall, P.E.Colorado License No. 23260    [SEAL]Vice President/s/ Scott J. WilsonScott J. Wilson, P.E.TBPE License No. 106681    [SEAL]Senior Vice President




|* | The work performed in this report for properties located in the state of Texas has been reviewed and approved by a licensed Texas professional engineer according to the
rules of the Texas Board of Professional Engineers (TBPE).
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Marshall, an employee of Ryder Scott Company L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating and supervising staff
and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Marshall served in a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding
Mr. Marshalls geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Marshall earned a B.S. in Geology from the University of Missouri in 1974 and a M.S. in Geological Engineering from the University of Missouri at Rolla in 1976. Marshall is a registered Professional
Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers, Wyoming Geological Association, Rocky Mountain Association of Geologists and the Society of Petroleum Evaluation Engineers.

Based on Marshalls educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of
petroleum reserves, Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as 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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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. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in
ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilsons geographic and job
specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Wilson
earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by
exam in the States of Alaska, Colorado, Wyoming, and Texas. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for
SPEs Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers, one book chapter, and holds two US patents.

In addition to gaining experience and competency through prior work experience, several Boards of Professional Engineers require continuing
education, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills. As part of his 2009 continuing education hours, Mr. Wilson attended an internally presented sixteen hours of formalized training as well
as a 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. Wilson attended an additional 10 hours of formalized external training during 2010 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and
petroleum economics evaluation methods, procedures and software and ethics for consultants.

In addition to gaining experience and competency
through prior work experience, the Wyoming 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. Wilson fulfills. As part
of his 2009 continuing education hours, Mr. Wilson attended an internally presented sixteen hours of formalized training as well as a 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. Wilson attended external presentations and training during 2009-2010
covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of petroleum
reserves, Mr. Wilson has attained the professional qualifications as 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:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND
EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the Modernization of Oil and Gas Reporting; Final Rule in the Federal Register of National
Archives and Records Administration (NARA). The Modernization of Oil and Gas Reporting; Final Rule includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas
reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, shall be
referred to herein collectively as the SEC regulations. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference
should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics
herein).

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. 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.
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. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of
probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any
document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become 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, natural gas 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. 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.



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PETROLEUM RESERVES DEFINITIONS

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These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves
categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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
(a)(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).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

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 the 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.



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PETROLEUM RESERVES DEFINITIONS

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(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.

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND
EXCHANGE COMMISSION (SEC)

and

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. Reference should be made to Title 17,
Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS
documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

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.

Developed Producing (SPE-PRMS
Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be
further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed
Producing Reserves

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



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RESERVES STATUS DEFINITIONS AND GUIDELINES

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



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RESERVES STATUS DEFINITIONS AND GUIDELINES

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Shut-In

Shut-in Reserves are expected to be recovered from:

| | (1) | completion intervals which are open at the time of the estimate, but which have not started producing;
| | --- | ------------------------------------------------------------------------------------------------------



| | (2) | wells which were shut-in for market conditions or pipeline connections; or
| | --- | --------------------------------------------------------------------------



| | (3) | wells not capable of production for mechanical reasons.
| | --- | -------------------------------------------------------

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.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange
Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

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.