	Alberta P. Eng. License 23579
	Senior Vice President

411 North Sam Houston Parkway E., Suite 400, Houston, Texas 77060-3545

T +1 281 448 6188 F +1 281 448 6189

E rpsenergy@rpsgroup.com

W www.rpsgroup.com

April 13, 2011

Pan American Energy, LLC

Leandro N. Allem 1180

1001 Buenos Aires, Argentina

RE:	Reserves Audit of Cerro Dragon, Anticlinal Funes, Koluel Kaike, Piedra Clavada and Acambuco areas in Argentina as of December 31, 2010

Gentlemen:

RPS has conducted the proved reserves audit of the referenced lease holding interests operated by Pan American Energy LLC (PAE) in the Republic of Argentina. The scope of the undertaking also includes the estimation of future production profiles and the corresponding income expected by each of the evaluated properties. The effective date of the audit is December 31, 2010. PAE working interest participation is these concession areas is as follows: Cerro Dragón 100%, Anticlinal Funes 80%, Koluel Kaike 100%, Piedra Clavada 100% and Acambuco 52%. This third party proved reserve report is presented to Pan American as per their request.

The reserve audit was 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) - Definition Section in Rule 4-10 of Regulations S-X.

RPS has conducted a detail evaluation of the reserve certification data provided by PAE for each field through January 15, 2011, estimating the Proved, Probable, and Possible hydrocarbon liquids and natural gas reserves. In the preparation of this proved reserves audit, RPS has relied upon the information furnished by PAE, including reservoir data, production, development and operating costs, product prices, agreements relating to current and future operations, product sales, and other information/data that was assessed and confirmed by the consultant for estimation of the reserve numbers. Following data review, RPS proceeded with tests, attesting assessment procedures utilized by PAE in their reserves certification procedure making the necessary adjustments and changes necessary for complying with proved reserves definition criteria outlined by SEC. All questions and clarifications that arose during the course of the audit process were responded by PAE at the auditor’s satisfaction.

RPS conducted the review of 100% of the reserve base presented by PAE. The reported hydrocarbon reserves is an estimate based on professional engineering judgment and its subject to future revision, upwards and downwards as a result of future operations or as additional information may become available.

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 audit were 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 weighted 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. Economic runs were completed using prevailing gas contract prices and governmental regulatory approvals for Gas Plus, when applicable.

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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 the reserve audit in terms of the Proved reserves are summarized in the following table:

SEC PARAMETERS

Estimated Net Reserves and Income Data

Attributable to Leasehold Interest and

Contracts of Pan American Energy, LLC

As of December 31, 2010

	Proved		Total Proved
	Developed Producing	Undeveloped	Total Proved
Net Remaining Reserves
Oil/Condensate - Mbbls	520,869	412,404	933,273
Gas – MMCF	892,937	653,174	1,546,111

Income Data (MUS$)
Future Gross Revenue	$21,210,248	$16,746,768	$37,957,016
Deductions	$ 8,761,041	$ 8,593,680	$17,354,721
Future Net Income (FNI)	$12,449,206	$ 8,153,089	$20,602,296

Discounted FNI @ 10%	$ 6,170,028	$ 2,166,590	$ 8,336,619

Hydrocarbon liquids are crude oil, condensate and gasoline. The Condensate and Gasoline estimates, which are reported in stock tank barrels, are volumes captured during field separation and gas plants treating in the field. The natural gas reserves reported in the table above include gas sales and fuel gas. These volumes are reported in million cubic feet (MMCF) at standard conditions of 14.7 psia and 600 Fahrenheit.

The Income values are in United States dollars (US$). The income values reflect gas sales only (excluding fuel gas). Proved natural gas sales volumes estimates are based on firm and existing gas contracts, and on the reasonable expectation that such gas sales contracts will be renewed on similar terms in the future.

The future gross revenue is net of royalty charges and turnover taxes, which are included in the price adjustment of the products. The Net Income is calculated after deduction of operating cost, well abandonment cost, and capital investment for future development program. Value is before income taxes. No deduction has been accounted neither for general administrative overhead, nor for any outstanding loans that may exist, adjustment for cash on hand or undistributed income.

Estimates of economically recoverable oil and natural gas reserves (including natural gas liquids) and the future net cash flows there from are based upon a number of variable factors and assumptions, such as availability of capital to fund required infrastructure, commodity prices, production performance of re-completed wells and well re-completion success rates, successful drilling of infill and development wells, the assumed effects of regulation by government agencies and future operating costs. All of these estimates may vary from actual results.

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Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected there from, may vary. The Company's actual production, revenues, taxes, development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material.

Reserves Included in This Report

The proved reserves included in this report conform to the Securities and Exchange Commission’s regulations Part 210.4-10(a). A condensate version of the SEC reserve definitions is included in Appendix 1.

According to SEC final rules definition, the term “proved oil and gas reserves” refers to “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 proved reserves in all five field evaluated included in this report were estimated using deterministic method. 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”. SEC also clarify that having a “high degree of confidence” means that a quantity is “much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease” to provide elaboration to the definition of reasonable certainty.

The reserve volumes included in this report have been estimated to either the end of the license contract life or their economic limit, whichever occurred first.

Estimates of Reserves

The reserve estimation is the quantification and classification of the recoverable oil and gas that exist in an accumulation. There are three analytical methods that are accepted for the process of reserve quantification: 1) the volumetric method; 2) evaluation of the performance history; and 3) analogy to other reservoirs. In addition, the evaluation also includes reservoir simulation models in a couple of fields in the Acambuco area. Reserve evaluators must select the method or combination of methods which based on the available data and technical judgment is most appropriate to estimate the reserves.

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In the evaluation process of reserves it may be found that a range of possible outcomes may be applicable for ascertaining the interpretation value of the data. In case when there is range of quantities applicable to the outcome, the evaluator must determine the uncertainty level related to the value of reserves. In the case when reserves value are estimated using the deterministic approach, the uncertainty related to each discrete incremental quantity is allocated to the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves 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 reserves category must meet the SEC definitions as noted above.

RPS audited the methodology that PAE used to estimate the reserve on each of the five fields: Cerro Dragon, Anticlinal Funes, Piedra Clavada, Koluel Kaike, and Acambuco. Most of the reserves estimates by PAE were made using deterministic methods. Given the number of existing wells with long production history, the main methodology used to assess proved developed reserves was the decline curve analysis. Well production data was available up to December 31, 2010. For this analysis the wells had to be clustered in 90 groups. Similarly the water injection areas were also grouped in 102 clusters. Most of thee well development program was assessed on the basis of the “Well Type model” developed by PAE which is based on well history performance analysis developed over the last several years. Several new water injection projects planned for these fields were assessed using analogy to well known developed water injection projects. For areas located in more isolated regions of the fields, PAE presented water injection projects studies that assessed the reserves volume.

Future Production Rates

The forecast of future production rates were based on historical performance data for wells on production as of December 31, 2010. Well historical data was audited to verify oil production decline rate, water cut performance and well cut off criteria. The methodology that PAE used for establishing production forecast for infill and step-out development wells was based on “well type curve” analysis, which was developed for 87 groups within the fields. RPS reviewed each type curve to confirm the accuracy for representing future behavior of new well locations planned for primary production.

Forecast production profiles for group of well producing under secondary recovery (water injection) were also reviewed, as well as studies completed for future water injection implementation within the field. A number of water injection development projects considered by PAE were based on analogies of existing schemes. RPS reviewed and validated each of the proposed groups confirming the production forecast associated with these projects.

Similarly, RPS undertook a detail review of all the production forecasts related to High GOR well, deep gas, well replacement and workovers for new reserves additions.

All five fields evaluated have been on production for a number of years and have significant reserves base remaining. An aggressive development drilling program have been historically maintained by PAE for several years, and it is predicted to be continued for developing Proved Undeveloped (PUD) locations for at least the next five (5) years. Given the reservoir performance to date it is expected that drilling will be successful, and oil production will increase considerably as the program evolves.

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As indicated in the table below, PAE’s plan call for the drilling of 1245 PUD (P1) wells in Cerro Dragón, 3 in Anticlinal Funes, 55 in Koluel Kaike, 58 in Piedra Clavada and 2 in Acambuco within the next 5 years.

Pan American Energy - PUD Development plan

Activity	Cerro Dragón	Anriclinal Funes	Koluel Kaike	Piedra Clavada	Acambuco
Prod Prim	845	3	41	29
Prod HGOR	97
Prod WF	144		12	28
Iny WF	82		2	1
Prod Repl WF	52
Iny Repl WF	15
Gas	10				2
Total	1245	3	55	58	2

Hydrocarbon Prices

The hydrocarbon prices used in the preparation of this audit were 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.

The economic test for the December 31, 2010 proved oil reserve volumes performed for each field was based on West Texas Intermediate (WTI) crude reference price of 79.81 $/bbl, which is the average value for 2010. This price, after the corresponding adjustment for oil quality, royalty and turnover tax was used in the economic runs. This reference value was used for both export and internal consumption volumes. PAE’s oil export volume equates to 42% of the Cerro Dragon production only.

The economic runs for natural gas were completed using prevailing gas contract prices and governmental regulatory approvals for Gas-Plus, when applicable. The price used on the economic validation was based on internal price sales contract regulated by the country and adjusted for royalty and turnover taxes.

Costs

Operating costs for all five fields are based on historical operating expenses reported by PAE. The operating costs furnished by PAE were accepted as factual data and reviewed by RPS for their reasonableness; however, RPS has not conducted an independent verification of the operating costs data used by PAE. A detailed review of historical operating costs and estimated procedure used by PAE indicates that all categories of costs were allocated as fixed and variable costs, including labor, maintenance, service, material, equipment, environmental related costs and support costs, among others.

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Development costs were prepared and supplied by PAE. These costs were based on historical data and concur with the well drilling development and abandonment plan for the next five years, facilities and other costs planned for the future. The development costs provided by PAE were accepted as factual data and reviewed by RPS for their reasonableness; however, RPS has not conducted an independent verification of the development costs data used by PAE. PAE has scheduled a well abandonment program on an annual basis. The estimates of these costs were included in the economic runs. RPS has not made a third party verification of the abandonment costs but has reviewed historical data for reliability. Other development costs such as power generation development, facilities and gathering lines were also included in the economic runs as planned for the next five years.

Standards of Independence and Professional Qualification

RPS is a multi-disciplinary consultancy, providing technical, commercial and project management support services in the fields of operations, geoscience, engineering and health, safety and environment to the energy sector worldwide.

RPS’s clients around the world include governments, national oil companies, integrated majors, independents, and start-ups, legal and financial institutions.

RPS USA is part of the larger UK based RPS Group plc that employs nearly 5,000 staff based in offices located in the UK, Ireland, the Netherlands, USA, Canada, Australia and Brazil. It also has permanent representatives in Bogota, Colombia and Buenos Aires, Argentina.

As an independent and experienced consultancy company with a global capability, RPS is well qualified to provide both technical and economic assessments of reserves/resources, prospect evaluation, field discoveries and producing fields. In the Oil and Gas Sector, RPS personnel has provided SEC and Competent Persons reports for inclusion in both public and private circulars for funding purposes. We have provided investors with confidential valuations and assessments during mergers and acquisitions. Asset appraisal and valuation have always been a core element of RPS consulting business.

As indicated above, this study was based on data supplied by PAE. The supplied information was reviewed for reasonableness from a technical perspective. As is common in oil field situations, basic physical measurements taken over time cannot be verified independently in retrospect. As such, beyond the application of normal professional judgment, such data must be accepted as representative. While we are not aware of any falsification of records or data pertinent to the results of this study, RPS does not warrant the accuracy of the data and accepts no liability for any losses from actions based upon reliance on data, which is subsequently shown to be falsified or erroneous.

RPS personnel who prepared this report are degreed professionals with the appropriate qualifications and experience to complete the audit work. RPS and its staff do not claim expertise in accounting, legal and environmental matters, and opinions on such matters do not form part of this report.

The results and conclusions represent informed professional judgments based on the data available and time frame allowed to perform this work. No warranty is implied or expressed that actual results will conform to these estimates. RPS accepts no liability for actions or losses derived from reliance on this report or the data on which it was based.

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Terms of Usage

The results of RPS evaluation were prepared in accordance with the disclosure requirements set forth in the SEC regulations.

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.

April 2011

Professional Qualifications of Primary Technical Engineer

The independent 2010 Reserves Audit of Pan American Energy LLC operated fields in Argentina, was completed on January 19, 2011. The analysis of reserves certification work completed by the company’s technical team was evaluated and revised as required by RPS’s professional team comprised of geologists, geophysicists, and reservoir and simulation engineers. The reserves evaluation team was led by Luis V. Bacigalupo, who was the main technical person responsible for overseeing the reserves estimation evaluation, production forecasting, capital development program and economic runs attesting proved reserves.

Luis V. Bacigalupo is Senior Vice President with RPS and has over 36 years of North America and international experience. He has been with the company since April 2008. He is responsible for RPS’s project management consulting including geosciences, engineering and integrated development projects. He also assists in the development of RPS’ worldwide new business activity with emphasis on Latin America and the U.S. He has been directly involved in the management and project evaluation in a number of Reserves certification, reserves audit and asset valuation projects in US and Latin America.

His industry experience extends from executive management and company building to practically all sectors of the industry, including engineering, production operations, strategic planning, and business development. He has well recognized experience in fully integrated studies, and re-activation and development of mature oil fields, with in-depth knowledge of the petroleum industry in North America and Latin America.

Prior to joining RPS, he was a Senior Advisor to YPF S.A. in Argentina, developing the company’s Integrated Asset Development Process for managing their investment development plan. Prior to that, he was Executive Vice President for Ziff Energy and led the effort in a significant expansion of the company’s Cost Benchmarking and Field Operations Efficiency Services in five continents. Before that, he was the founder and CEO/President of Mercantile International Petroleum, an E&P company with operating properties in Peru, Colombia and Southeast Asia. He was also Vice President Latin America for Gaffney, Cline & Associates (GCA), and an international engineering consulting firm in Houston. One of his main responsibilities in this company was reserves evaluation and asset valuation in Latino America. Luis has held managerial positions with Maxus Indonesia and Canada, Kerr McGee Canada, ERCB, PanCanadian Petroleum, and Amoco Canada.

Luis has a Bachelor of Science degree in Petroleum Engineering from the University of Belgrade, Yugoslavia, Reservoir Specialist Course in Novi Sad, Yugoslavia; and numerous graduated courses in the University of Calgary, Canada. He is a registered Professional Engineer and member of APPEGA, and SPE. He is fluent in English, Spanish, Serbo-Croatian, and proficient in Italian, Russian, Portuguese and Swedish languages.

RPS

APPENDIX 1

Petroleum Reserves Definition

As Adapted From:

Rule 4-10(a) of Regulation S-X Part 210

United States Securities and Exchange Commission (SEC)

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(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 (f.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (f.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(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,

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APPENDIX 1

	engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

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

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

	(A)	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an· analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

	(B)	The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an un weighted 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (18) defines probable oil and gas reserves as follows:

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

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

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

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

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APPENDIX 1

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

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §229.4-10(a) (18) defines possible oil and gas reserves as follows:

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

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

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

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

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

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

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

RPS

APPENDIX 1

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-PMRS)