reserves certification report for the rubiales field, colombia

Reserves Certification Report for the

Rubiales Field, Colombia

Prepared For: Metapetroleum LTD

February 2010

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February 9, 2010

Meta Petroleum Ltd. Calle 113 #7-80 Torre AR, Piso 13 Bogota, Columbia Attention: Ysidro Araujo, Reservoir Manager Re: Meta Petroleum Rubiales Field Reserve Evaluation

Dear Mr. Araujo,

As requested, RPS has completed the evaluation of Meta Petroleum’s Rubiales oil field assets

as of December 31, 2009 and submit the attached report. The assets evaluated consist of the

Rubiales field only in Columbia.

The evaluation was conducted using the guidelines of the Canadian Oil and Gas Evaluation

Handbook, and is consistent with the reporting requirements listed in t he Canadian National

Instrument 51-101. The Rubiales field has been evaluated at the Proved Developed Producing ,

Proved Developed Non Producing, Proved Undeveloped, Probable and Possible oil and gas

reserves levels. Additionally, production volumes beyond the concession expiry in 2016

and resource volumes which lie outside the mapped reserves areas have been included.

We appreciate the opportunity to conduct this reserves evaluation for you and trust that the

attached report meets your requirements.

Yours sincerely,

RPS Energy

Brian Weatherill, P.Eng. Reservoir Evaluations Specialist

RPS Reserves Certification Report

R01002 ii February 2010

Table of Contents

1.0 EXECUTIVE SUMMARY .................................................................................................. 1

2.0 CONCLUSIONS ............................................................................................................... 3

3.0 FIELD OVERVIEW ........................................................................................................... 4

3.1 OWNERSHIP ................................................................................................................... 4 3.2 DEVELOPMENT HISTORY ................................................................................................. 4

4.0 GEOSCIENCE .................................................................................................................. 6

5.0 PETROPHYSICS .............................................................................................................. 8

6.0 STATIC GEOCELLULAR MODEL ................................................................................... 9

7.0 RESERVES DETERMINATION ...................................................................................... 12

7.1 DISCUSSION ................................................................................................................. 12 7.2 DEVELOPED RESERVES ................................................................................................. 12 7.3 UNDEVELOPED RESERVES AND RESOURCES .................................................................. 14 7.4 SUMMARY ..................................................................................................................... 18

8.0 PRODUCTION FORECASTING ..................................................................................... 19

9.0 DETERMINATION OF VALUE ....................................................................................... 21

9.1 OWNERSHIP ................................................................................................................. 21 9.2 DETERMINATION OF VOLUMES ....................................................................................... 21 9.3 MARKETING .................................................................................................................. 23 9.4 COSTS ......................................................................................................................... 24 9.5 EVALUATION PARAMETERS ............................................................................................ 29 9.6 ANALYSIS RESULTS ....................................................................................................... 30

10.0 QUALIFICATIONS AND LIMITATIONS ......................................................................... 32

10.1 INDEPENDENCE AND CONFLICT OF INTEREST .................................................................. 32 10.2 PURPOSE, SCOPE AND USE OF THIS REPORT ................................................................. 32 10.3 AVAILABLE DATA ........................................................................................................... 32 10.4 PROFESSIONAL QUALIFICATIONS .................................................................................... 32 10.5 SITE VISIT AND INSPECTION ........................................................................................... 33 10.6 LIABILITY WAIVER ......................................................................................................... 33

List of Figures Figure 3.1 Rubiales Field Location Map Figure 3.2 Concession Map Figure 3.3 Rubiales Field Production Plot Figure 3.4 Rubiales Concession Production Plot Figure 3.5 Piriri Concession Production Plot Figure 4.1 Structure Top Arenas Basales Figure 4.2 Structure Oil – Water Contact Arenas Basales Figure 4.3 Structural Cross Section - West to East Figure 4.4 Gross Arenas Basales Isopach with Structure Top Arenas Basales Figure 4.5 Net to Gross Sand Ratio Arenas Basales Reservoir Interval


R01002 iii February 2010

Figure 4.6 Net Pay Isopach Arenas Basales Figure 5.1 Wells Drilled in 2009 with Petrophysical Analysis Figure 6.1 Net to Gross Distribution – 3D Model Figure 6.2 Porosity Distribution – 3D Model Figure 6.3 Water Saturation Distribution – 3D Model Figure 6.4 Facies Distribution – 3D Model Figure 6.5 STOIIP Map Figure 7.1 Type Well Production Curves for New Completions Figure 8.1 Production Plot - History and Forecast Figure 8.2 Production Plot by Reserve Category Figure 9.1 Fuel Consumption Forecast Figure 9.2 Pipeline Route from Rubiales Field to Covenas Sea Port

List of Tables Table 1.1 Summary of Oil and Gas Reserves Table 1.2 Net Present Value of Future Net Revenue Table 1.3 Total Future Net Revenue (Undiscounted) Table 1.4 Future Net Revenue by Production Group Table 1.5 Future Net Revenue (Unit Value Basis) by Production Group Table 1.6 Summary of Pricing and Inflation Rate Assumptions Table 1.7 Summary of Estimated Development Costs Attributable to Reserves Table 1.8 Summary of Production Estimates – Proved + Probable + Possible Reserves Table 7.1 Cumulative Field Production, Reserves and Estimated Ultimate Recovery Table 7.2 Calculation of Recovery Factor and Fieldwide Potential Table 7.3 Estimated Ultimate Recovery versus Net Pay by Well Type Table 7.4 Estimated Ultimate Recovery versus STOIIP by cell Table 7.5 Summary of Reserves and Production to June 30, 2016 Table 9.1 Crude Oil Production, Fuel Consumption, Naptha Purchases and Sales Table 9.2 WTI Crude Oil and Rubiales Crude Oil/Naptha Blend Price Forecast Table 9.3 Field Investment Summary Table 9.4 Field Expense Summary

List of Appendices Appendix 1 Reserves Guidelines issued by the Society of Petroleum Engineers Appendix 2 Before Tax Cases – Economic Summary Projections Appendix 3 After Tax Cases – Economic Summary Projections


R01002 1 February 2010

1.0 EXECUTIVE SUMMARY

RPS was engaged by Meta Petroleum Corporation (Meta) to perform a reserves certification

report effective December 31, 2009. The field has produced for a number of years and has a

significant reserves base remaining. An aggressive drilling program has been pursued to

develop the majority of the remaining reserves prior to the expiration of the Rubiales and Piriri

concessions. Given the reservoir performance to date and the associated development plan, the

drilling program should continue to be successful and oil production will increase considerably as

the work proceeds.

All reserves volumes in the field are categorized as proved, probable or possible based on the

definitions in the Petroleum Resource Management System of the Society of Petroleum

Engineers. Many of the wells to be drilled are in the probable and possible categories some

distance from the currently developed area; those volumes are unrisked in this report as is the

value placed on those volumes. The present value of the reserves was calculated at a ten

percent discount rate using a price forecast developed by the Strategic Planning Department of

RPS in London. All costs associated with the development of the reserves, including drilling,

infrastructure and water disposal wells are included.

The table below provides a summary of the reserves and value by each reserves category.

Reserves Category

Field Gross Reserves MMbbl

Meta Working Interest Reserves

MMbbl

NPV @ 10%

$MM US Gross Net BFIT AFIT

Proved

Developed Producing 94.1 41.6 33.3 1,420.2 980.3

Developed Non-Producing 27.1 11.4 9.1 314.8 225.1

Undeveloped 296.0 125.5 100.4 3,546.5 2,555.1

Total Proved 417.2 178.6 142.9 5,281.5 3,760.5

Probable 46.0 19.0 15.2 508.5 368.7

Total Proved + Probable 463.2 197.6 158.1 5,790.0 4,129.2

Possible 38.0 16.1 12.9 415.5 288.3

Total Pvd + Prob + Poss 501.2 213.7 171.0 6,205.5 4,417.5



RPS has updated the mapping of oil initially in place (OIIP) for the field to a new total of 4,248

MMstb, up from 3,886 MMstb calculated as of year-end 2008. This represents an increase of

362 MMstb (9.3 percent) and is due to updated geological mapping using data from 2009 drilling

and revised petrophysical analysis. Accounting for the 2009 production of 25.1 MMstb from the

field, the year-end 2009 reserves represent an increase in estimated total concession date

recovery of 146 MMstb at the proved level, and 90 MMstb at the proved and probable level.

The series of tables listed below show the results of the reserves, production, cash flow and

present worth calculations:

Table 1.1 Summary of Oil and Gas Reserves – gross and net volumes

Table 1.2 Net Present Value of Future Net Revenue – BFIT & AFIT at various discount rates

Table 1.3 Total Future Net Revenue (Undiscounted) – revenue and cost cash flows

Table 1.4 Future Net Revenue by Production Group – BFIT NPV @ 10%

Table 1.5

Table 1.6

Future Net Revenue (Unit Value Basis) by Production Group – BFIT NPV @ 10%

Summary of Pricing and Inflation Rate Assumptions

Table 1.7 Summary of Estimated Development Costs Attributable to Reserves

Table 1.8 Summary of Production Estimates – Proved, Probable and Possible Categories

The field wide proved, probable and possible reserves volume is 501 million barrels

(representing 11.8 percent of the oil initially in place) of which 83.2 percent is proved. Additional

resources that were not included in the evaluation were identified in areas adjacent to the

possible drilling locations and in outlying areas of lower thickness pay sand. The recovery

potential of these resources and economically recoverable volumes beyond the concession

expiry date is an additional 279 MMstb (6.6 percent OIIP). Coupled with the cumulative

production to year-end 2009 of 57.6 MMstb (1.3 percent OIIP) the potential ultimate recovery is

838 MMstb for a total potential recovery of 19.7 percent OIIP.

All references to costs and values in the report are in United States dollars. The net present

value reported is unrisked and does not represent the fair market value of Meta‟s ownership in

the Rubiales Field. A site inspection of the field, including existing wells, facilities, tanks and

pipelines as well as many major construction projects, was made on December 15, 2009. The

data provided by Meta was the sole source of information for this report.



2.0 CONCLUSIONS

This reserves certification report was prepared using field data and an investment program as

provided by Meta. The conclusions noted below relate to depletion of the existing wells and

implementation of the field development plan as it has been proposed.

The drilling campaigns in each of the past years have been very successful in finding and

developing oil and in validating the geological model and engineering projections from

earlier studies.

Due to Meta‟s higher working interest, the Piriri concession reserves have more value to

Meta than the reserves to be produced from the Rubiales concession.

Certain step-out locations that were some distance from proved reserves have been

drilled successfully, and as a result significant areas of the reservoir have had crude

volumes re-categorized to proved reserves much sooner than if the drilling program been

restricted to the proved undeveloped locations.

Production and cash flow have been maximized since the pipeline capacity has been

developed on schedule and the water disposal wells and facilities are being drilled and

built as needed to avoid or minimize the curtailment of production due to transportation or

processing limitations.

The production can be developed for a relatively low cost per barrel. Adherence to the

accelerated rig program will increase the recovery factor as high as it can be before the

concession expires.

An analysis of the historical drilling program results, in contrast to the remaining areas to

be drilled, indicates that future drilling will result in lower recovery per well due to the

thinning nature of the sand on the flanks of the structure.



3.0 FIELD OVERVIEW

3.1 Ownership

The Rubiales Field is located in the Llanos Basin on the eastern side of Columbia as shown in

Figure 3.1, the “Location Map”. Meta‟s working interest in the Rubiales Field is comprised of a

50% ownership in the Piriri concession (62,432 acres in size) and a 40% ownership in the

Rubiales concession (88,463 acres in size). The boundaries of the properties are shown in

Figure 3.2, the “Concession Map”. The Rubiales field is productive from 135,361 acres, which

comprises the majority of the entire extent of the concession area of 150,895 acres.

Meta pays a 20% royalty on working interest production. There are no other burdens or

overriding royalties associated with the concessions. The agreements expire on July 1, 2016.

This relatively close expiry date is the incentive to Meta to develop the field quickly and produce

field reserves as soon as possible.

3.2 Development History

The Rubiales field was discovered in 1981 by Exxon in association with the Tethys operating

group. Three wells were drilled from 1981 to 1982 and on July 1, 1988 a 28 year concession

was granted. Exxon then drilled 14 wells from 1988 to 1993. The field was then acquired by

Coplex Resources in 1994 who drilled 5 additional wells by 1997. Due to financial problems

within the company, the field was shut in until Tethys et al re-acquired it from Coplex in 2000.

Production was re-started in 2001 and two additional wells were drilled for a total of 24 wells at

that time.

In mid-2002 Rubiales Holdings acquired Tethys et al and quickly drilled 14 wells while improving

field operations. In 2004 Meta Petroleum became the operator of the Rubiales field following a

merger of the “et al” companies with the result being a 50% ownership in the Piriri concession

and a 40% ownership in the Rubiales concession. In 2005, studies conducted by Meta

confirmed the significant potential of the field and an investment program was approved.

From 2006 to the present Meta has conducted an aggressive drilling program that has resulted

in a current total of 139 producing wells that are pumping approximately 102,000 barrels of oil

per day at year end. During 2009, the field produced 25.1 MMstb of oil and at year-end had a

cumulative production of 57.6 MMstb. The results of this program are indicated on the field



production plot, Figure 3.3, and on the production plots for the Rubiales and Piriri concessions

on Figures 3.4 and 3.5, respectively. As of year-end 2009, in the fully developed areas of the

field, the wells have been drilled on an average spacing of 81 acres. At year-end 2009, the field

had the following well count:

Production Vertical 38

Horizontal 101

Disposal Vertical 3

Horizontal 12

Shut-In Vertical 59

Horizontal 15

Abandoned Vertical 8

Horizontal 0

Total wells Vertical 108

Horizontal 128

Grand total wells 236

Meta has scheduled an additional 536 wells to completely develop the field during the next six

years. RPS has classified the wells as proved, probable and possible drilling opportunities.

Meta has also scheduled 151 locations to which RPS has assigned resource volumes.



4.0 GEOSCIENCE

Geological Model for Entrapment

The geological model for the Rubiales field (proposed by RPS Scotia in 2007) was a

hydrodynamic trap, with oil trapped by basin ward (northwestward) flowing formation waters

trapping oil under a broad subtle structural nose at the top of the fluvial/alluvial Arenas Basales

Formation. This trapping model is supported by a tilted oil water contact, pressure data in the

reservoir section, log facies characteristics of available wells, and regional geologic information.

The mapping method used to define prospective areas, using this geologic model, was the

Trend Residual mapping method where subtle structural highs are identified as positive

anomalies with a positive residual value when compared to the regional structural trend.

The geological tops for 29 new well logs that were provided to RPS during 2009 continue to

support a tilted oil water contact. The oil-water contact and whether or not an area would be oil

bearing for a well drilled within the current producing field area can be predicted using the

hydrodynamic/tilted oil water contact model. Water productive wells are still located on structural

anomalies. However, the RPS hydrodynamic model is not predictive of oil production extending

outside the current producing area, given the current data available. The limits of the field do not

appear to have been defined and appear to lie outside the concession area. Without more

regionally extensive dry hole data delineating non-productive areas, a Trend Residual mapping

method is not useful to predict a Rubiales field productive extension. A brief mapping exercise

suggests that it is probable that more complex stratigraphic and hydrodynamic trapping elements

are involved in defining the geological limits of Rubiales oil production.

Geological Work Performed

New well locations and new well logs (LAS files) for the 29 vertical wells drilled during 2009 were

loaded into an existing Petra project file. Geological tops from Metapetroleum were also loaded

to the Petra Project file. Thirty seven additional horizontal wells have been drilled in 2009, but

LAS files and directional survey data on these wells were not made available to RPS.

The new producing wells and wet wells were inserted into the existing cross sections, and

additional cross sections were constructed, incorporating the new vertical wells. (Tops were not

used on RB 159 and RB 42H wells as directional survey data were not available.) RPS has over



a 90% agreement with the observed Meta geological tops. Any top discrepancies were

generally less than 10 feet of difference. Additional geological tops were picked for new wells.

These tops were incorporated into the cross sections and the geological maps.

Based on the new well data and new tops, several of the existing maps, such as the Structure

Top Arenas Basales, Structure Oil Water Contact Arenas Basales, Gross Arenas Basales

Interval, Net to Gross Sand Ratio Arenas Basales Reservoir Interval, Gross Isopach Pay

Interval, and Net Pay Isopach were updated and re-contoured in the Petra Project.

The Structure Top Arenas Basales map (Figure 4.1) shows monotonous northwest dip into the

basin. Almost all of the new wells drilled in 2009 in the Rubiales field fit the tilted water table and

hydrodynamic entrapment model as shown on Figure 4.2, the Structure Oil-Water Contact. The

cross section in Figure 4.3 documents this fit and demonstrates the tilted oil water contact.

Water productive wells are located on structural anomalies as noted by the contours near the

blue highlighted water wells in Figures 4.1 and 4.2.

The Arenas Basales Gross Reservoir Isopach map shows a northwest trending thick interval

(Figure 4.4) while the Net/Gross sand ratio map of this same interval shows the northwest

trending reservoir thickening is actually higher in shale content (Figure 4.5). The Net Pay

Isopach map shows an east-west trending pay interval which cuts across the northwest trending

gross reservoir thickening (Figure 4.6). More work would be necessary to define the potentially

more complex stratigraphic trap elements apparent from this observation.

The limits of the Rubiales field have yet to be defined. The current in-field drilling program still

fits the tilted water table and the hydrodynamic trap models. However, the RPS hydrodynamic

model is not predictive of the presence of oil that is known to extend outside the concession

boundaries in areas that remain sparsely drilled or not drilled at all. Without more regionally

extensive dry hole data delineating non-productive areas, the Trend Residual mapping method

done in previous audits (in 2007 and 2008) is not useful. It is likely that more complex

stratigraphic and hydrodynamic trapping elements are involved in defining the geological limits of

Rubiales oil production.



5.0 PETROPHYSICS

The petrophysical work used in this analysis includes the review of the existing static model of

the Rubiales Field, the validation of the petrophysical parameters and models, and an update to

the existing static model with information from 29 new wells (Figure 5.1). The objective was to

provide necessary petrophysical information in terms of Clay Volume (VSH), Effective Porosity

(PHIE), Water Saturation (Sw) and Oil-Water Contact (OWC) depths to be integrated into the

geocellular model for the volumetric estimation of the oil initially in place (OIIP) and to support

the development plan of the field. The project was developed in the RPS office in Houston with

interaction with Meta specialists incorporating the new well logs and core data.

An audit of all petrophysical input parameters and models used in the petrophysical evaluation of

the wells was performed using the specialized software Interactive Petrophysics version 3.5.5.0,

concluding that input parameters, models used, and results obtained from the petrophysical

evaluation are reasonable. The available data for the petrophysical review was considered

sufficient in terms of quantity, quality and consistency. A comparison of log-derived porosity and

water saturation against core-derived porosity and water saturation was also done with an

excellent fit. The determination of net pay thickness from the petrophysical modeling is also

considered accurate.

The OWC can be established from visual analysis of the log curves signature, corresponding to

a decrease of the Deep Resistivity curve into a range of 20 to 30 Ohm-m in front of a porous

sand body. The petrophysical model matches this response with 100 percent water saturation

below the OWC, and low water saturation values above the OWC. The variation in depth

indicates a tilted OWC associated with the hydrodynamic mechanism acting in the Llanos Basin.



6.0 STATIC GEOCELLULAR MODEL

The geocellular model of the Rubiales field that was generated by Meta during 2009 was

analyzed and validated. The model was then updated using seismic data, well log correlations,

stratigraphic data, facies studies and a petrophysical evaluation. Volume calculations of oil

initially in place were carried out to support the reserves certification objective and also to

validate the field development drilling program.

The geocellular model of the Rubiales field was constructed in three steps:

Structural Framework - The geometry or structural framework of the model was created

through the three-dimensional integration and matching of well locations and paths,

geological tops, and fault surfaces.

Grid Cells - The volume of rock contained within the structural framework was divided in

zones and layers and subdivided into small boxes or grids (cells). This procedure

generated more than 5,400,000 cells. In this step, the cells penetrated by wells (Cell-

wells) were populated with facies information and petrophysical parameters, using

averaging methods as arithmetic mean, root mean square, harmonic mean, midpoint

pick, etc. The facies population of the cell-wells was carried out based on facies logs and

stratigraphic-sedimentary models that were determined previously.

Extrapolation of Properties - The values within the „cell-wells‟ were distributed by

interpolation through all the model cells. The distribution was carried out applying

deterministic and stochastic algorithms, looking for the best distribution of discrete and

continuous data through each cell of the geocellular model. The final version of the

geocellular model of the Rubiales field is a scaled representation of the real oilfield where

the geological characteristics and fluid conditions can be studied, analyzed, quantified,

simulated and predicted.

The geocellular model was generated using Petrel software. The main components of the

geocellular model were the structural model, facies model and petrophysical model.

The structural model includes geological tops and fault surfaces that have a relationship with

fluid control. The structural model was created using six geological tops from the top of the

Arenas Basales to the top of the Paleozoic, originating five lithological zones. Each lithological


R01002 10 February 2010

zone was divided into layers. A total of 65 layers were created and divided into 50m x 50m cells

to get the cellular model frame with more than 5,400,000 cells.

The facies model was created by Meta using log analysis, core descriptions and sequence

stratigraphic concepts. The reservoir quality facies corresponds to isolated filled channels (CH),

stacked channel deposits (S-CH) and crevasse channel deposits (C-CH). The non-reservoir

facies are defined as single crevasse splay (SC) and over bank deposits (O).

The petrophysical evaluation was used in the update of the Rubiales geocellular model.

Detailed analysis of the well data evaluation was performed, and then several calculations of

new parameters were generated. Clay volume (VSH), effective porosity (PHIE), water saturation

(Sw) and net to gross sand ratio (NTG) were up scaled and loaded in the cell-wells. These data

were analyzed to determine the spatial characteristics of the data through histograms, trends

and variograms. This is an important and time-consuming process, which allowed determining

the best input parameters to deterministic and stochastic algorithms.

The cells penetrated by well paths (cell-wells) were populated with information derived from

facies and petrophysical data using averaging methods as arithmetic mean, root mean square,

harmonic mean etc. Very few cells are penetrated by wells. Previous to the stochastic spatial

distribution of cell-well values thru all the cells, data analyses were applied for quality control and

to characterize the cell values. In this process vertical proportionality, thickness variations,

histograms, trends and vertical and horizontal variograms of the cell values were generated,

analyzed and quantified. These spatial data characteristics became the input parameters used

for the stochastic algorithms in the stochastic spatial distribution of data through all the cells.

Hundreds of variograms were generated and analyzed in order to get the best possible strike

direction and trend for each facie, petrophysical parameter, and correlation facie-petrophysical

property.

Several deterministic and stochastic algorithms were tested in order to determine the best spatial

distribution of discrete (facies) and continuous (porosity, water saturation, etc.) data.

Facies data and petrophysical properties were spatially distributed to each cell, using the

Sequential Indicator Simulation algorithm. The petrophysical properties were conditioned to the

facies results.


R01002 11 February 2010

Finally, the geocellular model of the Rubiales field was created for a set of volumes divided into

millions of cells, embedded with lithology, porosity, water saturation and facies data. Figures 6.1

through 6.4 show the final distribution of these properties in the 3D model. This is the basic data

used in the oil initially in place (OIIP) volume calculation in the geocellular model. A contour map

that showed contours of stock tank oil initially in place (STOIIP) was also created (Figure 6.5).

The contours represented the STOIIP for a 50 meter by 50 meter cell surface area with a vertical

capture of the entire net pay sand thickness for the five sand members in the cell.

The volume calculation areas were defined by polygons representing the concession

boundaries. The productive and concession areas contained in the Petrel model are shown

below:

Rubiales Piriri Total

Productive Field Area (acres) 83,590.6 51,770.2 135,360.8

Total Concession Area (acres) 88,463.0 62,431.6 150,894.6

The results are grouped in the following table by the five zones determined by the

sedimentological facies in the entire concession area.

STOIIP - MMbbls

Rubiales Piriri Total

Zone 1 1078.7 530.1 1608.8

Zone 2 802.6 446.1 1248.7

Zone 3 1033.5 276.6 1310.1

Zone 4 69.8 9.8 79.6

Zone 5 0.5 0.00 0.5

Total 2985.1 1262.6 4247.7

These values and the derived STOIIP maps were used as a basis for much of the reservoir

engineering calculations in the study to aid in the reserve certification and support the proposed

field development drilling program.


R01002 12 February 2010

7.0 RESERVES DETERMINATION

7.1 Discussion

The Rubiales field contains low gravity, highly viscous oil. The recovery mechanism in the field

is primary recovery, with strong pressure support from a bottom water aquifer. In such a field,

the recovery factors under traditional oil field developments using vertical wells can be expected

to be relatively low, in the range of 10 percent to 20 percent of OIIP. RPS analysis indicates that

the maximum recovery factor of 20.3 percent can be expected for this field. To maximize the

recovery efficiency, Meta has pursued a development drilling plan that will increase the well

density and incorporate a significant number of horizontal wells.

The Rubiales field crude oil has low solution gas content, as represented by the gas-oil-ratio that

is estimated to be 5 scf/stb. As a result, there is insufficient produced gas to warrant gas sales.

Some produced gas is used as field fuel and the balance is flared. RPS has not attributed any

gas reserves to the field.

Two separate concessions hold the reserves in the Rubiales field. Each concession has a

unique operating and net revenue interest, thus the reserves and economics are calculated

separately for each concession and then summed to get the fieldwide figures.

7.2 Developed Reserves

Reserves estimates were made using production performance analysis, volumetric estimates

and production analogues. Analysis of the change in production rates, water-oil ratio and oil cut

as a function of cumulative production and time was performed to predict the ultimate

recoverable volumes for the producing wells. Parameters used to specify the shut in conditions

were two percent oil cut at a producing rate of 30 and 150 barrels of oil per day for vertical and

horizontal wells, respectively. These minimum operational production rates are dictated by

water handling capacity limitations and not due to an economic limit or flow assurance problems.

An exponential decline curve shape was used for the rate forecasts, with application of

hyperbolic performance where well performance supports the projection after the initial flush

production. Plots of the oil rate versus cumulative production, oil cut versus cumulative

production and water oil ratio versus cumulative production for the producing wells were

reviewed.


R01002 13 February 2010

Reserves for wells that were completed within the past few months that have not had sufficient

production decline performance were determined by using the type well analogies that were

applied to the drilling locations for the undeveloped reserves. All of the type wells are located in

the field, have perforated the subject sand interval, and have sufficient performance history to be

a good basis for rate projections.

As of December 2009 there were 74 wells in the shut in classification. Most of the wells have

prior production history, a lesser number have been tested only and have no cumulative

production. Meta has advised that 60 of these wells are scheduled to be placed on production in

2010 and 2011. These wells were forecasted and scheduled, and the reserves were included in

the proved developed non-producing category. The 14 remaining shut in wells are assumed to

have no potential since they were not part of the re-vitalization program.

The Rubiales field has been developed with 221 vertical and horizontal wells which have

indicated typical drainage areas of 50 and 87 acres, respectively. The typical drilling program

involves a centralized vertical well with five horizontal wells drilled outward from the same pad

location. A well cluster of this design typically drains an area of 485 acres. The horizontal wells

typically drill a distance between 500‟ and 1,200‟ feet through the reservoir. The recovery from

the horizontal wells exceeds that of the vertical wells. The wells have different performance

characteristics also. The vertical wells initially exhibit a lower average annual exponential

decline rate, and the horizontal wells initially produce at a much higher rate with a hyperbolic

decline. Table 7.1 lists all the wells that have been drilled in the field with the cumulative

production, proved reserves and estimated ultimate oil recovery of each.

The cumulative field production to year end 2009 was 57.6 MM barrels of oil, and the proved

reserves for the producing wells on December 31, 2009 are 94.1 MM barrels of oil. The ultimate

recovery (to the end of the concession term on June 30, 2016) from all wells drilled to date is

estimated to be 151.7 MM barrels of oil.

The reserves that were determined by performance analysis were checked against volumetric

calculations. Table 7.2 is a volumetric calculation that was performed to determine the oil initially

in place per acre-foot and a “maximum case” recovery efficiency for the field. The table

indicates oil initially in place of 1,450 barrels per acre-foot using the average reservoir

parameters of 26.4% porosity and 27.5% water saturation. Using a sweep efficiency of 85%, the


R01002 14 February 2010

recovery efficiency is 20.3% giving a recovery of 294 barrels per acre-foot. The 20.3% recovery

is considered a theoretical maximum, recognizing that not all the zones in each well will be

depleted due to mechanical and operational failures, unswept reservoir areas and bypassed oil

in zones that were not perforated.

A number of the wells have been drilled but have a short production history, thus performance

plots could not be used to forecast the production or to estimate the reserves for these wells.

These wells were classified as “proved developed producing” and assigned reserves using the

type curve method used for drilling locations (as described in the next section) based on

volumetric calculations and analogy. These wells with the associated proved reserves are

shown in Table 7.1 and given “well analogy” as the reserve basis.

The oil initially in place within the concession area, as calculated using the updated geocellular

model, is 4,248 MM stb. The concession area includes undrilled acreage on the flanks of the

structure that lies outside of the developed portion of the field. This untested area is evaluated

to be oil bearing based on a depositional analysis and available geological technical data which

indicates the pore volume is above the original oil water contact. The potential fieldwide oil

recovery using the 20.3% recovery factor would be 861 MM stb. This volume would include the

3P reserves contained in the cash flow analysis plus oil volumes from locations that are currently

captured in the “resource” category, which are volumes that lie outside the possible reserves

areas, volumes from wells that have been produced but in which all zones have not been

perforated, and economically recoverable volumes produced beyond the current concession

license expiry date.

7.3 Undeveloped Reserves and Resources

To estimate the reserves potential of the drilling program, a statistical analysis of past production

was used in combination with the Petrel static model. The net pay sand of the wells that have

sufficient performance to perform decline curve analysis was plotted against the estimated

ultimate recovery for both the vertical and horizontal wells. Table 7.3 shows that the 39

horizontal wells were drilled in thicker pay sections (50‟ average) than the 31 vertical wells (26‟

average), and that the horizontal wells have an average recovery that is higher than the vertical

wells, 1,325,000 stb versus 620,000 stb, respectively.


R01002 15 February 2010

A total of 687 locations that were included in Meta‟s development plan have been evaluated.

The wells were reviewed separately for each concession (Rubiales with 566 and Piriri with 121)

since the ownership is different for each property. The reserves determination was done in two

phases:

1. Assignment of reserves category based on proximity to production, and

2. Assignment of reserves volumes based on Petrel STOIIP cell values.

Phase 1

A base map containing the existing producing wells and Meta‟s proposed drilling locations was

used to assign the reserve classification based on proximity to production. Proved reserves

were assigned to new locations in areas that are undrilled and adjacent to existing wells within

the proved area of the reservoir that could reasonably be judged as continuous and being

commercially productive on the basis of available geoscience and engineering data. Probable

reserves were assigned to areas of the reservoirs that were adjacent to proved areas but where

data control or interpretations of available data was less certain. Possible reserves were

assigned to areas of the reservoirs adjacent to probable areas where data control and

interpretations of available data were progressively less certain.

Areas of the reservoir where the Petrel model indicated the reservoir should be present outside

of the proved, probable and possible areas were designated as areas in which Meta‟s proposed

wells would be drilled for oil volume in the resource category. The wells needed to develop

these resources were given drilling location names and volumes, but production and cash flow

projections were not made.

Six hundred eighty seven locations were classified as follows:

Proved 341 locations

Probable 91 locations

Possible 104 locations

Resources 151 locations


R01002 16 February 2010

Phase 2

Each of the proposed locations was identified on a fieldwide Petrel map that showed contours of

stock tank oil initially in place (STOIIP), Figure 6.5. The contours represent the STOIIP for a 50

meter by 50 meter cell surface area with a vertical capture of the entire net pay sand thickness

for the one to five sand members in the cell. Values for the contours ranged between 0 to

70,000 barrels per cell, although few wells remain to be drilled in contours over 40,000 since the

thicker pay sand areas have been effectively exploited by Meta.

Wells that have produced that are either depleted or that have reserves based on performance

are listed in Table 7.3. The estimated ultimate recovery and the net pay are tabulated for each

well, indicating the average estimated ultimate recovery and average net pay for vertical and

horizontal wells is 620,000 barrels and 26 feet of net pay, and 1,325,000 barrels and 50 feet of

net pay, respectively. The scatter to the data suggests that a definitive relationship between the

parameters may not be present and that the recovery from proposed locations is difficult to

predict from the net pay isopach map.

A second data set is shown on Table 7.4 for the relationship between the estimated ultimate

recovery and the STOIIP contour map from the Petrel model. This data is also scattered such

that the plot based on STOIIP values is not a good indicator of recovery from the proposed

locations. The average estimated recovery for each STOIIP cell value for a vertical and

horizontal well is 14.0 and 44.5 barrels, respectively.

Despite the scatter in the data relative to Tables 7.3 and 7.4, the average relationships are

reflective of the historical production data and are valid for the prediction of estimated reserves

for large numbers of locations such as those within the Meta drilling program. The earlier

geological discussion describes the hydrodynamic trap model with the tilted oil water contact

across the field, indicating the existence of many individual reservoir lobes with lateral barriers

that produce independently. Absent knowing the structure and extent of each of the lobes,

determination of the drainage area for each well (thus the reserves) will be best established

using the statistical methods based on past well performance as indicated.

The determination of reserves and production forecasts for each location was made from the

following calculations:


R01002 17 February 2010

1. The estimated ultimate recovery per STOIIP contour for vertical and horizontal wells

having production history was determined as shown on Table 7.4 to be 14.0 and 44.5

barrels per STOIIP contour per cell unit.

2. The estimated reserves for future locations were calculated using the above recoveries

multiplied by the discrete STOIIP contour from 4,000 to 60,000 where the wells are

spotted to be drilled.

3. The type curves shown on Figure 7.1 were generated based on past performance (initial

flowrates and decline rates) and matched to the associated reserves volumes.

4. The production type curve and reserves volume from these analogies were used for each

location that was scheduled to be drilled prior to the end of the concession period.

To ensure that all wells that were scheduled meet a profitability test, calculations to determine

the minimum reserves needed to drill a profitable well were performed. The average well cost

and the economic parameters that impact the profit calculation were used. The reserves needed

to drill and produce a vertical or horizontal well are 54,500 and 70,400 barrels, respectively.

Considering the different areas that a vertical versus a horizontal well would drain assuming a

thin pay sand interval, the associated Petrel STOIIP contours are approximately 5,400 and 4,400

stb OIIP per grid cell for vertical and horizontal wells (for net pay intervals of 6‟ and 5‟,

respectively.

The highest recovery from a vertical well and a horizontal well having performance from the plots

on Table 7.3 was 1.5 million and 3.2 million barrels, respectively. It is anticipated that none of

the wells drilled in the future would produce volumes approaching these figures.

In summary, there are 536 locations having 380 MMbbls of proved, probable and possible oil

reserves and 151 locations having 114 MMbbls of oil resources, with these volumes being the

total volume recoverable prior to depletion based on the locations that were provided by Meta.

One condition for undeveloped reserves potential to be included in this report as reserves is to

have a stated intention by the operator to drill the wells. Meta has indicated their intention to drill

the wells and has provided the drilling schedule for 2010, which was used as guidance to

continuing the drilling program through 2015. The majority of the locations in the earlier years

are proved wells, with the majority of the probable and possible locations being drilled in the later

years. Meta has indicated that in the later years of the concession, locations in the resource

category that have an expectation of at least 10‟ of net pay sand would be drilled.


R01002 18 February 2010

7.4 Summary

Reserves to End of Concession

Table 7.5 shows the reserves and annual production forecast by concession with a field total

until contract expiration on June 30, 2016. Approximately 77% of the field‟s 3P potential ultimate

recovery, or 559 MM barrels, should be produced by that date. A summary of the reserves is

shown below:

Rubiales Field Potential Ultimate Recovery (to Depletion) CUM CUM MMstb MMstb RE(%) RE(%) Cumulative Production @ Dec 31, 2009 57.6 57.6 1.4 1.4 Total 3P Reserves @ Jun 2016 501.2 558.8 11.8 13.2 Resource Volumes 114.1 672.9 2.7 15.8 Production from July 2016 to depletion 165.3 838.2 3.8 19.7

Rubiales Field Reserves at December 31, 2009 (to Expiration of Concessions)

MMBO Proved

Developed 121.2 Undeveloped 296.0

1P Reserves 417.2

Probable Undeveloped 46.0

2P Reserves 463.2

Possible Undeveloped 38.0

3P Reserves 501.2


R01002 19 February 2010

8.0 PRODUCTION FORECASTING

The Rubiales field was discovered in 1981; however it only produced periodically until 2002

when production was reported continuously. After Meta obtained control of the operation of the

field in 2004 the production increased until it reached 100 MBOPD in 2009 (Figure 8.1). The

production for the Rubiales field was forecasted from January 1, 2010 to the expiration of the

concession on June 30, 2016 as shown in Table 7.5. The field has 139 producing wells in the

concessions with the associated reserves volumes during the concession license period as

shown in the table below. These wells comprise the proved producing case.

Sixty shut in wells were scheduled to be back on production between 2010 and 2011. The

production from these wells during the concession period was scheduled. The volumes are

classified as proved non-producing reserves as shown in the following table:

The Rubiales field has 536 locations in the drilling program that is forecasted to continue into

2015. The locations are expected to generate 380 MM barrels of oil before the end of the

concession period. The table below shows the reserves volume split between the proved,

probable and possible categories as well as the number of locations in each.

Proved Undeveloped Locations

Probable Undeveloped Locations

Possible Undeveloped Locations

Rubiales Field Count Production MMbbls

Count Production MMbbls

Count Production MMbbls

Rubiales Concession 264 224.7 75 39.9 80 28.5

Piriri Concession 77 71.3 16 6.1 24 9.5

Total Field 341 296.0 91 46.0 104 38.0

Rubiales Field Producing Wells Reserves, MMbbls

Rubiales Concession 71 54.1

Piriri Concession 68 40.0

Total Field 139 94.1

Rubiales Field Shut in Wells Reserves, MMbbls

Rubiales Concession 46 21.2

Piriri Concession 14 5.9

Total Field 60 27.1


R01002 20 February 2010

The production forecasts for each of the drilling programs are shown in the cash flow forecast

evaluations to be discussed in Section 9.0 Determination of Value. Forecasts of the production

performance by reserves category were created following the list of new locations and the 2010

drilling schedule provided by Meta as shown on Figure 8.2. This schedule of development has

assumptions that include the number of rigs that would be contracted by year as well as the time

it would take to drill and complete a typical well. The production forecasts of the field

development plan were scheduled on an unrisked basis.

A total of 64 water disposal wells are planned to be drilled from 2010 through 2015 by Meta.

The wells will be grouped into 11 clusters and the drilling is scheduled as shown below:

Water Disposal Well Count

2010 2011 2012 2013 2014 2015 Total

Horizontal 9 10 9 9 8 4 49

Vertical 3 4 3 2 2 1 15

Total 12 14 12 11 10 5 64


R01002 21 February 2010

9.0 DETERMINATION OF VALUE

9.1 Ownership

Time Period

The assessment of value for the Rubiales field was calculated for the production forecast from

January 1, 2010 through the end of the Piriri and Rubiales concession contracts on June 30,

2016. Both of the concessions expire on the same date; reserves that remain after this date are

not recoverable by Meta Petroleum. The effective date for discounting of field value in the

evaluation is January 1, 2010.

Interests

Meta has different working and revenue interests in the two concessions as follows:

Rubiales Piriri

Working interest 40% 50%

Net Revenue interest 32% 40%

The royalty due from crude oil production that is sold from each concession is 20 percent.

Natural gas production is negligible and is not metered or sold. The economic analysis includes

the crude oil / naptha blend as the sales product. Royalty is paid on the crude oil but not on the

naptha. Thus, the royalty in the economic model is based on a ratio of crude oil at 20 percent

royalty and the naptha that has no royalty obligation. The net revenue share that was input into

the model to properly reflect the ownership of pipeline volume to sales is 81.7 percent.

9.2 Determination of Volumes

Production

The Piriri and Rubiales concessions each have value in the proved producing, proved non-

producing, and proved, probable and possible undeveloped categories. All volumes in this

report are presented unrisked. Appendix 1 is an exhibit that is taken from the Petroleum

Resources Management System (PRMS) report that was issued in 2007 by the Oil and Gas


R01002 22 February 2010

Reserves Committee of the Society of Petroleum Engineers and was reviewed and jointly

sponsored by the World Petroleum Council (WPC), the American Association of Petroleum

Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). The PRMS

report contains guidelines regarding the relative risk and uncertainty of recovery for the various

reserves categories that are contained within this reserves certification report. The reserves and

economics evaluations that were performed in this report followed the guidelines that were

provided in this exhibit. A summary of the well count that is associated with each reserves

category is as follows:

Proved Producing – As of year-end 2009 there were 139 wells producing oil. 68 percent

of the wells are expected to produce through June 2016 when the concessions expire.

Proved Non-Producing – There are 60 wells with past production or tests that are

scheduled to be re-completed in 2010 and 2011.

Proved Undeveloped – 341 locations are in close proximity to prior production.

Probable Undeveloped – 91 locations offset the proved undeveloped locations.

Possible Undeveloped – 104 locations offset the probable undeveloped locations.

Table 7.5 shows the annual production forecast that is developed from the above re-completion

and drilling program for the Rubiales field by concession and reserves category.

Lease Fuel

Some of the oil production is consumed as fuel in the field to heat the crude and enable the

separation of the oil from the water to be more efficient. While the produced volumes have

increased as the field is developed, the fuel volume has increased also. During 2009, fuel

consumption increased from approximately 250 to 450 barrels per day. The current projection of

fuel consumption in 2010 is 1,250 barrels per day, rising to 2,700 barrels per day in 2014 as

shown in Figure 9.1. After 2014 when field production declines, the fuel consumption is

forecasted to decline also to 2,400 barrels per day in 2016. Table 9.1 shows the forecasted

annual crude volume to be consumed. Fuel volume was scheduled by allocation to the proved,

probable and possible reserves categories for each concession.


R01002 23 February 2010

Sales

The annual production volumes from 2010 through 2016 in each reserves category, by

concession, were reduced by subtracting the oil consumed for lease fuel to determine the crude

volume that is to be sold. The oil volumes that are trucked or pipelined to sales at Covenas for

export are diluted by blending with naptha to increase the API gravity to meet pipeline and/or

sales specifications. This naptha volume plus the crude sales volumes (field production less

lease fuel consumption) comprise the total sales volumes. Table 9.1 shows the annual naptha

purchases and the annual net sales volumes. These sales volumes are the volumes that are

entered into the economic analysis. The costs of naptha purchase and transportation to the field

are treated as a field operating cost. Also, from the present through December 2011 Meta

forecasts the sale of 4,000 barrels per day of 12.5 degree API gravity crude to the local

Columbian market via trucking without the addition of naptha.

9.3 Marketing

Oil Price

The forecasted annual price of WTI benchmark oil was provided by the RPS Strategic Planning

Department in London in January 2010. The produced oil from Rubiales is 12.5 degrees API

gravity, a low gravity that has downward price adjustments due to quality of 17.29 percent and

9.22 percent, for the trucked and pipelined oil, respectively. The oil value is also reduced for

system losses of 3.29 percent and 5.16 percent, for the trucked and pipelined oil, respectively.

These values are based on Meta‟s 2009 sales data. These price adjustments were applied to

the RPS WTI price forecast and proportioned by the relative volumes that were forecasted to be

trucked locally, trucked to Guaduas, or pipelined to Covenas. A weighted average price forecast

was then calculated which is shown in Table 9.2. Trucking of the oil is scheduled to end in

December 2011; afterwards all the oil will be transported through the pipeline.

Transportation

From field discovery through mid 2009, all of the production from the Rubiales field was trucked

to sales. Trucking is very expensive and the excessive traffic damages the dirt roads within the

field. During 2009, Meta constructed and commissioned a 235 km 24 inch pipeline to increase

export capacity, increase safety and lower transportation costs for crude oil from the field.


R01002 24 February 2010

The pipeline originates in the Rubiales Field and initially transported 65,000 barrels per day in its

first phase. The pipeline goes from the field to Monterrey where it ties into existing pipeline

facilities which transport oil to the Pacific coast at Covenas for the oil to be loaded onto oil

tankers for export. The pipeline routes are shown on Figure 9.2. Because Meta‟s and

Ecopetrol‟s field production will be sold in the pipeline together, the gross field production plus

blended naptha is used to determine transported pipeline volumes. The scheduled growth of

pipeline capacity, to be accomplished by adding more pumping horsepower as the field volume

requires, is as follows:

Added Pumping

Capacity Completion Barrels per day

February 2010 120,000

March 2010 160,000

June 2010 170,000

March 2011 300,000

9.4 Costs

The investment program to develop the Rubiales field reserves with the associated infrastructure

was created in 2007 when the field potential was established. Subsequent drilling and

construction to this date has generally followed the original plan and resulted in a substantial

investment and increase in production during the past two years. The forecasted expenditures

appear to be sufficient to optimize field recovery prior to the expiration of the concessions on

June 30, 2016.

The field development has included drilling producing and water disposal wells, re-completing

shut in wells, building facilities to process produced fluids and to dispose of produced water, an

extensive system of flowlines and water disposal lines, and the construction of tankage and lines

for the purchase, handling and blending of naptha which is necessary to increase the oil gravity

to pipeline specifications.


R01002 25 February 2010

Investments - Drilling

A typical producing well program consists of one vertical well in a centralized pad location with

up to five horizontal wells drilled outward from the same pad area. Costs for the location

preparation, generators and pipelines are included in the well costs. The drilling well costs were

provided by Meta as follows:

Well Type Cost per well

Production well – horizontal $1,754,000

Production well – vertical $1,657,000

Disposal well – horizontal $1,573,000

Disposal well – vertical $1,296,000

These costs have been reviewed by RPS, including comparison with Meta‟s historical drilling

cost in the field, and deemed to be reasonable.

The timing of the producing well drilling program was scheduled by Meta for 2010 and by RPS

for 2011 and beyond based on the reserves analysis. The costs were assigned by the location

of each well to its concession and reserves category. The schedule for drilling the disposal wells

(timing and well type) was provided by Meta. Disposal well costs were distributed to each

concession and split by the proportional reserves volume in each reserves category. No

disposal well cost was distributed to the proved producing reserves cases because these

volumes already have water disposal capacity.

The drilling program is scheduled to continue uninterrupted into 2015. An analysis of the

horizontal and vertical producing wells indicates that for a horizontal and vertical well to be

profitable, 70,400 and 54,500 barrels of oil, respectively, must be recovered. At the expected

producing rates, the wells would payout in six months or less, making it attractive to continue the

drilling program through 2015.

The cost for a well re-completion was provided by Meta to be $250,000. A review of the shut in

wells across the field by Meta personnel resulted in a list of 60 re-work opportunities that were

reviewed by RPS. An analysis of the past performance of these wells indicates the potential to

re-establish production. The re-completions are scheduled to be completed in 2010 and 2011.


R01002 26 February 2010

Meta had signed contracts for five drilling rigs in 2008 that kept the rates constant for a three

year period through 2011. Thus, no cost inflation was applied to the well costs until 2012 when a

two percent annual inflation was applied. Meta uses just two types of rigs in the field. By limiting

the rig types to two, operating and maintenance costs are kept as low as possible. The re-

completion well work will be done using smaller rigs that have a two percent cost inflation

beginning in 2010.

The forecasted annual drilling and re-completion investments are shown on Table 9.3.

Investments - Facility

The work to expand the capacity of the field infrastructure continues concurrently with the drilling

program. The metering and processing facilities, water injection pumps and lines, and naptha

blending tanks and equipment to accommodate the increasing production are under

construction. New areas, as developed, will also benefit from infrastructure projects to process

higher volumes of produced fluids. These facility investments were scheduled by Meta and are

shown on Table 9.3. The costs were allocated to each concession and reserves category based

on the percentage of reserves to be recovered. The escalation rate applied to these costs was

two percent.

The costs to manage the rising water production are substantial and projected to increase into

the future. An additional 500,000 bwpd of capacity is scheduled for installation in 2010. At the

various water injection sites, clusters of horizontal injection wells are drilled around a single

vertical injection well, and pump capacity is designed based on the expected water production in

the area. If additional capacity is required due to higher than planned water production, more

pumping capacity is installed rather than the drilling of additional wells. Wells are planned to

dispose of 45,000 bwpd, but are capable of disposing of up to 70,000 bwpd. Produced water is

fresh with essentially no contaminants, and the continued disposal of 300,000 bwpd into the

nearby river is expected.

Expenses - Operating Costs

The operating cost history for the past several years for the Rubiales field has been provided by

Meta. The cost schedules have been reviewed by RPS, compared with historical costs and

deemed to be reasonable.


R01002 27 February 2010

The monthly costs in 2009 from January through October steadily increased as produced

volume increased from 1.5 to 2.5 million barrels per month. In October, the operating cost was

$9.3 million, or $3.64 per barrel. The trend line shows the costs were on track to reach $3.75

per barrel by year end 2009. An average operating cost of $4.00 per barrel was estimated for

2010. The forecast generated by RPS for this analysis indicated an average 2010 production

volume of 151,500 barrels of oil per day. As a result, the total operating cost that is forecast for

2010 is $221,192,000 which is substantially above the costs in the prior years.

The cost noted above was split at a 35% / 65% ratio between fixed and variable cost

components, respectively. The fixed cost of $77,417,000 that is shown on Table 9.4 represents

the annual operating cost that is independent of the well count or the production volume. To

reflect the growth in field facilities, the fixed cost was increased by five percent in 2011 and

2012, followed by no increase in 2013. The variable cost of $143,775,000 represents operating

costs that will vary with well count and production volume. The variable cost was split at a 35% /

65% ratio between well count and production volume. Variable costs of $286,000 per well

(based on the average 2010 forecasted well count) and $1.69 per barrel (based on the estimated

cost allocated to the forecasted 2010 production) were determined. All operating costs were

escalated at an annual rate of two percent.

In previous year analyses, a road maintenance cost of $0.79 per barrel was added to the

production expense due to the excessive road usage by the oil trucks prior to the construction of

the export pipeline. The road use by the trucks hauling oil has declined considerably now since

the pipeline is in operation, resulting in a less costly road repair program. Meta advised that the

cost of road maintenance is now handled by the army that is stationed in the field.

An additional variable cost that is charged is Meta‟s overhead and administration. Meta advised

that this cost is $0.50 per barrel; it was added to the variable cost of $1.69 to determine the total

variable cost of $2.19 per barrel of produced oil.

Expenses – Naptha Purchase

The produced crude oil has 12.5 degree API gravity, and due to its high viscosity it does not

meet pipeline specifications. Naptha at 82 degree API gravity is trucked to the field and blended

with the crude oil to lower the viscosity. The blended oil has 18.5 degree API gravity, meets

pipeline specifications and sells for a higher price than the unblended produced crude oil. The


R01002 28 February 2010

oil that is transported by trucks and sold locally is heated in the trucks to reduce its viscosity and

is not blended with naptha.

The required naptha volume is a function of the relative crude oil quality and produced volume

from the Rubiales, Caracara, Ocelote and Quifa fields. The crude oil from these fields is blended

in the pipeline, and the final mixture must be of pipeline quality. The forecasted production,

naptha requirements and pro-rated volume of naptha that is blended with Rubiales crude have

been determined by Meta and furnished to RPS for this analysis. The naptha is purchased for

the posted price of WTI oil less $5.00. The forecast of naptha prices, annual volume

requirement and annual expenditures to purchase the naptha are shown on Table 9.4.

Expenses – Tariffs and Blending

Until the pipeline in the field reaches its maximum capacity of 300,000 barrels per day in 2011

with additional pump installations, some crude oil will be trucked from the field to the Guaduas

Station. At Guaduas, the crude is blended with naptha to reach a API gravity of 18.5 degrees

prior to entering another pipeline to Covenas. The tariff to deliver the 82 degree API gravity

naptha from the Cartagena sea port to Guaduas is $11.55 per barrel, and an additional $0.33

per barrel is charged for the blending process. The crude oil that enters the field pipeline to

Covenas for export is blended with naptha in the Rubiales field to reach the API gravity of 18.5

degrees. The delivery charge for the naptha from the Cartagena sea port to the field is $9.80

per barrel, and there is no blending charge there. The naptha tariff and blending costs are

summarized in Table 9.4.

The crude oil and blended oil/naptha mix incur tariff charges also. Meta is charged $10.73 per

barrel for crude that is trucked to Guaduas. After blending there, the oil/naptha mix is pumped

into a pipeline that charges a tariff of $2.03 per barrel to deliver the mix to Covenas for export.

The blended oil/naptha mix that leaves the Rubiales field in the new pipeline directly to Covenas

for export is charged a tariff that is coupled with throughput volume as follows:

Daily Volume from Rubiales Field Tariff Charge

100,000 to 125,000 bbl per day $6.39 per barrel



Over 175,000 bbl per day $6.30 per barrel


R01002 29 February 2010

The crude oil and oil/naptha mix tariffs and blending costs are summarized in Table 9.4. The

average unescalated cost for tariffs and blending of produced crude oil and purchased naptha is

$8.07 per barrel over the life of the project.

Although the cost per barrel to truck the crude from the field is expected to decrease as the

pipeline capacity increases from 2010 to 2011 when the trucking is ended, the decline in cost

was not modeled in the economics as it is not significant relative to the overall analysis results.

Expenses - Abandonment and Reclamation

Production forecasts indicate that the majority of the wells would produce to at least June 30,

2016. The concession contracts do not require that Meta abandon inactive wells unless the

wells have been junked for mechanical reasons. Based on past experience, Meta has

forecasted that 2.5 percent of the wells in the field would need to be abandoned on an annual

basis at a cost of $300,000 each. The annual cost for this work has been included in the RPS

forecasts of field operating cost and is shown in Table 9.4.

9.5 Evaluation Parameters

The revenue and costs were input by concession so that the appropriate working and net

revenue interest cash flows could be calculated separately. The analysis was made for both

before tax and after tax cases. A two percent escalation was applied to the investment and

operating costs based on actual Columbian data and the global RPS oilfield forecast.

A 33 percent income tax was used in the after tax analysis. A tax credit for investments was

also used in which 40 percent of the total net investment for 2009 was deducted in 2010, and 30

percent of the total net investment in 2010 and 2011 was deducted in 2011 and 2012,

respectively. The tax credit was allocated by concession and reserves volume by category. No

tax credit was assigned to the proved producing reserves in 2011 and 2012 because those

volumes that were developed in prior years did not require future investments to produce to

depletion.


R01002 30 February 2010

The annual cash flow profit was then discounted to present worth using a 10 percent discount

rate, and summed to calculate the cumulative discounted cash flow by concession and reserves

category. All dollars mentioned in the report are in U. S. currency.

9.6 Analysis Results

The PHDWIN economic model was used to perform the economic calculations. Tables 1.1

through 1.8 contain the summary level results. Output from these runs is included by

concession for each reserves category in Appendix 2 (before tax cash flows) and Appendix 3

(after tax cash flows).

Note: Due to the inclusion of naptha diluent in the sales volumes, and "hardwired" program

output formats of the PHDWIN software, the summary outputs and column labels do not match

other reporting tables in this report. The following glossary should be used in interpreting the

PHDWIN cash flow output tables:

"PHDWIN Column Label" = Meaning for this report

"Gross Oil" = Total field oil production (ie gross field reserves) plus Naptha diluent less oil

shrinkage

"Net Oil" = Meta Working Interest share of Net Reserves = Meta share of [total oil reserves plus

Naptha diluent less oil shrinkage less Royalty]

"Oil Revenue" = Meta Working Interest Net (after royalty) revenue

" Well Count" = Number of PHDWIN cases included in analysis

"Net Investment" (on the before tax report) = Meta Working Interest share of Development Costs

"Net Investment" (on the after tax report) = Meta Working Interest share of Development Costs

minus Capital investment tax credits

"Net Lease Costs" (on the before tax report) and "Net Op Costs" (on the after tax report) = Meta

Working Interest share of Operating Costs (including annual abandonment costs)

"Federal Income Tax" = Meta Working Interest Federal Income tax before application of Capital

Investment tax credits


R01002 31 February 2010

Appendix 2 contains the detailed annual revenue, cost, net and discounted cash flow figures for

the before tax evaluation cases described as follows:

Page 1 Grand Total Page 2 Proved Producing Total Page 3 Piriri Concession – Proved Producing Page 4 Rubiales Concession – Proved Producing Page 5 Proved Non-Producing Total Page 6 Piriri Concession – Proved Non-Producing Page 7 Rubiales Concession – Proved Non-Producing Page 8 Proved Undeveloped Total Page 9 Piriri Concession – Proved Undeveloped Page 10 Rubiales Concession – Proved Undeveloped Page 11 Probable Undeveloped Total Page 12 Piriri Concession – Probable Undeveloped Page 13 Rubiales Concession – Probable Undeveloped Page 14 Possible Undeveloped Total Page 15 Piriri Concession – Possible Undeveloped Page 16 Rubiales Concession – Possible Undeveloped

Appendix 3 contains the detailed annual revenue, cost, net and discounted cash flow figures for

the after tax evaluation cases described as follows:

Page 1 Grand Total Page 2 Proved Producing Total Page 3 Piriri Concession – Proved Producing Page 4 Rubiales Concession – Proved Producing Page 5 Proved Non-Producing Total Page 6 Piriri Concession – Proved Non-Producing Page 7 Rubiales Concession – Proved Non-Producing Page 8 Proved Undeveloped Total Page 9 Piriri Concession – Proved Undeveloped Page 10 Rubiales Concession – Proved Undeveloped Page 11 Probable Undeveloped Total Page 12 Piriri Concession – Probable Undeveloped Page 13 Rubiales Concession – Probable Undeveloped Page 14 Possible Undeveloped Total Page 15 Piriri Concession – Possible Undeveloped Page 16 Rubiales Concession – Possible Undeveloped


R01002 32 February 2010

10.0 QUALIFICATIONS AND LIMITATIONS

10.1 Independence and Conflict of Interest

This report has been prepared by RPS. RPS is an international independent oil and gas

advisory firm with Energy Division offices in the USA, UK, Canada, Singapore, Australia and the

Netherlands. This report was prepared in the RPS office located in Houston, Texas. All

evaluations performed by RPS are strictly fee-based and RPS has not and will not receive any

benefit, which may be regarded as affecting its ability to render an unbiased opinion.

10.2 Purpose, Scope and Use of This Report

This report was commissioned by Mr. Ysidro Araujo of Meta to evaluate the Rubiales Field. The

scope of the project was restricted to this brief. This report was prepared exclusively for the use

of the stated parties and should not be duplicated or distributed to any third parties without the

express written consent of RPS, except as required by law.

10.3 Available Data

This study was based on data supplied by Meta and on nonproprietary data from in-house files.

The supplied data 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.

10.4 Professional Qualifications

RPS personnel who prepared this report are degreed professionals with the appropriate

qualifications and experience to complete the project brief. 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.


R01002 33 February 2010

10.5 Site Visit and Inspection

A site visit to the Rubiales field and Meta‟s technical office in Bogota was conducted by three

RPS personnel directly involved in the preparation of the report on December 14 and 15, 2009.

The ongoing development activity was observed, including drilling operations, production

facilities, water disposal facilities, and numerous construction projects that are in progress.

Pipelines, in-field gathering lines and the road system and living areas for staff and construction

crews were also observed. Every day, a personnel contingent of 5,800 people works in the field.

This requires a major coordination effort for personnel and materials that are brought in for the

field operations and construction projects. The work is conducted in a manner that respects the

native population as well as the environmental concerns of the government. RPS is not in a

position to comment on whether the operations are in compliance with any regulations that may

apply to them.

10.6 Liability Waiver

This report has been prepared on a best efforts basis to address the requirement of the brief

specified by the clients. 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.

Figures

Figure 3.1Rubiales Field Location Map

Rubiales Field

PIRIRI BLOCKRUBIALES BLOCK

QUIFA BLOCK

Figure 3.2Concession Map

Figure 3.3Rubiales Field Production Plot

1981 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 2000 01 02 03 04 05 06 07 08 09100

101

102

103

104

105

106

Date

LEASE: PIRIRI, RUBIALES(248)Oil Prod Rate (Calend Days) ( bbl/d ) Liquid Prod Rate (Calend Days) ( bbl/d ) Wells Producing Oil ( wells )

Rubiales FieldProduction History

Figure 3.4Rubiales Concession Production Plot

1981 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 2000 01 02 03 04 05 06 07 08 09100

101

102

103

104

105

106

Date

LEASE: RUBIALESOil Prod Rate (Calend Days) ( bbl/d ) Liquid Prod Rate (Calend Days) ( bbl/d ) Wells Producing Oil ( wells )

Rubiales ConcessionProduction History

Figure 3.5Piriri Concession Production Plot

1989 90 91 92 93 94 95 96 97 98 99 2000 01 02 03 04 05 06 07 08 09100

101

102

103

104

105

106

Date

LEASE: PIRIRIOil Prod Rate (Calend Days) ( bbl/d ) Liquid Prod Rate (Calend Days) ( bbl/d ) Wells Producing Oil ( wells )

Piriri ConcessionProduction History

Figure 4.1Structure Top Arenas Basales

Wells in Red produce from Arenas Basales Formation. Wells in Blue are water productive. Note limits of the hydrocarbon trap are not well defined in any direction.

Figure 4.2Structure Oil – Water Contact Arenas Basales

Figure 4.3Structural Cross Section - West to East

Structural Cross Section, West to East showing tilted Oil-Water Contact.

Figure 4.4Gross Arenas Basales Isopach with

Structure Top Arenas Basales

Note apparent northwestward thick trend. Wells in Red produce from Arenas Basales Formation. Wells in Blue are water productive

Figure 4.5Net to Gross Sand Ratio Arenas Basales Reservoir Interval

Note gray areas are more shale prone, and appear to trend northwestward along depositional thick

Figure 4.6Net Pay Isopach Arenas Basales

Note Net Pay Isopach appears to trend east-west across the northwest trending gross reservoir isopach trend

Figure 5.1Wells Drilled in 2009 with Petrophysical Analysis

RB-_1

RB-_2

RB-_3

RB-_4

RB-_5

RB-_6

RB-_7

RB-_8

RB-_9

RB-_10

RB-_11RB-_12RB-_13

RB-_14

RB-_15

RB-_16

RB-_17

RB-_18

RB-_19RB-_21

RB-_22

RB-_23RB-_24

RB-_25

RB-_26

RB-_27

RB-_28RB-_29

RB-_30

RB-_31 RB-_33

RB-_34

RB-_36

RB-_37

RB-_38RB-_39RB-_40

RB-_41

RB-_43D

RB-_44D

RB-_45H

RB-_46

RB-_47

RB-_48H

RB-_49H

RB-_50HRB-_50HRE

RB-_51

RB-_53

DW_01

QUIFA_1QUIFA_2

RB-_42H

RB-_54H

RB-_55HRB-_56H

RB-_57H

RB-_58H

QUIFA_3

QUIFA_4

RB-_59H

RB-_60HRB-_61H

RB-_62H

RB-_63HRB-_64H

RB-_65H

RB-_66H

RB-_83

RB-_85

DW_2H

RB-_67H

RB-_79

RB-_80

RB-_68H

RB-_69HRB-_70HRB-_71HRB-_72H

RB-_73H

RB-_74HRB-_75H

RB-_76H

RB-_77HRB-_78H

DW-3H

DW-3H_STDW-3H_ST2

RB-_81

RB-_82

RB-_84

RB-_86

RB-_87

RB-_88

RB-_90

RB-_91

RB-_89HRB-_92

RB-_94H

RB-_97H

RB-_98H

RB-_99HRB-_100H

RB-_104

RB-_105H-ST

RB-_112

RB-_113

RB-_111

RB-_106HRB-_107H

RB-_108HRB-_109H

RB-_114

RB-_115RB-_116

RB-_117RB-_118

RB-_119

RB-_120

RB-_121

RB-_122

RB-_123H

RB-_124H

RB-_125H

RB-_126_ST

RB-_127

RB-_128

RB-_129

RB-_130 RB-_131HRB-_132H_(ST)

RB-_133H

RB-_134H

RB-_135HRB-_136H

RB-_137H RB-_138H

RB-_140

RB-_141

RB-_142

RB-_143

RB-_144

RB-_145

DW_4HDW_5H

DW_6HDW_7HRB-_52

QUIFA_5

RB-_147

RB-_148

RB-_153H

RB-_157H

RB-_101HRB-_102HRB-_110H

RB-_139

RB-_150

RB-_154H

RB-_155

RB-_156HRB-_158

RB-_159

RB-_160

RB-_161

RB-_162

RB-_163RB-_164

RB-_165

RB-_168H

RB-_169HRB-_170H

RB-_171H

RB-_172H

RB-_173H

RB-_174H

RB-_175H

RB-_176H

RB-_177H

RB-_178H_ST

RB-_179H_STRB-_180H_ST

RB-_181H

RB-_182H

RB-_183HRB-_184H

RB-_185H

RB-_187H

RB-_188H

RB-_189H

RB-_190HRB-_191H

RB-_192H

RB-_195H

RB-_198

RB-_199

RB-_200H

RB-_201HRB-_202H

RB-_203H

RB-_204H

RB-_205H

RB-_206H

RB-_207H

RB-_208H

RB-_209H

RB-_210HRB-_212H RB-_214H

RB-_215H

RB-_216HRB-_93H

RB-_95H

DW_08

DW_09H

DW_10H

DW_11H

DW_12H

DW_13

DW_14H

QUIFA_7

QUIFA_8

QUIFA_9

RB-_217

RB-_218

RB-_219

RB-_220

RB-_221

RB-_222

RB-_223H

RB-_224

RB-_232H

RB-_234H

RB-_235H

RB-_236H

RB-_237H

RB-_238H

RB-_239H

RB-_240H

RB-_241

RB-_242

I-9

I-9_STI-9_ST2

QUIFA_10

QUIFA_12

RUBIALES 2009

Base Map - Vertical wells Drilled 2009

FEET

0 4,031 8,062

POSTED WELL DATA

PETRA 12/2/2009 2:13:15 PM

Figure 6.1Net to Gross Distribution – 3D Model

Figure 6.2Porosity Distribution – 3D Model

Figure 6.3Water Saturation Distribution – 3D Model

Figure 6.4Facies Distribution – 3D Model

Figure 6.5STOOIP Map

Figure 7.1Type Well Production Curves for New Completions

0

10

20

30

40

50

60

70

80

90

100

110

120

0 10 20 30 40 50 60 70 80 90 100 110 120

Oil

Pro

du

cti

on

-m

bo

pm

Months of Production

Horizontal Well Type Curves

Note shut in rate is 150 bopd, or 4,500 bopm

0

5

10

15

20

25

30

0 10 20 30 40 50 60 70 80 90 100 110 120

Oil

Prod

uctio

n -m

bopm

Months of Production

Vertical Well Type Curves

Note shut in rate is 30 bopd, or 900 bopm

Figure 8.1Production Plot – History and Forecast

5 6 8 1325

48

102

152

226 231 228 230

214

184

0

50

100

150

200

250

300

2002 2004 2006 2008 2010 2012 2014 2016 2018

MBO

PD

Date

History Production

Forecast Production

2016 production is for January through June only

Meta became the Operator

Figure 8.2Production Plot by Reserve Category

0

50

100

150

200

250

300

2010 2011 2012 2013 2014 2015 2016

MBO

PD Reserve 3P

Reserve 2P

Reserve 1P

Figure 9.1

Fuel Consumption Forecast

500

1000

1500

2000

2500

3000

0 1000 2000 3000 4000

Fuel

Con

sum

ptio

n -b

bl p

er d

ay

Total Produced Fluid - Mbbl per day

Correlation data provided by Meta

500

1000

1500

2000

2500

3000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Fuel

Con

sum

ptio

n -b

bl p

er d

ay

Field Production73,000 to 230,000 bopd

Field Production 230,000 to 188,000 bopd

Fuel consumption determined by RPS

Figure 9.2

Pipeline Route From Rubiales Field to Covenas Sea Port

Tables

FORM 51-101F1 Table 1.1

Summary of Oil and Gas Reserves

as of December 31, 2009

Forecast Prices and Costs

RESERVES

RESERVE CATEGORY

Gross

(Mbbl) Net (Mbbl)

Gross

(Mbbl) Net (Mbbl)

Gross

(MMscf)

Net

(MMscf)

Gross

(Mbbl) Net (Mbbl)

Gross

(Mltl)

Gross

(Mltl)

COLOMBIA

PROVED

Developed Producing - - 41,629 33,303 - - - - - - Developed Non Producing - - 11,426 9,141 - - - - - - Undeveloped - - 125,546 100,437 - - - - - -

TOTAL PROVED - - 178,600 142,881 - - - - - -

PROBABLE - - 18,992 15,193 - - - - - - TOTAL PROVED + PROBABLE 197,592 158,074

POSSIBLE 16,142 12,914 TOTAL PVD + PROB + POSS 213,734 170,988

UNITED STATES

PROVED

Developed Producing - - - - - - - - - - Developed Non Producing - - - - - - - - - - Undeveloped - - - - - - - - - -

TOTAL PROVED - - - - - - - - - -

PROBABLE - - - - - - - - - - TOTAL PROVED + PROBABLE

LIGHT AND MEDIUM

OIL

NATURAL GAS SULFURHEAVY OIL NATURAL GAS

LIQUIDS

RPS


Net Present Value of Future Net Revenue



RESERVE CATEGORY

0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

COLOMBIA

PROVED

Developed Producing 1,761.49 1,572.28 1,420.21 1,296.02 1,193.12 1,187.14 1,072.77 980.28 904.33 841.09 Developed Non Producing 420.62 361.90 314.85 276.57 245.01 292.97 255.52 225.14 200.14 179.30 Undeveloped 5,057.73 4,207.46 3,546.49 3,024.36 2,605.87 3,531.39 2,984.86 2,555.13 2,211.94 1,933.98

TOTAL PROVED 7,239.84 6,141.64 5,281.55 4,596.95 4,044.00 5,011.50 4,313.15 3,760.55 3,316.41 2,954.37

PROBABLE 796.76 632.45 508.48 413.53 339.78 555.60 449.56 368.74 306.24 257.25 TOTAL PROVED + PROBABLE 8,036.60 6,774.09 5,790.04 5,010.48 4,383.78 5,567.10 4,762.71 4,129.29 3,622.65 3,211.62

POSSIBLE 670.63 524.34 415.52 333.28 270.22 455.25 359.96 288.34 233.69 191.38 TOTAL PVD + PROB + POSS 8,707.22 7,298.43 6,205.56 5,343.76 4,654.00 6,022.35 5,122.67 4,417.63 3,856.34 3,403.00

UNITED STATES

PROVED

Developed Producing - - - - - - - - - - Developed Non Producing - - - - - - - - - - Undeveloped - - - - - - - - - -

TOTAL PROVED - - - - - - - - - -

PROBABLE - - - - - - - - - - TOTAL PROVED + PROBABLE - - - - - - - - - -

NET PRESENT VALUE OF FUTURE NET REVENUE (US$ millions)

BEFORE INCOME TAXES AFTER INCOME TAXES

RPS


Total Future Net Revenue (Undiscounted)as of December 31, 2009

Forecast Prices and Costs Forecast Prices ands Costs

RESERVE CATEGORY REVENUE ROYALTIES OTHER

REVENUE

OPERATING

COSTS

DEVELOPMENT

COSTS

ABANDON-

MENT COSTS

FUTURE NET

REVENUE

BEFORE

INCOME TAXES

INCOME TAXES FUTURE NET

REVENUE

AFTER INCOME

TAXES(MM$US) (MM$US) (MM$US) (MM$US) (MM$US) (MM$US) (MM$US) (MM$US) (MM$US)

COLOMBIA

PROVED

Developed Producing 3,338 611 - 956 - 10 1,761 575 1,186 Developed Non Producing 929 170 - 267 68 3 421 128 293 Undeveloped 10,335 1,891 - 2,619 758 8 5,058 1,526 3,532

TOTAL PROVED 14,602 2,672 - 3,842 826 21 7,241 2,229 5,012

PROBABLE 1,594 292 - 394 108 4 797 241 556 TOTAL PROVED + PROBABLE 16,196 2,964 - 4,236 934 25 8,037 2,470 5,567

POSSIBLE 1,366 250 - 336 109 - 671 215 456 TOTAL PVD + PROB + POSS 17,562 3,214 - 4,572 1,043 25 8,708 2,685 6,023

UNITED STATES

PROVED

Developed Producing - - - - - - - - - Developed Non Producing - - - - - - - - - Undeveloped - - - - - - - - -

TOTAL PROVED - - - - - - - - -

PROBABLE - - - - - - - - - TOTAL PROVED + PROBABLE - - - - - - - - -

RPS


Future Net Revenue by Production Group as of December 31, 2009


LIGHT AND

MEDIUM OIL (including solution gas and

other by-products)

HEAVY OIL (including solution gas and

other by-products)

NATURAL GAS (including by-products but

excluding solution gas from

oil wells)

RESERVE CATEGORY ($US Millions) ($US Millions) ($US Millions)

COLOMBIA

PROVED

Developed Producing - 1,420 - Developed Non Producing - 315 - Undeveloped - 3,546 -

TOTAL PROVED - 5,282 -

PROBABLE - 508 - TOTAL PROVED + PROBABLE - 5,790 -

POSSIBLE 416 TOTAL PVD + PROB + POSS 6,206 -

UNITED STATES

PROVED

Developed Producing - - - Developed Non Producing - - - Undeveloped - - -

TOTAL PROVED - - -

PROBABLE - - - TOTAL PROVED + PROBABLE - - -

FUTURE NET REVENUE BY PRODUCTION GROUP

BEFORE INCOME TAXES

Net present value discounted at 10% per year

RPS


Future Net Revenue (Unit Value Basis) by Production Group


FORECAST PRICES AND COSTS

LIGHT AND

MEDIUM OIL (including solution gas and

other by-products)

HEAVY OIL (including solution gas and

other by-products)

NATURAL GAS (including by-products but

excluding solution gas from

oil wells)

RESERVE CATEGORY ($US/bbl) ($US/bbl) ($US/Mcf)

COLOMBIA

PROVED

Developed Producing - 42.65 - Developed Non Producing - 34.44 - Undeveloped - 35.31 -

TOTAL PROVED - 36.96 -

PROBABLE - 33.47 - TOTAL PROVED + PROBABLE - 36.63 -

POSSIBLE 32.18 TOTAL PVD + PROB + POSS 36.29

UNITED STATES

PROVED

Developed Producing - - - Developed Non Producing - - - Undeveloped - - -

TOTAL PROVED - - -

PROBABLE - - - TOTAL PROVED + PROBABLE - - -

FUTURE NET REVENUE BY PRODUCTION GROUP

BEFORE INCOME TAXES

Net present value discounted at 10% per year

RPS


RPS WTI

Forecast

Forecasted

Price

After Quality

Adjustment

Net Selling

Price

After Tariff and

blendingUS$/bbl US$/bbl US$/bbl %/annum %/annum %/annum %/annum

2010 79.16 69.49 68.01 2.0% 2.0% 2.0% 2.0% 0.0%2011 84.24 74.57 72.42 2.0% 2.0% 2.0% 2.0% 0.0%2012 87.28 77.61 75.14 2.0% 2.0% 2.0% 2.0% 2.0%2013 89.31 79.64 76.89 2.0% 2.0% 2.0% 2.0% 2.0%2014 92.01 82.34 79.22 2.0% 2.0% 2.0% 2.0% 2.0%2015 93.85 84.18 80.80 2.0% 2.0% 2.0% 2.0% 2.0%2016 95.72 86.05 82.41 2.0% 2.0% 2.0% 2.0% 2.0%

%/annum

Summary of Pricing and Inflation Rate AssumptionsForecast Prices and Costs


Infrastructure

Inflation Rate

Drilling

Inflation RateYear

Oil Benchmarks

Reference

Colombia

Inflation Rate

Reference

USA

Inflation Rate

Operating Cost

Inflation Rate

RPS


TOTAL PROVED +

PROBABLE

TOTAL PVD + PROB

+ POSS

COLOMBIA

2010 329.0 349.1 364.5 2011 204.6 213.5 226.4 2012 116.3 125.6 147.5 2013 84.8 129.4 133.8 2014 64.2 85.4 117.2 2015 27.0 30.2 52.6 2016 0.9 1.4 1.8

Total all years 826.7 934.5 1,043.8

UNITED STATES

20102011201220132014 - - 2015 - - 2016 - -

Total all years - -

TOTAL PROVED

ESTIMATED DEVELOPMENT COSTS ($US millions)

Summary of Estimated Development Costs

Attributable To Reserves

Using forecast Prices and Costs

RPS


Summary of Production Estimates Proved + Probable + Possible Reserves Case

For Year 2010

LIGHT AND

MEDIUM OIL

Heavy Oil NATURAL GAS NATURAL GAS

LIQUIDS

RESERVE CATEGORY (Mbbl) (Mbbl) (MMscf) (Mbbl)

COLOMBIA

Total Company - - - Significant Fields

(1)

Rubiales - 24,158 - - - - - - - - - - - - - -

UNITED STATES

Total Company - - - Significant Fields

(1)

- - -

(1): Significant fields represent greater than 20% of Company total (by country) of production in first year of forecast

Estimated Production - 2010

RPS

Table 7.1Cumulative Field Production, Reserves and Ultimate Recovery

# Well Name Concession Status Reserve Basis

Cumulative Production

to YE 2009

ProvedReserves

12/31/2009Ultimate

Recovery

0MBO MBO MBO

1 RB-001 Rub Shut-In Actual Cum 20 0 202 RB-002 Rub Shut-In Actual Cum 0 0 03 RB-003 Rub Shut-In Actual Cum 0 0 04 RB-004 Rub Active DCA 923 461 13845 RB-005 Rub Abandoned Actual Cum 8 0 86 RB-006 Piriri Shut-In Actual Cum 141 0 1417 RB-007 Rub Shut-In Actual Cum 0 0 08 RB-008 Piriri Abandoned Actual Cum 0 0 09 RB-009 Piriri Abandoned Actual Cum 0 0 010 RB-010 Rub Active DCA 391 304 69511 RB-011 Rub Shut-In Well Analogy 49 91 14012 RB-012 Piriri Shut-In DCA 661 200 86113 RB-013 Rub Abandoned Actual Cum 7 0 714 RB-014 Rub Abandoned Actual Cum 0 0 015 RB-015 Piriri Abandoned Actual Cum 19 0 1916 RB-016 Rub Shut-In DCA 1371 365 173617 RB-017 Piriri Shut-In DCA 507 288 79518 RB-018 Rub Shut-In Actual Cum 5 0 519 RB-019 Piriri Active DCA 1508 42 155020 RB-021 Rub Shut-In Actual Cum 0 0 021 RB-022 Rub Shut-In Actual Cum 0 0 022 RB-023 Rub Shut-In DCA 433 244 67723 RB-024 Rub Shut-In DCA 835 227 106224 RB-025 Rub Active DCA 391 304 69525 RB-026 Rub Shut-In DCA 109 92 20126 RB-027 Rub Active DCA 372 206 57827 RB-028 Rub Shut-In DCA 38 41 7928 RB-029 Rub Shut-In Actual Cum 0 0 029 RB-030 Piriri Active DCA 349 115 46430 RB-031 Rub Active DCA 675 326 100131 RB-033 Rub Active Actual Cum 758 22 78132 RB-034 Rub Shut-In DCA 102 46 14833 RB-036 Rub Shut-In DCA 41 37 7834 RB-037 Rub Active DCA 513.5 185 69835 RB-038 Piriri Active DCA 559 67 62636 RB-039 Rub Shut-In DCA 421 91 51337 RB-040 Rub Active DCA 301 307 60838 RB-041 Piriri Active DCA 547 170 71739 RB-042H Piriri Active DCA 1620 1170 279040 RB-043D Piriri Active DCA 441 342 78341 RB-044D Piriri Active DCA 215 281 49742 RB-045H Piriri Active DCA 1554 968 252143 RB-046 Piriri Shut-In Actual Cum 0 0 044 RB-047 Rub Shut-In DCA 400 119 51945 RB-048HST Rub Active DCA 1793 441 2233

RPS 1




to YE 2009

ProvedReserves

12/31/2009Ultimate

Recovery46 RB-049H Rub Shut-In DCA 209 167 37647 RB-050HST Rub Shut-In DCA 130 104 23348 RB-051 Rub Shut-In DCA 47 138 18549 RB-052 Rub Shut-In Well Analogy 23 480 50350 RB-053 Rub Shut-In Well Analogy 15 229 24451 RB-054H Rub Active DCA 1155 446 160152 RB-055H Rub Shut-In DCA 1055 370 142453 RB-056H Rub Shut-In DCA 356 159 51554 RB-057H Rub Active DCA 609 348 95755 RB-058H Piriri Active DCA 1558 1025 258456 RB-059H Piriri Active DCA 522 405 92857 RB-060H Piriri Active DCA 439 301 74058 RB-061H Piriri Active DCA 1087 623 171059 RB-062H Piriri Active DCA 950 923 187360 RB-063H Piriri Active DCA 1561 591 215161 RB-064H Piriri Active DCA 662 283 94662 RB-065H Rub Active DCA 1077 352 142963 RB-066H Rub Active DCA 392 713 110564 RB-067H Rub Active DCA 1307 1191 249865 RB-068H Rub Active DCA 928 681 161066 RB-069H Piriri Active DCA 923 1341 226467 RB-070H Piriri Active DCA 535 506 104168 RB-071H Piriri Active DCA 626 648 127469 RB-072H Piriri Active DCA 234 183 41770 RB-073H Piriri Active DCA 817 1055 187271 RB-074H Rub Active DCA 793 829 162272 RB-075H Rub Active DCA 642 271 91373 RB-076H Rub Shut-In Actual Cum 17 0 1774 RB-077H Rub Active DCA 427 104 53175 RB-078H Rub Active DCA 782 977 175976 RB-079 Piriri Active DCA 136 212 34877 RB-080 Piriri Shut-In Well Analogy 3 217 22078 RB-081 Piriri Shut-In Well Analogy 12 148 16079 RB-082 Rub Shut-In Well Analogy 0 242 24280 RB-084 Piriri Shut-In Well Analogy 0 166 16781 RB-085 Rub Shut-In Well Analogy 0 442 44282 RB-087 Rub Shut-In Actual Cum 0 0 083 RB-089H Rub Shut-In DCA 151 229 38084 RB-090 Piriri Active DCA 114 56 17085 RB-091 Rub Active DCA 72 0 7286 RB-092 Piriri Shut-In DCA 14 84 9987 RB-093H Piriri Active DCA 46 1027 107388 RB-094H Piriri Active DCA 380 915 129589 RB-095H Piriri Active DCA 75 493 56790 RB-097H Rub Shut-In Well Analogy 21 1097 111891 RB-098H Rub Shut-In Well Analogy 27 1014 104192 RB-099H Piriri Shut-In DCA 248 134 383

RPS 2




to YE 2009

ProvedReserves

12/31/2009Ultimate

Recovery93 RB-100H Piriri Active DCA 826 789 161594 RB-101H Piriri Active DCA 122 226 34895 RB-102H Piriri Shut-In Well Analogy 0 1227 122796 RB-104 Piriri Active DCA 137 212 34897 RB-105HST Piriri Active DCA 396 317 71398 RB-106H Piriri Active DCA 500 874 137499 RB-107H Piriri Active DCA 199 560 759100 RB-108H Piriri Active DCA 672 417 1088101 RB-109H Piriri Active DCA 317 106 422102 RB-110H Piriri Active Well Analogy 146 815 962103 RB-111 Piriri Shut-In Well Analogy 3 181 184104 RB-112 Rub Shut-In Well Analogy 0 166 166105 RB-113 Rub Shut-In DCA 38 88 126106 RB-114 Rub Shut-In DCA 0 546 547107 RB-115 Piriri Shut-In Well Analogy 2 295 298108 RB-116 Piriri Shut-In Well Analogy 0 345 345109 RB-117 Rub Active DCA 92 293 385110 RB-118 Rub Active DCA 1 263 265111 RB-119 Rub Active DCA 46 61 108112 RB-120 Rub Abandoned Actual Cum 0 0 0113 RB-121 Rub Shut-In Actual Cum 0 0 0114 RB-122 Rub Shut-In Well Analogy 0 268 268115 RB-123HST Rub Active Well Analogy 16 1992 2008116 RB-124H Rub Active Actual Cum 218 0 218117 RB-125H Rub Active DCA 516 1080 1596118 RB-126ST Rub Shut-In Well Analogy 6 282 288119 RB-127 Rub Shut-In DCA 18 58 76120 RB-128 Rub Active DCA 69 162 231121 RB-129 Rub Shut-In DCA 6 185 191122 RB-130 Rub Shut-In Actual Cum 0 0 0123 RB-131H Rub Active DCA 742 931 1673124 RB-132HST Rub Active Well Analogy 56 1493 1550125 RB-133H Rub Shut-In Well Analogy 12 1135 1147126 RB-134H Rub Shut-In Well Analogy 26 1343 1369127 RB-135H Piriri Active Well Analogy 232 996 1228128 RB-136H Piriri Active DCA 324 386 710129 RB-137H Piriri Shut-In Well Analogy 0 1003 1003130 RB-138H Piriri Active DCA 448 546 994131 RB-139 Piriri Active Well Analogy 112 202 314132 RB-140 Piriri Active Well Analogy 71 119 190133 RB-141 Piriri Active Well Analogy 81 385 466134 RB-142 Piriri Abandoned Actual Cum 0 0 0135 RB-143 Rub Shut-In Well Analogy 4 339 343136 RB-144 Rub Shut-In Well Analogy 7 531 537137 RB-145 Rub Active DCA 103 213 315138 RB-147 Rub Shut-In Well Analogy 7 239 246139 RB-148 Piriri Shut-In Well Analogy 0 139 139

RPS 3




to YE 2009

ProvedReserves

12/31/2009Ultimate

Recovery140 RB-149 Rub Active Well Analogy 8 413 421141 RB-150 Rub Shut-In Well Analogy 5 204 209142 RB-153H Rub Shut-In Well Analogy 29 998 1027143 RB-154H Piriri Active DCA 355 208 563144 RB-155 Rub Shut-In Well Analogy 14 239 253145 RB-156H Rub Active DCA 709 1505 2214146 RB-157H Rub Active DCA 646 1379 2025147 RB-158 Rub Active DCA 165 251 415148 RB-159 Piriri Active Well Analogy 7 263 271149 RB-160 Rub Shut-In Well Analogy 0 214 215150 RB-161 Piriri Active Well Analogy 19 178 197151 RB-162 Piriri Shut-In Well Analogy 8 45 53152 RB-163 Rub Shut-In Well Analogy 0 508 508153 RB-164 Rub Shut-In Well Analogy 0 312 312154 RB-165 Rub Active DCA 90 291 381155 RB-168H Piriri Active Well Analogy 133 913 1046156 RB-169H Piriri Active Well Analogy 99 502 601157 RB-170H Piriri Active Well Analogy 135 692 827158 RB-171H Rub Active Well Analogy 197 613 809159 RB-172H Rub Active Well Analogy 46 1145 1191160 RB-173H Rub Active Well Analogy 397 1032 1430161 RB-174H Rub Active Well Analogy 445 867 1312162 RB-175H Rub Active Well Analogy 517 1209 1726163 RB-176H Rub Active Well Analogy 418 1007 1425164 RB-177H Rub Active Well Analogy 10 1493 1503165 RB-178HST Rub Active Well Analogy 77 988 1064166 RB-179HST Rub Active Well Analogy 248 1172 1419167 RB-180HST Rub Active Well Analogy 35 1677 1712168 RB-181H Piriri Active DCA 293 294 587169 RB-182H Piriri Active DCA 139 58 197170 RB-183H Rub Active Well Analogy 190 795 985171 RB-184H Rub Active Well Analogy 196 1058 1254172 RB-185H Rub Active Well Analogy 234 1460 1693173 RB-187H Rub Active Well Analogy 233 979 1212174 RB-188H Rub Active Well Analogy 243 826 1069175 RB-189H Piriri Active Well Analogy 354 768 1122176 RB-190H Piriri Active Well Analogy 117 965 1082177 RB-191H Rub Active Well Analogy 124 630 753178 RB-192H Rub Active Well Analogy 62 987 1049179 RB-193H Rub Shut-In Actual Cum 29 0 29180 RB-194H Rub Active Well Analogy 8 932 941181 RB-195H Rub Active Well Analogy 28 639 666182 RB-196H Rub Active Well Analogy 22 867 889183 RB-197H Piriri Active Well Analogy 21 778 800184 RB-198 Piriri Active Well Analogy 10 381 392185 RB-199 Rub Active Well Analogy 13 333 346186 RB-200H Piriri Active Well Analogy 176 1413 1589

RPS 4




to YE 2009

ProvedReserves

12/31/2009Ultimate

Recovery187 RB-201H Piriri Active Well Analogy 174 1078 1252188 RB-202H Piriri Active Well Analogy 235 1108 1343189 RB-203H Piriri Active Well Analogy 273 519 792190 RB-204H Rub Active Well Analogy 144 754 898191 RB-205H Rub Active Well Analogy 517 826 1343192 RB-206H Piriri Active Well Analogy 119 554 673193 RB-207H Piriri Active Well Analogy 146 944 1090194 RB-208H Piriri Active Well Analogy 68 613 681195 RB-209H Piriri Active Well Analogy 103 63 165196 RB-210H Piriri Active Well Analogy 230 554 784197 RB-212H Rub Active Well Analogy 40 1811 1852198 RB-214H Rub Active Well Analogy 37 1126 1163199 RB-215H Rub Active Well Analogy 58 988 1045200 RB-216H Rub Active Well Analogy 44 1563 1607201 RB-217 Rub Active Well Analogy 0 136 136202 RB-218 Rub Active Well Analogy 76 458 535203 RB-219 Rub Active Well Analogy 1 264 265204 RB-220 Rub Active Well Analogy 21 331 353205 RB-221 Rub Active Well Analogy 2 214 215206 RB-222 Rub Active Well Analogy 8 129 137207 RB-223H Rub Active Well Analogy 187 742 929208 RB-224 Rub Shut-In Actual Cum 0 0 0209 RB-232H Rub Active Well Analogy 61 427 488210 RB-233 Piriri Active Well Analogy 3 191 194211 RB-234H Rub Active Well Analogy 21 1531 1552212 RB-235H Rub Active Well Analogy 69 742 811213 RB-236H Piriri Active Well Analogy 43 703 746214 RB-237H Piriri Active Well Analogy 5 766 771215 RB-238H Piriri Active Well Analogy 49 512 561216 RB-239H Piriri Active Well Analogy 94 840 934217 RB-240H Piriri Active Well Analogy 45 1134 1179218 RB-241 Piriri Active Well Analogy 3 310 313219 RB-242 Rub Active Well Analogy 3 245 248220 RB-251 Rub Active Well Analogy 1 392 393221 RB-254HST Rub Active Well Analogy 3 713 716222 RB-256H Rub Active Well Analogy 13 778 791223 RB-257H Rub Active Well Analogy 6 778 784224 RB-366 Rub Active Well Analogy 3 245 247

RPS 5

Table 7.2

Calculation of Recovery Factor and Fieldwide Potential

Client: META Petroleum Date: 02/04/10

Field: Rubiales

Reservoir:Areniscas Basales OIIP determination total field

OIL RESERVES -- CALCULATION SHEET

At 15.025 psia Pressure Base

RESERVOIR PARAMETERS: I) NaCl (ppm) = 950

I) Gas Gravity = 0.7254

I) Oil Gvty (°API) .............. 12.5

Bubble Point Pressure, Pbp ... 75 I) Subsea Depth, ft 2,960

I) Gas Saturation at Pa, Sga .... 0 %

I) Average Porosity ............ 26.4 %

I) Average Perm., k (md)......... 4000

I) Water Saturation, Sw ......... 27.5 %

Residual Oil Sat, Sor (C & B) 55.2 %

I) Drive Mechanism (W, S, or L) . w I) Prod. acres = 135,361

(Water,Sol gas,Liquid exp) I) Avg Net Pay, ft 21.64

I) Sweep Efficiency, SE ......... 85 % Vb,Res Vol(acft) 2929448

***** ********* ******** ******** ******* |***** ******* ********* *********** ********

Initial Conditions | Abandonment Conditions

***** ********* ******** ******** ******* |***** ******* ********* *********** ********

I) Temp Grad, °/100' ..... 2.41 | I) Temp Grad, °/100' ..... 2.41

Ti = 145 °F, 605 °R | Ta = 145 °F, 605 °R

I) Pressure Grad, psi/ft . 1170 |

[If calc by diff. method input new grad.w grad. or pressure in grad. slot.]

Pi = 1,155 psig, 1,170 psia |I)Pa= 1,155 psig, 1,170 psia

|

I) Sol. GOR, Rsi (ft3/Bbl) 5 | Sol. GOR,Rsa (ft3/Bbl) 5

Boi, (RB/STB) ......... 1.024 | Boa, (RB/STB) ........ 1.024

Oil viscosity, Uoi (cp) 400 | Oil viscosity, Uoa (cp) 400

Wtr viscosity, Uwi (cp) 0.446 | Wtr viscosity, Uwa (cp) 0.446

***** ********* ******** ******** ******* |***** ******* ********* *********** ********

1. OIP/acft =(7758)( 0.264)(1- 0.275)/(1.024) = 1,450 STB/AC-FT

2. Oil In-Place = ( 2929448)(1450)= 4247700000 STB

WATER DRIVE (9) RF = (1-Sw-Sor)(SE)/(1-Sw) = 20.3 %

(10) Recovery/Ac-Ft = 1450 X 0.203 = 294 STB/Acft

(11) Recoverable Oil = 294 X 2929448 = 861,258 MSTB

12. Recoverable Dissolved Gas =

[RN*Rsi+(N-RN)(Rsi-Rsa)-Sga*Por*Vb*Bga]/10^6 = 4.3 MMCF

STOOIP

Acres 135,361 from Petrel Tech recovery 861.3

MMbbl 4247.7 from Petrel Recovery to depl 838.0

Ftg 21.64 calculated % rec with Meta 97.3%

b/af 1,450 calculated above development plan including resources

and field depletion

RPS

Table 7.3

Estimated Ultimate Recovery vs Net Pay by Well Type

Vertical

Well

Estimated

Ultimate

Recovery

Net Pay From

Petrel

All zones in well

Horizontal

Well

Estimated

Ultimate

Recovery

Net Pay From

Petrel

All zones in well

Mbbls Ft Mbbls Ft

RB-004 1408 12 RB-042H 3082 57

RB-010 695 9 RB-045H 2521 47

RB-016* 1371 30 RB-048HST 2031 61

RB-019* 1484 25 RB-054H 1414 44

RB-023* 433 30 RB-057H 827 50

RB-024* 835 25 RB-058H 2593 62

RB-025 2564 39 RB-059H 928 34

RB-027 578 30 RB-060H 740 42

RB-030* 347 13 RB-061H 1710 47

RB-031 1001 24 RB-062H 1907 50

RB-033* 781 23 RB-063H 2151 44

RB-037 698 35 RB-065H 1334 62

RB-038 626 26 RB-066H 915 68

RB-039* 496 27 RB-067H 2056 60

RB-040 608 22 RB-068H 1436 55

RB-041 717 26 RB-069H 2493 59

RB-043D 822 31 RB-070H 1041 32

RB-044D 500 28 RB-071H 1234 57

RB-047 519 18 RB-073H 1674 52

RB-051RD* 115 28 RB-074H 1496 63

RB-079 348 24 RB-075H 693 61

RB-081* 126 25 RB-077H 447 64

RB-090 133 16 RB-078H 1222 62

RB-091* 179 29 RB-094H 960 34

RB-104 301 17 RB-100H 1621 61

RB-113* 67 12 RB-105HST 577 36

RB-117 371 30 RB-106H 941 48

RB-119 88 28 RB-107H 434 47

RB-128 213 32 RB-108H 975 40

RB-158 415 54 RB-109H 338 40

RB-165 381 30 RB-125H 1477 54

Average 620 26 RB-131H 1491 60

RB-136H 592 54

RB-138H 860 42

RB-154H 560 48

*Shut-in Wells as of December 2009 RB-156H 2214 44

RB-157H 2025 32

RB-181H 477 46

RB-182H 195 32

Average 1325 50

0

10

20

30

40

50

60

70

80

0 1000 2000 3000 4000

Ne

t P

ay (

ft)

Estimated Ultimate Recovery (Mbbls)

Horizontal Wells

0

10

20

30

40

50

60

0 1000 2000 3000

Ne

t P

ay (

ft)

Estimated Ultimate Recovery (Mbbls)

Vertical Wells

RPS

Table 7.4

Estimated Ultimate Recovery vs STOOIP per cell

Vertical

Well

Estimated

Ultimate

Recovery

STOOIP

per Cell

Horizontal

Well

Estimated

Ultimate

Recovery

STOOIP

per Cell

MBbls Bbls MBbls Bbls

RB-038 626 44,000 RB-042H 3,082 38,000

RB-041 717 33,000 RB-045H 2,521 22,000

RB-043D 822 37,000 RB-058H 2,593 42,000

RB-044D 500 37,000 RB-059H 928 8,000

RB-079 348 30,000 RB-060H 740 22,000

RB-090 133 24,000 RB-061H 1,710 31,000

RB-104 301 48,000 RB-062H 1,907 25,000

RB-010 695 16,000 RB-063H 2,151 28,000

RB-027 578 63,000 RB-069H 2,493 44,000

RB-031 1,001 52,000 RB-070H 1,041 25,000

RB-037 698 54,000 RB-071H 1,234 36,000

RB-040 608 32,000 RB-073H 1,674 36,000

RB-047 519 52,000 RB-094H 960 18,000

RB-117 371 20,000 RB-100H 1,621 40,000

RB-128 213 26,000 RB-105HST 577 18,000

RB-158 415 35,000 RB-106H 941 20,000

RB-165 381 33,000 RB-107H 434 36,000

Cum 8,928 636,000 RB-108H 975 23,000

Average 14.04 RB-109H 338 25,000

RB-136H 592 42,000

RB-138H 860 22,000

RB-154H 560 23,000

RB-181H 477 18,000

RB-182H 195 13,000

RB-048HST 2,233 42,000

RB-054H 1,601 14,000

RB-057H 957 26,000

RB-065H 1,429 33,000

RB-066H 1,105 52,000

RB-067H 2,498 43,000

RB-068H 1,610 45,000

RB-074H 1,622 44,000

RB-075H 913 51,000

RB-077H 447 20,000

RB-078H 1,222 48,000

RB-125H 1,477 32,000

RB-131H 1,491 50,000

RB-156H 2,214 20,000

RB-157H 2,025 27,000

Cum 53,448 1,202,000

Average 44.47

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

0 500 1,000 1,500

OO

IP (

bb

ls p

er

cell)

EUR (Mbbls)

Vertical Wells

0

10,000

20,000

30,000

40,000

50,000

60,000

0 1,000 2,000 3,000 4,000

OO

IP (

bb

ls p

er

cell)

EUR (Mbbls)

Horizontal Wells

RPS

Table 7.5

Summary of Reserves and Prodution to June 30, 2016

All volumes in MBOReserves

@ 12/31/09 2010 2011 2012 2013 2014 2015 2016Rubiales

ProvedDeveloped - Producing 54,072 17,552 11,771 8,458 6,299 4,709 3,576 1,707Developed - Non-Producing 21,210 1,879 6,329 5,163 3,322 2,240 1,571 705Undeveloped 224,713 14,725 35,825 41,666 41,112 39,476 36,538 15,371

Total Proved (1P) 299,995 34,156 53,925 55,286 50,734 46,425 41,685 17,783

ProbableUndeveloped 39,903 239 1,269 1,060 8,927 13,394 10,621 4,394

Total Probable 39,903 239 1,269 1,060 8,927 13,394 10,621 4,394

Total 2P 339,898 34,395 55,194 56,346 59,661 59,819 52,306 22,177

PossibleUndeveloped 28,517 520 1,363 1,703 1,267 6,798 11,866 5,000

Total Possible 28,517 520 1,363 1,703 1,267 6,798 11,866 5,000

Total 3P 368,415 34,915 56,557 58,049 60,927 66,617 64,173 27,177

PiririProved

Developed - Producing 40,000 12,453 8,873 6,465 4,687 3,508 2,742 1,272Developed - Non-Producing 5,884 1,021 1,663 1,129 812 595 443 220Undeveloped 71,321 6,384 14,486 16,196 12,688 9,986 8,085 3,496

Total Proved (1P) 117,204 19,858 25,022 23,790 18,187 14,089 11,271 4,987

ProbableUndeveloped 6,061 438 672 1,222 1,403 1,106 863 357

Total Probable 6,061 438 672 1,222 1,403 1,106 863 357

Total 2P 123,266 20,296 25,694 25,012 19,590 15,195 12,134 5,344

PossibleUndeveloped 9,471 87 210 1,389 2,755 2,292 1,906 831

Total Possible 9,471 87 210 1,389 2,755 2,292 1,906 831

Total 3P 132,737 20,383 25,905 26,402 22,345 17,487 14,041 6,175

Total FieldProved

Developed - Producing 94,071 30,005 20,644 14,923 10,986 8,217 6,318 2,978Developed - Non-Producing 27,094 2,900 7,992 6,292 4,134 2,835 2,015 926Undeveloped 296,034 21,109 50,311 57,861 53,800 49,462 44,623 18,867

Total Proved (1P) 417,199 54,014 78,947 79,076 68,921 60,514 52,956 22,771

ProbableUndeveloped 45,964 677 1,941 2,282 10,329 14,499 11,484 4,750

Total Probable 45,964 677 1,941 2,282 10,329 14,499 11,484 4,750

Total 2P 463,164 54,691 80,888 81,359 79,250 75,013 64,441 27,521

PossibleUndeveloped 37,988 607 1,573 3,092 4,022 9,090 13,773 5,831

Total Possible 37,988 607 1,573 3,092 4,022 9,090 13,773 5,831

Total 3P 501,152 55,298 82,461 84,451 83,272 84,103 78,213 33,352

RPS

Table 9.1

Crude Oil Production, Fuel Consumption, Naptha Purchases and Sales

for the 3P Reserves Case

Crude Oil Fuel Naptha Net Sales

Production Consumption Purchases Volumes

Mbbls Mbbls Mbbls Mbbls

2010 55,298 456 7,363 62,2052011 82,461 639 9,257 91,0792012 84,451 785 6,717 90,3832013 83,272 922 6,918 89,2682014 84,103 1,022 7,097 90,1782015 78,213 958 6,429 83,6842016 33,352 437 2,150 35,065

Totals 501,150 5,219 45,931 541,862

RPS

Table 9.2

WTI Crude Oil and Rubiales Crude Oil/Naptha Blend Price Forecasts

RPS WTI Rubiales

Crude Oil Crude Oil / Naptha Blend

$/bbl $/bbl

2010 79.16 68.012011 84.24 72.422012 87.28 75.142013 89.31 76.892014 92.01 79.222015 93.85 80.802016 95.72 82.41

RPS

Table 9.3

Field Investment Summary


Drilling Drilling Well Facilities and

Production Disposal Re-Completion Infrastructure Total

$MM $MM $MM $MM $MM

2010 238 18 14 576 8452011 189 21 1 313 5242012 147 18 0 161 3262013 144 17 0 144 3052014 142 15 0 108 2652015 72 8 0 39 1192016 0 0 0 4 4

Totals 932 97 15 1,345 2,388

RPS

Table 9.4

Field Expense Summary


Fixed Tariff & Blending Total

Operating Purchase Purchased Purchase for Crude Oil Well Field

Costs Cost Volume Cost and Naptha Abandonments Expenses

$MM $/bbl MMbbls $MM $MM $MM $MM

2010 77.4 74.16 7.36 546.1 532.8 2.1 1,158.42011 81.3 79.24 9.26 733.5 746.8 3.0 1,564.62012 85.4 82.28 6.72 552.7 603.2 3.6 1,244.92013 85.4 84.31 6.92 583.3 614.0 4.2 1,286.92014 76.8 87.01 7.10 617.5 623.7 4.5 1,322.52015 69.1 88.85 6.43 571.2 623.9 4.8 1,269.02016 31.1 90.72 2.15 195.1 297.2 2.4 525.8

Totals 506.5 45.94 3,799.4 4,041.6 24.6 8,372.1

Variable costs that are determined by well count and crude oil volume are not included above

Naptha for Blending with Crude Oil

RPS

Appendix

Appendix 1

Recoverable Resources Classes and Sub-Classes

Class/Sub-Class Definition Guidelines

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.

To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame.

A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. 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.

To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

On Production The development project is

currently producing and selling petroleum to market.

The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project.

Approved for Development

All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way.

At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells.

Sandy

Text Box

APPENDIX 1

PartneyD

Stamp

PartneyD

Typewritten Text

Class/Sub-Class Definition Guidelines Justified for Development

Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time.

Contingent Resources

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized 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 economic status.

Development Pending

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status.

The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.

PartneyD

Stamp

Class/Sub-Class Definition Guidelines Development Unclarified or on Hold

A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.

The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a re-classification of the project to “Not Viable” status.

The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies.

Development Not Viable

A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.

The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions.

The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future.

Prospective Resources

Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration.

Prospect A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.

Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.

Lead A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios.

Play A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

PartneyD

Stamp

Reserves Status Definitions and Guidelines

Status Definition Guidelines

Developed Reserves

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 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 Reserves

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

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 yet 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 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

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

(1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

PartneyD

Stamp

Reserves Category Definitions and Guidelines

Category Definition Guidelines

Proved 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 and 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. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (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: • The locations are in undrilled areas of the reservoir that can be

judged with reasonable certainty to be commercially productive.

• Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations.

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.

Probable Reserves

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.

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 (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.

Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria.

Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

PartneyD

Stamp

Category Definition Guidelines

Possible Reserves

Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves.

The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project.

Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

Probable and Possible Reserves

(See above for separate criteria for Probable Reserves and Possible Reserves.)

The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.

PartneyD

Stamp

Appendix 2

RPS Page 1 of 16 Appendix 2

Net

Gas

(MMcf)

As Of Date : 01/01/2010

Discount Rate (%) : 10.00

Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

BFIT ECONOMIC SUMMARY PROJECTION 02/03/2010 10:53:50AM Date :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

Metapetroleum - Rubiales Field

All Cases

GRAND TOTAL CASE

Total

68.01 0.00 62,205.49 0.00 22,159.27 0.00 1,507,051.94 0.00 0.00 2010

72.42 0.00 91,076.63 0.00 32,041.82 0.00 2,320,468.69 0.00 0.00 2011

75.14 0.00 90,630.02 0.00 31,872.31 0.00 2,394,885.33 0.00 0.00 2012

76.89 0.00 89,270.61 0.00 31,070.45 0.00 2,389,007.22 0.00 0.00 2013

79.22 0.00 90,179.09 0.00 30,948.77 0.00 2,451,761.18 0.00 0.00 2014

80.80 0.00 83,686.11 0.00 28,530.38 0.00 2,305,254.68 0.00 0.00 2015

82.41 0.00 34,821.17 0.00 11,889.27 0.00 979,794.79 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

10.00 2010 0.00 0.00 364,476.68 600,117.69 0.00 542,457.56 0.00 0.00 500,514.96

10.00 2011 0.00 0.00 226,394.10 828,390.22 0.00 1,265,684.37 0.00 0.00 1,588,472.79

10.00 2012 0.00 0.00 147,476.70 713,441.67 0.00 1,533,966.96 0.00 0.00 2,791,981.80

10.00 2013 0.00 0.00 133,754.66 748,190.86 0.00 1,507,061.70 0.00 0.00 3,867,179.79

10.00 2014 0.00 0.00 117,249.05 779,019.75 0.00 1,555,492.39 0.00 0.00 4,876,766.13

10.00 2015 0.00 0.00 52,631.53 764,828.82 0.00 1,487,794.33 0.00 0.00 5,756,392.06

10.00 2016 0.00 0.00 1,801.86 163,225.91 0.00 814,767.03 0.00 0.00 6,205,556.46

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 1,043,784.58 4,597,214.92 0.00 8,707,224.34 0.00

0.00 0.00

0.00

0.00

6,205,556.46

0.00 0.00

76.11 0.00

0.00

541,869.11 0.00

0.00 0.00 0.00 0.00 0.00 0.00

541,869.11 0.00 188,512.27 0.00 14,348,223.84 0.00 0.00

Disc. Initial Invest. (M$) :

ROInvestment (disc/undisc) :

Years to Payout :

16.86 / 19.54

1.09

Internal ROR (%) :

Present Worth Profile (M$)

0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

8,707,224.34

7,298,434.39 6,205,556.46

15.00% : 20.00% :

5,343,756.64 4,654,000.63

PW 8,707,224.34 0.00% :

391,385.56

>1000


Net

Gas

(MMcf)

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

BFIT ECONOMIC SUMMARY PROJECTION Proved Rsv Class

Producing Rsv Category

02/03/2010 10:53:50AM Date :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00


All Cases

REPORT BREAK TOTAL CASE

68.01 0.00 33,753.01 0.00 12,150.53 0.00 826,357.58 0.00 0.00 2010

72.42 0.00 22,801.19 0.00 8,237.74 0.00 596,577.41 0.00 0.00 2011

75.14 0.00 16,014.70 0.00 5,792.62 0.00 435,257.28 0.00 0.00 2012

76.89 0.00 11,777.46 0.00 4,254.73 0.00 327,146.48 0.00 0.00 2013

79.22 0.00 8,810.37 0.00 3,183.84 0.00 252,224.08 0.00 0.00 2014

80.80 0.00 6,760.53 0.00 2,447.97 0.00 197,796.07 0.00 0.00 2015

82.41 0.00 3,088.53 0.00 1,116.86 0.00 92,040.60 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

2.00 2010 0.00 0.00 0.00 327,581.98 0.00 498,775.60 0.00 0.00 475,704.62

2.00 2011 0.00 0.00 0.00 217,449.96 0.00 379,127.45 0.00 0.00 804,446.43

2.00 2012 0.00 0.00 0.00 135,717.70 0.00 299,539.59 0.00 0.00 1,040,560.35

2.00 2013 0.00 0.00 0.00 109,149.18 0.00 217,997.30 0.00 0.00 1,196,760.14

2.00 2014 0.00 0.00 0.00 87,462.65 0.00 164,761.42 0.00 0.00 1,304,089.83

2.00 2015 0.00 0.00 0.00 72,131.99 0.00 125,664.07 0.00 0.00 1,378,513.33

2.00 2016 0.00 0.00 0.00 16,416.94 0.00 75,623.66 0.00 0.00 1,420,213.18

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 965,910.41 0.00 1,761,489.09 0.00

0.00 0.00

0.00

0.00

1,420,213.18

0.00 0.00

73.35 0.00

0.00

103,005.77 0.00

0.00 0.00 0.00 0.00 0.00 0.00

103,005.77 0.00 37,184.30 0.00 2,727,399.50 0.00 0.00



Years to Payout :

0.00 / 0.00

0.00

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

1,761,489.09

1,572,280.64 1,420,213.18

15.00% : 20.00% :

1,296,017.16 1,193,115.70

PW 1,761,489.09 0.00% :

0.00

0.00


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :

BFIT ECONOMIC PROJECTION

Proved Producing

Rubiales Field

Piriri Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Piriri - Proved Prod

68.01 0.00 14,008.70 0.00 5,712.47 0.00 388,505.12 0.00 0.00 2010

72.42 0.00 9,800.25 0.00 3,997.35 0.00 289,487.95 0.00 0.00 2011

75.14 0.00 6,938.26 0.00 2,830.88 0.00 212,712.21 0.00 0.00 2012

76.89 0.00 5,024.23 0.00 2,050.54 0.00 157,666.25 0.00 0.00 2013

79.22 0.00 3,760.96 0.00 1,535.45 0.00 121,637.98 0.00 0.00 2014

80.80 0.00 2,934.24 0.00 1,198.13 0.00 96,808.91 0.00 0.00 2015

82.41 0.00 1,318.95 0.00 538.65 0.00 44,389.85 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 0.00 155,320.53 0.00 233,184.59 0.00 0.00 222,398.47

1.00 2011 0.00 0.00 0.00 106,438.27 0.00 183,049.68 0.00 0.00 381,120.98

1.00 2012 0.00 0.00 0.00 67,121.87 0.00 145,590.34 0.00 0.00 495,883.51

1.00 2013 0.00 0.00 0.00 53,044.55 0.00 104,621.70 0.00 0.00 570,847.20

1.00 2014 0.00 0.00 0.00 42,319.59 0.00 79,318.39 0.00 0.00 622,517.16

1.00 2015 0.00 0.00 0.00 35,490.16 0.00 61,318.75 0.00 0.00 658,832.67

1.00 2016 0.00 0.00 0.00 7,970.83 0.00 36,419.02 0.00 0.00 678,913.03

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 467,705.81 0.00 843,502.47 0.00

0.00 0.00

0.00

0.00

678,913.03

0.00 0.00

73.40 0.00

0.00

43,785.58 0.00

0.00 0.00 0.00 0.00 0.00 0.00

43,785.58 0.00 17,863.46 0.00 1,311,208.28 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.50000000

0.40850000

06/29/2016

0.00 / 0.00

0.00

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

843,502.47

752,237.86 678,913.03

15.00% : 20.00% :

619,047.99 569,464.58

PW 843,502.47 0.00% :

0.00

1,167,391.67

221,646.25

0.00


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Proved Producing

Rubiales Field

Rubiales Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Rubiales - Proved Prod

68.01 0.00 19,744.31 0.00 6,438.06 0.00 437,852.46 0.00 0.00 2010

72.42 0.00 13,000.94 0.00 4,240.40 0.00 307,089.46 0.00 0.00 2011

75.14 0.00 9,076.43 0.00 2,961.74 0.00 222,545.07 0.00 0.00 2012

76.89 0.00 6,753.23 0.00 2,204.19 0.00 169,480.23 0.00 0.00 2013

79.22 0.00 5,049.41 0.00 1,648.40 0.00 130,586.10 0.00 0.00 2014

80.80 0.00 3,826.30 0.00 1,249.84 0.00 100,987.16 0.00 0.00 2015

82.41 0.00 1,769.58 0.00 578.22 0.00 47,650.75 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 0.00 172,261.45 0.00 265,591.01 0.00 0.00 253,306.15

1.00 2011 0.00 0.00 0.00 111,011.69 0.00 196,077.77 0.00 0.00 423,325.45

1.00 2012 0.00 0.00 0.00 68,595.83 0.00 153,949.24 0.00 0.00 544,676.85

1.00 2013 0.00 0.00 0.00 56,104.64 0.00 113,375.60 0.00 0.00 625,912.95

1.00 2014 0.00 0.00 0.00 45,143.06 0.00 85,443.04 0.00 0.00 681,572.67

1.00 2015 0.00 0.00 0.00 36,641.83 0.00 64,345.33 0.00 0.00 719,680.66

1.00 2016 0.00 0.00 0.00 8,446.11 0.00 39,204.64 0.00 0.00 741,300.15

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 498,204.60 0.00 917,986.62 0.00

0.00 0.00

0.00

0.00

741,300.15

0.00 0.00

73.30 0.00

0.00

59,220.19 0.00

0.00 0.00 0.00 0.00 0.00 0.00

59,220.19 0.00 19,320.84 0.00 1,416,191.22 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.40000000

0.32680000

06/28/2016

0.00 / 0.00

0.00

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

917,986.62

820,042.78 741,300.15

15.00% : 20.00% :

676,969.17 623,651.12

PW 917,986.62 0.00% :

0.00

1,645,359.17

299,026.25

0.00


Net

Gas

(MMcf)

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Non-Producing Rsv Category

02/03/2010 10:53:50AM Date :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00


All Cases


68.01 0.00 3,262.01 0.00 1,158.93 0.00 78,818.65 0.00 0.00 2010

72.42 0.00 8,827.89 0.00 3,033.89 0.00 219,714.53 0.00 0.00 2011

75.14 0.00 6,752.33 0.00 2,305.02 0.00 173,199.14 0.00 0.00 2012

76.89 0.00 4,432.20 0.00 1,519.16 0.00 116,807.86 0.00 0.00 2013

79.22 0.00 3,039.72 0.00 1,045.30 0.00 82,808.77 0.00 0.00 2014

80.80 0.00 2,156.06 0.00 743.27 0.00 60,056.48 0.00 0.00 2015

82.41 0.00 953.87 0.00 330.35 0.00 27,224.10 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

2.00 2010 0.00 0.00 35,405.00 36,335.69 0.00 7,077.96 0.00 0.00 5,112.48

2.00 2011 0.00 0.00 18,599.70 80,804.23 0.00 120,310.60 0.00 0.00 108,651.78

2.00 2012 0.00 0.00 7,209.97 54,142.55 0.00 111,846.61 0.00 0.00 196,539.44

2.00 2013 0.00 0.00 4,435.85 39,916.00 0.00 72,456.01 0.00 0.00 248,301.57

2.00 2014 0.00 0.00 2,067.45 29,875.45 0.00 50,865.87 0.00 0.00 281,371.49

2.00 2015 0.00 0.00 585.16 23,296.11 0.00 36,175.21 0.00 0.00 302,779.08

2.00 2016 0.00 0.00 0.00 5,335.04 0.00 21,889.06 0.00 0.00 314,848.08

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 68,303.13 269,705.05 0.00 420,621.33 0.00

0.00 0.00

0.00

0.00

314,848.08

0.00 0.00

74.85 0.00

0.00

29,424.07 0.00

0.00 0.00 0.00 0.00 0.00 0.00

29,424.07 0.00 10,135.92 0.00 758,629.51 0.00 0.00



Years to Payout :

28.49 / 33.50

1.19

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

420,621.33

361,897.78 314,848.08

15.00% : 20.00% :

276,574.70 245,014.98

PW 420,621.33 0.00% :

11,453.15

372.71


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Proved Non-Producing

Rubiales Field

Piriri Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Piriri - Proved Non-Prod

68.01 0.00 1,147.93 0.00 468.78 0.00 31,881.41 0.00 0.00 2010

72.42 0.00 1,837.05 0.00 750.22 0.00 54,331.08 0.00 0.00 2011

75.14 0.00 1,211.83 0.00 494.91 0.00 37,187.39 0.00 0.00 2012

76.89 0.00 870.53 0.00 355.53 0.00 27,336.78 0.00 0.00 2013

79.22 0.00 638.39 0.00 260.74 0.00 20,655.91 0.00 0.00 2014

80.80 0.00 474.50 0.00 193.82 0.00 15,660.93 0.00 0.00 2015

82.41 0.00 228.06 0.00 93.16 0.00 7,677.52 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 13,425.00 13,801.17 0.00 4,655.25 0.00 0.00 3,818.84

1.00 2011 0.00 0.00 4,462.50 20,190.96 0.00 29,677.63 0.00 0.00 29,364.67

1.00 2012 0.00 0.00 1,716.66 11,996.32 0.00 23,474.41 0.00 0.00 47,802.79

1.00 2013 0.00 0.00 1,167.33 9,516.14 0.00 16,653.31 0.00 0.00 59,694.67

1.00 2014 0.00 0.00 595.34 7,705.12 0.00 12,355.45 0.00 0.00 67,724.49

1.00 2015 0.00 0.00 55.20 6,307.07 0.00 9,298.66 0.00 0.00 73,229.93

1.00 2016 0.00 0.00 0.00 1,534.92 0.00 6,142.61 0.00 0.00 76,616.79

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 21,422.03 71,051.69 0.00 102,257.31 0.00

0.00 0.00

0.00

0.00

76,616.79

0.00 0.00

74.41 0.00

0.00

6,408.27 0.00

0.00 0.00 0.00 0.00 0.00 0.00

6,408.27 0.00 2,617.16 0.00 194,731.03 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.50000000

0.40850000

06/29/2016

4.79 / 5.77

0.24

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

102,257.31

88,009.66 76,616.79

15.00% : 20.00% :

67,361.91 59,736.96

PW 102,257.31 0.00% :

3,719.62

95,660.42

38,325.00

330.34


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Proved Non-Producing

Rubiales Field

Rubiales Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Rubiales - Proved Non-Prod

68.01 0.00 2,114.08 0.00 690.15 0.00 46,937.23 0.00 0.00 2010

72.42 0.00 6,990.85 0.00 2,283.67 0.00 165,383.45 0.00 0.00 2011

75.14 0.00 5,540.51 0.00 1,810.11 0.00 136,011.75 0.00 0.00 2012

76.89 0.00 3,561.67 0.00 1,163.62 0.00 89,471.08 0.00 0.00 2013

79.22 0.00 2,401.34 0.00 784.56 0.00 62,152.86 0.00 0.00 2014

80.80 0.00 1,681.56 0.00 549.45 0.00 44,395.55 0.00 0.00 2015

82.41 0.00 725.81 0.00 237.19 0.00 19,546.57 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 21,980.00 22,534.52 0.00 2,422.71 0.00 0.00 1,293.63

1.00 2011 0.00 0.00 14,137.20 60,613.27 0.00 90,632.98 0.00 0.00 79,287.10

1.00 2012 0.00 0.00 5,493.31 42,146.23 0.00 88,372.21 0.00 0.00 148,736.64

1.00 2013 0.00 0.00 3,268.52 30,399.86 0.00 55,802.70 0.00 0.00 188,606.89

1.00 2014 0.00 0.00 1,472.11 22,170.33 0.00 38,510.42 0.00 0.00 213,647.00

1.00 2015 0.00 0.00 529.96 16,989.04 0.00 26,876.55 0.00 0.00 229,549.16

1.00 2016 0.00 0.00 0.00 3,800.12 0.00 15,746.45 0.00 0.00 238,231.30

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 46,881.10 198,653.36 0.00 318,364.02 0.00

0.00 0.00

0.00

0.00

238,231.30

0.00 0.00

75.00 0.00

0.00

23,015.80 0.00

0.00 0.00 0.00 0.00 0.00 0.00

23,015.80 0.00 7,518.76 0.00 563,898.48 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.40000000

0.32680000

06/29/2016

6.52 / 7.79

0.36

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

318,364.02

273,888.12 238,231.30

15.00% : 20.00% :

209,212.79 185,278.01

PW 318,364.02 0.00% :

7,733.53

176,173.33

121,970.83

392.62


Net

Gas

(MMcf)

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Undeveloped Rsv Category

02/03/2010 10:53:50AM Date :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00


All Cases


68.01 0.00 23,745.44 0.00 8,330.77 0.00 566,575.77 0.00 0.00 2010

72.42 0.00 55,566.14 0.00 19,425.20 0.00 1,406,773.14 0.00 0.00 2011

75.14 0.00 62,094.83 0.00 21,667.18 0.00 1,628,072.25 0.00 0.00 2012

76.89 0.00 57,675.84 0.00 19,918.84 0.00 1,531,559.85 0.00 0.00 2013

79.22 0.00 53,036.33 0.00 18,179.63 0.00 1,440,190.57 0.00 0.00 2014

80.80 0.00 47,745.65 0.00 16,294.79 0.00 1,316,618.78 0.00 0.00 2015

82.41 0.00 19,667.81 0.00 6,720.69 0.00 553,852.21 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

2.00 2010 0.00 0.00 293,600.00 221,209.15 0.00 51,766.62 0.00 0.00 35,791.89

2.00 2011 0.00 0.00 185,966.40 492,273.23 0.00 728,533.50 0.00 0.00 659,685.80

2.00 2012 0.00 0.00 109,137.96 472,442.42 0.00 1,046,491.87 0.00 0.00 1,480,407.78

2.00 2013 0.00 0.00 80,322.83 468,845.76 0.00 982,391.26 0.00 0.00 2,181,524.07

2.00 2014 0.00 0.00 62,131.61 450,287.91 0.00 927,771.06 0.00 0.00 2,783,937.08

2.00 2015 0.00 0.00 26,376.49 431,183.25 0.00 859,059.04 0.00 0.00 3,291,952.51

2.00 2016 0.00 0.00 900.93 91,239.60 0.00 461,711.68 0.00 0.00 3,546,492.76

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 758,436.22 2,627,481.32 0.00 5,057,725.04 0.00

0.00 0.00

0.00

0.00

3,546,492.76

0.00 0.00

76.39 0.00

0.00

319,532.03 0.00

0.00 0.00 0.00 0.00 0.00 0.00

319,532.03 0.00 110,537.11 0.00 8,443,642.58 0.00 0.00



Years to Payout :

14.75 / 17.83

1.45

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

5,057,725.04

4,207,464.55 3,546,492.76

15.00% : 20.00% :

3,024,361.28 2,605,870.41

PW 5,057,725.04 0.00% :

257,969.39

318.36


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Proved Undeveloped

Rubiales Field

Piriri Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Piriri - Proved Undeveloped

68.01 0.00 7,181.74 0.00 2,926.79 0.00 199,050.97 0.00 0.00 2010

72.42 0.00 16,000.14 0.00 6,521.41 0.00 472,280.51 0.00 0.00 2011

75.14 0.00 17,380.61 0.00 7,084.42 0.00 532,323.03 0.00 0.00 2012

76.89 0.00 13,602.09 0.00 5,543.78 0.00 426,261.03 0.00 0.00 2013

79.22 0.00 10,707.28 0.00 4,366.23 0.00 345,892.40 0.00 0.00 2014

80.80 0.00 8,650.50 0.00 3,530.03 0.00 285,226.68 0.00 0.00 2015

82.41 0.00 3,628.15 0.00 1,481.56 0.00 122,095.76 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 102,400.00 78,346.98 0.00 18,303.99 0.00 0.00 12,720.85

1.00 2011 0.00 0.00 70,176.00 166,961.03 0.00 235,143.49 0.00 0.00 213,663.54

1.00 2012 0.00 0.00 30,275.64 156,973.81 0.00 345,073.58 0.00 0.00 484,509.93

1.00 2013 0.00 0.00 14,697.73 133,443.09 0.00 278,120.21 0.00 0.00 683,278.93

1.00 2014 0.00 0.00 8,659.46 111,537.91 0.00 225,695.03 0.00 0.00 830,029.17

1.00 2015 0.00 0.00 2,705.00 97,037.36 0.00 185,484.32 0.00 0.00 939,803.37

1.00 2016 0.00 0.00 0.00 20,931.24 0.00 101,164.52 0.00 0.00 995,582.43

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 228,913.83 765,231.42 0.00 1,388,985.14 0.00

0.00 0.00

0.00

0.00

995,582.43

0.00 0.00

75.77 0.00

0.00

77,150.50 0.00

0.00 0.00 0.00 0.00 0.00 0.00

77,150.50 0.00 31,454.22 0.00 2,383,130.38 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.50000000

0.40850000

06/29/2016

5.75 / 7.07

0.72

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

1,388,985.14

1,168,762.75 995,582.43

15.00% : 20.00% :

857,244.93 745,168.55

PW 1,388,985.14 0.00% :

77,638.81

598,478.33

609,702.08

302.14


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Proved Undeveloped

Rubiales Field

Rubiales Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Rubiales - Proved Undeveloped

68.01 0.00 16,563.70 0.00 5,403.98 0.00 367,524.80 0.00 0.00 2010

72.42 0.00 39,566.00 0.00 12,903.79 0.00 934,492.63 0.00 0.00 2011

75.14 0.00 44,714.22 0.00 14,582.77 0.00 1,095,749.22 0.00 0.00 2012

76.89 0.00 44,073.75 0.00 14,375.07 0.00 1,105,298.82 0.00 0.00 2013

79.22 0.00 42,329.05 0.00 13,813.41 0.00 1,094,298.17 0.00 0.00 2014

80.80 0.00 39,095.15 0.00 12,764.75 0.00 1,031,392.10 0.00 0.00 2015

82.41 0.00 16,039.66 0.00 5,239.13 0.00 431,756.45 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 191,200.00 142,862.17 0.00 33,462.63 0.00 0.00 23,071.05

1.00 2011 0.00 0.00 115,790.40 325,312.21 0.00 493,390.02 0.00 0.00 446,022.26

1.00 2012 0.00 0.00 78,862.32 315,468.61 0.00 701,418.29 0.00 0.00 995,897.85

1.00 2013 0.00 0.00 65,625.10 335,402.67 0.00 704,271.05 0.00 0.00 1,498,245.14

1.00 2014 0.00 0.00 53,472.15 338,750.00 0.00 702,076.03 0.00 0.00 1,953,907.91

1.00 2015 0.00 0.00 23,671.49 334,145.89 0.00 673,574.72 0.00 0.00 2,352,149.14

1.00 2016 0.00 0.00 900.93 70,308.36 0.00 360,547.16 0.00 0.00 2,550,910.33

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 529,522.39 1,862,249.90 0.00 3,668,739.90 0.00

0.00 0.00

0.00

0.00

2,550,910.33

0.00 0.00

76.63 0.00

0.00

242,381.53 0.00

0.00 0.00 0.00 0.00 0.00 0.00

242,381.53 0.00 79,082.90 0.00 6,060,512.20 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.40000000

0.32680000

06/30/2016

6.51 / 7.93

0.95

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

3,668,739.90

3,038,701.80 2,550,910.33

15.00% : 20.00% :

2,167,116.34 1,860,701.85

PW 3,668,739.90 0.00% :

180,330.57

1,380,308.33

2,680,620.8

4

326.83


Net

Gas

(MMcf)

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

BFIT ECONOMIC SUMMARY PROJECTION Probable Rsv Class


02/03/2010 10:53:50AM Date :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00


All Cases


68.01 0.00 762.12 0.00 287.84 0.00 19,576.14 0.00 0.00 2010

72.42 0.00 2,144.01 0.00 758.23 0.00 54,911.31 0.00 0.00 2011

75.14 0.00 2,449.27 0.00 901.38 0.00 67,730.02 0.00 0.00 2012

76.89 0.00 11,073.37 0.00 3,728.74 0.00 286,702.94 0.00 0.00 2013

79.22 0.00 15,546.45 0.00 5,157.23 0.00 408,555.62 0.00 0.00 2014

80.80 0.00 12,287.73 0.00 4,070.30 0.00 328,880.09 0.00 0.00 2015

82.41 0.00 4,988.91 0.00 1,653.72 0.00 136,282.72 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

2.00 2010 0.00 0.00 20,110.00 8,282.79 0.00 -8,816.66 0.00 0.00 -9,339.08

2.00 2011 0.00 0.00 8,945.40 21,279.70 0.00 24,686.20 0.00 0.00 11,690.12

2.00 2012 0.00 0.00 9,228.35 22,220.59 0.00 36,281.08 0.00 0.00 39,935.54

2.00 2013 0.00 0.00 44,623.80 88,152.66 0.00 153,926.48 0.00 0.00 148,677.21

2.00 2014 0.00 0.00 21,194.02 127,333.42 0.00 260,028.18 0.00 0.00 317,397.28

2.00 2015 0.00 0.00 3,234.96 108,264.01 0.00 217,381.13 0.00 0.00 446,047.11

2.00 2016 0.00 0.00 450.46 22,556.87 0.00 113,275.39 0.00 0.00 508,483.55

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 107,786.99 398,090.04 0.00 796,761.81 0.00

0.00 0.00

0.00

0.00

508,483.55

0.00 0.00

78.67 0.00

0.00

49,251.85 0.00

0.00 0.00 0.00 0.00 0.00 0.00

49,251.85 0.00 16,557.44 0.00 1,302,638.84 0.00 0.00



Years to Payout :

9.72 / 11.95

3.09

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

796,761.81

632,449.53 508,483.55

15.00% : 20.00% :

413,525.63 339,775.15

PW 796,761.81 0.00% :

58,345.28

185.19


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Probable Undeveloped

Rubiales Field

Piriri Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Piriri - Probable Undeveloped

68.01 0.00 492.75 0.00 201.10 0.00 13,676.95 0.00 0.00 2010

72.42 0.00 742.41 0.00 302.96 0.00 21,940.06 0.00 0.00 2011

75.14 0.00 1,311.74 0.00 533.97 0.00 40,122.49 0.00 0.00 2012

76.89 0.00 1,503.80 0.00 609.39 0.00 46,856.04 0.00 0.00 2013

79.22 0.00 1,185.52 0.00 479.31 0.00 37,970.89 0.00 0.00 2014

80.80 0.00 923.82 0.00 374.11 0.00 30,228.39 0.00 0.00 2015

82.41 0.00 372.55 0.00 151.27 0.00 12,466.30 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 12,750.00 5,804.84 0.00 -4,877.89 0.00 0.00 -5,242.04

1.00 2011 0.00 0.00 1,683.00 8,652.85 0.00 11,604.21 0.00 0.00 4,749.16

1.00 2012 0.00 0.00 8,271.18 12,876.26 0.00 18,975.04 0.00 0.00 19,389.61

1.00 2013 0.00 0.00 1,750.99 15,713.22 0.00 29,391.82 0.00 0.00 40,388.64

1.00 2014 0.00 0.00 1,190.68 13,328.51 0.00 23,451.70 0.00 0.00 55,628.05

1.00 2015 0.00 0.00 55.20 11,336.57 0.00 18,836.61 0.00 0.00 66,782.27

1.00 2016 0.00 0.00 0.00 2,388.20 0.00 10,078.11 0.00 0.00 72,338.45

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 25,701.05 70,100.45 0.00 107,459.61 0.00

0.00 0.00

0.00

0.00

72,338.45

0.00 0.00

76.64 0.00

0.00

6,532.59 0.00

0.00 0.00 0.00 0.00 0.00 0.00

6,532.59 0.00 2,652.11 0.00 203,261.11 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.50000000

0.40850000

06/30/2016

4.11 / 5.18

1.53

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

107,459.61

87,679.55 72,338.45

15.00% : 20.00% :

60,254.93 50,603.13

PW 107,459.61 0.00% :

13,663.56

41,062.50

62,262.92

131.44


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Probable Undeveloped

Rubiales Field

Rubiales Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Rubiales - Probable Undeveloped

68.01 0.00 269.37 0.00 86.74 0.00 5,899.18 0.00 0.00 2010

72.42 0.00 1,401.60 0.00 455.28 0.00 32,971.24 0.00 0.00 2011

75.14 0.00 1,137.53 0.00 367.41 0.00 27,607.54 0.00 0.00 2012

76.89 0.00 9,569.57 0.00 3,119.35 0.00 239,846.91 0.00 0.00 2013

79.22 0.00 14,360.93 0.00 4,677.92 0.00 370,584.73 0.00 0.00 2014

80.80 0.00 11,363.91 0.00 3,696.18 0.00 298,651.71 0.00 0.00 2015

82.41 0.00 4,616.36 0.00 1,502.44 0.00 123,816.42 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 7,360.00 2,477.95 0.00 -3,938.77 0.00 0.00 -4,097.03

1.00 2011 0.00 0.00 7,262.40 12,626.85 0.00 13,081.99 0.00 0.00 6,940.95

1.00 2012 0.00 0.00 957.17 9,344.33 0.00 17,306.04 0.00 0.00 20,545.93

1.00 2013 0.00 0.00 42,872.80 72,439.44 0.00 124,534.66 0.00 0.00 108,288.57

1.00 2014 0.00 0.00 20,003.35 114,004.91 0.00 236,576.47 0.00 0.00 261,769.23

1.00 2015 0.00 0.00 3,179.75 96,927.44 0.00 198,544.52 0.00 0.00 379,264.83

1.00 2016 0.00 0.00 450.46 20,168.67 0.00 103,197.29 0.00 0.00 436,145.11

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 82,085.94 327,989.59 0.00 689,302.20 0.00

0.00 0.00

0.00

0.00

436,145.11

0.00 0.00

79.06 0.00

0.00

42,719.26 0.00

0.00 0.00 0.00 0.00 0.00 0.00

42,719.26 0.00 13,905.33 0.00 1,099,377.72 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.40000000

0.32680000

07/01/2016

7.97 / 9.45

3.10

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

689,302.20

544,769.98 436,145.11

15.00% : 20.00% :

353,270.70 289,172.02

PW 689,302.20 0.00% :

44,681.72

22,447.50

767,290.83

228.59


Net

Gas

(MMcf)

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

BFIT ECONOMIC SUMMARY PROJECTION Possible Rsv Class


02/03/2010 10:53:50AM Date :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00


All Cases


68.01 0.00 682.92 0.00 231.20 0.00 15,723.80 0.00 0.00 2010

72.42 0.00 1,737.40 0.00 586.75 0.00 42,492.30 0.00 0.00 2011

75.14 0.00 3,318.89 0.00 1,206.10 0.00 90,626.64 0.00 0.00 2012

76.89 0.00 4,311.75 0.00 1,648.98 0.00 126,790.09 0.00 0.00 2013

79.22 0.00 9,746.23 0.00 3,382.76 0.00 267,982.15 0.00 0.00 2014

80.80 0.00 14,736.15 0.00 4,974.05 0.00 401,903.26 0.00 0.00 2015

82.41 0.00 6,122.06 0.00 2,067.65 0.00 170,395.16 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

2.00 2010 0.00 0.00 15,361.68 6,708.07 0.00 -6,345.95 0.00 0.00 -6,754.95

2.00 2011 0.00 0.00 12,882.60 16,583.09 0.00 13,026.61 0.00 0.00 3,998.66

2.00 2012 0.00 0.00 21,900.42 28,918.42 0.00 39,807.81 0.00 0.00 34,538.70

2.00 2013 0.00 0.00 4,372.18 42,127.26 0.00 80,290.65 0.00 0.00 91,916.79

2.00 2014 0.00 0.00 31,855.98 84,060.31 0.00 152,065.86 0.00 0.00 189,970.45

2.00 2015 0.00 0.00 22,434.92 129,953.47 0.00 249,514.87 0.00 0.00 337,100.03

2.00 2016 0.00 0.00 450.46 27,677.47 0.00 142,267.23 0.00 0.00 415,518.88

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 109,258.25 336,028.09 0.00 670,627.07 0.00

0.00 0.00

0.00

0.00

415,518.88

0.00 0.00

79.16 0.00

0.00

40,655.38 0.00

0.00 0.00 0.00 0.00 0.00 0.00

40,655.38 0.00 14,097.49 0.00 1,115,913.41 0.00 0.00



Years to Payout :

7.53 / 9.05

3.15

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

670,627.07

524,341.90 415,518.88

15.00% : 20.00% :

333,277.87 270,224.39

PW 670,627.07 0.00% :

63,617.75

166.97


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Possible Undeveloped

Rubiales Field

Piriri Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Piriri - Possible Undeveloped

68.01 0.00 98.19 0.00 40.11 0.00 2,727.78 0.00 0.00 2010

72.42 0.00 232.14 0.00 94.83 0.00 6,867.53 0.00 0.00 2011

75.14 0.00 1,491.08 0.00 609.11 0.00 45,768.36 0.00 0.00 2012

76.89 0.00 2,953.95 0.00 1,206.45 0.00 92,764.04 0.00 0.00 2013

79.22 0.00 2,457.18 0.00 1,003.47 0.00 79,495.19 0.00 0.00 2014

80.80 0.00 2,039.62 0.00 833.00 0.00 67,306.28 0.00 0.00 2015

82.41 0.00 869.96 0.00 355.32 0.00 29,281.72 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 4,401.68 1,224.04 0.00 -2,897.94 0.00 0.00 -2,959.44

1.00 2011 0.00 0.00 561.00 2,881.07 0.00 3,425.46 0.00 0.00 -12.84

1.00 2012 0.00 0.00 20,027.70 14,035.46 0.00 11,705.20 0.00 0.00 8,446.82

1.00 2013 0.00 0.00 2,971.38 29,728.11 0.00 60,064.54 0.00 0.00 51,381.20

1.00 2014 0.00 0.00 1,894.26 26,191.40 0.00 51,409.53 0.00 0.00 84,810.88

1.00 2015 0.00 0.00 662.45 23,157.77 0.00 43,486.06 0.00 0.00 110,546.17

1.00 2016 0.00 0.00 0.00 5,008.41 0.00 24,273.31 0.00 0.00 123,928.29

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 30,518.47 102,226.28 0.00 191,466.15 0.00

0.00 0.00

0.00

0.00

123,928.29

0.00 0.00

78.27 0.00

0.00

10,142.11 0.00

0.00 0.00 0.00 0.00 0.00 0.00

10,142.11 0.00 4,142.29 0.00 324,210.90 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.50000000

0.40850000

06/30/2016

6.12 / 7.52

2.57

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

191,466.15

153,118.68 123,928.29

15.00% : 20.00% :

101,374.86 83,712.68

PW 191,466.15 0.00% :

19,202.99

8,182.08

145,391.67

172.12


Operator :

Case :

Reserve Cat. :

Field :

Reservoir :

Co., State :


Possible Undeveloped

Rubiales Field

Rubiales Concession

,

As Of Date : 01/01/2010


Custom Selection

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

02/03/2010 10:53:50AM Date :

Project Name :

Partner :

Case Type :

Archive Set :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00

0.00


All Cases

LEASE CASE

default

Rubiales - Possible Undeveloped

68.01 0.00 584.73 0.00 191.09 0.00 12,996.01 0.00 0.00 2010

72.42 0.00 1,505.26 0.00 491.92 0.00 35,624.77 0.00 0.00 2011

75.14 0.00 1,827.80 0.00 597.00 0.00 44,858.28 0.00 0.00 2012

76.89 0.00 1,357.80 0.00 442.53 0.00 34,026.06 0.00 0.00 2013

79.22 0.00 7,289.05 0.00 2,379.29 0.00 188,486.96 0.00 0.00 2014

80.80 0.00 12,696.53 0.00 4,141.05 0.00 334,596.98 0.00 0.00 2015

82.41 0.00 5,252.10 0.00 1,712.33 0.00 141,113.44 0.00 0.00 2016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

1.00 2010 0.00 0.00 10,960.00 5,484.03 0.00 -3,448.01 0.00 0.00 -3,795.51

1.00 2011 0.00 0.00 12,321.60 13,702.02 0.00 9,601.15 0.00 0.00 4,011.50

1.00 2012 0.00 0.00 1,872.72 14,882.95 0.00 28,102.61 0.00 0.00 26,091.88

1.00 2013 0.00 0.00 1,400.79 12,399.15 0.00 20,226.11 0.00 0.00 40,535.60

1.00 2014 0.00 0.00 29,961.72 57,868.91 0.00 100,656.33 0.00 0.00 105,159.57

1.00 2015 0.00 0.00 21,772.47 106,795.69 0.00 206,028.82 0.00 0.00 226,553.86

1.00 2016 0.00 0.00 450.46 22,669.06 0.00 117,993.92 0.00 0.00 291,590.58

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 78,739.78 233,801.81 0.00 479,160.93 0.00

0.00 0.00

0.00

0.00

291,590.58

0.00 0.00

79.53 0.00

0.00

30,513.27 0.00

0.00 0.00 0.00 0.00 0.00 0.00

30,513.27 0.00 9,955.20 0.00 791,702.51 0.00 0.00

Major Phase :

Perfs :

Initial Rate :

Abandonment :

Initial Decline :

Beg Ratio :

End Ratio :

Oil

0 - 0

0.00

bbl/month

bbl/month

% year b = 0.000

0.000

0.000

Working Int :

Revenue Int :

Abandonment Date :



Years to Payout :

0.40000000

0.32680000

07/01/2016

5.97 / 7.13

3.06

Internal ROR (%) :


0.00% :

5.00% : 10.00% :

PW

PW PW PW PW

479,160.93

371,223.21 291,590.58

15.00% : 20.00% :

231,903.01 186,511.71

PW 479,160.93 0.00% :

44,414.76

48,727.50

872,958.33

164.28

Appendix 3


Grand Total

AFIT ECONOMIC SUMMARY PROJECTION

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

Cum Gas (MMcf) : 0.00

Cum Oil (Mbbl) : 0.00

Archive Set : default

Case Type : GRAND TOTAL CASE

Partner : All Cases

Project Name : Metapetroleum - Rubiales Field

Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

62,205.49 0.00 2010 68.01 0.00 0.00 0.00 1,507,051.94 0.00 22,159.27

91,076.63 0.00 2011 72.42 0.00 0.00 0.00 2,320,468.69 0.00 32,041.82

90,630.02 0.00 2012 75.14 0.00 0.00 0.00 2,394,885.33 0.00 31,872.31

89,270.61 0.00 2013 76.89 0.00 0.00 0.00 2,389,007.22 0.00 31,070.45

90,179.09 0.00 2014 79.22 0.00 0.00 0.00 2,451,761.18 0.00 30,948.77

83,686.11 0.00 2015 80.80 0.00 0.00 0.00 2,305,254.68 0.00 28,530.38

34,821.17 0.00 2016 82.41 0.00 0.00 0.00 979,794.79 0.00 11,889.27

Rem

Total

Ult

0.00

541,869.11

541,869.11

0.00

0.00

0.00

0.00 0.00 0.00

76.11

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 265,338.68 429,869.03 407,111.50 0.00 0.00 600,117.69 0.00 0.00 211,726.54 10

2011 115,077.42 922,590.70 1,220,580.14 0.00 0.00 828,390.22 0.00 0.00 454,410.35 10

2012 76,584.88 1,075,255.38 2,084,708.33 0.00 0.00 713,441.67 0.00 0.00 529,603.40 10

2013 133,754.66 1,009,731.34 2,820,134.33 0.00 0.00 748,190.86 0.00 0.00 497,330.36 10

2014 117,249.05 1,042,179.90 3,510,890.03 0.00 0.00 779,019.75 0.00 0.00 513,312.49 10

2015 52,631.53 996,822.20 4,113,266.49 0.00 0.00 764,828.82 0.00 0.00 490,972.13 10

2016 1,801.86 545,893.91 4,417,641.06 0.00 0.00 163,225.91 0.00 0.00 268,873.12 10

762,438.09 6,022,342.46

Rem.

Total

0.00 0.00 0.00 0.00 0.00

4,417,641.06 0.00

0.00

0.00 4,597,214.92 0.00 0.00 2,966,228.37

0.00 0.00 0.00

0.00

0.00 0.00 14,348,223.84 0.00 188,512.27


Internal ROR (%) :


Years to Payout :


6,022,342.46

5,122,662.83

4,417,641.06

3,856,342.56

3,402,997.88

6,022,342.46

0.84

292,247.565

16.12 / 33.00

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : >1000


Proved Rsv Class

Producing Rsv Category


Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year




Case Type : REPORT BREAK TOTAL CASE

Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

33,753.01 0.00 2010 68.01 0.00 0.00 0.00 826,357.58 0.00 12,150.53

22,801.19 0.00 2011 72.42 0.00 0.00 0.00 596,577.41 0.00 8,237.74

16,014.70 0.00 2012 75.14 0.00 0.00 0.00 435,257.28 0.00 5,792.62

11,777.46 0.00 2013 76.89 0.00 0.00 0.00 327,146.48 0.00 4,254.73

8,810.37 0.00 2014 79.22 0.00 0.00 0.00 252,224.08 0.00 3,183.84

6,760.53 0.00 2015 80.80 0.00 0.00 0.00 197,796.07 0.00 2,447.97

3,088.53 0.00 2016 82.41 0.00 0.00 0.00 92,040.60 0.00 1,116.86

Rem

Total

Ult

0.00

103,005.77

103,005.77

0.00

0.00

0.00

0.00 0.00 0.00

73.35

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 -10,363.00 341,122.86 333,276.21 0.00 0.00 327,581.98 0.00 0.00 168,015.74 2

2011 0.00 254,015.39 558,579.15 0.00 0.00 217,449.96 0.00 0.00 125,112.06 2

2012 0.00 200,691.52 720,412.52 0.00 0.00 135,717.70 0.00 0.00 98,848.06 2

2013 0.00 146,058.19 827,464.11 0.00 0.00 109,149.18 0.00 0.00 71,939.11 2

2014 0.00 110,390.15 901,022.50 0.00 0.00 87,462.65 0.00 0.00 54,371.27 2

2015 0.00 84,194.93 952,028.58 0.00 0.00 72,131.99 0.00 0.00 41,469.14 2

2016 0.00 50,667.85 980,284.33 0.00 0.00 16,416.94 0.00 0.00 24,955.81 2

-10,363.00 1,187,140.90

Rem.

Total

0.00 0.00 0.00 0.00 0.00

980,284.33 0.00

0.00

0.00 965,910.41 0.00 0.00 584,711.19

0.00 0.00 0.00

0.00

0.00 0.00 2,727,399.50 0.00 37,184.30


Internal ROR (%) :


Years to Payout :


1,187,140.90

1,072,767.25

980,284.33

904,334.08

841,088.49

1,187,140.90

0.00

-10,363.000

-93.59 / -113.56

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : >1000


Piriri Concession

Operator : Rubiales Field

Case :

Reserve Cat. : Proved Producing Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Piriri - Proved Prod

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year




Case Type : LEASE CASE

Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

14,008.70 0.00 2010 68.01 0.00 0.00 0.00 388,505.12 0.00 5,712.47

9,800.25 0.00 2011 72.42 0.00 0.00 0.00 289,487.95 0.00 3,997.35

6,938.26 0.00 2012 75.14 0.00 0.00 0.00 212,712.21 0.00 2,830.88

5,024.23 0.00 2013 76.89 0.00 0.00 0.00 157,666.25 0.00 2,050.54

3,760.96 0.00 2014 79.22 0.00 0.00 0.00 121,637.98 0.00 1,535.45

2,934.24 0.00 2015 80.80 0.00 0.00 0.00 96,808.91 0.00 1,198.13

1,318.95 0.00 2016 82.41 0.00 0.00 0.00 44,389.85 0.00 538.65

Rem

Total

Ult

0.00

43,785.58

43,785.58

0.00

0.00

0.00

0.00 0.00 0.00

73.40

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 -3,770.00 158,759.57 155,058.91 0.00 0.00 155,320.53 0.00 0.00 78,195.01 1

2011 0.00 122,643.29 263,839.23 0.00 0.00 106,438.27 0.00 0.00 60,406.39 1

2012 0.00 97,545.53 342,497.91 0.00 0.00 67,121.87 0.00 0.00 48,044.81 1

2013 0.00 70,096.54 393,874.30 0.00 0.00 53,044.55 0.00 0.00 34,525.16 1

2014 0.00 53,143.32 429,286.30 0.00 0.00 42,319.59 0.00 0.00 26,175.07 1

2015 0.00 41,083.56 454,175.10 0.00 0.00 35,490.16 0.00 0.00 20,235.19 1

2016 0.00 24,400.74 467,781.89 0.00 0.00 7,970.83 0.00 0.00 12,018.28 1

-3,770.00 567,672.55

Rem.

Total

0.00 0.00 0.00 0.00 0.00

467,781.89 0.00

0.00

0.00 467,705.81 0.00 0.00 279,599.91

0.00 0.00 0.00

0.00

0.00 0.00 1,311,208.28 0.00 17,863.46

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :

Initial Decline : % year

Abandonment :

Beg Ratio :

End Ratio :

Working Int : 0.50000000

Revenue Int : 0.40850000


Internal ROR (%) :


Years to Payout :

1,167,391.668 bbl/month

221,646.250 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000

Abandonment Date : 6/29/2016 Present Worth Profile (M$)

567,672.55

512,436.97

467,781.89

431,116.87

400,591.30

567,672.55

0.00

-3,770.000

0.000 b = -123.08 / -149.58

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : >1000


Rubiales Concession


Case :

Reserve Cat. : Proved Producing Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Rubiales - Proved Prod

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

19,744.31 0.00 2010 68.01 0.00 0.00 0.00 437,852.46 0.00 6,438.06

13,000.94 0.00 2011 72.42 0.00 0.00 0.00 307,089.46 0.00 4,240.40

9,076.43 0.00 2012 75.14 0.00 0.00 0.00 222,545.07 0.00 2,961.74

6,753.23 0.00 2013 76.89 0.00 0.00 0.00 169,480.23 0.00 2,204.19

5,049.41 0.00 2014 79.22 0.00 0.00 0.00 130,586.10 0.00 1,648.40

3,826.30 0.00 2015 80.80 0.00 0.00 0.00 100,987.16 0.00 1,249.84

1,769.58 0.00 2016 82.41 0.00 0.00 0.00 47,650.75 0.00 578.22

Rem

Total

Ult

0.00

59,220.19

59,220.19

0.00

0.00

0.00

0.00 0.00 0.00

73.30

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 -6,593.00 182,363.29 178,217.30 0.00 0.00 172,261.45 0.00 0.00 89,820.72 1

2011 0.00 131,372.10 294,739.92 0.00 0.00 111,011.69 0.00 0.00 64,705.66 1

2012 0.00 103,145.99 377,914.61 0.00 0.00 68,595.83 0.00 0.00 50,803.25 1

2013 0.00 75,961.65 433,589.81 0.00 0.00 56,104.64 0.00 0.00 37,413.95 1

2014 0.00 57,246.83 471,736.20 0.00 0.00 45,143.06 0.00 0.00 28,196.20 1

2015 0.00 43,111.37 497,853.48 0.00 0.00 36,641.83 0.00 0.00 21,233.96 1

2016 0.00 26,267.11 512,502.43 0.00 0.00 8,446.11 0.00 0.00 12,937.53 1

-6,593.00 619,468.35

Rem.

Total

0.00 0.00 0.00 0.00 0.00

512,502.43 0.00

0.00

0.00 498,204.60 0.00 0.00 305,111.27

0.00 0.00 0.00

0.00

0.00 0.00 1,416,191.22 0.00 19,320.84

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :

1,645,359.168 bbl/month

299,026.250 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000


619,468.35

560,330.28

512,502.43

473,217.21

440,497.19

619,468.35

0.00

-6,593.000

0.000 b = -76.73 / -92.96

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : >1000


Proved Rsv Class

Non-Producing Rsv Category


Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

3,262.01 0.00 2010 68.01 0.00 0.00 0.00 78,818.65 0.00 1,158.93

8,827.89 0.00 2011 72.42 0.00 0.00 0.00 219,714.53 0.00 3,033.89

6,752.33 0.00 2012 75.14 0.00 0.00 0.00 173,199.14 0.00 2,305.02

4,432.20 0.00 2013 76.89 0.00 0.00 0.00 116,807.86 0.00 1,519.16

3,039.72 0.00 2014 79.22 0.00 0.00 0.00 82,808.77 0.00 1,045.30

2,156.06 0.00 2015 80.80 0.00 0.00 0.00 60,056.48 0.00 743.27

953.87 0.00 2016 82.41 0.00 0.00 0.00 27,224.10 0.00 330.35

Rem

Total

Ult

0.00

29,424.07

29,424.07

0.00

0.00

0.00

0.00 0.00 0.00

74.85

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 33,946.00 5,719.76 4,009.55 0.00 0.00 36,335.69 0.00 0.00 2,817.20 2

2011 8,836.26 87,149.61 80,936.66 0.00 0.00 80,804.23 0.00 0.00 42,924.43 2

2012 1,786.37 78,571.05 144,226.27 0.00 0.00 54,142.55 0.00 0.00 38,699.17 2

2013 4,435.85 48,545.53 179,652.96 0.00 0.00 39,916.00 0.00 0.00 23,910.48 2

2014 2,067.45 34,080.13 202,296.86 0.00 0.00 29,875.45 0.00 0.00 16,785.74 2

2015 585.16 24,237.39 216,963.22 0.00 0.00 23,296.11 0.00 0.00 11,937.82 2

2016 0.00 14,665.67 225,141.39 0.00 0.00 5,335.04 0.00 0.00 7,223.39 2

51,657.08 292,969.14

Rem.

Total

0.00 0.00 0.00 0.00 0.00

225,141.39 0.00

0.00

0.00 269,705.05 0.00 0.00 144,298.23

0.00 0.00 0.00

0.00

0.00 0.00 758,629.51 0.00 10,135.92


Internal ROR (%) :


Years to Payout :


292,969.14

255,516.56

225,141.39

200,141.86

179,295.29

292,969.14

1.09

9,994.151

23.53 / -78.08

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 386.59


Piriri Concession


Case :

Reserve Cat. : Proved Non-Producing Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Piriri - Proved Non-Prod

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

1,147.93 0.00 2010 68.01 0.00 0.00 0.00 31,881.41 0.00 468.78

1,837.05 0.00 2011 72.42 0.00 0.00 0.00 54,331.08 0.00 750.22

1,211.83 0.00 2012 75.14 0.00 0.00 0.00 37,187.39 0.00 494.91

870.53 0.00 2013 76.89 0.00 0.00 0.00 27,336.78 0.00 355.53

638.39 0.00 2014 79.22 0.00 0.00 0.00 20,655.91 0.00 260.74

474.50 0.00 2015 80.80 0.00 0.00 0.00 15,660.93 0.00 193.82

228.06 0.00 2016 82.41 0.00 0.00 0.00 7,677.52 0.00 93.16

Rem

Total

Ult

0.00

6,408.27

6,408.27

0.00

0.00

0.00

0.00 0.00 0.00

74.41

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 13,183.00 3,281.16 2,591.19 0.00 0.00 13,801.17 0.00 0.00 1,616.09 1

2011 812.94 22,329.21 22,362.23 0.00 0.00 20,190.96 0.00 0.00 10,997.97 1

2012 323.56 16,661.23 35,785.11 0.00 0.00 11,996.32 0.00 0.00 8,206.28 1

2013 1,167.33 11,157.72 43,922.45 0.00 0.00 9,516.14 0.00 0.00 5,495.59 1

2014 595.34 8,278.15 49,419.76 0.00 0.00 7,705.12 0.00 0.00 4,077.30 1

2015 55.20 6,230.10 53,192.40 0.00 0.00 6,307.07 0.00 0.00 3,068.56 1

2016 0.00 4,115.55 55,487.39 0.00 0.00 1,534.92 0.00 0.00 2,027.06 1

16,137.37 72,053.12

Rem.

Total

0.00 0.00 0.00 0.00 0.00

55,487.39 0.00

0.00

0.00 71,051.69 0.00 0.00 35,488.85

0.00 0.00 0.00

0.00

0.00 0.00 194,731.03 0.00 2,617.16

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :

95,660.417 bbl/month


0.00

mcf/bbl

mcf/bbl

0.000

0.000


72,053.12

62,900.64

55,487.39

49,390.23

44,306.46

72,053.12

0.00

3,477.619

0.000 b = 16.96 / -70.82

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 333.51


Rubiales Concession


Case :

Reserve Cat. : Proved Non-Producing Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Rubiales - Proved Non-Prod

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

2,114.08 0.00 2010 68.01 0.00 0.00 0.00 46,937.23 0.00 690.15

6,990.85 0.00 2011 72.42 0.00 0.00 0.00 165,383.45 0.00 2,283.67

5,540.51 0.00 2012 75.14 0.00 0.00 0.00 136,011.75 0.00 1,810.11

3,561.67 0.00 2013 76.89 0.00 0.00 0.00 89,471.08 0.00 1,163.62

2,401.34 0.00 2014 79.22 0.00 0.00 0.00 62,152.86 0.00 784.56

1,681.56 0.00 2015 80.80 0.00 0.00 0.00 44,395.55 0.00 549.45

725.81 0.00 2016 82.41 0.00 0.00 0.00 19,546.57 0.00 237.19

Rem

Total

Ult

0.00

23,015.80

23,015.80

0.00

0.00

0.00

0.00 0.00 0.00

75.00

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 20,763.00 2,438.61 1,418.36 0.00 0.00 22,534.52 0.00 0.00 1,201.11 1

2011 8,023.32 64,820.39 58,574.43 0.00 0.00 60,613.27 0.00 0.00 31,926.46 1

2012 1,462.80 61,909.82 108,441.16 0.00 0.00 42,146.23 0.00 0.00 30,492.90 1

2013 3,268.52 37,387.81 135,730.51 0.00 0.00 30,399.86 0.00 0.00 18,414.89 1

2014 1,472.11 25,801.98 152,877.10 0.00 0.00 22,170.33 0.00 0.00 12,708.44 1

2015 529.96 18,007.29 163,770.83 0.00 0.00 16,989.04 0.00 0.00 8,869.26 1

2016 0.00 10,550.12 169,654.00 0.00 0.00 3,800.12 0.00 0.00 5,196.33 1

35,519.71 220,916.02

Rem.

Total

0.00 0.00 0.00 0.00 0.00

169,654.00 0.00

0.00

0.00 198,653.36 0.00 0.00 108,809.38

0.00 0.00 0.00

0.00

0.00 0.00 563,898.48 0.00 7,518.76

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :

176,173.334 bbl/month

121,970.833 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000


220,916.02

192,615.93

169,654.00

150,751.63

134,988.83

220,916.02

0.00

6,516.531

0.000 b = 27.03 / -80.77

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 413.30


Proved Rsv Class



Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

23,745.44 0.00 2010 68.01 0.00 0.00 0.00 566,575.77 0.00 8,330.77

55,566.14 0.00 2011 72.42 0.00 0.00 0.00 1,406,773.14 0.00 19,425.20

62,094.83 0.00 2012 75.14 0.00 0.00 0.00 1,628,072.25 0.00 21,667.18

57,675.84 0.00 2013 76.89 0.00 0.00 0.00 1,531,559.85 0.00 19,918.84

53,036.33 0.00 2014 79.22 0.00 0.00 0.00 1,440,190.57 0.00 18,179.63

47,745.65 0.00 2015 80.80 0.00 0.00 0.00 1,316,618.78 0.00 16,294.79

19,667.81 0.00 2016 82.41 0.00 0.00 0.00 553,852.21 0.00 6,720.69

Rem

Total

Ult

0.00

319,532.03

319,532.03

0.00

0.00

0.00

0.00 0.00 0.00

76.39

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 229,514.00 77,621.26 65,110.77 0.00 0.00 221,209.15 0.00 0.00 38,231.36 2

2011 95,421.00 548,782.87 547,851.44 0.00 0.00 492,273.23 0.00 0.00 270,296.04 2

2012 50,769.44 740,256.46 1,142,832.21 0.00 0.00 472,442.42 0.00 0.00 364,603.93 2

2013 80,322.83 658,202.14 1,622,465.18 0.00 0.00 468,845.76 0.00 0.00 324,189.12 2

2014 62,131.61 621,606.61 2,034,712.15 0.00 0.00 450,287.91 0.00 0.00 306,164.45 2

2015 26,376.49 575,569.56 2,382,642.50 0.00 0.00 431,183.25 0.00 0.00 283,489.48 2

2016 900.93 309,346.83 2,555,129.09 0.00 0.00 91,239.60 0.00 0.00 152,364.86 2

545,436.30 3,531,385.72

Rem.

Total

0.00 0.00 0.00 0.00 0.00

2,555,129.09 0.00

0.00

0.00 2,627,481.32 0.00 0.00 1,739,339.24

0.00 0.00 0.00

0.00

0.00 0.00 8,443,642.58 0.00 110,537.11


Internal ROR (%) :


Years to Payout :


3,531,385.72

2,984,857.00

2,555,129.09

2,211,941.89

1,933,978.78

3,531,385.72

1.26

193,883.387

14.18 / 41.36

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 451.72


Piriri Concession


Case :

Reserve Cat. : Proved Undeveloped Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Piriri - Proved Undeveloped

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

7,181.74 0.00 2010 68.01 0.00 0.00 0.00 199,050.97 0.00 2,926.79

16,000.14 0.00 2011 72.42 0.00 0.00 0.00 472,280.51 0.00 6,521.41

17,380.61 0.00 2012 75.14 0.00 0.00 0.00 532,323.03 0.00 7,084.42

13,602.09 0.00 2013 76.89 0.00 0.00 0.00 426,261.03 0.00 5,543.78

10,707.28 0.00 2014 79.22 0.00 0.00 0.00 345,892.40 0.00 4,366.23

8,650.50 0.00 2015 80.80 0.00 0.00 0.00 285,226.68 0.00 3,530.03

3,628.15 0.00 2016 82.41 0.00 0.00 0.00 122,095.76 0.00 1,481.56

Rem

Total

Ult

0.00

77,150.50

77,150.50

0.00

0.00

0.00

0.00 0.00 0.00

75.77

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 78,689.00 28,150.04 23,823.24 0.00 0.00 78,346.98 0.00 0.00 13,864.95 1

2011 38,994.60 178,437.67 180,452.01 0.00 0.00 166,961.03 0.00 0.00 87,887.21 1

2012 9,168.00 245,341.42 377,938.50 0.00 0.00 156,973.81 0.00 0.00 120,839.80 1

2013 14,697.73 186,340.54 514,004.39 0.00 0.00 133,443.09 0.00 0.00 91,779.67 1

2014 8,659.46 151,215.67 614,493.73 0.00 0.00 111,537.91 0.00 0.00 74,479.36 1

2015 2,705.00 124,274.49 689,703.05 0.00 0.00 97,037.36 0.00 0.00 61,209.83 1

2016 0.00 67,780.23 727,499.87 0.00 0.00 20,931.24 0.00 0.00 33,384.29 1

152,913.79 981,540.07

Rem.

Total

0.00 0.00 0.00 0.00 0.00

727,499.87 0.00

0.00

0.00 765,231.42 0.00 0.00 483,445.11

0.00 0.00 0.00

0.00

0.00 0.00 2,383,130.38 0.00 31,454.22

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :

598,478.334 bbl/month

609,702.084 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000


981,540.07

840,092.00

727,499.87

636,508.24

561,962.65

981,540.07

0.09

53,927.813

0.000 b = 14.49 / 92.98

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 442.83


Rubiales Concession


Case :

Reserve Cat. : Proved Undeveloped Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Rubiales - Proved Undeveloped

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

16,563.70 0.00 2010 68.01 0.00 0.00 0.00 367,524.80 0.00 5,403.98

39,566.00 0.00 2011 72.42 0.00 0.00 0.00 934,492.63 0.00 12,903.79

44,714.22 0.00 2012 75.14 0.00 0.00 0.00 1,095,749.22 0.00 14,582.77

44,073.75 0.00 2013 76.89 0.00 0.00 0.00 1,105,298.82 0.00 14,375.07

42,329.05 0.00 2014 79.22 0.00 0.00 0.00 1,094,298.17 0.00 13,813.41

39,095.15 0.00 2015 80.80 0.00 0.00 0.00 1,031,392.10 0.00 12,764.75

16,039.66 0.00 2016 82.41 0.00 0.00 0.00 431,756.45 0.00 5,239.13

Rem

Total

Ult

0.00

242,381.53

242,381.53

0.00

0.00

0.00

0.00 0.00 0.00

76.63

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 150,825.00 49,471.21 41,287.53 0.00 0.00 142,862.17 0.00 0.00 24,366.42 1

2011 56,426.40 370,345.19 367,399.42 0.00 0.00 325,312.21 0.00 0.00 182,408.83 1

2012 41,601.43 494,915.05 764,893.71 0.00 0.00 315,468.61 0.00 0.00 243,764.13 1

2013 65,625.10 471,861.60 1,108,460.79 0.00 0.00 335,402.67 0.00 0.00 232,409.45 1

2014 53,472.15 470,390.94 1,420,218.42 0.00 0.00 338,750.00 0.00 0.00 231,685.09 1

2015 23,671.49 451,295.06 1,692,939.45 0.00 0.00 334,145.89 0.00 0.00 222,279.66 1

2016 900.93 241,566.60 1,827,629.22 0.00 0.00 70,308.36 0.00 0.00 118,980.56 1

392,522.51 2,549,845.66

Rem.

Total

0.00 0.00 0.00 0.00 0.00

1,827,629.22 0.00

0.00

0.00 1,862,249.90 0.00 0.00 1,255,894.13

0.00 0.00 0.00

0.00

0.00 0.00 6,060,512.20 0.00 79,082.90

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :

1,380,308.335 bbl/month

2,680,620.836 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000


2,549,845.66

2,144,765.00

1,827,629.22

1,575,433.65

1,372,016.14

2,549,845.66

0.34

139,955.574

0.000 b = 14.06 / 34.19

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 456.23


Probable Rsv Class



Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

762.12 0.00 2010 68.01 0.00 0.00 0.00 19,576.14 0.00 287.84

2,144.01 0.00 2011 72.42 0.00 0.00 0.00 54,911.31 0.00 758.23

2,449.27 0.00 2012 75.14 0.00 0.00 0.00 67,730.02 0.00 901.38

11,073.37 0.00 2013 76.89 0.00 0.00 0.00 286,702.94 0.00 3,728.74

15,546.45 0.00 2014 79.22 0.00 0.00 0.00 408,555.62 0.00 5,157.23

12,287.73 0.00 2015 80.80 0.00 0.00 0.00 328,880.09 0.00 4,070.30

4,988.91 0.00 2016 82.41 0.00 0.00 0.00 136,282.72 0.00 1,653.72

Rem

Total

Ult

0.00

49,251.85

49,251.85

0.00

0.00

0.00

0.00 0.00 0.00

78.67

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 -3,120.00 9,656.94 9,565.51 0.00 0.00 8,282.79 0.00 0.00 4,756.40 2

2011 2,638.74 20,765.22 27,872.50 0.00 0.00 21,279.70 0.00 0.00 10,227.64 2

2012 6,276.73 26,285.91 48,828.57 0.00 0.00 22,220.59 0.00 0.00 12,946.79 2

2013 44,623.80 103,130.74 122,867.01 0.00 0.00 88,152.66 0.00 0.00 50,795.74 2

2014 21,194.02 174,218.88 238,288.88 0.00 0.00 127,333.42 0.00 0.00 85,809.30 2

2015 3,234.96 145,645.36 326,429.88 0.00 0.00 108,264.01 0.00 0.00 71,735.77 2

2016 450.46 75,894.51 368,741.38 0.00 0.00 22,556.87 0.00 0.00 37,380.88 2

75,298.71 555,597.55

Rem.

Total

0.00 0.00 0.00 0.00 0.00

368,741.38 0.00

0.00

0.00 398,090.04 0.00 0.00 273,652.53

0.00 0.00 0.00

0.00

0.00 0.00 1,302,638.84 0.00 16,557.44


Internal ROR (%) :


Years to Payout :


555,597.55

449,561.27

368,741.38

306,236.60

257,250.34

555,597.55

2.99

35,115.277

11.50 / 14.79

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : >1000


Piriri Concession


Case :

Reserve Cat. : Probable Undeveloped Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Piriri - Probable Undeveloped

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

492.75 0.00 2010 68.01 0.00 0.00 0.00 13,676.95 0.00 201.10

742.41 0.00 2011 72.42 0.00 0.00 0.00 21,940.06 0.00 302.96

1,311.74 0.00 2012 75.14 0.00 0.00 0.00 40,122.49 0.00 533.97

1,503.80 0.00 2013 76.89 0.00 0.00 0.00 46,856.04 0.00 609.39

1,185.52 0.00 2014 79.22 0.00 0.00 0.00 37,970.89 0.00 479.31

923.82 0.00 2015 80.80 0.00 0.00 0.00 30,228.39 0.00 374.11

372.55 0.00 2016 82.41 0.00 0.00 0.00 12,466.30 0.00 151.27

Rem

Total

Ult

0.00

6,532.59

6,532.59

0.00

0.00

0.00

0.00 0.00 0.00

76.64

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 9,386.00 -1,014.30 -1,423.73 0.00 0.00 5,804.84 0.00 0.00 -499.58 1

2011 -2,371.50 10,491.34 7,981.40 0.00 0.00 8,652.85 0.00 0.00 5,167.38 1

2012 7,586.60 13,171.95 18,312.45 0.00 0.00 12,876.26 0.00 0.00 6,487.68 1

2013 1,750.99 19,692.52 32,685.00 0.00 0.00 15,713.22 0.00 0.00 9,699.30 1

2014 1,190.68 15,712.64 43,117.49 0.00 0.00 13,328.51 0.00 0.00 7,739.06 1

2015 55.20 12,620.53 50,761.52 0.00 0.00 11,336.57 0.00 0.00 6,216.08 1

2016 0.00 6,752.33 54,526.75 0.00 0.00 2,388.20 0.00 0.00 3,325.77 1

17,597.97 77,427.00

Rem.

Total

0.00 0.00 0.00 0.00 0.00

54,526.75 0.00

0.00

0.00 70,100.45 0.00 0.00 38,135.69

0.00 0.00 0.00

0.00

0.00 0.00 203,261.11 0.00 2,652.11

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :



0.00

mcf/bbl

mcf/bbl

0.000

0.000


77,427.00

64,601.63

54,526.75

46,492.74

39,998.32

77,427.00

0.87

10,299.556

0.000 b = 6.29 / 12.33

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 197.98


Rubiales Concession


Case :

Reserve Cat. : Probable Undeveloped Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Rubiales - Probable Undeveloped

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

269.37 0.00 2010 68.01 0.00 0.00 0.00 5,899.18 0.00 86.74

1,401.60 0.00 2011 72.42 0.00 0.00 0.00 32,971.24 0.00 455.28

1,137.53 0.00 2012 75.14 0.00 0.00 0.00 27,607.54 0.00 367.41

9,569.57 0.00 2013 76.89 0.00 0.00 0.00 239,846.91 0.00 3,119.35

14,360.93 0.00 2014 79.22 0.00 0.00 0.00 370,584.73 0.00 4,677.92

11,363.91 0.00 2015 80.80 0.00 0.00 0.00 298,651.71 0.00 3,696.18

4,616.36 0.00 2016 82.41 0.00 0.00 0.00 123,816.42 0.00 1,502.44

Rem

Total

Ult

0.00

42,719.26

42,719.26

0.00

0.00

0.00

0.00 0.00 0.00

79.06

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 -12,506.00 10,671.24 10,989.24 0.00 0.00 2,477.95 0.00 0.00 5,255.98 1

2011 5,010.24 10,273.88 19,891.10 0.00 0.00 12,626.85 0.00 0.00 5,060.27 1

2012 -1,309.86 13,113.96 30,516.12 0.00 0.00 9,344.33 0.00 0.00 6,459.11 1

2013 42,872.80 83,438.23 90,182.01 0.00 0.00 72,439.44 0.00 0.00 41,096.44 1

2014 20,003.35 158,506.24 195,171.39 0.00 0.00 114,004.91 0.00 0.00 78,070.24 1

2015 3,179.75 133,024.83 275,668.36 0.00 0.00 96,927.44 0.00 0.00 65,519.69 1

2016 450.46 69,142.18 314,214.63 0.00 0.00 20,168.67 0.00 0.00 34,055.10 1

57,700.74 478,170.55

Rem.

Total

0.00 0.00 0.00 0.00 0.00

314,214.63 0.00

0.00

0.00 327,989.59 0.00 0.00 235,516.84

0.00 0.00 0.00

0.00

0.00 0.00 1,099,377.72 0.00 13,905.33

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :


767,290.834 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000


478,170.55

384,959.64

314,214.63

259,743.86

217,252.02

478,170.55

3.05

24,815.721

0.000 b = 13.66 / 15.29

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : >1000


Possible Rsv Class



Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

682.92 0.00 2010 68.01 0.00 0.00 0.00 15,723.80 0.00 231.20

1,737.40 0.00 2011 72.42 0.00 0.00 0.00 42,492.30 0.00 586.75

3,318.89 0.00 2012 75.14 0.00 0.00 0.00 90,626.64 0.00 1,206.10

4,311.75 0.00 2013 76.89 0.00 0.00 0.00 126,790.09 0.00 1,648.98

9,746.23 0.00 2014 79.22 0.00 0.00 0.00 267,982.15 0.00 3,382.76

14,736.15 0.00 2015 80.80 0.00 0.00 0.00 401,903.26 0.00 4,974.05

6,122.06 0.00 2016 82.41 0.00 0.00 0.00 170,395.16 0.00 2,067.65

Rem

Total

Ult

0.00

40,655.38

40,655.38

0.00

0.00

0.00

0.00 0.00 0.00

79.16

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 15,361.68 -4,251.79 -4,850.54 0.00 0.00 6,708.07 0.00 0.00 -2,094.17 2

2011 8,181.42 11,877.62 5,340.40 0.00 0.00 16,583.09 0.00 0.00 5,850.17 2

2012 17,752.35 29,450.44 28,408.76 0.00 0.00 28,918.42 0.00 0.00 14,505.44 2

2013 4,372.18 53,794.74 67,685.07 0.00 0.00 42,127.26 0.00 0.00 26,495.92 2

2014 31,855.98 101,884.12 134,569.65 0.00 0.00 84,060.31 0.00 0.00 50,181.73 2

2015 22,434.92 167,174.96 235,202.31 0.00 0.00 129,953.47 0.00 0.00 82,339.91 2

2016 450.46 95,319.04 288,344.87 0.00 0.00 27,677.47 0.00 0.00 46,948.19 2

100,408.99 455,249.14

Rem.

Total

0.00 0.00 0.00 0.00 0.00

288,344.87 0.00

0.00

0.00 336,028.09 0.00 0.00 224,227.19

0.00 0.00 0.00

0.00

0.00 0.00 1,115,913.41 0.00 14,097.49


Internal ROR (%) :


Years to Payout :


455,249.14

359,960.75

288,344.87

233,688.13

191,384.97

455,249.14

3.26

63,617.749

5.53 / 7.11

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 169.87


Piriri Concession


Case :

Reserve Cat. : Possible Undeveloped Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Piriri - Possible Undeveloped

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

98.19 0.00 2010 68.01 0.00 0.00 0.00 2,727.78 0.00 40.11

232.14 0.00 2011 72.42 0.00 0.00 0.00 6,867.53 0.00 94.83

1,491.08 0.00 2012 75.14 0.00 0.00 0.00 45,768.36 0.00 609.11

2,953.95 0.00 2013 76.89 0.00 0.00 0.00 92,764.04 0.00 1,206.45

2,457.18 0.00 2014 79.22 0.00 0.00 0.00 79,495.19 0.00 1,003.47

2,039.62 0.00 2015 80.80 0.00 0.00 0.00 67,306.28 0.00 833.00

869.96 0.00 2016 82.41 0.00 0.00 0.00 29,281.72 0.00 355.32

Rem

Total

Ult

0.00

10,142.11

10,142.11

0.00

0.00

0.00

0.00 0.00 0.00

78.27

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 4,401.68 -1,941.62 -2,089.77 0.00 0.00 1,224.04 0.00 0.00 -956.32 1

2011 -786.42 3,197.83 779.63 0.00 0.00 2,881.07 0.00 0.00 1,575.05 1

2012 19,852.91 7,959.59 6,437.74 0.00 0.00 14,035.46 0.00 0.00 3,920.40 1

2013 2,971.38 40,243.24 35,830.37 0.00 0.00 29,728.11 0.00 0.00 19,821.30 1

2014 1,894.26 34,444.38 58,722.59 0.00 0.00 26,191.40 0.00 0.00 16,965.14 1

2015 662.45 29,135.66 76,354.29 0.00 0.00 23,157.77 0.00 0.00 14,350.40 1

2016 0.00 16,263.12 85,422.89 0.00 0.00 5,008.41 0.00 0.00 8,010.19 1

28,996.26 129,302.20

Rem.

Total

0.00 0.00 0.00 0.00 0.00

85,422.89 0.00

0.00

0.00 102,226.28 0.00 0.00 63,686.16

0.00 0.00 0.00

0.00

0.00 0.00 324,210.90 0.00 4,142.29

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :

8,182.083 bbl/month

145,391.667 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000


129,302.20

104,506.01

85,422.89

70,525.21

58,743.51

129,302.20

2.54

19,202.987

0.000 b = 5.45 / 7.13

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 170.53


Rubiales Concession


Case :

Reserve Cat. : Possible Undeveloped Field :

Reservoir :

Co., State :

AFIT ECONOMIC PROJECTION Rubiales - Possible Undeveloped

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Gas

(MMcf)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year





Partner : All Cases


Date : 2/3/2010 11:46:38AM

As Of Date : 1/1/2010


Custom Selection

584.73 0.00 2010 68.01 0.00 0.00 0.00 12,996.01 0.00 191.09

1,505.26 0.00 2011 72.42 0.00 0.00 0.00 35,624.77 0.00 491.92

1,827.80 0.00 2012 75.14 0.00 0.00 0.00 44,858.28 0.00 597.00

1,357.80 0.00 2013 76.89 0.00 0.00 0.00 34,026.06 0.00 442.53

7,289.05 0.00 2014 79.22 0.00 0.00 0.00 188,486.96 0.00 2,379.29

12,696.53 0.00 2015 80.80 0.00 0.00 0.00 334,596.98 0.00 4,141.05

5,252.10 0.00 2016 82.41 0.00 0.00 0.00 141,113.44 0.00 1,712.33

Rem

Total

Ult

0.00

30,513.27

30,513.27

0.00

0.00

0.00

0.00 0.00 0.00

79.53

0.00

0.00

0.00 0.00

Year

Net Tax

Prod+Adv

(M$)

Net

Investment

(M$)

Net

Op Costs

(M$)

Net

Depreciation

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Net

Depletion

(M$)

Well

Count

Net

Profits

(M$)

Federal

Income Tax

(M$)

2010 10,960.00 -2,310.17 -2,760.77 0.00 0.00 5,484.03 0.00 0.00 -1,137.84 1

2011 8,967.84 8,679.79 4,560.77 0.00 0.00 13,702.02 0.00 0.00 4,275.12 1

2012 -2,100.57 21,490.85 21,971.03 0.00 0.00 14,882.95 0.00 0.00 10,585.05 1

2013 1,400.79 13,551.49 31,854.70 0.00 0.00 12,399.15 0.00 0.00 6,674.62 1

2014 29,961.72 67,439.74 75,847.06 0.00 0.00 57,868.91 0.00 0.00 33,216.59 1

2015 21,772.47 138,039.31 158,848.02 0.00 0.00 106,795.69 0.00 0.00 67,989.51 1

2016 450.46 79,055.93 202,921.98 0.00 0.00 22,669.06 0.00 0.00 38,937.99 1

71,412.73 325,946.94

Rem.

Total

0.00 0.00 0.00 0.00 0.00

202,921.98 0.00

0.00

0.00 233,801.81 0.00 0.00 160,541.03

0.00 0.00 0.00

0.00

0.00 0.00 791,702.51 0.00 9,955.20

Major Phase : Oil

Perfs : 0 - 0

Initial Rate :


Abandonment :

Beg Ratio :

End Ratio :




Internal ROR (%) :


Years to Payout :


872,958.334 bbl/month

0.00

mcf/bbl

mcf/bbl

0.000

0.000


325,946.94

255,454.74

202,921.98

163,162.92

132,641.46

325,946.94

2.91

44,414.762

0.000 b = 5.57 / 7.11

PW 0.00% :

PW 5.00% :

PW 10.00% :

PW 15.00% :

PW 20.00% :

PW 0.00% : 169.52

reserves certification report for the rubiales field, colombia

Documents