0 EVALUATION OF THE INTERESTS OF PACIFIC RUBIALES …€¦ · IN THE OIL & GAS PROPERTIES WITH...

0

EVALUATION OF THE INTERESTS OF

PACIFIC RUBIALES ENERGY CORP.

IN THE OIL & GAS PROPERTIES WITH

PROVED AND PROBABLE RESERVES

IN COLOMBIA FOR YEAR-ENDING 2008

Volume 2 of 2

(Forecast Prices and Costs)

Prepared For

Pacific Rubiales Energy Corp.

By

Petrotech Engineering Ltd.

Effective Date

December 31, 2008

1

Table of Contents VII Abanico Block in the Upper Magdalena Valley VIII Quifa Block in the Llanos Basin IX Las Quinchas Block in the Middle Magdalena Valley X Buganviles Block in the Upper Magdalena Valley XI Guasimo Block in the Upper Magdalena Valley XII Cicuco Block in the Lower Magdalena Valley Figures Description VII-1 Abanico Block in the Upper Magdalena Valley VII-2 Productive and Prospectived Areas of the Abanico Field VII-3 Upper Guadalupe Development Map VII-4 Abanico Field – Upper Guadalupe Oil Rate vs. Time Log Plot VII-5 Abanico Field – Upper Guadalupe Oil Rate vs. Cumulative Oil Plot VII-6 Abanico Field – Upper Guadalupe Water Rate vs. Time Log Plot VII-7 Abanico Field Proved Production Profile VII-8 Abanico Field Proved + Probable Production Profile VIII-1 Quifa Block in Llanos Basin VIII-2 Electric Log Section of Quifa 5 Well VIII-3 Structure Map of Quifa 5 Area VIII-4 Rubiales Field Well Models VIII-4 Rubiales Field Well Models Comparison IX-1 Acacia Este Seismic Closure Mapping IX-2 Acacia Este 2 D Seismic Line IX-3 Analog Fields IX-4 Acacia Este #1 Test Results IX-5 Acacia Este #2 Test Results IX-6 Acacia Este #1 Electric Log Section IX-7 Acacia Este #2 Electric Log Section IX-8 Acacia Este #4 Electric Log Section IX-9 Acacia Este #5 Electric Log Section IX-10 Acacia Este #1 AOF Test Results X-1 Location of Buganviles Block in the Upper Magdalena Valley X-2 Caballos Limestone Structure Map of Delta 1 Well X-3 Delta 1-ST2 and Gualanday-3 Cross Section X-4 Delta 1-ST2 Well Petrophysical Log X-5 Rate versus Time for Delta 1-ST2 X-6 Rate versus Cumulative Production for Delta 1-ST2 XI-1 Location of Guasimo Block in the Upper Magdalena Valley XI-2 Upper Guadalupe Structure Map of Lisa Field XI-3 Upper Guadalupe Trap Model of Lisa Field XI-4 Lisa 1 Well Petrophysical Log XI-5 Rate versus Time for Lisa 1 Well XI-6 Rate versus Cumulative Production for Lisa 1 Well

2

XII-1 Cicuco Block with the Oil and Gas Fields XII-2 Violo Cienaga de Oro gas Tables Description VII-1 Summary of Total Proved Reserves and Cash Flow Values of Abanico Field VII-2 Summary of Total Proved + Probable Reserves and Cash Flow Values of Abanico Field VII-3 Summary of Total Proved Developed Producing Reserves and Cash Flow Values of

Abanico Field VII-4 Summary of Total Proved Developed Non-Producing and Proved Undeveloped

Reserves and Cash Flow Values of Abanico Field VII-5 Summary of Total Probable Reserves and Cash Flow Values of Abanico Field VII-6 Summary of Total Probable Developed Non-Producing and Undeveloped Reserves and

Cash Flow Values of Abanico Field VII-7 Total Proved Reserves and Cash Flow Values of Abanico Field VII-8 Total Proved + Probable Reserves and Cash Flow Values of Abanico Field VII-9 Total Probable Reserves and Cash Flow Values of Abanico Field VII-10 Proved Developed Producing Reserves and Cash Flow Values of Abanico Field VII-11 Proved + Probable Developed Producing Reserves and Cash Flow Values of

Abanico Field VII-12 Probable Developed Producing Reserves and Cash Flow Values of Abanico Field VII-13 Proved Developed Non-Producing Reserves and Cash Flow Values of Abanico Field VII-14 Proved + Probable Developed Non-Producing Reserves and Cash Flow Values of

Abanico Field VII-15 Probable Developed Non-Producing Reserves and Cash Flow Values of Abanico Field VII-16 Proved Undeveloped Reserves and Cash Flow Values of Abanico Field VII-17 Proved + Probable Undeveloped Reserves and Cash Flow Values of Abanico Field VII-18 Probable Undeveloped Reserves and Cash Flow Values of Abanico Field VIII-1 Summary of Proved + Probable Reserves and Cash Flow Values of Quifa 5 Cluster

Wells VIII-2 Proved Developed Producing Reserves and Cash Flow Values of Quifa 5 Well VIII-3 Proved Undeveloped Reserves and Cash Flow Values of Quifa 5 Offset Wells VIII-4 Probable Undeveloped Reserves and Cash Flow Values of Quifa 5 Offset Wells IX-1 Summary of Acacia Este Proved Reserves and Cash Flow Values IX-2 Summary of Acacia Este Proved + ProbableReserves and Cash Flow Values IX-3 Proved Developed Producing Reserves and Cash Flow Values of Acacia Este #1 IX-4 Probable Developed Producing Reserves and Cash Flow Values of Acacia Este #1 IX-5 Proved + Probable Developed Producing Reserves and Cash Flow Values of

Acacia Este #1 IX-6 Proved Undeveloped Reserves and Cash Flow Values of Acacia Este #2 IX-7 Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #2 IX-8 Proved + Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #2 IX-9 Proved Undeveloped Reserves and Cash Flow Values of Acacia Este #4 IX-10 Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #4 IX-11 Proved + Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #4 IX-12 Proved Undeveloped Reserves and Cash Flow Values of Acacia Este #5

3

IX-13 Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #5 IX-14 Proved + Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #5 X-1 Summary of Delta Oil Field Proved and Probable Reserves and Cash Flow Values X-2 Proved Developed Producing Reserve and Cash Flow Values of Delta 1 Well X-3 Probable Developed Producing Reserve and Cash Flow Values of Delta 1 Well X-4 Probable Undeveloped Producing Reserve and Cash Flow Values of Delta 1 Well XI-1 Summary of Lisa Oil Field Proved and Probable Reserves and Cash Flow Values XI-2 Proved Developed Producing Reserve and Cash Flow Values of Lisa 1 Well XI-3 Proved Undeveloped Reserve and Cash Flow Values of Lisa Oil Field XI-4 Probable Developed Producing Reserve and Cash Flow Values of Lisa 1 Well XI-5 Probable Undeveloped Reserve and Cash Flow Values of Lisa Oil Field XII-1 Summary of Violo Gas Field Proved + Probable Reserves and Cash Flow Values XII-2 Proved Undeveloped Reserve and Cash Flow Values of Violo Gas Field XII-3 Proved + Probable Undeveloped Reserve and Cash Flow Values of Violo Gas Field Appendices Description A Conversion Factors and Abbreviations B Production Plots of Abanico Wells

4

VII Evaluation of the Abanico Block in the Upper Magdalena Valley

The Abanico Association Contract (see Figure VII-1) is with Ecopetrol with an effective date of October 11, 1996 and expires in July 2024. The current area of the block is 25,315 hectares. Production is subject to 5% royalty for oil and 8 to 25% sliding scale royalty for gas. Through the ownership of Kappa Energy Holdings Limited, the Company has various working interests in the Abanico field as follows: Well Working Interest Abanico 1, 2 21.14% Abanico 4 21.51% Abanico 5 19.75% Abanico 6 21.31% Abanico 7 21.11% Abancio 8, 9, 11, 12, 14, 15, 16, 21, 22, 23, 24, 25, and 26 22.50% Abanico 17, 18, 19, 27, and 28 25.00% The Company has a 14.225% working interest in the Ventilador 2 gas well located within the Abanico Field. Due to insufficient pressure, the Ventilador well is currently shut-in and no reserve is assigned until compression is installed. Kappa’s working interests and expected royalty rates in the remaining exploration areas are as follows: Prospect Name Working Interest (%) Royalty Rate (%) Abanico North Block 22.50 5.00% Abanico North Fault Block 2 26.95 8.00% sliding scale Abanico North Fault Block 3 22.50 5.00% Abanico Field The Abanico Field was discovered in September 1999 with the drilling of the Abanico 1 well to a total depth of 3,070 feet. The Guadalupe formation was tested in three intervals as follows:

2,540 – 2,589 feet Recovered 103 barrels of 22.8oAPI crude 2,610 – 2,665 feet Recovered 82 barrels of 22.8oAPI crude 2,722 – 2,736 feet Recovered 400.8 barrels of 22.8oAPI crude

The Abanico Field has reported production in September 1999 under long-term test but field production commenced in August 2000 from the Upper and Lower Guadalupe in Abanico 1 and Abanico 2 wells. Field development has included four wells from 2003 to 2004, five wells in 2005, three wells in 2006, five wells in 2007, and five wells in 2008 (see petrophysical summary below).

5

Top

Depth

Net Pay

Thickness Porosity

Water

Saturation Permeability

Well Name Formation (feet) (feet) (%) (%) (mD)

Abanico-17 Upper Guadalupe 2,662 20.5 12.7% 49.7% 2.547

Abanico-18 Upper Guadalupe A 2,721 6.5 15.8% 55.9% 2.13

Upper Guadalupe B 2,878 37.5 15.9% 44.6% 2.11

Abanico-19 Upper Guadalupe 2,670 111.5 18.0% 40.0% n/a

Abanico-27 Upper Guadalupe 2,727 128.0 17.1% 33.9% 1.96

Abanico-28 Upper Guadalupe 2,980 81.0 18.1% 52.2% n/a Currently there are 12 wells producing from the Upper Guadalupe and 9 wells producing from the Lower Guadalupe. The cumulative production to December 31, 2008 was 6,057,225 barrels of oil, 5,898,496 barrels of water, and 2,886,202 Mcf of gas. The 2008 production was 1,287,634 barrels of oil, 2,748,193 barrels of water, and 648,934 Mcf of gas with a daily production rate (based on production days of the 21 wells) of 3,100 barrels of oil, 11,739 barrels of water, and 1,493 Mcf of gas in the month of December 2008. Capital Expenditure and Work Program Proved developed non-producing: The Abanico-28 well drilled in 2008 has not produced due to potential poor cement bond in the Upper Guadalupe. A remedial cement job is expected to take place in Q1 2009 at a total cost of $500,000 (or $125,000 to the Company). Undeveloped Reserves: Future development drilling for 2009 and 2010 is summarized as follows:

Year (no. wells) (M$) (no. wells) (M$) (no. wells) (M$) (no. wells) (M$)

2009 2 3,600 3 5,400 4 7,200 9 16,200

2010 3 5,400 - - - - 3 5,400

Total 5 9,000 3 5,400 4 7,200 12 21,600

South Fault Block Central Fault Block North Fault Block All Fault Blocks

2009 & 2010 Work Program and Total Capital Cost

The Company’s share of the total cost for the above work program is estimated at $5,400,000. The total cost for one development well (with tie-in) is $1,800,000 and the Company’s share at 25% working interest is $450,000. The 2009 development wells are expected to contribute to field production in Q4 of 2009 and the 2010 development wells in Q2 of 2010. The development drilling schedule will require two drilling rigs and one completion rig. The reserves attributed to the development wells are found in the Reserves section of the evaluation.

6

The current facilities are designed to handle up to 40,000 bwpd and water injection of up to 15,000 bwpd. An additional capital expenditure of $2,000,000 ($500,000 to the Company) will increase water injection capacity to 40,000 bwpd. This additional water injection capacity will be required to handle the expected future water (see Production Forecast and Methods section). The abandonment cost (net of salvage) is estimated at $100,000 per well and the total abandonment cost for the total proved plus probable reserves is $3,500,000. The Company’s share of this cost varies by well based on its share of the working interest. Operating Expenditure The total 2008 operating expenses were $6,037,180 for production of 1,287,634 barrels of oil. The operating expenses are split at approximately 70% to variable costs and 30% to fixed costs. The resulting fixed cost is $93,920 per well per year and the variable lifting cost is $3.22 per barrel. The transportation cost from Abanico Field to the sales point is $0.32 per barrel and from the tie-in point to Coveňas sales point is $2.50 per barrel for a total cost of $2.82 per barrel. Economics Parameters Working Interest see Abanico Block Association Contract summary Royalty Rate 5% for oil and 8% for associated/non-associated gas Forecast Oil Price 90% of NYMEX future for WTI light sweet crude Forecast Gas Price $3.50 per MMBtu then escalate at NYMEX heating oil Natural Gas Heat Value estimated at 1,000 Btu/scf Escalation Factor 5%/year on costs and 2%/year on prices Gas-Oil Ratio see Production Forecast and Methods section Abandonment Cost $100,000 per well Operating Days 350 per year Effective Date December 31, 2008 Reserves Proved plus probable developed producing reserves are assigned to 21 Abanico Field wells (see table below). The reserves are assigned based on production decline analysis and for the recently drilled wells production analogs (see Production Forecast and Methods section). Below is a summary of the proved plus probable developed producing reserves:

7

Well Name Producing Fm. (bbl) (bbl) (bbl) (bbl) (bbl) (bbl) (bbl)

Abanico-1 Upper Guadalupe 127,694 151,085 151,085 23,391 23,391 17,739 17,739

Abanico-2 Lower Guadalupe 693,400 1,385,001 1,385,001 691,601 691,601 691,601 691,601

Abanico-4 Lower Guadalupe 470,448 605,079 605,079 134,631 134,631 130,089 130,089


Abanico-6 Lower Guadalupe 1,085,637 1,273,166 1,273,166 187,529 187,529 179,497 179,497











Abanico-21 Lower Guadalupe 549,548 1,120,619 1,227,364 571,071 677,816 571,071 677,816






Abanico-27 Upper Guadalupe - 58,507 100,003 58,507 100,003 58,507 93,458

Total 5,343,469 8,896,449 9,135,467 3,552,981 3,791,998 3,509,594 3,742,066

Proved + Probable

Remaining

Recoverable to

Limit

Proved

EUR

Proved +

Probable

EUR

Proved

Remaining

Recoverable

Proved +

Probable

Remaining

Recoverable

Proved

Remaining

Recoverable

to Limit

Cumluative

Oil

Production

12/31/08

The limit for the proved plus probable developed producing reserves is either economic or a BS&W of 99.5% whichever comes first. Proved plus probable developed non-producing reserves are assigned to the Abanico-19 and Abanico-28 wells. The reserves are assigned to the two wells based on production analogs. The Abanico-28 well also requires a capital expenditure for a remedial cement job (see Capital Costs and Work Program section). Below is a summary of the proved plus probable developed non-producing reserves:




Total - 117,014 200,006 117,014 200,006 117,014 185,525

Proved + Probable

Remaining

Recoverable to

Limit

Cumluative

Oil

Production

12/31/08

Proved

EUR

Proved +

Probable

EUR

Proved

Remaining

Recoverable

Proved +

Probable

Remaining

Recoverable

Proved

Remaining

Recoverable

to Limit

The limit for the proved plus probable developed producing reserves is either economic or an oil rate of 10 bopd.

8

Proved plus probable undeveloped reserves have been assigned to 12 Upper Guadalupe locations in 3 producing fault blocks (see Figures VII-2 & 3). The reserves are assigned based on 2D Seismic interpretations and production analogs. Below is a summary of the proved plus probable undeveloped reserves:


ABA N-1 Upper Guadalupe - 58,507 100,003 58,507 100,003 58,507 98,775

ABA N-2 Upper Guadalupe - 58,507 100,003 58,507 100,003 58,507 98,775

ABA N-3 Upper Guadalupe - - 100,003 - 100,003 - 98,775

ABA N-4 Upper Guadalupe - - 100,003 - 100,003 - 98,775

ABA C-1 Upper Guadalupe - 58,507 100,003 58,507 100,003 58,507 99,100



ABA S-1 Upper Guadalupe - 100,003 213,610 100,003 213,610 100,003 208,784



ABA S-4 Upper Guadalupe - - 100,003 - 100,003 - 97,744

ABA S-5 Upper Guadalupe - - 100,003 - 100,003 - 97,744

Total - 551,048 1,427,250 551,048 1,427,250 551,048 1,403,200

Cumluative

Oil

Production

12/31/08

Proved

EUR

Proved +

Probable

EUR

Proved

Remaining

Recoverable

Proved +

Probable

Remaining

Recoverable

Proved

Remaining

Recoverable

to Limit

Proved + Probable

Remaining

Recoverable to

Limit

The limit for the proved plus probable developed producing reserves is either economic or an oil rate of 10 bopd. Based on the results of the 2008 development drilling campaign the Lower Guadalupe is no longer considered for undeveloped reserve assignment in the currently producing fault blocks. Production Forecast and Methods Proved plus probable developed producing wells are assigned production and decline rates based on production decline analysis (see Appendix B). For the recently drilled developed producing wells the decline rate is based on the production analog. Below is a table summarizing the production characteristics of the developed producing wells:

9

Well Name (%/year) (%/year) (bopd) (bwpd) (%) (scf/bbl)

Abanico-1 36.0 36.0 26.9 52.0 65.9 692

Abanico-2 9.0 9.0 200.7 209.0 51.0 374

Abanico-4 48.0 48.0 162.9 3,155.6 95.1 381

Abanico-5 15.0 15.0 176.5 1,087.8 86.0 413

Abanico-6 54.0 54.0 233.9 2,981.6 92.7 406

Abanico-7 24.0 24.0 132.8 94.3 41.5 1,067

Abanico-8 18.0 18.0 13.0 33.5 72.1 983

Abanico-9 21.0 21.0 30.7 22.8 42.6 1,385

Abanico-11 30.0 30.0 89.5 54.8 38.0 1,063

Abanico-12 24.0 24.0 45.5 75.5 62.4 1,274

Abanico-14 48.0 48.0 69.7 412.4 85.5 2,148

Abanico-15 30.0 30.0 142.9 942.5 86.8 736

Abanico-16 120.0 120.0 99.2 501.2 83.5 681

Abanico-17 36.0 36.0 33.4 47.7 58.8 454

Abanico-18 36.0 36.0 65.9 35.0 34.7 1,329

Abanico-21 24.0 12.0 694.6 485.4 41.1 162

Abanico-22 24.0 24.0 268.0 98.5 26.9 401

Abanico-23 36.0 36.0 167.4 40.4 19.4 179

Abanico-24 48.0 48.0 130.2 60.6 31.8 995

Abanico-25 43.8 31.8 240.8 66.5 21.6 160

Abanico-26 31.8 31.8 113.5 2,514.2 95.7 348

Total 3,137.9 12,971.2

12/31/08

Avg.

GOR

Proved

Decline

Rate

Proved +

Probable

Decline Rate

12/31/08

Avg. Daily

Oil Rate

12/31/08

Avg. Daily

Water

12/31/08

Avg.

BS&W

All decline rates are hyperbolic at exponent 0.1. Production decline analysis by well is available in Appendix B. The Abanico-27 well is producing; however it has only 2 weeks of production history and as a result has been assigned reserves based on production analogs (see Figures VII-4 through VII-6). This is also the case for Abanic-19 and Abanico-28 which are developed but non-producing. The production analogs are also used in assignment of the undeveloped reserves. Below is a table summarizing the production forecast for the Abanico-27, Abanico-19, Abanico-28 and undeveloped wells:

10

Well Name (%/year) (%/year) (bopd) (bopd) (bbl) (bbl) (#) (#)

Abanico-19 60.0 34.8 100.0 100.0 58,507 100,003 Model #1 Model #2



ABA N-1 60.0 34.8 100.0 100.0 58,507 100,003 Model #1 Model #2

ABA N-2 60.0 34.8 100.0 100.0 58,507 100,003 Model #1 Model #2

ABA N-3 - 34.8 - 100.0 100,003 Model #2

ABA N-4 - 34.8 - 100.0 100,003 Model #2

ABA C-1 60.0 34.8 100.0 100.0 58,507 100,003 Model #1 Model #2

ABA C-2 60.0 34.8 100.0 100.0 58,507 100,003 Model #1 Model #2

ABA C-3 60.0 34.8 100.0 100.0 58,507 100,003 Model #1 Model #2

ABA S-1 34.8 24.0 100.0 150.0 100,003 213,610 Model #2 Model #3

ABA S-2 34.8 24.0 100.0 150.0 100,003 213,610 Model #2 Model #3

ABA S-3 60.0 34.8 100.0 100.0 58,507 100,003 Model #1 Model #2

ABA S-4 - 34.8 - 100.0 100,003 Model #2

ABA S-5 - 34.8 - 100.0 100,003 Model #2

Proved

Analog

Proved +

Probable

Analog

Proved

Decline

Rate

Proved +

Probable

Decline Rate

Proved

I.P.R.

Proved +

Probable

I.P.R

Proved

EUR

Proved +

Probable

EUR

All decline rates are hyperbolic at exponent 0.1. The estimated ultimate recoverable are based on an economic limit of 10 bopd. The GOR is estimated at 400 scf per barrel and the water production rates are shown in the production analog models (see Figures VII-4 through VII-6. In addition there are proved and proved plus probable Abanico Field production profiles found in Figures VII-7 and VII-8.

11

12

Figure VII-2 Productive and Prospective Areas of the Abanico Field

13

Figure VII-3 Upper Guadalupe Development Map

Additional locations in the North have not been considered for reserves. A recent 3D Seismic acquisition over the Northern extension is currently being interpreted.

14

Figure VII-4 Abanico Field – Upper Guadalupe Oil Rate vs. Time Log Plot

10

100

1,000

0 20 40 60 80 100 120 140 160 180

Oil

Ra

te (b

op

d)

Time (# of months)

Upper Guadalupe Analog Models - Oil Rate vs Time

Abanico-1

Abanico-7

Abanico-8

Abanico-9

Abanico-11

Abanico-12

Abanico-14

Abanico-15

Abanico-17

Abanico-18

Abanico-24

Analog Model #1

Analog Model #2

Analog Model #3

15

Figure VII-5 Abanico Field – Upper Guadalupe Oil Rate vs. Cumulative Oil

0

50

100

150

200

250

300

0 50 100 150 200 250

Oil

Ra

te (b

op

d)

Cumulative Oil Production (Mbbl)

Upper Guadalupe Analog Models - Rate vs Cumulative Oil Production

Abanico-1

Abanico-7

Abanico-8

Abanico-9

Abanico-11

Abanico-12

Abanico-17

Abanico-18

Abanico-24

Analog Model #1

Analog Model #2

Analog Model #3

16

Figure VII-6 Abanico Field – Upper Guadalupe Water Rate vs. Time Log Plot

1

10

100

1,000

0 20 40 60 80 100 120

Wat

er

Ra

te (b

op

d)

Time (# of months)

Upper Guadalupe Analog Models - Water Rate vs Time

Abanico-1

Abanico-7

Abanico-8

Abanico-9

Abanico-11

Abanico-12

Abanico-14

Abanico-15

Abanico-17

Abanico-18

Abanico-24

Analog Model #1

Analog Model #2

Analog Model #3

17

Figure VII-7 – Abanico Field Proved Production Profile

0.0

0.1

1.0

10.0

10

100

1,000

10,000

100,000

2008 2013 2018 2023 2028

Av

era

ge

Da

ily G

as

Ra

te (

MM

cf p

er

da

y)

Av

era

te D

aily

Ra

te

Time (Years)

Abanico Field Proved - Forecast Rates vs Time Log Plot

Average Daily Oil (bopd)

Average Daily Water (bwpd)

Average Daily Total Fluid (bfpd)

Average Daily Gas

18

Figure VII-8 – Abanico Field Proved + Probable Production Profile

0.0

0.1

1.0

10.0

10

100

1,000

10,000

100,000

2008 2013 2018 2023 2028

Av

era

ge

Da

ily G

as

Ra

te (

MM

cf p

er

da

y)

Av

era

te D

aily

Ra

te

Time (Years)

Abanico Field Proved Plus Probable - Forecast Rates vs Time Log Plot

Average Daily Oil (bopd)

Average Daily Water (bwpd)

Average Daily Total Fluid (bfpd)

Average Daily Gas

19

Ta

ble

VII

-1 S

umm

ary

of T

otal

Pro

ved

Res

erve

s an

d C

ash F

low

Val

ues

of A

bani

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ield

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(M$

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(M$

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(M$

)(M

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(M$

)(M

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Ab

an

ico

-11

7.7

3

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3.6

2

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2.2

0

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0

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2

05

.8

23

.3

85

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9

6.6

9

2.1

88

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84

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8

1.3

Ab

an

ico

-26

91

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1

46

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1

38

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8

6.1

79

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7

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3

5.0

1

0,0

49

.8

58

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2,0

53

.7

7

,90

2.2

5,5

02

.6

4

,14

4.5

3,3

06

.4

2

,75

0.2

Ab

an

ico

-41

30

.1

2

8.0

2

6.6

1

2.8

11

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1

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4

.3

1

,57

2.8

28

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34

1.4

1

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8.3

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95

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,00

9.7

93

8.1

8

77

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Ab

an

ico

-54

71

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9

3.2

8

8.5

2

6.6

24

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4

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1

0.1

5

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0.2

39

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1,1

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4

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9.8

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6.1

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1.8

Ab

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-61

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3

8.3

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2.6

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4

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6.9

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7.6

1,3

19

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5.7

Ab

an

ico

-71

73

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6.5

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4.7

6

9.7

64

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2

5.0

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0.1

28

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53

0.2

1

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6.6

1,5

84

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1

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4.7

1,2

29

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1

,10

6.5

Ab

an

ico

-83

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0.9

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25

Table VII-7 Total Proved Reserves and Cash Flow Values of Abanico Field Average Working Interest = 22.29% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $14,400,000 for 8 development wells (at 25% W.I.) Capital Expenditure #2 = $500,000 for Abanico-28 workover Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $3,100,000 for 31 wells Effective Date = December 31, 2008

100% Gross Net Gross Net Oil Gas Revenue CapEx OpEx

Year (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (M$) (M$) (M$) (M$) (M$)

2009 1,119.2 249.0 236.6 128.2 117.9 12.5 37.4 11,909.6 4,104.3 2,007.7 5,760.2

2010 939.8 213.4 202.7 105.3 96.9 10.7 36.0 12,469.9 51.1 2,006.6 10,376.2

2011 659.4 148.8 141.4 73.5 67.7 7.4 27.1 9,083.9 48.1 1,638.5 7,370.2

2012 390.2 87.5 83.1 48.2 44.3 4.4 18.1 5,551.8 52.3 1,254.9 4,226.6

2013 268.8 59.6 56.7 34.2 31.5 3.0 13.1 3,878.3 203.6 1,064.3 2,597.3

2014 173.5 37.7 35.8 22.3 20.5 1.9 8.7 2,501.2 217.0 621.6 1,653.9

2015 111.2 23.7 22.5 14.7 13.5 1.2 5.9 1,609.2 87.5 468.1 1,047.8

2016 85.1 18.0 17.1 11.6 10.6 0.9 4.7 1,249.3 31.7 358.6 854.4

2017 67.3 14.0 13.3 8.7 8.0 0.7 3.6 989.2 110.8 250.4 624.4

2018 57.6 11.9 11.3 7.4 6.8 0.6 3.1 856.2 - 198.3 654.7

2019 48.3 10.0 9.5 5.1 4.7 0.5 2.2 725.6 28.3 189.7 505.4

2020 42.7 8.8 8.4 4.2 3.9 0.4 1.9 653.1 - 154.0 497.3

2021 38.9 8.0 7.6 3.9 3.5 0.4 1.7 607.0 - 153.4 451.9

2022 35.5 7.3 7.0 3.5 3.3 0.4 1.6 564.9 - 153.2 410.1

2023 30.6 6.3 6.0 3.1 2.9 0.3 1.5 498.5 39.1 149.3 308.6

2024 19.4 4.1 3.9 2.4 2.2 0.2 1.2 331.5 - 91.2 239.2

2025 18.0 3.8 3.6 2.2 2.1 0.2 1.1 313.5 - 91.9 220.6

2026 16.7 3.5 3.3 2.1 1.9 0.2 1.0 296.6 - 92.8 202.9

2027 15.5 3.3 3.1 1.9 1.8 0.2 1.0 280.8 - 93.8 186.0

2028 14.4 3.0 2.9 1.8 1.6 0.2 0.9 266.0 - 95.0 170.1

2029 13.3 2.8 2.7 1.7 1.5 0.1 0.9 252.1 - 96.4 154.8

2030 12.4 2.6 2.5 1.5 1.4 0.1 0.8 239.0 58.9 98.0 81.4

Total 4,177.7 927.2 880.9 487.5 448.5 46.4 173.6 55,127.5 5,032.6 11,327.6 38,593.8

0% 5% 10% 15% 20%

38,593.8 32,611.9 28,458.0 25,375.7 22,975.2

L&M Oil Reserves Associated Gas Royalty Before Tax

NPV

NPV of Future Net Revenue

Before Tax Discounted (in M$) @

26

Table VII-8 Total Proved + Probable Reserves and Cash Flow Values of Abanico-Field Average Working Interest = 22.82% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $21,600,000 for 12 development wells (at 25% W.I.) Capital Expenditure #2 = $500,000 for Abanico-28 workover Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $3,500,000 for 35 wells Effective Date = December 31, 2008



2009 1,116.7 251.3 238.8 131.5 120.9 12.6 38.4 12,026.9 5,087.3 2,005.7 4,895.6

2010 1,163.9 269.8 256.3 128.2 117.9 13.5 43.9 15,747.0 1,057.0 2,417.1 12,229.0

2011 903.5 209.1 198.6 96.9 89.1 10.5 35.7 12,734.4 48.1 2,133.0 10,517.6

2012 563.6 130.8 124.2 65.6 60.4 6.5 24.7 8,269.8 52.3 1,658.2 6,534.6

2013 404.7 93.5 88.9 47.4 43.6 4.7 18.2 6,051.8 112.4 1,420.4 4,500.8

2014 299.1 68.9 65.5 34.4 31.7 3.4 13.5 4,544.4 153.2 1,196.1 3,181.6

2015 190.0 43.4 41.2 22.5 20.7 2.2 9.0 2,924.8 87.5 904.7 1,923.6

2016 146.0 33.3 31.6 17.7 16.2 1.7 7.2 2,287.2 277.9 780.0 1,222.1

2017 91.7 20.1 19.1 11.1 10.2 1.0 4.6 1,412.9 - 415.4 992.9

2018 74.0 16.0 15.2 9.0 8.3 0.8 3.8 1,147.2 193.9 344.3 605.1

2019 48.3 10.0 9.5 5.1 4.7 0.5 2.2 725.6 28.3 189.7 505.4

2020 42.7 8.8 8.4 4.2 3.9 0.4 1.9 653.1 - 154.0 497.3

2021 38.9 8.0 7.6 3.9 3.5 0.4 1.7 607.0 - 153.4 451.9

2022 35.5 7.3 7.0 3.5 3.3 0.4 1.6 564.9 - 153.2 410.1

2023 30.6 6.3 6.0 3.1 2.9 0.3 1.5 498.5 39.1 149.3 308.6

2024 19.4 4.1 3.9 2.4 2.2 0.2 1.2 331.5 - 91.2 239.2

2025 18.0 3.8 3.6 2.2 2.1 0.2 1.1 313.5 - 91.9 220.6

2026 16.7 3.5 3.3 2.1 1.9 0.2 1.0 296.6 - 92.8 202.9

2027 15.5 3.3 3.1 1.9 1.8 0.2 1.0 280.8 - 93.8 186.0

2028 14.4 3.0 2.9 1.8 1.6 0.2 0.9 266.0 - 95.0 170.1

2029 13.3 2.8 2.7 1.7 1.5 0.1 0.9 252.1 - 96.4 154.8

2030 12.4 2.6 2.5 1.5 1.4 0.1 0.8 239.0 58.9 98.0 81.4

Total 5,258.7 1,199.8 1,139.8 597.8 550.0 60.0 214.7 72,175.3 7,195.8 14,733.6 50,031.2

0% 5% 10% 15% 20%

50,031.2 42,026.3 36,321.3 32,027.0 28,662.1


NPV



27

Table VII-9 Total Probable Reserves and Cash Flow Values of Abanico Field Average Working Interest = 24.66% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $7,200,000 for 4 development wells (at 25% W.I.) Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $400,000 for 4 wells Effective Date = December 31, 2008



2009 2.6- 0.2 0.2 3.3 3.0 0.0 1.0 20.6 983.0 14.4- 948.9-

2010 224.1 54.8 52.0 22.9 21.0 2.7 7.8 3,183.1 1,005.9 400.2 1,769.2

2011 244.1 59.1 56.1 23.3 21.5 3.0 8.6 3,579.9 - 486.7 3,084.5

2012 173.3 42.4 40.3 17.5 16.1 2.1 6.6 2,664.6 - 397.4 2,260.7

2013 135.9 33.2 31.6 13.2 12.1 1.7 5.1 2,133.4 91.2- 351.4 1,868.0

2014 125.6 30.8 29.2 12.1 11.1 1.5 4.7 2,012.8 63.8- 570.9 1,501.0

2015 78.8 19.7 18.7 7.9 7.3 1.0 3.1 1,315.6 - 436.6 875.8

2016 61.0 15.2 14.5 6.1 5.6 0.8 2.5 1,037.9 246.2 421.5 367.7

2017 24.4 6.1 5.8 2.4 2.2 0.3 1.0 423.7 110.8- 165.0 368.5

2018 16.4 4.1 3.9 1.6 1.5 0.2 0.7 291.0 193.9 146.0 49.6-

2019 - - - - - - - - - - -

2020 - - - - - - - - - - -

2021 - - - - - - - - - - -

2022 - - - - - - - - - - -

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Total 1,081.1 265.6 252.3 110.3 101.5 13.3 41.1 16,662.6 2,163.3 3,361.2 11,097.0

0% 5% 10% 15% 20%

11,097.0 9,109.7 7,587.7 6,399.5 5,455.0


NPV



28

Table VII-10 Proved Developed Producing Reserves and Cash Flow Values of Abanico

Field Average Working Interest = 21.77% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $2,100,000 for 21 wells Effective Date = December 31, 2008



2009 1,024.5 226.6 215.3 119.2 109.7 11.3 34.8 10,845.5 47.3 1,797.8 8,965.7

2010 701.3 154.6 146.9 81.8 75.3 7.7 28.0 9,057.0 51.1 1,398.0 7,579.9

2011 514.6 113.1 107.4 59.3 54.5 5.7 21.9 6,919.5 48.1 1,149.5 5,700.0

2012 299.3 65.1 61.8 39.2 36.1 3.3 14.8 4,144.3 52.3 832.1 3,245.1

2013 213.4 45.9 43.6 28.7 26.4 2.3 11.0 2,995.5 142.8 682.6 2,159.1

2014 154.1 32.8 31.2 20.4 18.7 1.6 8.0 2,183.2 57.4 478.5 1,639.3

2015 99.1 20.7 19.6 13.4 12.4 1.0 5.4 1,406.5 87.5 350.4 963.2

2016 76.0 15.7 15.0 10.7 9.8 0.8 4.3 1,094.2 31.7 241.4 816.9

2017 64.2 13.2 12.6 8.3 7.7 0.7 3.5 935.3 - 200.6 731.3

2018 57.6 11.9 11.3 7.4 6.8 0.6 3.1 856.2 - 198.3 654.7

2019 48.3 10.0 9.5 5.1 4.7 0.5 2.2 725.6 28.3 189.7 505.4

2020 42.7 8.8 8.4 4.2 3.9 0.4 1.9 653.1 - 154.0 497.3

2021 38.9 8.0 7.6 3.9 3.5 0.4 1.7 607.0 - 153.4 451.9

2022 35.5 7.3 7.0 3.5 3.3 0.4 1.6 564.9 - 153.2 410.1

2023 30.6 6.3 6.0 3.1 2.9 0.3 1.5 498.5 39.1 149.3 308.6

2024 19.4 4.1 3.9 2.4 2.2 0.2 1.2 331.5 - 91.2 239.2

2025 18.0 3.8 3.6 2.2 2.1 0.2 1.1 313.5 - 91.9 220.6

2026 16.7 3.5 3.3 2.1 1.9 0.2 1.0 296.6 - 92.8 202.9

2027 15.5 3.3 3.1 1.9 1.8 0.2 1.0 280.8 - 93.8 186.0

2028 14.4 3.0 2.9 1.8 1.6 0.2 0.9 266.0 - 95.0 170.1

2029 13.3 2.8 2.7 1.7 1.5 0.1 0.9 252.1 - 96.4 154.8

2030 12.4 2.6 2.5 1.5 1.4 0.1 0.8 239.0 58.9 98.0 81.4

Total 3,509.6 763.2 725.0 421.8 388.1 38.2 150.4 45,466.1 644.5 8,787.8 35,883.4

0% 5% 10% 15% 20%

35,883.4 30,454.9 26,759.2 24,059.7 21,982.2


NPV



29

Table VII-11 Proved + Probable Developed Producing Reserves and Cash Flow Values of Abanico Field

Average Working Interest = 21.87% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $2,100,000 for 21 wells Effective Date = December 31, 2008



2009 1,002.1 221.9 210.8 120.5 110.9 11.1 35.2 10,636.1 47.3 1,747.0 8,806.7

2010 751.0 166.1 157.8 87.4 80.4 8.3 29.9 9,727.8 24.8 1,444.7 8,228.5

2011 587.7 129.8 123.3 65.6 60.4 6.5 24.2 7,928.1 48.1 1,257.8 6,597.9

2012 329.9 72.1 68.5 42.5 39.1 3.6 16.0 4,587.2 52.3 880.0 3,638.9

2013 229.9 49.6 47.1 30.1 27.7 2.5 11.5 3,234.7 112.4 709.3 2,401.3

2014 167.1 35.7 34.0 21.3 19.6 1.8 8.4 2,374.6 89.3 530.4 1,746.6

2015 99.1 20.7 19.6 13.4 12.4 1.0 5.4 1,406.5 87.5 350.4 963.2

2016 76.0 15.7 15.0 10.7 9.8 0.8 4.3 1,094.2 31.7 241.4 816.9

2017 64.2 13.2 12.6 8.3 7.7 0.7 3.5 935.3 - 200.6 731.3

2018 57.6 11.9 11.3 7.4 6.8 0.6 3.1 856.2 - 198.3 654.7

2019 48.3 10.0 9.5 5.1 4.7 0.5 2.2 725.6 28.3 189.7 505.4

2020 42.7 8.8 8.4 4.2 3.9 0.4 1.9 653.1 - 154.0 497.3

2021 38.9 8.0 7.6 3.9 3.5 0.4 1.7 607.0 - 153.4 451.9

2022 35.5 7.3 7.0 3.5 3.3 0.4 1.6 564.9 - 153.2 410.1

2023 30.6 6.3 6.0 3.1 2.9 0.3 1.5 498.5 39.1 149.3 308.6

2024 19.4 4.1 3.9 2.4 2.2 0.2 1.2 331.5 - 91.2 239.2

2025 18.0 3.8 3.6 2.2 2.1 0.2 1.1 313.5 - 91.9 220.6

2026 16.7 3.5 3.3 2.1 1.9 0.2 1.0 296.6 - 92.8 202.9

2027 15.5 3.3 3.1 1.9 1.8 0.2 1.0 280.8 - 93.8 186.0

2028 14.4 3.0 2.9 1.8 1.6 0.2 0.9 266.0 - 95.0 170.1

2029 13.3 2.8 2.7 1.7 1.5 0.1 0.9 252.1 - 96.4 154.8

2030 12.4 2.6 2.5 1.5 1.4 0.1 0.8 239.0 58.9 98.0 81.4

Total 3,670.1 800.3 760.3 440.8 405.5 40.0 157.2 47,809.6 619.7 9,018.4 38,014.2

0% 5% 10% 15% 20%

38,014.2 32,306.4 28,382.5 25,494.3 23,258.8


NPV



30

Table VII-12 Probable Developed Producing Reserves and Cash Flow Values of Abanico Field

Average Working Interest = 23.34% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $2,100,000 for 21 wells Effective Date = December 31, 2008



2009 22.4- 4.7- 4.4- 1.3 1.2 0.2- 0.4 209.4- - 50.8- 159.0-

2010 49.7 11.5 10.9 5.6 5.1 0.6 1.9 670.9 26.3- 46.6 648.6

2011 73.1 16.7 15.8 6.4 5.9 0.8 2.4 1,008.5 - 108.3 897.9

2012 30.5 7.0 6.7 3.3 3.0 0.4 1.2 442.9 - 47.9 393.8

2013 16.5 3.7 3.5 1.4 1.3 0.2 0.5 239.1 30.4- 26.7 242.2

2014 13.1 2.9 2.8 1.0 0.9 0.1 0.4 191.4 31.9 51.8 107.3

2015 - - - - - - - - - - -

2016 - - - - - - - - - - -

2017 - - - - - - - - - - -

2018 - - - - - - - - - - -

2019 - - - - - - - - - - -

2020 - - - - - - - - - - -

2021 - - - - - - - - - - -

2022 - - - - - - - - - - -

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Total 160.5 37.2 35.3 19.0 17.4 1.9 6.8 2,343.5 24.7- 230.6 2,130.8

0% 5% 10% 15% 20%

2,130.8 1,851.5 1,623.3 1,434.6 1,276.6


NPV



31

Table VII-13 Proved Developed Non-Producing Reserves and Cash Flow Values of Abanico Field

Average Working Interest = 25.00% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $500,000 for Abanico-28 workover Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $200,000 for 2 wells Effective Date = December 31, 2008



2009 49.2 12.3 11.7 4.4 4.1 0.6 1.3 581.5 125.0 119.1 336.1

2010 33.2 8.3 7.9 3.0 2.8 0.4 1.0 480.8 - 100.3 379.4

2011 19.3 4.8 4.6 1.7 1.6 0.2 0.6 291.9 - 82.8 208.4

2012 11.6 2.9 2.7 1.0 1.0 0.1 0.4 180.7 - 73.6 106.6

2013 3.7 0.9 0.9 0.3 0.3 0.0 0.1 59.1 60.8 63.3 65.1-

2014 - - - - - - - - - - -

2015 - - - - - - - - - - -

2016 - - - - - - - - - - -

2017 - - - - - - - - - - -

2018 - - - - - - - - - - -

2019 - - - - - - - - - - -

2020 - - - - - - - - - - -

2021 - - - - - - - - - - -

2022 - - - - - - - - - - -

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Total 117.0 29.3 27.8 10.5 9.7 1.5 3.5 1,593.9 185.8 439.1 965.5

0% 5% 10% 15% 20%

965.5 903.0 848.5 800.7 758.3


NPV



32

Table VII-14 Proved + Probable Developed Non-Producing Reserves and Cash Flow Values of Abanico Field

Average Working Interest = 25.00% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $500,000 for Abanico-28 workover Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $200,000 for 2 wells Effective Date = December 31, 2008



2009 53.9 13.5 12.8 4.9 4.5 0.7 1.4 637.1 125.0 126.1 384.7

2010 45.1 11.3 10.7 4.1 3.7 0.6 1.4 652.4 - 118.7 532.3

2011 32.5 8.1 7.7 2.9 2.7 0.4 1.1 491.0 - 104.2 385.7

2012 23.7 5.9 5.6 2.1 2.0 0.3 0.8 370.2 - 94.3 275.1

2013 17.4 4.4 4.1 1.6 1.4 0.2 0.6 278.5 - 87.8 190.1

2014 12.9 3.2 3.1 1.2 1.1 0.2 0.5 210.8 63.8 83.8 62.8

2015 - - - - - - - - - - -

2016 - - - - - - - - - - -

2017 - - - - - - - - - - -

2018 - - - - - - - - - - -

2019 - - - - - - - - - - -

2020 - - - - - - - - - - -

2021 - - - - - - - - - - -

2022 - - - - - - - - - - -

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Total 185.5 46.4 44.1 16.7 15.4 2.3 5.7 2,640.1 188.8 614.9 1,830.7

0% 5% 10% 15% 20%

1,830.7 1,644.6 1,491.9 1,364.8 1,257.8


NPV



33

Table VII-15 Probable Developed Non-Producing Reserves and Cash Flow Values of Abanico Field

Average Working Interest = 25.00% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Effective Date = December 31, 2008



2009 4.7 1.2 1.1 0.4 0.4 0.1 0.1 55.7 - 6.9 48.6

2010 11.9 3.0 2.8 1.1 1.0 0.1 0.4 171.7 - 18.4 152.9

2011 13.2 3.3 3.1 1.2 1.1 0.2 0.4 199.1 - 21.4 177.3

2012 12.1 3.0 2.9 1.1 1.0 0.2 0.4 189.6 - 20.7 168.5

2013 13.7 3.4 3.3 1.2 1.1 0.2 0.5 219.4 60.8- 24.6 255.2

2014 12.9 3.2 3.1 1.2 1.1 0.2 0.5 210.8 63.8 83.8 62.8

2015 - - - - - - - - - - -

2016 - - - - - - - - - - -

2017 - - - - - - - - - - -

2018 - - - - - - - - - - -

2019 - - - - - - - - - - -

2020 - - - - - - - - - - -

2021 - - - - - - - - - - -

2022 - - - - - - - - - - -

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Total 68.5 17.1 16.3 6.2 5.7 0.9 2.3 1,046.3 3.0 175.7 865.2

0% 5% 10% 15% 20%

865.2 741.6 643.3 564.2 499.5


NPV



34

Table VII-16 Proved Undeveloped Reserves and Cash Flow Values of Abanico Field Average Working Interest = 25.00% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $14,400,000 for 8 development wells (@ 25% W.I.) Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $800,000 for 8 wells Effective Date = December 31, 2008



2009 45.5 11.4 10.8 4.5 4.2 0.6 1.3 539.1 3,932.0 98.1 3,492.3-

2010 205.3 51.3 48.8 20.5 18.9 2.6 7.0 2,978.9 - 513.4 2,458.5

2011 125.5 31.4 29.8 12.5 11.5 1.6 4.6 1,900.9 - 409.3 1,487.0

2012 79.3 19.8 18.8 7.9 7.3 1.0 3.0 1,244.5 - 351.1 890.4

2013 51.7 12.9 12.3 5.2 4.8 0.6 2.0 829.4 - 319.1 508.3

2014 19.4 4.9 4.6 1.9 1.8 0.2 0.8 318.0 159.5 143.1 14.6

2015 12.1 3.0 2.9 1.2 1.1 0.2 0.5 202.7 - 117.7 84.6

2016 9.1 2.3 2.2 0.9 0.8 0.1 0.4 155.1 - 117.2 37.5

2017 3.1 0.8 0.7 0.3 0.3 0.0 0.1 53.9 110.8 49.8 106.9-

2018 - - - - - - - - - - -

2019 - - - - - - - - - - -

2020 - - - - - - - - - - -

2021 - - - - - - - - - - -

2022 - - - - - - - - - - -

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Total 551.0 137.8 130.9 55.1 50.7 6.9 19.7 8,222.6 4,202.3 2,118.8 1,881.7

0% 5% 10% 15% 20%

1,881.7 1,380.4 967.9 625.4 338.3


NPV



35

Table VII-17 Proved Plus Probable Undeveloped Reserves and Cash Flow Values of Abanico Field

Average Working Interest = 25.00% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $21,600,000 for 12 development wells (@ 25% W.I.) Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $1,200,000 for 12 wells Effective Date = December 31, 2008



2009 60.7 15.2 14.4 6.1 5.6 0.8 1.8 718.9 4,915.0 128.2 4,326.1-

2010 367.8 91.9 87.3 36.8 33.8 4.6 12.6 5,336.2 1,032.2 850.4 3,441.1

2011 283.3 70.8 67.3 28.3 26.1 3.5 10.4 4,292.5 - 768.5 3,513.5

2012 210.0 52.5 49.9 21.0 19.3 2.6 7.9 3,295.1 - 682.0 2,605.2

2013 157.4 39.3 37.4 15.7 14.5 2.0 6.0 2,525.6 - 621.7 1,897.8

2014 119.1 29.8 28.3 11.9 11.0 1.5 4.7 1,949.1 - 580.8 1,363.6

2015 90.9 22.7 21.6 9.1 8.4 1.1 3.6 1,518.3 - 554.3 960.4

2016 70.1 17.5 16.6 7.0 6.4 0.9 2.9 1,193.0 246.2 538.7 405.2

2017 27.5 6.9 6.5 2.7 2.5 0.3 1.1 477.6 - 214.8 261.6

2018 16.4 4.1 3.9 1.6 1.5 0.2 0.7 291.0 193.9 146.0 49.6-

2019 - - - - - - - - - - -

2020 - - - - - - - - - - -

2021 - - - - - - - - - - -

2022 - - - - - - - - - - -

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Total 1,403.2 350.8 333.2 140.3 129.1 17.5 51.7 21,597.3 6,387.3 5,085.3 10,072.9

0% 5% 10% 15% 20%

10,072.9 7,973.5 6,354.7 5,083.4 4,067.6


NPV



36

Table VII-18 Probable Undeveloped Reserves and Cash Flow Values of Abanico Field Average Working Interest = 25.00% Royalty Rate = 5% on oil and 8% on associated gas Escalation Factor = 5% on costs and 2% on prices Forecast Oil Price = 90% of NYMEX futures for WTI light sweet crude Forecast Gas Price = $3.50 per MMBtu escalating based on NYMEX future for heating oil Capital Expenditure #1 = $7,200,000 for 4 development wells (@ 25% W.I.) Fixed Operating Cost = $93,200 per year per well Variable Operating Cost = $3.22 per barrel Transportation Cost = $2.82 per barrel Operating Days = 350 days Abandonment Cost = $400,000 for 4 wells Effective Date = December 31, 2008


Year (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (M$) (M$) (M$) (M$)

2009 15.2 3.8 3.6 1.5 1.4 0.2 0.4 179.8 983.0 30.1

2010 162.5 40.6 38.6 16.2 14.9 2.0 5.6 2,357.3 1,032.2 337.0

2011 157.8 39.5 37.5 15.8 14.5 2.0 5.8 2,391.5 - 359.2

2012 130.7 32.7 31.0 13.1 12.0 1.6 4.9 2,050.6 - 330.9

2013 105.7 26.4 25.1 10.6 9.7 1.3 4.1 1,696.2 - 302.6

2014 99.7 24.9 23.7 10.0 9.2 1.2 3.9 1,631.1 159.5- 437.7

2015 78.8 19.7 18.7 7.9 7.3 1.0 3.1 1,315.6 - 436.6

2016 61.0 15.2 14.5 6.1 5.6 0.8 2.5 1,037.9 246.2 421.5

2017 24.4 6.1 5.8 2.4 2.2 0.3 1.0 423.7 110.8- 165.0

2018 16.4 4.1 3.9 1.6 1.5 0.2 0.7 291.0 193.9 146.0

2019 - - - - - - - - - -

2020 - - - - - - - - - -

2021 - - - - - - - - - -

2022 - - - - - - - - - -

2023 - - - - - - - - - -

2024 - - - - - - - - - -

2025 - - - - - - - - - -

2026 - - - - - - - - - -

2027 - - - - - - - - - -

2028 - - - - - - - - - -

2029 - - - - - - - - - -

2030 - - - - - - - - - -

Total 852.1 213.0 202.4 85.2 78.4 10.7 32.0 13,374.7 2,185.0 2,966.5

0% 5% 10% 15% 20%

8,191.2 6,593.1 5,386.8 4,458.0 3,729.3

L&M Oil Reserves Associated Gas Royalty



37

VIII Quifa Block in the Llanos Basin The Company has an Exploration and Production (E&P) contract with Ecopetrol in the Quifa Block, Llanos Basin, Colombia as follows (see Figure VIII-1): Description Interest (%) Production 60% Capital Expenditure 70% Operating Expenditure 70% The remaining interest belongs to Ecopetrol and the Company is the operator. The production is subject to a sliding scale royalty rate based on the average gross daily production per month (see Royalty Rates with Ecopetrol). The current E&P contract is in Phase 5 of the work program of which a discovery well (Rubiales 147 well) in Prospect “D” was drilled and identified 35 feet of net oil pay in the Carbonera sand formation in September 2008. The remaining phase is to drill one exploratory well and the Company drilled another discovery in the Prospect “E” (Quifa 5 well) in November 2008. The Rubiales 147 well is drilled within the buffer zone and would be considered part of the Rubiales field; whereas the Quifa 5 discovery well is in the Quifa Block. Quifa 5 well was completed and started production before the end of December 2008. The production from Carbonera formation in the Quifa block is considered an extension of the Rubiales field (see Geology in Section I of the Rubiales Field. The reservoir has very similar characteristics and the oil gravity is 13.4oAPI (see Figure VIII-2). Analog Production To date, 117 vertical and horizontal wells have been drilled in the Rubiales Field of which 97 wells have a cumulative production of 32,470,161 barrels of oil and 118,036,947 barrels of water from December 1981 to December 31, 2008. Most of the oil was produced from 2002 onwards. Oil accumulation is concentrated in sandstones of the Lower Tertiary Basal Carbonera formation (Eocene – Oligocene) within a general depth of 2,400 feet to 2,900 feet measured depth. These reservoirs lie unconformably on the Palaeozoic basement. They underlie an Oligocene sequence of inter-bedded fluvial to marginal marine sandstone, shale, limestone and coal. Because of the good performance of the horizontal wells to date, the future development plan is being designed as “clusters” made up of one vertical well and four to five horizontal wells, all starting from the same surface location. The design of the horizontal well is to have a lateral section of 1,200 feet in length and capable of pumping a maximum rate of 10,000 barrels of fluid per day. The initial oil rates vary from 1,900 to 3,500 barrels of oil per day with initial water cut from 40 to 70%. Once the water cut reaches 80%, then the pump rate would increase to 10,000 barrels per day. The vertical well can be capable of initial production of 300 barrels of oil per day and can be converted into water injection wells later. It is anticipated that the horizontal well

38

would recover between 0.9 and 2.2 million barrels of oil per well using a recovery factor between 18 and 24% (from static model of the Integrated Reservoir Study). Capital Costs The capital costs and work program for the Quifa 5 discovery include drilling of four horizontal wells and construction of ~20km 8” pipeline to the Rubiales central processing facilities. The following summarizes the capital costs and work program: Description Total Cost (M$) Pipeline from Prospect “E” (Quifa 5 well) to Rubiales CPF for Q1 2010 1,600 Drill, test and complete four horizontal wells for Q1 2010 7,832 Tie-in Quifa-5 and four horizontal wells to pipeline for Q1 2010 100 Total 9,532 The Company’s share of the capital costs at 70% working interest is $6,672,400. The abandonment cost (net of salvage) for the five well is estimated at $500,000 and the Company’s share of this cost is $350,000. Operating Costs Currently the Quifa-5 oil is being trucked to Rubiales Field where it is processed and trucked to Guaduas for blending. The blended oil then enters the Ocensa pipeline system to Convenas for sale to the International market. The pipeline from Quifa-5 to Rubiales CPF is scheduled for completion in early 2010 at which time the Rubiales to Monterrey pipeline will be operational and the Rubiales CPF upgrades will be complete. At this time the Rubiales CPF will have capacity for the additional Quifa-5 horizontal development wells but due to Rubiales-Monterrey pipeline capacities the oil from Quifa will continue to be trucked to Guaduas for blending. The Rubiales-Monterrey pipeline is designed to accept up to 320,000 bopd with the addition of pump stations, however for the purposes of this evaluation the pipeline will be at maximum capacity with Rubiales Field oil. The Quifa Block processing agreement excludes the cost of oil processing at Rubiales and results in a final lifting cost of $3.32 per barrel (or ~60% of the Rubiales Field lifting cost). The fixed cost for the Quifa-5 cluster is estimated at $300,000 per year. The transportation cost from Quifa-5 to Rubiales is estimated at $1.00 per barrel in 2009 and in 2010 when the pipeline from Quifa-5 to Rubiales is complete the trucking cost will be replaced by a $0.30 per barrel pipeline tariff. The cost to trucked oil from Rubiales to Guaduas is $11.20 per barrel and the blending cost in Guaduas is $0.45 per barrel. The cost to transport blend oil to Guaduas is $9.90 per barrel and the blend (light oil and naphtha mix) is roughly 115% of WTI light sweet crude oil price. The cost from Guaduas to Conveas in the Ocensa pipline is $5.40 per barrel of blended oil. All operating costs are expected to inflate at 5% per year. Economic Parameters and Assumptions Working Interest 60% of production

39

70% on capital and operating expenses Royalty Rate ANH sliding scale minimum 6% for heavy oil Forecast Oil Price 80% of NYMEX future for WTI light sweet crude December 31, 2008 Oil Prices West Texas Intermediate $44.61 per barrel Vasconia 25° API $40.72 per barrel Cost of Blend Oil $51.30 per barrel Blended 18.5° API $35.83 per barrel Forecast Product Prices see Forecast Crude Oil Prices Guaduas Station Blend Ratio 18% blend oil 82% Rubiales 12.5° API Oil Colombian Corporate Income Tax Rate 33% per year Colombian Fiscal Benefit 40% of CapEx in 2008/2009 Operating days 350 per year Abandonment Cost (net of salvage) $100,000 per well Effective date December 31, 2008 Reserve Proved developed producing reserve is assigned to the Quifa-5 exploration well and proved and probable undeveloped reserve is assigned to four horizontal offset wells. The proved developed producing reserve is assigned based on offsetting analogous Rubiales Field, production testing of Quifa-5 well, electric log analysis and 2D Seismic interpretations. The proved and probable undeveloped reserve is assigned based on the results of the Quifa-5 exploration well in conjunction with the 2D Seismic interpretations and analogous Rubiales Field. The following summarizes the reserve assignment based on volumetric calculations supported by analog production profiles:

Well Name (category) (type) (Mbbl) (Mbbl) (Mbbl)

Quifa-5 PDP V2-Vertical 1,645.0 329.0 329.0

Offset #1 PUD T2-Horizontal 5,323.5 1,064.7 1,064.7

Offset #2 PUD T2-Horizontal 5,323.5 1,064.7 1,064.7

Offset #3 Probable T2-Horizontal 5,323.5 1,064.7 1,064.7

Offset #4 Probable T2-Horizontal 5,323.5 1,064.7 1,064.7

Total 22,939.0 4,587.8 4,587.8

ReserveOriginal Oil-

In-Place

Recoverable

Oil

Remaining

Recoverable

Rubiales

Analog Model

The resulting recovery factor for the above volumetric summary is 20%. The Piriri Contract area in the Rubiales Field has been assigned a 20% recovery factor based on a recoverable versus ultimate recoverable model. The Quifa-5 discovery well shares similar net pay thickness to the Piriri Contract and therefore the 20% recovery factor was a better analog than the Rubiales Contract area with 14% recovery factor and thinner productive section of Carbonera. Detailed

40

volumetric calculations are found later in this section. The Rubiales Field analog models are found in the Production Forecast and Methods section. Based on 2D Seismic interpretations (see Figure VIII-3) the Prospect “E” (Quifa-5 explroation well) closure could have an aerial extent of up to 4,635-acres. The Company plans to drill the Quifa-5B appraisal well sometime in 2009. If this well proves the aerial extent of the Basal Carbonera sands the Company would see a considerable write up in proved undeveloped reserves in Prospect “E”. Production Forecasts The production forecasts are based on analog well models from the Rubiales Field (see Figure VIII-4 and 5). The Quifa-5 well encountered 33’ of net pay with porosities and water saturation similar to the analogous Rubiales Field. The analog model selection for the Quifa-5 well is the Type-1 vertical well and for the offsetting horizontal wells the Type-2 horizontal.

41

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia)

Reserve Category: Proved Developed Producing Field Name: Prospect “E” (Quifa-5 discovery), Quifa

Block, Llanos Basin Well Name: Quifa-5 Interval (feet) 2,991 – 3,045 (MD) Formation Basal Carbonera Sandstone Total area (acres) 53.5 Gross reservoir (feet) 65.0 Net pay thickness (feet) 33.0 Rock volume (acre-feet) 1,766.0 Porosities (%) 31.0 Water saturation (%) 41.0 Formation volume factor (rb/stb) 1.04 Stock tank initial oil-in-place (stb/acre-feet) 948.1 Stock tank initial oil-in-place (stb) 1,645,000 Recovery factor (%) 20.0 Recoverable oil (stb) 329,000 Cumulative production (stb) 5,875 Remaining recoverable oil (stb) 329,000 Reservoir pressure Reservoir temperature Permeability API 13.4 The Quifa-5 well cumulative production is based on an average test rate of 235 bopd from December 6th through December 31st of 2008. The well is expected to reach 300 bopd when adequate facilities have been installed.

42

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved Undeveloped Field Name: Prospect “E” (Quifa-5 discovery), Quifa

Block, Llanos Basin Well Names: Quifa-5 Horizontal Offsets x 2 Interval (feet) 2,340 – 2,320 TVDSS Formation Basal Carbonera Sandstone Total area (acres) 340.3 Gross reservoir (feet) 65.0 Net pay thickness (feet) 33.0 Rock volume (acre-feet) 11,229.6 Porosities (%) 31.0 Water saturation (%) 41.0 Formation volume factor (rb/stb) 1.04 Stock tank initial oil-in-place (stb/acre-feet) 948.1 Stock tank initial oil-in-place (stb) 10,647,000 Recovery factor (%) 20.0 Recoverable oil (stb) 2,129,400 Cumulative production (stb) 0 Remaining recoverable oil (stb) 2,129,400 Reservoir pressure Reservoir temperature Permeability API 13.4 The volumetric calculation above is for four horizontal oil producers. The drainage area per well is 170.1-acres with STOOIP of 5,323.5 Mbbl and recoverable oil of 1,064.7 Mbbl at a recovery factor of 20%.

43

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Probable Undeveloped Field Name: Prospect “E” (Quifa-5 discovery), Quifa

Block, Llanos Basin Well Names: Quifa-5 Horizontal Offsets x 2 Interval (feet) 2,340 – 2,320 TVDSS Formation Basal Carbonera Sandstone Total area (acres) 340.3 Gross reservoir (feet) 65.0 Net pay thickness (feet) 33.0 Rock volume (acre-feet) 11,229.6 Porosities (%) 31.0 Water saturation (%) 41.0 Formation volume factor (rb/stb) 1.04 Stock tank initial oil-in-place (stb/acre-feet) 948.1 Stock tank initial oil-in-place (stb) 10,647,000 Recovery factor (%) 20.0 Recoverable oil (stb) 2,129,400 Cumulative production (stb) 0 Remaining recoverable oil (stb) 2,129,400 Reservoir pressure Reservoir temperature Permeability API 13.4 The volumetric calculation above is for four horizontal oil producers. The drainage area per well is 170.1-acres with STOOIP of 5,323.5 Mbbl and recoverable oil of 1,064.7 Mbbl at a recovery factor of 20%.

44

45

Figure VIII-2 – Electric Log Section of Quifa 5 Well

Pay Section Gross Net Net Porosity SW Vcl (pay) Above OWC Reservoir Reservoir Pay 2991-3056’ 65’ 49’ 35’ 0.31 0.41 0.08

46

Fig

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QU

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47

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Tab

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Sum

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Res

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Rev

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10%

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Res

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Cat

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(Mbb

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(Mbb

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Pro

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Qui

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329

197

186

12

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1,60

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Pro

ved

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2,12

9

1,27

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1,20

1

77

261

1,

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80

,311

3,1

03

54,

268

22,9

40

19,8

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17,3

54

15,3

48

13

,699

Tota

l Pro

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2,4

58

1,4

75

1,3

87

89

301

1

,674

91,

824

4,2

67

6

2,42

5 2

5,13

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5

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4,5

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2,7

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165

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50

Table VIII-2 Proved Developed Producing Reserves and Cash Flow Values of Quifa 5 Well

Working Interest = 60% of production and 70% for capital and operating expenses Royalty Rate = ANH sliding scale royalty minimum 6% for heavy oil Escalation Factor = 5%/year for costs and 2%/year for prices Forecast Oil Price = 80% of NYMEX future for WTI light sweet crude Capital Expenditure = $1,600,000 for 8” pipeline from Quifa-5 to Rubiales CPF Fixed Operating Cost = $25,000 per month for Quifa-5 cluster Variable Operating Cost = $3.32/bbl for lifting; $0.45/bbl for blending Transportation Cost = $12.20/bbl to Guaduas (2009); $11.20/bbl to Guaduas (2010) Pipeline Cost = $0.30/bbl tariff to Rubiales CPF; $5.40/bbl from Guaduas to Covenas Blend Cost = $9.90/bbl to transport to Guaduas; 115% of NYMEX future for WTI to purchase Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date: December 31, 2008

100% Gross Net Royalty Blend Oil Sales Oil Revenue CapEx OpEx

Year (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (M$) (M$) (M$) (M$)

2009 104.9 63.0 59.2 3.8 12.9 71.5 3,072 1,120 2,472 520-

2010 77.7 46.6 43.8 2.8 9.5 52.9 2,790 - 1,838 952

2011 57.6 34.6 32.5 2.1 7.1 39.2 2,156 - 1,456 700

2012 42.7 25.6 24.1 1.5 5.2 29.0 1,655 - 1,138 516

2013 31.6 19.0 17.8 1.1 3.9 21.5 1,254 - 886 368

2014 14.5 8.7 8.2 0.5 1.8 9.9 587 45 427 115

Total 329.0 197.4 185.6 11.8 40.3 224.0 11,513 1,165 8,218 2,130

0% 5% 10% 15% 20%

2,130 1,815 1,559 1,349 1,174

Heavy Oil Reserves Before

Tax NPV



51

Table VIII-3 Proved Undeveloped Reserves and Cash Flow Values and Quifa 5 Offset Wells

Working Interest = 60% of production and 70% for capital and operating expenses Royalty Rate = ANH sliding scale royalty minimum 6% for heavy oil Escalation Factor = 5%/year for costs and 2%/year for prices Forecast Oil Price = 80% of NYMEX future for WTI light sweet crude Capital Expenditure = $3,966,000 to drill, test, complete and tie-in two horizontal producers Fixed Operating Cost = $25,000 per month for Quifa-5 cluster Variable Operating Cost = $3.32/bbl for lifting; $0.45/bbl for blending Transportation Cost = $12.20/bbl to Guaduas (2009); $11.20/bbl to Guaduas (2010) Pipeline Cost = $0.30/bbl tariff to Rubiales CPF; $5.40/bbl from Guaduas to Covenas Blend Cost = $9.90/bbl to transport to Guaduas; 115% of NYMEX future for WTI to purchase Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date: December 31, 2008



2009 - - - - - - - - - -

2010 842.9 505.7 475.4 30.3 103.3 574.0 30,249 2,915 19,834 7,499

2011 474.8 284.9 267.8 17.1 58.2 323.3 17,775 - 11,903 5,872

2012 294.6 176.8 166.2 10.6 36.1 200.6 11,427 - 7,757 3,670

2013 214.5 128.7 121.0 7.7 26.3 146.1 8,511 - 5,904 2,607

2014 172.1 103.2 97.0 6.2 21.1 117.2 6,962 - 4,944 2,018

2015 130.6 78.3 73.6 4.7 16.0 88.9 5,388 188 3,926 1,275

Total 2,129.4 1,277.7 1,201.0 76.7 261.0 1,450.0 80,311 3,103 54,268 22,940

0% 5% 10% 15% 20%

22,940 19,831 17,354 15,348 13,699


Tax NPV



52

Table VIII-4 Probable Undeveloped Reserves and Cash Flow Values and Quifa 5 Offset Wells

Working Interest = 60% of production and 70% for capital and operating expenses Royalty Rate = ANH sliding scale royalty minimum 6% for heavy oil Escalation Factor = 5%/year for costs and 2%/year for prices Forecast Oil Price = 80% of NYMEX future for WTI light sweet crude Capital Expenditure = $3,966,000 to drill, test, complete and tie-in two horizontal producers Fixed Operating Cost = $25,000 per month for Quifa-5 cluster Variable Operating Cost = $3.32/bbl for lifting; $0.45/bbl for blending Transportation Cost = $12.20/bbl to Guaduas (2009); $11.20/bbl to Guaduas (2010) Pipeline Cost = $0.30/bbl tariff to Rubiales CPF; $5.40/bbl from Guaduas to Covenas Blend Cost = $9.90/bbl to transport to Guaduas; 115% of NYMEX future for WTI to purchase Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date: December 31, 2008



2009 - - - - - - - - - -

2010 729.1 437.5 411.2 26.2 89.4 496.5 26,165 2,915 17,164 6,086

2011 526.1 315.7 296.7 18.9 64.5 358.3 19,698 - 13,186 6,512

2012 315.0 189.0 177.7 11.3 38.6 214.5 12,217 - 8,290 3,927

2013 224.5 134.7 126.6 8.1 27.5 152.8 8,905 - 6,175 2,730

2014 177.5 106.5 100.1 6.4 21.7 120.8 7,180 - 5,098 2,083

2015 151.4 90.8 85.4 5.4 18.6 103.1 6,247 188 4,542 1,517

Total 2,123.5 1,274.1 1,197.7 76.4 260.3 1,446.0 80,413 3,103 54,455 22,855

0% 5% 10% 15% 20%

22,855 19,627 17,067 15,004 13,316


Tax NPV



53

IX Evaluation of the Las Quinchas Block in the Middle Magdalena Valley The Las Quinchas Association Contract is with Ecopetrol with an effective date of February 19, 1996 and expires in October 2024. The current area of the block is 50,389 hectares. Production is subject to 6% royalty for heavy oil. In both Acacia Este and Arce Fields, the Company has a 50% working interest through the ownership of Kappa Energy Holdings Limited. Under the Association Contract, Ecopetrol has the right to back-in for 50% and has yet to exercise the back-in right for the Acacia Este Field. In the Arce Field, the operation is deemed uneconomical at this time due to the low oil price. Acacia Este Field The Acacia Este Field is a large well defined normal fault closure (see Figures IX-1 and IX-2) similar to the Cocorna-Teca Field which has produced roughly 200 million barrels (see Figure V-3). In 2007, the Acacia Este #1 and #2 wells were drilled to the Upper and Lower Mugrosa formation (see Figures IX-4 and IX-5). The reservoir section consists of two layers. The lower formation is an interbedded fluvial sand deposit with a more massive zone and is interpreted to be coalesced braided stream deposits. The upper zone is probably a meander deposit consisting of re-working lower sands. The Acacia Este #1 well started production in July 2007 and has produced 12,366 barrels of 14.5° API heavy oil and 535 barrels of water to the end of December 2008 with the 2008 production of 9,689 barrels of oil and 36 barrels of water from143 days of operation. The Acacia Este #2 well has produced 237 barrels of 14.5° API heavy oil and 137 barrels of water from 33 days of operation in January and February 2008. A workover to sidetrack the Acacia Este #2 and complete with open hole completion and gravel pack with PCP pump is scheduled for Q1 of 2009. The Acacia Este #4 well was drilled and completed in late 2008 and penetrated oil bearing Mugrosa sands from 3,700’ to 4,070’ (md). The well is currently being stimulated and tested. The Acacia Este #5 well was drilled to a total depth of 4,281 feet in late January 2009 and penetrated oil bearing Mugrosa Sands from 3,710’ to 4,090’ (md). As of December 31, 2008 the well is expected to be completed early Q1 2009. Updated petrophysical analysis of the Acacia Este #1 and #2 along with the petrophysical for Acacia Este #4 and #5 are summarized below:

Well Name Gross Int Net Pay N/G Phi Sw

Acacia Este #1 827.0 73.0 8.8% 18.0% 43.0%

Acacia Este #2 767.0 60.0 7.8% 18.0% 49.0%

Acacia Este #4 925.0 69.0 7.5% 17.0% 53.0%

Acacia Este #5 933.0 89.5 9.6% 19.0% 52.0%

Average 863.0 72.9 8.4% 18.0% 49.3%

Summary of Petrophysical Analysis

(1) Cutoff: Phi>12%; Vschl <50%; Sw<60% (2) Rw = 0.10 ohmm (3) Electric log sections are found in Figures IX-6, 7, 8, and 9.

54

The current mechanical status of the four wells can be found in Appendix A. The most successful completion thus far is an open hole gravel pack with slotted liner and screw pump. Work Program and Capital Costs The work program and capital costs for the Acacia Este Oil Field are as follows: Description Total Cost (M$) Complete Acacia Este #5 well in Q1 of 2009 500.000 Workover Acacia Este #2 well in Q1 of 2009 1,000.000 Total 1,500.000 The Company’s share of the capital cost at 50% working interest is $750,000. The abandonment cost (net of salvage) is estimated at $100,000 per well for a total abandonment cost of $400,000. The Company’s share of this cost is $200,000. Operating Expenditure Based on adjusted 2008 operating expenses the Acacia Este Field is expected to cost $1,010,480 for production from 4 heavy oil wells. Fixed operating costs make up 12.8% of the operating expenses which result in a $32,330 per year per well fixed cost. Variable operating costs make up the difference and based on 2009 oil production forecast result in $11.74 per barrel of oil for lifting, road maintenance and stimulation. The oil is purchased by Ecopetrol at the wellhead and therefore no transportation cost. Economic Parameters and Assumptions Working Interest 50% Royalty Rate ANH sliding scale 6% for heavy oil Forecast Oil Price 70% of NYMEX futures for WTI Escalation 5%/year on costs and 2%/year on prices Original Oil Gravity 14.5° API Corporate Income Tax 33%/year Operating Days 350 per year Abandonment Cost (net of salvage) $100,000 per well Effective Date December 31, 2008 Proved plus probable (developed producing, developed non-producing and undeveloped) reserves have been assigned to 4 wells in the Acacia Este Field. The reserve is assigned to a drainage area of 120-acres (30-acres per well) based on production decline analysis, surrounding analog fields, 2D Seismic interpretations and electric log analysis. Below is a summary of the reserves based on volumetric calculations:

55

Well Name (bbl) (category) (bbl) (bbl) (bbl) (bbl) (bbl) (bbl)

Acacia Este #1 12,306 PDP 115,631 156,928 103,325 144,622 103,060 135,189

Acacia Este #2 237 PUD 75,359 102,273 75,122 102,036 74,001 96,495

Acacia Este #4 - PUD 40,799 67,998 40,799 67,998 40,651 67,998

Acacia Este #5 - PUD 69,502 115,837 69,502 115,837 69,248 114,529

Total 12,543 - 301,291 443,035 288,748 430,492 286,960 414,212

Proved

Remaining

to Limit

Proved +

Probable

Remaining

to Limit

Cumulative

Production

12/31/08

Proved

EUR

Proved +

Probable

EUR

Reserve

Proved

Remaining

Recoverable

Proved +

Probable

Remaining

Recoverable

The estimated ultimate recoverable cutoff is 15 bopd of heavy oil. The limit is 15 bopd or economic whichever comes first. Detailed volumetric calculations are found later in this section. Production Forecast and Methods The production forecast for the Acacia Este wells is based on the Acacia Este #1 analog well and the nearby Cocorna Teca Oil Field. Below is a table summarizing the production forecast:

Well Name (category) (bopd) (%/year) (bbl) (year) (bopd) (%/year) (bbl) (year)

Acacia Este #1 PDP 60.0 15.7 115,631 5.3 60.0 8.3 156,928 7.2

Acacia Este #2 PUD 49.3 16.5 75,359 4.2 49.3 12.0 102,273 5.7

Acacia Este #4 PUD 56.7 37.4 40,799 2.0 56.7 22.2 67,998 3.3

Acacia Este #5 PUD 73.6 30.5 69,502 2.6 73.6 18.1 115,837 4.3

Proved +

Probable

Reserve

Life Index

Reserve Proved Oil

Rate

Proved

Decline

Rate

Proved

EUR

Proved

Reserve

Life Index

Proved

+Probable

Oil Rate

Proved +

Probable

Decline

Rate

Proved +

Probable

EUR

The Cocorna Teca and Acacia Este #1 well production decline analysis are found later in this section. The estimated ultimate recoverable oil is based on a cutoff of 15 bopd. The initial rates for the Acacia Este #2, #4, and #5 wells are adjusted based on net pay thickness to the Acacia Este #1 oil rate of 60 bopd (see Figure IX-10 for Acacia Este #1 AOF test). All declines are exponential.

56

Acacia Este #1 exponential decline rate = 24%/year

Cocorna Teca Oil Field exponential decline rate = 8%

1

10

100

17-Jun-07 15-Sep-07 14-Dec-07 13-Mar-08 11-Jun-08 9-Sep-08 8-Dec-08

Av

era

ge

Mo

nth

ly O

il R

ate

(b

op

d)

Time (months)

Acacia Este #1 Well - Rate vs Time Log Plot

Cocorna Teca Field Historical Oil Rates

Forecast Oil Rate

100

1,000

6-Oct-03 30-Sep-04 25-Sep-05 20-Sep-06 15-Sep-07 9-Sep-08

Av

era

ge

Mo

nth

ly O

il R

ate

(b

op

d)

Time (months)

Cocorna Teca Oil Field - Rate vs Time Log Plot

Cocorna Teca Field Historical Oil Rates

Forecast Oil Rate

57

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia)

Reserve Category: Proved Developed Producing Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley Well Name: Acacia Este 1 Interval (feet) 3,060 – 3,887 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 827.0 Net pay thickness (feet) 73.0 Rock volume (acre-feet) 2,190.0 Porosities (percent) 18.0 Water saturation (percent) 43.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 377.1 Stock tank initial oil-in-place (stb) 825,935 Recovery factor (%) 14.0 Recoverable oil (stb) 115,631 Cumulative production (stb) 12,366 Remaining recoverable oil (stb) 103,265 Reservoir Pressure (psia) 983.0 Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 Gas Gravity ~0.65

Recovery factor based on 60% final oil saturation and average initial water saturation from Acacia Este #1 and Acacia Este #2. Reserve life index based on 60 bopd is 4.7 years.

58

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved Plus Probable Developed Producing

Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley, Colombia

Well Name: Acacia Este 1 Interval (feet) 3,060 – 3,887 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 827.0 Net pay thickness (feet) 73.0 Rock volume (acre-feet) 2,190.0 Porosities (percent) 18.0 Water saturation (percent) 43.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 377.1 Stock tank initial oil-in-place (stb) 825,935 Recovery factor (%) 19.0 Recoverable oil (stb) 156,928 Cumulative production (stb) 12,366 Remaining recoverable oil (stb) 144,562 Reservoir Pressure (psia) 983.0 Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 Gas Gravity ~0.65 Recovery factor based on 65% final oil saturation and average initial water saturation from Acacia Este #1 and Acacia Este #2. Reserve life index based on 60 bopd is 6.6 years.

59

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved Undeveloped Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley Well Name: Acacia Este 2 ST1 Interval (feet) 2,953 – 3,270 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 767.0 Net pay thickness (feet) 60.0 Rock volume (acre-feet) 1,800.0 Porosities (percent) 18.0 Water saturation (percent) 49.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 299.0 Stock tank initial oil-in-place (stb) 538,280 Recovery factor (%) 14.0 Recoverable oil (stb) 75,359 Cumulative production (stb) 237 Remaining recoverable oil (stb) 75,122 Reservoir Pressure (psia) 983.0 (from AE #1 well) Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 (from AE #1 well) Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 (from AE #1 well) Gas Gravity ~0.65

Recovery factor based on 60% final oil saturation and average initial water saturation from Acacia Este #1 and Acacia Este #2. Reserve life index based on 49.3 bopd is 4.2 years. The sidetrack reservoir parameters are based on the Acacia Este #2 petrophysical analysis.

60

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved + Probable Undeveloped Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley Well Name: Acacia Este 2 ST1 Interval (feet) 2,953 – 3,270 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 767.0 Net pay thickness (feet) 60.0 Rock volume (acre-feet) 1,800.0 Porosities (percent) 18.0 Water saturation (percent) 49.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 299.0 Stock tank initial oil-in-place (stb) 538,280 Recovery factor (%) 19.0 Recoverable oil (stb) 102,273 Cumulative production (stb) 237 Remaining recoverable oil (stb) 102,036 Reservoir Pressure (psia) 983.0 (from AE #1 well) Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 (from AE #1 well) Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 (from AE #1 well) Gas Gravity ~0.65

Recovery factor based on 65% final oil saturation and average initial water saturation from Acacia Este #1 and Acacia Este #2. Reserve life index based on 49.3 bopd is 5.7 years. The sidetrack reservoir parameters are based on the Acacia Este #2 petrophysical analysis.

61

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved Undeveloped Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley Well Name: Acacia Este 4 Interval (feet) 2,991 – 3,916 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 925.0 Net pay thickness (feet) 69.0 Rock volume (acre-feet) 2,070.0 Porosities (percent) 17.0 Water saturation (percent) 53.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 262.8 Stock tank initial oil-in-place (stb) 543,983 Recovery factor (%) 7.5 Recoverable oil (stb) 40,799 Cumulative production (stb) 0 Remaining recoverable oil (stb) 40,799 Reservoir Pressure (psia) 983.0 (from AE #1 well) Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 (from AE #1 well) Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 (from AE #1 well) Gas Gravity ~0.65

Recovery factor based on 60% final oil saturation and average initial water saturation from Acacia Este #4 and Acacia Este #5. Reserve life index based on 56.7 bopd is 2.0 years.

62

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved Plus Probable Undeveloped

Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley, Colombia

Well Name: Acacia Este 4 Interval (feet) 2,991 – 3,916 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 925.0 Net pay thickness (feet) 69.0 Rock volume (acre-feet) 2,070.0 Porosities (percent) 17.0 Water saturation (percent) 53.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 262.8 Stock tank initial oil-in-place (stb) 543,983 Recovery factor (%) 12.5 Recoverable oil (stb) 67,998 Cumulative production (stb) 0 Remaining recoverable oil (stb) 67,998 Reservoir Pressure (psia) 983.0 (from AE #1 well) Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 (from AE #1 well) Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 (from AE #1 well) Gas Gravity ~0.65


63

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved Undeveloped Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley Well Name: Acacia Este 5 Interval (feet) 2,952 – 3,885 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 933.0 Net pay thickness (feet) 89.5 Rock volume (acre-feet) 2,685.0 Porosities (percent) 19.0 Water saturation (percent) 52.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 345.1 Stock tank initial oil-in-place (stb) 926,694 Recovery factor (%) 7.5 Recoverable oil (stb) 69,502 Cumulative production (stb) 0 Remaining recoverable oil (stb) 69,502 Reservoir Pressure (psia) 983.0 (from AE #1 well) Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 (from AE #1 well) Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 (from AE #1 well) Gas Gravity ~0.65


64

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category: Proved + Probable Undeveloped Field Name: Acacia Este Field, Las Quinchas Block, Middle Magdalena Valley Well Name: Acacia Este 5 Interval (feet) 2,952 – 3,885 TVD Formation name Mugrosa Sands Total area (acres) 30 Gross reservoir (feet) 933.0 Net pay thickness (feet) 89.5 Rock volume (acre-feet) 2,685.0 Porosities (percent) 19.0 Water saturation (percent) 52.0 Formation volume factor (rb/stb) 1.035 Stock tank initial oil-in-place (stb/acre-feet) 345.1 Stock tank initial oil-in-place (stb) 926,694 Recovery factor (%) 12.5 Recoverable oil (stb) 115,837 Cumulative production (stb) 0 Remaining recoverable oil (stb) 115,837 Reservoir Pressure (psia) 983.0 (from AE #1 well) Reservoir Temperature (degrees F) 115 (from AE #5 well) Permeability (mD) 997.45 (from AE #1 well) Gas Oil Ratio (scf/bbl) ~200 API (degree) 14.5 (from AE #1 well) Gas Gravity ~0.65


65

Figure IX-1. Acacia Este Seismic Closure Mapping

Proved plus probable (developed producing and undeveloped) reserves is assigned to 120-acres of the Mugrosa Sands (outlined in Green above).

66

Fig

ure

IX-2

Aca

cia

Est

e 2D

Sei

smic

Lin

e

67

Fig

ure

IX-3

Ana

log

Fie

lds

68

Figure IX-4 Acacia Este #1 Test Results

69

Figure IX-5 Acacia Este #2 Test Results

70

Figure IX-6 Acacia Este #1 Electric Log Section

Evaluación Petrofísica Gráfica. Pozo Acacia Este-1

Formación Mugrosa

3523’ – 3528’3542’ – 3550’3556’ – 3570’

3596’ – 3612’

3650’ – 3690’

Correlation

GR

0 150GAPI

SP

-100 50MV

CALI(HCAL)

6 16IN

Shale Volume

Vshl

0.0 1.0

Sandstone

Shale

Depth

MD

Resistivity

RT

0 50

Porosity

PHIE

0.3 0.0

BVW

0.3 0.0

Hydrocarbon

Water

Saturation

Sw MS

1.0 0.0

Net Pay / Ca;oneo

Pay

0.000 2

Oil

3100

3150

3200

3250

3300

3350

3400

3450

3500

3550

3600

3650

3700

3750

3800

3850

Mugrosa_Fm

71

Figure IX-7 Acacia Este #2 Electric Log Section

Evaluación Petrofísica Gráfica. Pozo Acacia Este-2

Formación Mugrosa

3512’ – 3540’

3555’ – 3580’

3595’ – 3630’

Correlation

GR

0 150GAPI

SP

-100 50MV

CALI(HCAL)

6 16IN

Shale Volume

Vshl

0.0 1.0

Sandstone

Shale

Depth

MD

Resistivity

RT

0 50

Porosity

PHIE

0.3 0.0

BVW

0.3 0.0

Hydrocarbon

Water

Saturation

Sw MS

1.0 0.0

Net Pay / Ca;oneo

Pay

0.000 2

Oil

3000

3050

3100

3150

3200

3250

3300

3350

3400

3450

3500

3550

3600

3650

3700

Mugrosa_Fm

72

Fig

ure

IX-8

Aca

cia

Est

e #4

Ele

ctric

Log

Sec

tion

AC

AC

IA E

ST

E-4

Ev

alu

aci

ón

Pe

tro

físi

ca G

ráfi

ca

Are

na

Ba

sal M

ug

rosa

-B

asa

me

nto

Inte

rva

lo: 3

70

0’

–4

07

0’

MD

Pre

sen

ta:

•Ne

t P

ay

= 8

4 p

ies

(MD

) /

69

pie

s (T

VD

)

•Po

rosi

da

d =

17

%

•Rw

uti

liza

do

= 0

.10

oh

mm

•m =

1.8

Co

rre

latio

n

GR

015

0G

AP

I

SP

-10

05

0M

V

CA

LI(

HC

AL)

61

6IN

Sh

ale

Vo

lum

e

Vs

hl

0.0

1.0

San

dsto

ne

Sha

le

De

pth

MD

Re

sis

tivity

RT

020

Poro

sity

PH

IE

0.3

0.0

BV

W

0.3

0.0

Hy

droc

arbo

n

Wa

ter

Sa

tura

tion

Sw

MS

1.0

0.0

Ne

t Pa

y /

Ca;

oneo

Pay

0.0

002

Oil

3650

3700

3750

3800

3850

3900

3950

4000

4050

4100

Arena B

asal M

ugro

sa

73

Fig

ure

IX-9

Aca

cia

Est

e #5

Ele

ctric

Log

Sec

tion

AC

AC

IA E

STE

-5

Eva

lua

ció

n P

etr

ofí

sica

Grá

fica

Are

na

Ba

sal M

ugr

osa

-B

asa

me

nto

Cor

rela

tion

GR

015

0G

API

SP

-100

50M

V

CA

LI(C

AL

)

616

IN

Sh

ale

Vol

ume

Vsh

Th

0.00

01.

000

San

dsto

ne

Sha

le

Dep

th

MD

Res

istiv

ity

RT

020

Poro

sity

PHIE

0.3

0.0

BV

W

0.3

0.0

Hyd

roca

rbo

n

Wat

er

Sat

urat

ion

Sw

MS

_I

10

Net

Pay

/ C

a;on

eo

Pay_

I

0.00

02

Oil

3750

3800

3850

3900

3950

4000

4050

4100

4150

Arena

Bas

al M

ugrosa

Inte

rva

lo: 3

71

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74

Figure IX-10 Acacia Este #1 AOF Test Results

75

Table IX-1 Summary of Acacia Este Proved Reserves and Cash Flow Values

Proved Developed Producing

100% Gross Net Royalty Revenue OpEx CapEx 0% 5% 10% 15% 20%

Well Name (Mbbl) (Mbbl) (Mbbl) (Mbbl) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)

Acacia Este #1 103.1 51.5 48.4 3.1 2,303.9 883.6 73.9 1,346.4 1,151.3 1,001.9 885.2 792.2

Total 103.1 51.5 48.4 3.1 2,303.9 883.6 73.9 1,346.4 1,151.3 1,001.9 885.2 792.2

Proved Undeveloped



Acacia Este #2 74.0 37.0 34.8 2.2 1,674.5 649.7 570.4 454.4 333.6 239.9 166.2 107.3

Acacia Este #4 40.7 20.3 19.1 1.2 824.3 320.2 57.9 446.2 419.4 396.0 375.4 357.2

Acacia Este #5 69.2 34.6 32.5 2.1 1,482.8 549.8 313.8 619.3 543.0 479.8 426.9 382.1

Total 183.9 92.0 86.4 5.5 3,981.6 1,519.7 942.1 1,519.8 1,295.9 1,115.7 968.5 846.6

Total Proved



Acacia Este #1 103.1 51.5 48.4 3.1 2,303.9 883.6 73.9 1,346.4 1,151.3 1,001.9 885.2 792.2

Acacia Este #2 74.0 37.0 34.8 2.2 1,674.5 649.7 570.4 454.4 333.6 239.9 166.2 107.3

Acacia Este #4 40.7 20.3 19.1 1.2 824.3 320.2 57.9 446.2 419.4 396.0 375.4 357.2

Acacia Este #5 69.2 34.6 32.5 2.1 1,482.8 549.8 313.8 619.3 543.0 479.8 426.9 382.1

Total 287.0 143.5 134.9 8.6 6,285.5 2,403.3 1,015.9 2,866.3 2,447.3 2,117.6 1,853.7 1,638.8

Heavy Oil Reserves

Heavy Oil Reserves






Before Tax Discounted (in M$) @Heavy Oil Reserves

76

Table IX-2 Summary of Acacia Este Proved Plus Probable Reserves and Cash Flow Values

Probable Developed Producing



Acacia Este #1 32.1 16.1 15.1 1.0 776.4 267.0 3.7 505.6 394.0 313.2 253.7 208.9

Total 32.1 16.1 15.1 1.0 776.4 267.0 3.7 505.6 394.0 313.2 253.7 208.9

Probable Undeveloped



Acacia Este #2 22.5 11.2 10.6 0.7 561.2 230.2 7.2 323.7 241.1 183.6 142.7 113.1

Acacia Este #4 27.3 13.7 12.9 0.8 634.9 251.4 9.1 374.3 321.5 278.5 243.3 214.1

Acacia Este #5 45.3 22.6 21.3 1.4 1,093.1 408.5 10.1 674.6 530.9 426.1 348.1 288.8

Total 95.1 47.6 44.7 2.9 2,289.2 890.2 26.4 1,372.6 1,093.6 888.3 734.1 615.9

Total Probable



Acacia Este #1 32.1 16.1 15.1 1.0 776.4 267.0 3.7 505.6 394.0 313.2 253.7 208.9

Acacia Este #2 22.5 11.2 10.6 0.7 561.2 230.2 7.2 323.7 241.1 183.6 142.7 113.1

Acacia Este #4 27.3 13.7 12.9 0.8 634.9 251.4 9.1 374.3 321.5 278.5 243.3 214.1

Acacia Este #5 45.3 22.6 21.3 1.4 1,093.1 408.5 10.1 674.6 530.9 426.1 348.1 288.8

Total 127.3 63.6 59.8 3.8 3,065.5 1,157.2 30.1 1,878.2 1,487.6 1,201.5 987.8 824.8

Total Proved Plus Probable



Acacia Este #1 135.2 67.6 63.5 4.1 3,080.2 1,150.6 77.6 1,852.1 1,545.3 1,315.2 1,138.9 1,001.1

Acacia Este #2 96.5 48.2 45.4 2.9 2,235.6 880.0 577.6 778.1 574.7 423.5 308.9 220.4

Acacia Este #4 68.0 34.0 32.0 2.0 1,459.2 571.7 67.0 820.5 740.9 674.5 618.7 571.3

Acacia Este #5 114.5 57.3 53.8 3.4 2,576.0 958.3 323.9 1,293.8 1,073.9 905.9 774.9 670.9

Total 414.2 207.1 194.7 12.4 9,351.0 3,560.5 1,046.0 4,744.5 3,934.9 3,319.1 2,841.5 2,463.7



Heavy Oil Reserves







Heavy Oil Reserves

77

Table IX-3 Proved Developed Producing Reserve and Cash Flow Values of Acacia Este #1 Well

Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = n/a Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 60 bopd for January 2009 Exponential Decline Rate = 15.7%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008

100% Gross Net Royalty Revenue OpEx CapEx

Year (Mbbl) (Mbbl) (Mbbl) (Mbbl) (M$) (M$) (M$) (M$)

2009 19.7 9.9 9.3 0.6 347.2 131.9 - 215.3

2010 16.9 8.4 7.9 0.5 364.1 120.9 - 243.1

2011 14.4 7.2 6.8 0.4 324.9 111.2 - 213.7

2012 12.3 6.2 5.8 0.4 288.0 102.6 - 185.4

2013 10.6 5.3 5.0 0.3 252.2 95.1 - 157.1

2014 9.0 4.5 4.3 0.3 220.2 88.4 - 131.8

2015 7.7 3.9 3.6 0.2 192.3 82.6 - 109.7

2016 6.6 3.3 3.1 0.2 168.0 77.6 - 90.5

2017 5.7 2.8 2.7 0.2 146.8 73.2 73.9 0.2-

2018 - - - - - - - -

Total 103.1 51.5 48.4 3.1 2,303.9 883.6 73.9 1,346.4

0% 5% 10% 15% 20%

1,346.4 1,151.3 1,001.9 885.2 792.2


Tax NPV



78

Table IX-4 Probable Developed Producing Reserves and Cash Flow Values of Acacia Este #1

Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = n/a Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Operating Days = 350 per year Effective Date = December 31, 2008



2009 0.7 0.3 0.3 0.0 11.7 3.9 - 7.8

2010 1.9 0.9 0.9 0.1 41.0 11.7 - 29.3

2011 2.8 1.4 1.3 0.1 64.1 18.4 - 45.7

2012 3.6 1.8 1.7 0.1 83.0 24.2 - 58.8

2013 4.1 2.0 1.9 0.1 97.3 29.1 - 68.2

2014 4.4 2.2 2.1 0.1 108.0 33.2 - 74.8

2015 4.7 2.3 2.2 0.1 115.9 36.7 - 79.2

2016 4.8 2.4 2.3 0.1 121.6 39.7 - 81.9

2017 4.8 2.4 2.3 0.1 125.2 42.0 73.9- 157.0

2018 0.3 0.2 0.2 0.0 8.7 28.1 77.6 97.0-

Total 32.1 16.1 15.1 1.0 776.4 267.0 3.7 505.6

0% 5% 10% 15% 20%

505.6 394.0 313.2 253.7 208.9


Tax NPV



79

Table IX-5 Proved + Probable Developed Producing Reserves and Cash Flow Values of Acacia Este #1

Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = n/a Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 60 bopd for January 2009 Exponential Decline Rate = 8.3%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008



2009 20.4 10.2 9.6 0.6 358.9 135.8 - 223.1

2010 18.8 9.4 8.8 0.6 405.0 132.6 - 272.4

2011 17.3 8.6 8.1 0.5 389.0 129.6 - 259.4

2012 15.9 8.0 7.5 0.5 371.0 126.8 - 244.2

2013 14.6 7.3 6.9 0.4 349.5 124.1 - 225.3

2014 13.5 6.7 6.3 0.4 328.2 121.7 - 206.5

2015 12.4 6.2 5.8 0.4 308.3 119.4 - 188.9

2016 11.4 5.7 5.4 0.3 289.6 117.2 - 172.4

2017 10.5 5.3 5.0 0.3 272.0 115.2 - 156.8

2018 0.3 0.2 0.2 0.0 8.7 28.1 77.6 97.0-

Total 135.2 67.6 63.5 4.1 3,080.2 1,150.6 77.6 1,852.1

0% 5% 10% 15% 20%

1,852.1 1,545.3 1,315.2 1,138.9 1,001.1


Tax NPV



80

Table IX-6 Proved Undeveloped Reserves and Cash Flow Values of Acacia Este #2 Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = $1,000,000 for sidetrack and complete Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 49.3 bopd for July 2009 Exponential Decline Rate = 16.5%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008



2009 8.1 4.0 3.8 0.2 142.2 55.5 500.0 413.3-

2010 14.9 7.5 7.0 0.4 322.2 109.0 - 213.2

2011 12.7 6.3 6.0 0.4 285.1 99.8 - 185.4

2012 10.7 5.4 5.1 0.3 250.7 91.7 - 158.9

2013 9.1 4.6 4.3 0.3 217.7 84.7 - 132.9

2014 7.7 3.9 3.6 0.2 188.5 78.7 - 109.8

2015 6.6 3.3 3.1 0.2 163.3 73.4 - 89.9

2016 4.1 2.1 1.9 0.1 104.9 57.0 70.4 22.4-

2017 - - - - - - - -

2018 - - - - - - - -

Total 74.0 37.0 34.8 2.2 1,674.5 649.7 570.4 454.4

0% 5% 10% 15% 20%

454.4 333.6 239.9 166.2 107.3


Tax NPV



81

Table IX-7 Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #2 Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = n/a Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Operating Days = 350 per year Effective Date = December 31, 2008



2009 0.2 0.1 0.1 0.0 2.9 1.0 - 1.9

2010 0.6 0.3 0.3 0.0 13.4 3.8 - 9.6

2011 1.1 0.6 0.5 0.0 25.5 7.3 - 18.1

2012 1.5 0.7 0.7 0.0 34.8 10.1 - 24.7

2013 1.7 0.9 0.8 0.1 41.5 12.4 - 29.1

2014 1.9 0.9 0.9 0.1 46.1 14.2 - 31.9

2015 2.0 1.0 0.9 0.1 49.1 15.6 - 33.6

2016 3.5 1.7 1.6 0.1 87.5 28.5 70.4- 129.3

2017 6.7 3.4 3.2 0.2 174.2 82.4 - 91.8

2018 3.3 1.6 1.5 0.1 86.1 54.8 77.6 46.3-

Total 22.5 11.2 10.6 0.7 561.2 230.2 7.2 323.7

0% 5% 10% 15% 20%

323.7 241.1 183.6 142.7 113.1


Tax NPV



82

Table IX-8 Proved + Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #2

Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = $1,000,000 for sidetrack and complete Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 49.3 bopd for July 2009 Exponential Decline Rate = 12.0%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008



2009 8.2 4.1 3.9 0.2 145.1 56.4 500.0 411.4-

2010 15.5 7.8 7.3 0.5 335.6 112.8 - 222.8

2011 13.8 6.9 6.5 0.4 310.6 107.1 - 203.5

2012 12.2 6.1 5.8 0.4 285.5 101.9 - 183.6

2013 10.9 5.4 5.1 0.3 259.2 97.1 - 162.0

2014 9.6 4.8 4.5 0.3 234.6 92.9 - 141.8

2015 8.6 4.3 4.0 0.3 212.4 89.0 - 123.4

2016 7.6 3.8 3.6 0.2 192.4 85.5 - 106.9

2017 6.7 3.4 3.2 0.2 174.2 82.4 - 91.8

2018 3.3 1.6 1.5 0.1 86.1 54.8 77.6 46.3-

Total 96.5 48.2 45.4 2.9 2,235.6 880.0 577.6 778.1

0% 5% 10% 15% 20%

778.1 574.7 423.5 308.9 220.4


Tax NPV



83

Table IX-9 Proved Undeveloped Reserves and Cash Flow Values of Acacia Este #4 Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = n/a Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 56.7 bopd for January 2009 Exponential Decline Rate = 37.4%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008



2009 17.0 8.5 8.0 0.5 298.6 115.7 - 182.9

2010 11.7 5.8 5.5 0.4 252.2 89.0 - 163.2

2011 8.1 4.0 3.8 0.2 181.6 70.0 - 111.6

2012 3.9 2.0 1.9 0.1 91.9 45.5 57.9 11.5-

2013 - - - - - - - -

2014 - - - - - - - -

2015 - - - - - - - -

2016 - - - - - - - -

2017 - - - - - - - -

2018 - - - - - - - -

Total 40.7 20.3 19.1 1.2 824.3 320.2 57.9 446.2

0% 5% 10% 15% 20%

446.2 419.4 396.0 375.4 357.2


Tax NPV



84

Table IX-10 Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #4




2009 1.2 0.6 0.5 0.0 20.3 6.8 - 13.5

2010 2.8 1.4 1.3 0.1 61.0 17.4 - 43.6

2011 3.6 1.8 1.7 0.1 80.5 23.1 - 57.3

2012 5.4 2.7 2.5 0.2 125.9 36.7 57.9- 147.1

2013 7.5 3.7 3.5 0.2 178.8 73.1 - 105.7

2014 6.0 3.0 2.8 0.2 146.4 65.7 - 80.7

2015 0.9 0.4 0.4 0.0 21.9 28.6 67.0 73.7-

2016 - - - - - - - -

2017 - - - - - - - -

2018 - - - - - - - -

Total 27.3 13.7 12.9 0.8 634.9 251.4 9.1 374.3

0% 5% 10% 15% 20%

374.3 321.5 278.5 243.3 214.1


Tax NPV



85


Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = n/a Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 56.7 bopd for January 2009 Exponential Decline Rate = 22.2%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008



2009 18.1 9.1 8.5 0.5 318.9 122.5 - 196.4

2010 14.5 7.3 6.8 0.4 313.3 106.4 - 206.8

2011 11.6 5.8 5.5 0.3 262.1 93.1 - 168.9

2012 9.3 4.7 4.4 0.3 217.8 82.2 - 135.6

2013 7.5 3.7 3.5 0.2 178.8 73.1 - 105.7

2014 6.0 3.0 2.8 0.2 146.4 65.7 - 80.7

2015 0.9 0.4 0.4 0.0 21.9 28.6 67.0 73.7-

2016 - - - - - - - -

2017 - - - - - - - -

2018 - - - - - - - -

Total 68.0 34.0 32.0 2.0 1,459.2 571.7 67.0 820.5

0% 5% 10% 15% 20%

820.5 740.9 674.5 618.7 571.3


Tax NPV



86

Table IX-12 Proved Undeveloped Reserves and Cash Flow Values Acacia Este #5 Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = $500,000 to complete well with gravel pack and PCP pump Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 73.6 bopd for April 2009 Exponential Decline Rate = 30.5%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008



2009 17.0 8.5 8.0 0.5 299.1 111.9 250.0 62.7-

2010 18.2 9.1 8.6 0.5 392.7 129.1 - 263.6

2011 13.4 6.7 6.3 0.4 302.4 104.7 - 197.6

2012 9.9 5.0 4.7 0.3 231.4 86.1 - 145.2

2013 7.3 3.7 3.4 0.2 175.0 72.0 - 103.0

2014 3.4 1.7 1.6 0.1 82.3 46.0 63.8 27.5-

2015 - - - - - - - -

2016 - - - - - - - -

2017 - - - - - - - -

2018 - - - - - - - -

Total 69.2 34.6 32.5 2.1 1,482.8 549.8 313.8 619.3

0% 5% 10% 15% 20%

619.3 543.0 479.8 426.9 382.1


Tax NPV



87

Table IX-13 Probable Undeveloped Reserves and Cash Flow Values of Acacia Este #5




2009 0.9 0.5 0.4 0.0 16.7 5.6 - 11.1

2010 2.7 1.4 1.3 0.1 59.3 16.9 - 42.4

2011 4.0 2.0 1.9 0.1 91.2 26.2 - 65.0

2012 4.7 2.3 2.2 0.1 108.9 31.7 - 77.2

2013 4.8 2.4 2.3 0.1 115.7 34.6 - 81.1

2014 6.8 3.4 3.2 0.2 165.3 50.9 63.8- 178.3

2015 8.5 4.3 4.0 0.3 211.1 88.5 - 122.5

2016 7.1 3.6 3.3 0.2 179.9 81.4 - 98.5

2017 5.6 2.8 2.6 0.2 145.0 72.6 73.9 1.4-

2018 - - - - - - - -

Total 45.3 22.6 21.3 1.4 1,093.1 408.5 10.1 674.6

0% 5% 10% 15% 20%

674.6 530.9 426.1 348.1 288.8


Tax NPV



88


Working Interest = 50% Royalty Rate = ANH sliding scale royalty for heavy oil minimum 6% Escalation Factor = 5%/year on costs and 2%/year on prices Forecast Oil Price = 80% of NYMEX futures for WTI light sweet crude Capital Expenditure = $500,000 to complete well with gravel pack and PCP pump Fixed Operating Cost = $32,300 per year Variable Operating Cost = $11.74/bbl for lifting, road maintenance and stimulation Transportation Cost = sold at the wellhead Initial Production Rate = 73.6 bopd for April 2009 Exponential Decline Rate = 18.1%/year Operating Days = 350 per year Abandonment Cost (net of salvage) = $100,000 Effective Date = December 31, 2008



2009 17.9 9.0 8.4 0.5 315.8 117.4 250.0 51.6-

2010 20.9 10.5 9.8 0.6 452.0 146.1 - 305.9

2011 17.5 8.7 8.2 0.5 393.5 130.9 - 262.6

2012 14.6 7.3 6.9 0.4 340.3 117.8 - 222.4

2013 12.2 6.1 5.7 0.4 290.7 106.6 - 184.1

2014 10.2 5.1 4.8 0.3 247.6 96.9 - 150.8

2015 8.5 4.3 4.0 0.3 211.1 88.5 - 122.5

2016 7.1 3.6 3.3 0.2 179.9 81.4 - 98.5

2017 5.6 2.8 2.6 0.2 145.0 72.6 73.9 1.4-

2018 - - - - - - - -

Total 114.5 57.3 53.8 3.4 2,576.0 958.3 323.9 1,293.8

0% 5% 10% 15% 20%

1,293.8 1,073.9 905.9 774.9 670.9


Tax NPV



89

X Evaluation of the Buganviles Block in the Upper Magdalena Block The Buganviles Association Contract is with Ecopetrol with an effective date of November 17, 2000 for a period of 28 years. The current area of the block is 61,333 hectares. Production is subject to an 8% royalty for oil. Pacific Rubiales Energy has a 49.375% working interest in the Delta 1 well and the remaining exploration area. The Buganviles block is located approximately 120 km south-west of the City of Bogota and is west of the Abanico field (No. 2362) and north of the Chipalo Block (No. 2070 in Figure X-1). Abanico and Chipalo blocks are also operated by the Company. Reserve The Buganviles block contains one proved producing well in the Delta field. Delta 1-ST2 produces 34.5oAPI oil from the Caballos-Cretaceous formation at a depth of 6,150 feet SS. The reservoir is limestone with fractured porosity. The initial reservoir pressure is 3,250 psi at 174oF reservoir temperature. Delta 1 well was lost due to drilling difficulties. A side track well (Delta 1-ST2) was drilled to a total depth of 7,988 feet MD in May 2008. The well was perforated from 7,736 to 7,764 feet MD and from 7,774 to 7,792 feet MD in the Caballos formation. The well was acid-stimulated with no success. A second acid-fractured treatment was attempted with moderate success. Currently, the well is producing at a daily rate of 60 barrels of oil with 14% BS&W. Work Program and Capital Expenditure Another acid-fractured treatment on the Delta 1-ST2 well is scheduled for the second half of 2009. The cost for the stimulation is estimated at $500,000.

Well Name First Production Total Cost, $ Company’s Share, $ Delta 1-ST2 Q3 2009 500,000 500,000 Total Proved + Probable 500,000 500,000

Operating Costs The variable lifting cost is estimated at $12.80 per barrel. Transportation cost is estimated at $3.65/bbl. Fixed operating cost is estimated at $7,800 per month per well. The operating costs above are for 2009 and expected to escalate at 5% per year in accordance with Colombian inflation rate estimates. Economic Parameters and Assumptions Working Interest 49.375% Royalty Rate Ecopetrol, 8% on Oil

90

Forecast Oil Price NYMEX futures for WTI adjusted for 34.5° API Delta Crude (see Forecast Oil Price)

Escalation Factor 5% on costs Corporate Income Tax Rate 33% per year Operating Days 350 per year Abandonment Cost $200,000 per well Effective Date December 31, 2008 Reserve Assignment Proved producing reserves are assigned to 190-acre drainage area that is supported by petrophysical analysis, 2D Seismic interpretations and mapping. The Delta 1-ST2 production decline was constructed by analogue wells producing from the Caballos limestone formation. Proved plus probable producing and undeveloped reserves includes improved recovery from the Delta 1-ST2 well.

Formation Proved (bbl)

Proved + Probable (bbl)

Caballos-Cretaceous Limestone 78,000 139,000 Total 78,000 139,000 Detailed volumetric calculations are found later in this section. Production Forecast and Methods The production forecast for Delta 1-ST2 oil well is as follows:

Reserve Category Initial Rate (bbl/d)

Decline Rate (%/year)

Hyperbolic Exponent

Proved Developed Producing 60 18.0 0.1 Proved + Probable Producing 60 18.0 0.3 Proved + Probable Undeveloped 80 18.0 0.2 The production forecasts for producing and undeveloped cases were determined using OFMTM software.

91

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Field Name Delta Oil Field

Buganviles Block, Upper Magdalena Valley Formation Name Caballos-Cretaceous, Limestone Reservoir Interval 5980-6300 feet SS

Proved Proved + Probable

Drainage Area (acres) 190 190 Net Pay Thickness (feet) 29 29 Bulk Rock Volume (acre-feet) 5,450 5,450 Porosities (percent) 3.0 3.0 Initial Water Saturation (percent) 40.0 40.0 Volume Formation Factor (percent) 1.33 1.33 Stock tank initial oil in place (Stb/ac-ft) 73.8 73.8 Stock tank initial oil in place (Mstb) 570 570 Recovery Factor (%) 20 30 Recoverable Oil Reserve (Mstb) 60 170 Cumulative Production (Mstb) 0.0 0 Remaining Recoverable Oil (Mstb) 115 170 Reservoir Pressure (psia) 3,250 Reservoir Temperature (oF) 174 API (degree) 34.5 Note: Porosities included fractures

92

93

Figure X-2 Caballos Limestone Structure Map of Delta 1 Well

94

Figure X-3 Delta 1-ST2 and Gualanday-3 Cross Section

95

Figure X-4 Delta 1-ST2 Petrophysical Log

96

Figure X-5 Rate versus Time for Delta 1-ST2

Figure X-6 Rate versus Cumulative Production for Delta 1-ST2

Production Rate versus Time for Delta 1-ST2

1

10

100

Jan-09 Jan-11 Jan-13 Jan-15 Jan-17 Jan-19 Jan-21 Jan-23 Jan-25 Jan-27 Jan-29

Time

Qliq

uid

(bbl

/d)

Oil - 1P Oil - 2P Oil - 2PUD

Production Rate versus Cumulative Production for De lta 1-ST2

0

10

20

30

40

50

60

70

80

90

100

0 20 40 60 80 100 120 140 160 180 200

Cumulative Production (Mbbl)

Qo (b

bl/d

)

Oil 1P Oil 2P Oil 2PUD

Ta

ble

X-1

Sum

ma

ry o

f Del

ta O

il F

ield

Res

erve

s an

d Cash

Flo

w V

alue

s

Res

erve

Ca

tego

ry

Oil

Res

erve

s N

PV

of F

utur

e N

et R

eser

ves

Bef

ore

Tax

Dis

coun

ted

($M

) @

10

0%

(Mbb

l)

Gro

ss

(Mbb

l)

Net

(M

bbl

) 0%

5%

10

%

15%

20

%

Pro

ved

pro

duci

ng

78

38

35

1,1

68

1,0

51

954

8

73

805

Pro

ved

Tot

al

78

38

35

1,1

68

1,0

51

954

8

73

805

Pro

bab

le p

rodu

cing

1

1 5

5

180

142

113

92

75

Pro

bab

le u

ndev

elop

ed

50

25

23

479

314

194

1

05

38

Pro

ved

plus

pro

babl

e Tot

al

139

68

63

1,8

27

1,50

7 1,

262

1,07

0 91

8

98

Table X-2 Proved Producing Reserve and Cash Flow Values of Delta 1 ST2 Well

Working Interest = 49.375% Royalty Rate = 8% to Ecopetrol Forecast Oil Price = NYMEX future for WTI minus API adjustment for 34.5o API Escalation Factor = 2% on commodity prices (if required) and 5% on costs Capital Expenditure = $0 Variable Operating Cost = $12.80/bbl lifting; $3.65/bbl transportation Fixed Operating Cost = $7,800/well/month Abandonment Cost = $200,000/well Operating Days = 350 days per year Effective Date = December 31, 2008

100% Gross Net Royalty Revenue CapEx OpEx

Year (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)

2009 19 10 9 1 468 - 201 268

2010 16 8 7 1 479 - 184 295

2011 14 7 6 1 418 - 170 248

2012 11 6 5 0 362 - 158 204

2013 9 5 4 0 309 - 148 161

2014 8 4 4 0 263 132 139 8-

Total 78 38 35 3 2,299 132 999 1,168

0% 5% 10% 15% 20%

1,168 1,051 954 873 805

L&M Oil Reserves Before

Tax NPV



99

Table X-3 Probable Producing Reserve and Cash Flow Values of Delta #1 ST2 Well

Working Interest = 49.375% Royalty Rate = 8% to Ecopetrol Forecast Oil Price = NYMEX future for WTI minus API adjustment for 34.5o API Escalation Factor = 2% on commodity prices (if required) and 5% on costs Capital Expenditure = $0 Variable Operating Cost = $12.80/bbl lifting; $3.65/bbl transportation Fixed Operating Cost = $7,800/well/month Abandonment Cost = $200,000/well Operating Days = 350 days per year Effective Date = December 31, 2008



2009 0 0 0 0 1 - 0 0

2010 0 0 0 0 5 - 1 3

2011 0 0 0 0 11 - 3 8

2012 1 0 0 0 19 - 6 14

2013 1 0 0 0 27 - 8 19

2014 1 0 0 0 34 132- 10 156

2015 8 4 4 0 264 140 145 20-

Total 11 5 5 0 361 8 173 180

0% 5% 10% 15% 20%

180 142 113 92 75


Tax NPV



100

Table X-4 Probable Undeveloped Reserve and Cash Flow Values of Delta Oil Field

Working Interest = 49.375% Royalty Rate = 8% to Ecopetrol Forecast Oil Price = NYMEX future for WTI minus API adjustment for 34.5o API Escalation Factor = 2% on commodity prices (if required) and 5% on costs Capital Expenditure = $500,000 for stimulation treatment Variable Operating Cost = $12.80/bbl lifting; $3.65/bbl transportation Fixed Operating Cost = $7,800/well/month Abandonment Cost = $200,000/well Operating Days = 350 days per year Effective Date = December 31, 2008



2009 4 2 2 0 103 500 34 431-

2010 7 4 3 0 217 - 61 156

2011 6 3 3 0 188 - 53 134

2012 5 2 2 0 161 - 46 114

2013 4 2 2 0 136 - 40 96

2014 3 2 2 0 115 - 35 80

2015 3 1 1 0 97 140- 31 207

2016 9 5 4 0 319 - 168 151

2017 8 4 4 0 282 153 158 29-

Total 50 25 23 2 1,618 513 626 479

0% 5% 10% 15% 20%

479 314 194 105 38


Tax NPV



101

XI Evaluation of the Guasimo Block in the Upper Magdalena Block The Guasimo E&P Contract is 100% working interest with ANH with an effective date of November 11, 2004 for a period of 28 years. The current area of the block is 10,931 hectares and 6,106 square meters. Production is subject to the sliding scale royalty at a minimum of 8% for oil and gas under the ANH royalty agreement. Reserve The Lisa field was discovered in 2008 by the Lisa-1 well. The well encountered producible oil from the upper Guadalupe Formation at a depth of 4,200 feet SS. The reservoir is a syncline structure consisting of procellanitic rock where hydrocarbon is trapped between the spill point and a tertiary unconformity at the crest. Porosity and permeability are dominated by the fracture network within the reservoir. The well is perforated between 5,292 and 5,330 feet MD. Testing began on December 18, 2008 and the well began to flow water to surface without artificial lift. It was determined that the water was coming from the Lower Guadalupe behind the 7” liner. The annulus leak was repaired with a conventional cement squeeze and a plug installed at 5,282 feet. The Upper Guadalupe was re-perforated between 5,238 and 5,260 feet MD, fractured and equipped with a progressive cavity pump. Currently the daily production is 50 barrels of 24 oAPI oil with a 10% BS&W. Proved reserve includes two offset locations adjacent to Lisa-1. Proved plus probable reserve includes two additional locations for a total of five wells in the Lisa field. Work Program and Capital Expenditure The cost to drill a deviated well to 5,500 feet MD is estimated at $3,300,000. For each well, an additional $400,000 has been allocated for tie-in, roads, etc. The work program and corresponding capital costs are estimated as follows:

Well Name First Production Total Cost, $ Company’s Share, $ Lisa-2 January 2010 3,700,000 3,700,000 Lisa-3 January 2010 3,700,000 3,700,000 Proved Total 7,400,000 7,400,000 Lisa-4 July 2010 3,700,000 3,700,000 Lisa-5 July 2010 3,700,000 3,700,000 Proved + Probable Total 14,800,000 14,800,000

The abandonment cost (net of salvage) is estimated at $100,000 per well. Operating Costs The variable lifting cost is estimated at $4.12 per barrel. The fixed operating cost is estimated at $29,000 per month per well with escalation at 5% per year.

102

Economic Parameters and Assumptions Working Interest 100% Royalty Rate ANH sliding scale, 8% on Oil Forecast Oil Price NYMEX futures for WTI adjusted for 24°

API Lisa Crude (see Forecast Oil Prices) Escalation Factor 5% on costs based on Colombian index Corporate Income Tax Rate 33% per year Operating Days 350 per year Abandonment Cost $100,000 per well Effective Date December 31, 2008 Reserve Assignment Proved producing and undeveloped reserves are assigned to 166-acrea of the Upper Guadalupe in the upper portion of the Porcellanite. The reserves are assigned based on initial production rates of the Lisa-1 well, petrophysical analysis, 2D Seismic interpretations and mapping. Proved plus probable producing and undeveloped reserves includes the lower Porcellanite within the Upper Guadalupe.

Formation Proved (bbl)

Proved + Probable (bbl)

Upper Guadalupe, Upper Porcellanite 434,000 450,000 Upper Guadalupe, Lower Porcellanite 955,000 Total 434,000 1,405,000 Detailed volumetric calculations of the closures as defined by seismic data are found later in this section. Production Forecast and Methods The production forecast for an oil well is as follows:

Reserve Category Initial Rate (bbl/d)

Decline Rate (%/year)

Hyperbolic Exponent

Proved Developed Producing 50 30.0 0 Proved Undeveloped 125 17.5 0 Proved + Probable Producing 50 17.5 0 Proved + Probable Undeveloped 200 17.5 0 The production forecast is based on the initial production from Lisa-1. Undeveloped wells will be drilled deviated to which will improve productivity due to increased pay and contacting the fracture network within the porcellanite formation.

103

Estimated Crude Oil Reserves at Standard Conditions (60oF and 14.65 psia) Field Name Lisa Oil Field

Guasimo Block, Upper Magdalena Valley, Colombia Formation Name Upper Guadalupe, Porcellanite Reservoir Interval 4,020 – 4,400 feet SS

Proved Proved + Probable

Drainage Area (acres) 166 166 Net Pay Thickness (feet) 48.6 206 Bulk Rock Volume (acre-ft) 8,080 34,200 Porosities (percent) 16.0 16.0 Initial Water Saturation (percent) 50.0 50.0 Volume Formation Factor (percent) 1.08 1.08 Stock tank initial oil in place (Stb/ac-ft) 599 2,530 Stock tank initial oil in place (Mstb) 4,640 19,600 Recovery Factor (%) 10.0 10 Recoverable Oil Reserve (Mstb) 460 1,960 Cumulative Production (Mstb) 0.0 0 Remaining Recoverable Oil (Mstb) 460 1,960 Reservoir Pressure (psia) 2,310 Reservoir Temperature (oF) 143 API (degree) 24

104

Figure XI–1 Location of Guasimo Block

105

Figure XI-2 Upper Guadalupe Structure Map of Lisa Field

106

Figure XI-3 Upper Guadalupe Trap Model of Lisa Field

107

Figure XI-4 Lisa-1 Well Petrophysical Log

108

Figure XI-5 Rate versus Time for Lisa-1 Well

Figure XI-6 Rate versus Cumulative Production for Lisa-1 Well

Production Rate versus Time for Lisa - 1

1

10

100

Jan-09 Jan-11 Jan-13 Jan-15 Jan-17 Jan-19 Jan-21

Time

Qliq

uid

(bbl

/d)

Oil - 1P Oil - 2P

Production Rate versus Cumulative Production for Li sa - 1

0

10

20

30

40

50

60

70

80

90

100

0 10 20 30 40 50 60 70 80 90 100

Cumulative Production (Mbbl)

Qo

(bbl

/d)

Oil 1P Oil 2P

Ta

ble

XI-

1 S

umm

ary

of L

isa

Oil

Fie

ld R

eser

ves

and

Cash

Flo

w V

alue

s

Res

erve

Cat

egor

y L&

M O

il R

eser

ves

NP

V o

f Fut

ure

Net

Res

erve

s B

efo

re T

ax D

isco

unt

ed (

$M

) @

1

00%

(M

bbl)

Gro

ss

(Mbb

l) N

et

(Mbb

l) 0

%

5%

10

%

15%

20

%

Pro

ved

pro

duci

ng

35

35

32

408

394

382

370

360

Pro

ved

und

evel

oped

39

9 39

9 36

7 5

,941

4

,017

2

,556

1

,4

27

539

Pro

ved

Tot

al

434

434

399

6,34

9 4

,411

2

,938

1

,798

89

9 P

rob

able

pro

duci

ng

16

16

14

410

372

339

311

286

Pro

bab

le u

ndev

elop

ed

956

956

879

32

,96

9 2

5,2

87

19

,90

4 1

6,0

36

13

,19

2 P

rove

d pl

us p

roba

ble

(in to

tal)

1,40

5 1,

405

1,29

3 3

9,72

8 30

,070

23

,181

18

,145

14

,378

110

Table XI-2 Proved Producing Reserve and Cash Flow Values of Lisa 1 Well

Working Interest = 100% Royalty Rate = Minimum 8% for Oil Sliding Scale Forecast Oil Price = NYMEX future for WTI minus API adjustment for 24o API Escalation Factor = 2% on commodity prices (if required) and 5% on costs Capital Expenditure = $0 Variable Operating Cost = $4.12/bbl Fixed Operating Cost = $29,000/well/month Abandonment Cost = $100,000/well Operating Days = 350 days per year Effective Date = December 31, 2008



2009 15 15 14 1 681 - 413 268

2010 11 11 10 1 618 - 417 202

2011 8 8 8 1 478 116 424 62-

Total 35 35 32 3 1,777 116 1,254 408

0% 5% 10% 15% 20%

408 394 382 370 360


Tax NPV



111

Table XI-3 Proved Undeveloped Reserve and Cash Flow Values of Lisa Oil Field

Working Interest = 100% Royalty Rate = Minimum 8% for Oil Sliding Scale Forecast Oil Price = NYMEX future for WTI minus API adjustment for 24o API Escalation Factor = 2% on commodity prices (if required) and 5% on costs Capital Expenditure = Drill 2 wells (Lisa 2 and 3)

$3,300,000/well drill and complete $400,000/well equip and tie-in

Variable Operating Cost = $4.12/bbl Fixed Operating Cost = $29,000/well/month Abandonment Cost = $100,000/well Operating Days = 350 days per year Effective Date = December 31, 2008



2009 - - - - - 7,400 - 7,400-

2010 81 81 74 6 4,409 - 1,085 3,324

2011 68 68 62 5 3,860 - 1,080 2,780

2012 57 57 52 5 3,356 - 1,082 2,274

2013 48 48 44 4 2,882 - 1,090 1,792

2014 40 40 37 3 2,467 - 1,104 1,362

2015 34 34 31 3 2,112 - 1,124 988

2016 28 28 26 2 1,808 - 1,149 659

2017 24 24 22 2 1,547 - 1,172 376

2018 20 20 18 2 1,325 326 1,213 214-

Total 399 399 367 32 23,765 7,726 10,098 5,941

0% 5% 10% 15% 20%

5,941 4,017 2,556 1,427 539


Tax NPV



112

Table XI-4 Probable Producing Reserve and Cash Flow Values of Lisa 1 Well

Working Interest = 100% Royalty Rate = Minimum 8% for Oil Sliding Scale Forecast Oil Price = NYMEX future for WTI minus API adjustment for 24o API Escalation Factor = 2% on commodity prices (if required) and 5% on costs Capital Expenditure = $0 Variable Operating Cost = $4.12/bbl Fixed Operating Cost = $29,000/well/month Abandonment Cost = $100,000/well Operating Days = 350 days per year Effective Date = December 31, 2008



2009 1 1 1 0 38 - 4 35

2010 2 2 2 0 122 - 10 112

2011 3 3 3 0 170 116- 14 272

2012 10 10 9 1 563 122 451 9-

Total 16 16 14 1 894 6 478 410

0% 5% 10% 15% 20%

410 372 339 311 286


Tax NPV



113

Table XI-5 Probable Undeveloped Reserve and Cash Flow Values of Lisa Oil Field

Working Interest = 100% Royalty Rate = Minimum 8% for Oil Sliding Scale Forecast Oil Price = NYMEX future for WTI minus API adjustment for 24o API Escalation Factor = 2% on commodity prices (if required) and 5% on costs Capital Expenditure = Drill 2 wells (Lisa 4 and 5)

$3,300,000/well drill and complete $400,000/well equip and tie-in

Variable Operating Cost = $4.12/bbl Fixed Operating Cost = $29,000/well/month Abandonment Cost = $100,000/well Operating Days = 350 days per year Effective Date = December 31, 2008



2009 - - - - - 7,400- - 7,400

2010 55 55 51 4 3,013 15,540 239 12,766-

2011 169 169 156 14 9,624 - 1,540 8,084

2012 142 142 131 11 8,367 - 1,487 6,880

2013 119 119 110 10 7,184 - 1,447 5,737

2014 100 100 92 8 6,149 - 1,419 4,730

2015 84 84 77 7 5,264 - 1,401 3,863

2016 70 70 65 6 4,506 - 1,393 3,113

2017 59 59 54 5 3,858 - 1,377 2,481

2018 50 50 46 4 3,303 326- 1,403 2,225

2019 58 58 54 5 3,961 - 2,672 1,289

2020 49 49 45 4 3,391 718 2,739 67-

Total 956 956 879 76 58,620 8,533 17,118 32,969

0% 5% 10% 15% 20%

32,969 25,287 19,904 16,036 13,192


Tax NPV



114

XII Evaluation of the Cicuco Block in the Lower Magdalena Valley The Incremental Production Contract (IPC) is with Ecopetrol with an effective date of February 2001 and expires in February 2023. The current area of the block is 37,610 hectares. Under the IPC, production is subject to 21% royalty for oil and 10% for gas and an overriding royalty of 2% before payout and 4% after payout to Ranpetrol as they have re-assigned their 30% working interest back to Kappa. Currently, Kappa has a 100% working interest in the IPC. For exploration in the remaining contract area, Kappa has a 94% working interest. Reserve The block has two discovered fields and they are the Zenon oil field and the Violo gas field. Under December 2008 economics for capital and operating costs, the Zenon field is deemed uneconomical at this time due to low oil price. Violo Gas Field The field has produced 18.2 Bcf of gas and will involve re-activation of the exploration/development of “shallow” gas resources associated with at least a number of offsetting structures. The non-associated Violo Gasfield was discovered by Colpet in 1958. Their initial attempt at reaching the Cicuco Limestone objective (Oligocene) was “junked” when a blowout from a shallow gas sand(s) located above 2,100 feet ignited and destroyed the Violo #1 drill rig. Subsequently, the location was re-drilled resulting in the Violo #1A discovery, which was confirmed two years later with the successful Violo #3 “follow-up” well located 1 km to the southeast (Violo #2 was miss-positioned, and drilled off-structure). Production commenced in 1967 when the gas was tied into the Boquete Field located 11 km to the west. The productive Cicuco Limestone reservoir was found at a depth of -3,994 feet in both Violo #1A and #3 wells, which is approximately 100 feet down dip from the crest of the structure, and 101 feet updip from a Gas Water Contact at -4,095 feet. Due to the open-hole completions, “bottom water” could not be controlled, and the field was shut-in four years later in 1971 after producing 2.6 Bcf gas and 51,243 barrels of water. The remaining recoverable gas reserve is estimated by volumetric method in the table shown later in this section. Work Program and Capital Expenditure and Work Program The field development is expected to drill vertical wells to 4,100 feet (TVD) at estimated cost of $2,100,000 per well including the costs of tie-in, roads, etc. In addition there is a $1,500,000 for a ~10 km sales gas pipeline to Cicuco Field. The work program and corresponding capital costs are as follows:

115

Well Name First Production Total Cost, $ Company’s Share, $ Violo #5 June 2009 2,100,000 2,100,000 Violo #6 July 2009 2,100,000 2,100,000 Violo #7 August 2009 2,100,000 2,100,000 Violo #8 September 2009 2,100,000 2,100,000 Violo Sales Line June 2009 1,500,000 1,500,000 Total 9,900,000 9,900,000 The abandonment cost (net of salvage) is estimated at $100,000 per well for a total cost of $400,000 for the four gas wells. Operating Costs The variable processing cost is estimated at $0.50 per Mcf and the fixed monthly operating cost of $7,500 per well. The operating costs above are for 2008 and expected to escalate at 5% per year in accordance with Colombian inflation rate estimates. Economic Parameters and Assumptions Working Interest 100% Royalty Rate 10% on Gas; 21% on Oil Overriding Royalty 2% BPO and 4% APO on Gas/Oil Royalty Payment All paid in Cash Forecast Gas Price $3.48 per MMBtu and escalate at

NYMEX futures for heating oil adjusted for 1,000 Btu/scf sale gas contract (see Forecast Gas Prices)

Escalation Factor 5% on costs G&A Costs $0.95 per net barrel of oil equivalent DD&A Costs $4.75 per net barrel of oil equivalent Other Costs $0.15 per net barrel of oil equivalent Fiscal Benefit 40% of Capital Expenditures to 2010 Corporate Income Tax Rate 33% per year Operating Days 350 per year Abandonment Cost $100,000 per well Effective Date December 31, 2008 Reserve Assignment Proved plus probable plus possible reserves are assigned to 1,165-acres of the Cicuco Basal Limestone located in the Violo Gas Field. The reserves are assigned based on historical production of the Violo #1A and Violo #3 wells, petrophysical analysis, 2D seismic interpretations and mapping and well test results. The proved plus probable plus possible estimated ultimate recoverable reserves assigned to each of the wells are outlined as follows based on 220-acres of drainage:

116

Proved+ Proved Probable Formation (MMcf) (MMcf) Cicuco Basal Limestones 2,449 3,063 Detailed volumetric calculations of the closures as defined by Seismic data are found later in this section. Production Forecast and Methods The production forecast model for the gas wells is as follows: Initial Rate Decline Rate Exponent Reserve Category (MMcf/d) (%/year) (b) Proved 1.9 36 0.3 Proved + Probable 2.3 33 0.3 The production forecasts are based on test results from the Violo #1A and Violo #3. The decline rates are based on acceptable decline rates for gas wells with similar reservoir characteristics.

117

Estimated Natural Gas Reserves at Standard Conditions (60oF and 14.65 psia) Reserve Category Proved + Probable Undeveloped Field Name Violo Gas Field, Cicuco

Block, Middle Magdalena Valley, Colombia

Formation Name Cicuco Basal Limstone Reservoir Interval (feet) 4,000’ to 4,200’ (TVD) Drainage area (acres) 1,165 Net pay thickness (feet) 45 Bulk rock volume (acre-feet) 52,425 Porosities (percent) 15.0 Water saturation (percent) 40.0 Oil saturation (percent) 0.0 Reservoir pressure (psia) 1,847 Reservoir temperature (oR) 592 Compressibility factor 0.88 Proved+ Proved Probable Initial gas-in-place (Mcf/acre-ft) 493.0 493.0 Initial gas-in-place (MMcf) 25,845 25,845 Recovery factor (percent) 50.0 60.0 Recoverable gas reserve (MMcf) 12,922 15,507 Cumulative production (MMcf) 2,611 2,611 Remaining recoverable reserve (MMcf) 10,311 12,896 Surface loss (percent) 5.0 5.0 Marketable gas reserve (MMcf) 9,796 12,251 Permeability (mD) H2S (percent) 0 CO2 (percent) 0.05 Heating value (Btu/Mcf) ~1,000 Specific gravity (Air=1.000) 0.55

118

Fig

ure

XII–

1 C

icuc

o B

lock

with

the

Oil

and

Ga

s F

ields

119

Figure XII-2 Violo Cienaga de Oro Gas

Tab

le X

II-1

Sum

mar

y o

f Vio

lo G

as F

ield

Pro

ved

+ P

roba

ble

Res

erve

s a

nd C

ash

Flo

w V

alue

s

N

atur

al G

as R

esou

rces

N

PV

of F

utur

e N

et R

even

ue

Bef

ore

Ta

x D

isco

unt

ed (

in M

$) @

N

PV

of F

utu

re N

et R

even

ue

A

fter

Ta

x D

isco

unt

ed (

in M

$) @

100

%

Gro

ss

Net

Res

erve

Cat

egor

y (M

Mcf

) (M

Mcf

) (M

Mcf

) 0

%

5%

10

%

15%

20

%

0%

5

%

10%

1

5%

20%

Pro

ved

und

evel

op

ed

8,5

49

8,5

49

7

,41

6

7,2

68

4,9

69

3

,315

2

,106

1

,20

9

5,0

75

3,2

87

2

,010

1

,083

4

02

P

rob

able

un

deve

lop

ed

2,7

20

2,7

20

2

,35

1

6,5

36

4,9

56

3

,878

3

,119

2

,56

7

5,1

23

3,8

83

3

,038

2

,443

2

,01

0

Pro

ved

+ p

rob

able

un

deve

lop

ed

11

,26

9

1

1,2

69

9

,76

7

13

,804

9

,92

5

7,1

94

5,2

25

3,7

76

1

0,1

98

7,1

71

5

,048

3

,526

2

,41

2

121

Table XII-2 Proved Undeveloped Reserve and Cash Flow Values of Violo Gas Field

Working Interest = 100% Royalty = 10% for gas Overriding royalty = 2% BPO and 4% APO Forecast Gas Price = $3.48 per MMBtu and escalation using NYMEX heating oil prices Capital Expenditure #1 = $2.1 million per well for drilling and completion Capital Expenditure #2 = $1.5 million for pipeline tie-in Operating Costs = $7,500 per month per well for fixed and $0.50 per Mcf for variable Abandonment Costs (net of salvage) = $100,000 per well Operating Days = 350 per year Effective Date = December 31, 2008 Natural Gas Resources Before

Tax Cash After

Tax Cash 100% Gross Net Royalty Revenue CapEx OpEx Year (MMcf) (MMcf) (MMcf) (M$) (M$) (M$) (M$) (M$) (M$) 2008 - - - - - - - - - 2009 1,168 1,168 1,028 487 4,061 10,395 787 (7,608) (6,825) 2010 2,005 2,005 1,765 802 6,682 - 1,502 4,378 3,501 2011 1,466 1,466 1,260 718 5,128 - 1,265 3,145 2,513 2012 1,100 1,100 946 566 4,043 - 1,106 2,370 1,893 2013 845 845 727 457 3,261 - 999 1,805 1,444 2014 662 662 569 375 2,682 - 926 1,380 1,108 2015 527 527 453 314 2,242 - 878 1,051 850 2016 426 426 366 266 1,903 - 847 790 647 2017 349 349 300 229 1,635 621 829 (43) (55) Total 8,549 8,549 7,416 4,214 31,637 11,016 9,138 7,268 5,075

NPV of Future Net Revenue Before Tax Discounted (in M$) @

NPV of Future Net Revenue After Tax Discounted (in M$) @

0% 5% 10% 15% 20% 0% 5% 10% 15% 20% 7,268 4,969 3,315 2,106 1,209 5,075 3,287 2,010 1,083 402

122

Table XII-3 Proved + Probable Undeveloped Reserve and Cash Flow Values of Violo Gas Field

Working Interest = 100% Royalty = 10% for gas Overriding royalty = 2% BPO and 4% APO Forecast Gas Price = $3.48 per MMBtu and escalation using NYMEX heating oil prices Capital Expenditure #1 = $2.1 million per well for drilling and completion Capital Expenditure #2 = $1.5 million for pipeline tie-in Operating Costs = $7,500 per month per well for fixed and $0.50 per Mcf for variable Abandonment Costs (net of salvage) = $100,000 per well Operating Days = 350 per year Effective Date = December 31, 2008 Natural Gas Resources Before

Tax Cash After

Tax Cash 100% Gross Net Royalty Revenue CapEx OpEx Year (MMcf) (MMcf) (MMcf) (M$) (M$) (M$) (M$) (M$) (M$) 2008 - - - - - - - - - 2009 1,369 1,369 1,205 571 4,760 10,395 892 (7,099) (6,427) 2010 2,395 2,395 2,107 957 7,979 - 1,717 5,305 4,232 2011 1,791 1,791 1,540 877 6,266 - 1,453 3,935 3,132 2012 1,371 1,371 1,179 705 5,037 - 1,271 3,061 2,430 2013 1,071 1,071 921 578 4,130 - 1,143 2,409 1,911 2014 851 851 732 482 3,445 - 1,052 1,911 1,515 2015 686 686 590 408 2,917 - 989 1,520 1,208 2016 560 560 482 350 2,502 - 946 1,206 963 2017 463 463 398 304 2,171 - 918 950 765 2018 387 387 333 267 1,904 - 901 736 600 2019 326 326 280 236 1,685 684 894 (130) (132) Total 11,269 11,269 9,767 5,737 42,797 11,079 12,177 13,804 10,198

NPV of Future Net Revenue Before Tax Discounted (in M$) @

NPV of Future Net Revenue After Tax Discounted (in M$) @

0% 5% 10% 15% 20% 0% 5% 10% 15% 20% 13,804 9,925 7,194 5,225 3,776 10,198 7,171 5,048 3,526 2,412

123

Zenon Oil Field (for information only)

The Zenon field is 4.5 km east of the 18.5 MMBO Boquete Field and 11 km southeast of the 51 MMBO Cicuco Field. At a drill depth of 6,100 feet, the Zenon Field is 2100 feet down dip of Violo Gas Field situated 7.5 km further to the southeast. Only three wells (2 oil and 1 dry) were ever drilled at Zenon. The Zenon #1 discovery well was drilled by Colpet in 1959, and successfully followed-up by the Zenon #2 step-out (located 856 m southwest) one year later. The Zenon #3 step-out, drilled in 1960, was Colpet’s final effort at delineating the field. It was located at 1130 m NNE of Zenon #1 and was abandoned after appraising the down dip limit of the field where the bulk of the reservoir section was found to be wet. Zenon #1 was the only well to be tied-in and produced (4” flow-line to Cicuco Battery) before Colpet lost interest in the field in 1965, and concentrated on developing its larger Boquete and Cicuco projects. A series of “disappointments” beginning with the Zenon #3 failure caused Colpet to abandon its plans to drill at least 6 multi-lateral development wells. Some of the operational/logistical problems faced by Colpet included repeated flooding of the locations, stolen flow-lines, a failed attempt to install artificial lift at Zenon #1, and a lost fish which “junked” Zenon #2. The Field eventually reverted to Ecopetrol who re-activated the Zenon #1 well in 1979 after installing gas lift. Ecopetrol shut-in Zenon #1 in late 1996 after the well had produced 82,890 barrels of 40.6˚ API waxy crude (9.9% wax), 18,164 barrels of water, and 157 MMcf of gas. The primary reservoir in the Zenon Field is the Cicuco Clastic section consisting of greater than 50’ (net) of fair quality interbedded sandstones with porosities of 11 to 16% and permeabilities of 6 to 155 mD. As in the offsetting fields, these sands are sensitive to fresh-water and acid. Secondary reservoirs associated with the overlying Cicuco Limestones, and deeper, fractured Basal “Lag”/Basement sections may also contribute. Except for a few of the most poorly developed sands, the entire reservoir section appears to share a common Oil-Water-Contact at -6,258 feet. If this is the case, the vertical oil column could be in excess of 243 feet thick. Although the reservoir is ultimately trapped by a series of updip faults, paleo-topography has influenced reservoir distribution. This was confirmed by the drilling of Zenon #2, which tested the crest of a “buried hill/knoll” where the clastic section is dramatically thinned. Despite a thinned reservoir section, Zenon #2 tested oil at a flowing rate from 68 to 104 bopd, which is comparable to Zenon #1 test rates of 75 to 148 bopd. Compared to the Boquete Field, which has a very similar reservoir section, the Zenon wells have under-performed probably because they failed to intersect a significant fracture system. Fracture networks are expected, but will be irregularly distributed as in the offsetting Boquete Field where recoveries range from roughly 200,000 barrels of oil to greater than 2 million barrels of oil in the most heavily fractured wells. Since Zenon #1 was drilled with fresh-water and acidized, formation damage could have further compromised reservoir performance. Conversion from a slotted-liner to a cased-hole completion also adversely affected production. The fact that the Cicuco Clastic reservoir has been successfully exploited in nearby fields bodes well for the development of the Zenon Field. It is expected that field productivity could be enhanced by (a) implementing compatible completions including the use of invert mud, (b) immediately installing artificial lift, (c) fracture stimulating updip wells, or wells drilled on paleo-highs (ie. Zenon #2) and (d) maintaining pressure support through gas, or water injection.

124

Appendix A – Conversion Factors and Abbreviations

Conversion Factors 1 metre 3.28 feet 1 cubic metre of gas 35.31467 cubic feet of gas 1 cubic metre of liquid 6.28981 barrels 1 kg/sq. cm. 14.22334 psi 1 hectare (10,000 square metres) 2.471054 acres

Abbreviations

ac acre AOF absolute open flow API American Petroleum Institute bbl barrel bopd barrels of oil per day BTU British Thermal Unit cp centipose oF degrees, Fahrenheit oR degrees, Rankin ft feet GOR gas oil ratio KB Kelly bushing LT long tonne m metre Mbbl thousands of barrels MMbbl millions of barrels $M thousand dollars Mcf thousand cubic feet mD milli-Darcy MD measured depth MMcf million cubic feet ppm parts per million PVT pressure-volume-temperature psia pounds per square inch absolute psig pounds per square inch gauge rb reservoir barrel RFT Repeat formation test scf standard cubic feet ss subsea stb stock tank barrel STOOIP stock tank original oil-in-place TVD true vertical depth WI working interest

125

Appendix B – Production Plots of Abanico Wells

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