|II |  | Evaluation of the Guaduas
Field in Middle/Upper Magdalena Valley
|-- |  | ----------------------------------------------------------------

The
Guaduas field is located in the Dindal and Rio Seco Blocks. It covers 30,665 acres in the Middle Magdalena Valley and is approximately
62 miles northwest of the City of Bogota. The Company purchased 90.6% working interest in this property from SiPetrol S.A. on
July 6, 2006 and became the operator. The remaining 9.4% working interest belongs to Cimarrona Oil & Gas. The oil and gas
production are subject to a 20% royalty rate. Geology.
Discovery, and Production of the Guaduas Field The
Guaduas field is located in the Middle Magdalena Valley Basin on the west flank of the Guaduas syncline and is a hanging-wall
anticlinal feature created by the movement of the Honda thrust. The Guaduas field was discovered in 1996 by GHK Company, LLC of
Oklahoma from the drilling of the El Segundo-IE well and was placed on production later that year through an extended production
test. Production is from the late Cretaceous Cimarrona formation, which is a sequence of alternating clastic and carbonate rocks
deposited in a transitional marine environment. The Cimarrona formation in the uaduas field is composed of fractured limestone
and calcareous sandstone, interbedded with calcareous shale and siltstones. The
Guaduas closure to the north, south and west is structural in nature, while the eastern closure is based on a facies change. The
deposit environment is marine to transitional. In the area of the Guaduas field, wells encountered Cimarrona thickness between
230 and 350 feet. During exploration, it was discovered that hydrocarbon accumulations are controlled by the presence of fractures
and limited almost exclusively to the fractures. Development focused on fracturing and evelopment of limestone and sands, drilling
perpendicularly to the direction of the fractures in order to drain most of the hydrocarbons found in the fractures. Full
field development began in 2001 with production peaking in 2002 prior to declining to present day levels. In the early stages
of exploration, the Cimarrona formation was identified as a clastic sequence that varied in lithology, from onglomerate sediments
related to deltaic fans, canals and marine bars from coastal environments, to shallow-water limestone. Later exploration efforts
resulted in the discovery that hydrocarbon accumulations in the area were controlled by the presence of fractures and limited
almost exclusively to the fractures, with minimal matrix contribution. Development therefore focused on fracturing and the development
of limestone and sandstone by drilling perpendicularly to the direction of the fractures in order to drain the highest percentage
of hydrocarbons found in these fracture systems. As
of year-end 2010, 17 wells have been drilled with seven producing oil wells and eight non-producing oil wells, one water injection
well and one gas injection well. For the purposes of this evaluation, all seven oil wells are producing and two non-producing
oil wells were scheduled for workovers in 2010 but no work was done. The daily average rate for 2010 was 641 barrels of 19°API
crude, 4,270 Mcf of gas and 1,076 barrels of water for the 2010 production of 234,133 barrels of oil, 1,558,595 Mcf of gas and
392,737 barrels of water. Cumulative production to December 31, 2010 was 10,990,993 barrels of oil, 22,930,983 Mcf of gas and
4,269,587 barrels of water. Wells produce through a combination of electrical submersible pumps (ESP), progressive cavity pumps
(PCP) and gas lift. Produced gas is used for fuel, re-injected for pressure maintenance and gas sales. Produced water is re-injected
for disposal. A review of gas-oil ratio performance indicates that gas breakthrough has occurred in a number of producing wells.  1
 
 The
discovery well, the El Segundo IE well, was located using the seismic database existing in 1996 that consisted only of 2-D seismic.
The 2-D seismic outlining the field consists of 14 seismic profiles with separations between transversal lines of approximately
three km and six km between the direction lines. The reprocessing resulted in an improvement in the frequency content, image reproduction
and seismic character. There is a total of 254 km of 2-D seismic available for the area. In
view of the exploratory success with additional wells, 129 km2 of 3-D seismic was acquired. Additional reprocessing
was performed on the 3-D seismic to eliminate static problems and to improve definition of seismic events of the Cimarrona Formation,
to better define the faults and to visualize the reservoir's area. The 3-D seismic was used to improve mapping of the structure,
defining orientation of principal faults and pin-pointing the reservoirs position, allowing for better planning of development
wells. As part of an integrated reservoir study, in conjunction with the seismic reprocessing, synthetic seismograms were built
relating to the area wells to improve structural interpretation of the reservoir Reservoir
Evaluation Within
the Cimarrona formation, the porosity ranges from 0 to 5% with permeability ranges from 0.01 to 1 mD. The oil is trapped in fractures.
Based on petrophysical properties combined with a stratigraphic model, the Cimarrona formation is divided into the Upper Cimarrona
(Flow units FU1, FU2, FU3,FU4 and FU5) and Lower Cimarrona (Flow units FU6, FU7 and FU8). The FU2 is the principal reservoir
and FU4 and FU5 are considered good reservoirs Work
Program Through
infill drilling the Company plans to continue development of the field in order to maintain production decline rates as existing
wells are abandoned. One highly delineated well is planned for 2010. If successful, another development well will be drilled in
2011 (see Figure II-3). Two more similar wells are planned for 2012 depending on the results of the 2010 infill drilling.  2
 
 Figure
II-1 Location Map of the Guaduas Field in the Middle Magdalena Valley,Colombia      3
 
  Figure
II-2 Stratigraphic Chart of the Middle Magdalena Valley    4
 
  Figure
II-3 Guaduas Field Delineated Well Development Locations    5
 
  Capital
Costs  The total capital expenditures for the drilling of four additional wells are as follows:  Description
    Cost (in U.S. M$)ES_2S
    workover to fix mechanical problem in 2011
    300.0Drill
    and complete 1 deviated well in 2011
    5,500.0Facility,
    location, tie-in and environmental study for 1 well in 2011
    500.0Drill
    and complete 1 vertical well in 2012
    3,000.0Facility,
    location, tie-in and environmental study for 1 well in 2012
    500.0Drill
    and complete 2 deviated (1 vert. + 1 horiz.) wells in 2012
    8,500.0Facility,
    location, tie-in and environmental study for 2 wells in 2012
    1,000.0Total
    Costs
    19,300.0 The
Company's share of field development costs at 90.6% working interest is equal to $17,485,800. The following is a detailed timeline
for abandonment of Guaduas wells:  Well
    Name
    Date
    Well
    Name
    Date
    Well
    Name
    DateTP
    7W
    2011
    ES_1S
    2021
    Development
    Well #1
    2019TP
    IE
    2019
    TP_6E_ST2
    2016
    Development
    Well #2
    2016ES
    2S
    2018
    ES_2E_ST1
    2015
    Development
    Well #3
    2021TP
    6N
    2012
    ES_5N
    2021
    Development
    Well #4
    2016 Operating
Costs The
total 2010 operating expenses (excluding transportation) totaled $4,198,399 (100% working interest). The fixed cost was 95% of
the total operating cost, resulting in $336,671 per month for the Guaduas oil field. The variable cost is 5% of the total operating
cost and, based on 212,124 barrels of total oil production, the resulting cost was $4.09 per barrel. The transportation cost was
$1.50 per barrel.  Economic Assumptions and ParametersWorking
    Interest
    90.6%Royalty
    Rate
    20%WTI
    Oil Price on December 31, 2010
    US$91.40
    per barrelVasconia
    Price on December 31, 2010
    US$90.80
    per barrelGuaduas
    Oil Price 2010
    US$89.16
    per barrelForecast
    Oil Price
    Escalate
    at NYMEX futures for WTI light crudeEscalation
    factor for costs
    4%
    per year based on Colombia consumer indexContract
    Expiration
    February
    2021Operating
    Days
    estimated
    at 365 per yearAbandonment,
    salvage, clean-up
    $100,000/well   6
 
  Reserve Proved
developed producing reserves have been assigned to seven Guaduas wells based on theproduction performance trends of the historical data. The following table outlines the proved developed
producing reserves estimates:  Estimated
    
    Remaining to
    Remaining toCumulative
    Ultimate
    Remaining
    Contract
    EconomicProduction
    Recoverable
    Recoverable
    Expiry
    LimitWell Name
    Category
    (bbl)
    (bbl)
    (bbl)
    (bbl)
    (bbl)ES_1S
    PDP
    2,655,246
    3,555,567
    900,321
    603,285
    720,996ES_2E_ST1
    PDP
    866,099
    1,006,020
    139,921
    72,542
    72,542ES_5N
    PDP
    870,304
    1,709,067
    838,763
    394,942
    614,427TP_1E
    PDP
    1,700,124
    1,937,036
    236,912
    143,338
    143,338TP_6E_ST2
    PUP
    424,047
    582,847
    158,800
    76,025
    76.025TP_6N
    PDP
    677,368
    705,958
    28,590
    8,673
    8,6737P_7W
    PDP
    352,019
    361,961
    9,942
    —
    —Total
    
    7,545,207
    9,858,456
    2,313,249
    1,298,805
    1,636,001 (1)        
Production decline analysis found in Appendix B (2)         
Cumulative production to December 31, 2010. (3)         
Estimate ultimate recoverable based on 5 bopd cutoff. Based
on surrounding production analogues and 3-D seismic interpretations, proved undeveloped reserve are assigned to two delineated
infill wells (DevelopmentWell #1& Development Well #2) in theGuaduas field (see Figure II-3).  Estimated
    
    Remaining to
    Remaining toCumulative
    Ultimate
    Remaining
    Contract
    EconomicProduction
    Recoverable
    Recoverable
    Expiry
    LimitWell Name
    Category
    (bbl)
    (bbl)
    (bbl)
    (bbl)
    (bbl)Development Well #1
    PUD
    —
    1,689,233
    1,689,233
    1,020,346
    1,020,346Development Well #2
    PUD
    —
    262,377
    262,377
    149,259
    149,259Total
    
    —
    1,951,610
    1,951,610
    1,169,605
    1,169,605 (1)         
Analogue models found later in this section. (2)         
Estimate ultimate recoverable based on 15 bopd cutoff (3)         
Development Well #2 to be drilled in pressure depleted reservoir therefore lower recovery  Estimated
    
    Remaining to
    Remaining toCumulative
    Ultimate
    Remaining
    Contract
    EconomicProduction
    Recoverable
    Recoverable
    Expiry
    LimitWell Name
    Category
    (bbl)
    (bbl)
    (bbl)
    (bbl)
    (bbl)ES_IN
    PDNP
    300,985
    572,808
    271,823
    176,154
    176,154ES_2S
    PDNP
    175,191
    844,631
    669,440
    146,791
    146,791ES_6E_ST2
    PDNP
    103,862
    263,642
    159,780
    102,713
    102,713Total
    
    580,038
    1,681,081
    1,101,043
    425,658
    425,658 (1)
The ES_2S reserve is based on the well coming back at the same rate it was shut-in August 2008 (see Production Forecast and Methods
section).  7
 
 Based
on surrounding production analogs and 3-D seismic interpretations, probable undeveloped reserve is assigned to two delineated
infill wells (Development Well #3 &Development Well #4) in the Guaduas field. These infill locations will offset the Development
#1 and #2 wells depending on results.  Estimated
    
    Remaining to
    Remaining toCumulative
    Ultimate
    Remaining
    Contract
    EconomicProduction
    Recoverable
    Recoverable
    Expiry
    LimitWell Name
    Category
    (bbl)
    (bbl)
    (bbl)
    (bbl)
    (bbl)Development Well #3
    Probable
    —
    1,689,233
    1,689,233
    1,020,129
    1,020,129Development Well #4
    Probable
    —
    262,377
    262,377
    256,677
    256,677Total
    
    —
    1,951,610
    1.951,610
    1,276,806
    1,276506 (1)          
Analogue models found later in this section. (2)          
Estimate ultimate recoverable based on 15 bopd cutoff (3)          
Development Well #4 to be drilled in pressure depleted reservoir therefore lower recovery Production
Forecast and Declines The
proved developed producing forecasts are based on production performance trends.  PDP
                                                                                                                 InitialRate
                                                                                                                                    in 2011
    PDP Decline RateWell Name
    (bopd)
    (%/year)ES_IS
    284.0
    10.4ES_2E ST1
    57.7
    12.2ES_5N
    152.5
    6.4TP_1E
    68.5
    9.1TP_6E_ST2
    48.2
    9.1TP_6N
    27.6
    23.47P_7W
    18.1
    37.2  (1)	Production
decline analyses are in Appendix B. The
proved developed non-producing forecast for the ES_2S workover is based on production performance trends of the ES_2S well.  PDNP Initial
    PDNP DeclineRate
    RateWell Name
    (bopd)
    (%/year)ES_2S
    95.2
    14.0 The
proved undeveloped and probable undeveloped forecasts are based on two analog well models. Analog Model #2 (see plot below) is
for a location with initial reservoir pressure and Analog Model #1 (see Figure II-4 and II-5) is for a location within the pressure
depleted reservoir. Initial Rate
    Decline RateWell Name
    (bopd)
    (%/year)Analogue Model #1
    250.0
    42.0Analogue Model #2
    1,250.0
    36.0  8
 
  Table
    II-l - Summary of Guaduas Reserve and Net Present ValuesHeavy
    Oil Reserves
    
    Before
    Tax NPV100%
    Gross
    Net
    0%
    5%
    10%
    15%
    20%Well
    Category
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (M$)
    (M$)
    (M$)
    (M$)
    (M$)ES-lS
    Proved
    developed producing
    603
    547
    437
    30,297
    25,240
    21.565
    18,816
    16,703ES-2E-ST1
    Proved
    developed producing
    73
    66
    53
    1,740
    1,620
    1.518
    1,430
    1,354ES-5N
    Proved
    developed producing
    395
    358
    286
    17,993
    14,760
    12,439
    10,724
    9,422TP-1E
    Proved
    developed producing
    143
    130
    104
    3,606
    3,204
    2.883
    2,623
    2,409TP-6E-ST2
    Proved
    developed producing
    76
    69
    55
    1,387
    1,292
    1,210
    1,139
    1,076TP-6N*
    Proved
    developed producing
    9
    8
    6
    -25
    24
    -24
    -23
    -23TP-7W*
    Proved
    developed producing
    -
    -
    
    -94
    -92
    -90
    -88
    -86Total
    PDP
    1,299
    1,177
    941
    54,904
    46,000
    39,502
    34,620
    30,854ES-1N
    Proved
    developed non-producing
    177
    160
    128
    5,074
    4,394
    3,875
    3,471
    3,148ES-2S
    Proved
    147
    133
    106
    4,133
    3,731
    3,402
    3,129
    2,899ES-6E-ST2
    Proved
    developed non-producing
    103
    93
    74
    2,960
    2,725
    2,527
    2,359
    2,215Total
    PDNP
    427
    386
    309
    12,166
    10,850
    9,805
    8,959
    8,263PUD-1
    Proved
    undeveloped
    1,020
    924
    740
    50,312
    44,909
    40,534
    36,937
    33,933PUD-2
    Proved
    undeveloped
    155
    140
    112
    3,420
    2,943
    2,552
    2,229
    1,960Total
    PUD
    1,175
    1,064
    852
    53,732
    47,851
    43,087
    39,167
    35,892Total
    Proved
    2,900
    2,628
    2,102
    120,801
    104,701
    92,393
    82,746
    75,009ES-lS
    Probable
    Producing
    426
    386
    309
    25,213
    20,791
    17,607
    15,247
    13,447Total
    Probable Producing
    426
    386
    309
    25,213
    20,791
    17,607
    15,247
    13,447PBUD-1
    Probable
    Undeveloped
    1.020
    924
    739
    49,247
    41,584
    35,604
    30,851
    27,009PB
    UD-2
    Probable
    Undeveloped
    154
    140
    112
    3,100
    2,504
    2,030
    1,649
    1,339Total
    Probable Undeveloped
    1,175
    1,064
    851
    52,346
    44,088
    37,634
    32,500
    28,348Total
    Probable
    1,601
    1,450
    1,160
    77,559
    64,880
    55,241
    47,747
    41,796Total
    Proved + Probable
    4,501
    4,078
    3,262
    198,360
    169,581
    147,635
    130,493
    116,805* Uneconomic wells are included with abandonment costs.   9
 
 Table
II-2 Guaduas Field Total Proved Developed Producing Reserve and Net
Present Values Working
Interest = 90.6% Royalty
rate = 20% Escalation
Factor = 4% per year based on Colombian Consumer Index Forecast
Oil Price = see Forecast Oil Prices Fixed
OpEx = $446,000 per well per year fixed cost Variable
OpEx = $6.30 per barrel Operating
Days = 365 per year Abandonment
Cost = $100,000 per well Effective
Date = December 31, 2010  Heavy
    Oil Reserves
    
    
    RevenueGas
    
    
    BeforeGross
    

(Less
    
    
    Tax100%
    Gross Net
    Royalty
    Gas
    Oil

Royalty)
    CapEx
    OpEx
    NPVYear
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (MMcf)
    (M$)
    (M$)
    (M$)
    (M$)
    (M$)2011
    219
    198
    159
    40
    43
    14,133
    111
    188
    3,924
    10,1312012
    186
    168
    135
    34
    36
    12,048
    105
    -
    3,422
    8,7312013
    165
    150
    120
    30
    32
    10,587
    98
    -
    3,431
    7,2542014
    148
    134
    107
    27
    29
    9,455
    90
    -
    3,460
    6,0852015
    134
    121
    97
    24
    26
    8,568
    84
    110
    3,504
    5,0382016
    113
    102
    82
    20
    22
    7,269
    73
    115
    2,956
    4,2712017
    95
    86
    69
    17
    18
    6,210
    62
    -
    2,377
    3,8952018
    87
    79
    63
    16
    17
    5,844
    58
    -
    2,417
    3,4852019
    81
    73
    59
    15
    16
    5,523
    55
    129
    2,464
    2,9862020
    66
    59
    47
    12
    13
    4,558
    46
    -
    1,802
    2,8022021
    5
    5
    4
    1
    1
    379
    4
    -
    155
    228Total
    1,299
    1,177
    941
    235
    253
    84,573
    785
    542
    29,912
    54,904  NPV
    of Future Net RevenueBefore Tax Discounted (in M$)@0%
    5%
    10%
    15%
    20%54,904

46,000
    39,502
    34,620
    30,854    10
 
  Table
II-3 Guaduas Field Proved Developed Non-Producing Reserve and Net
Present Values Working
Interest = 90.6% Royalty
rate = 20% Escalation
Factor = 4% per year based on Colombian Consumer Index Forecast
Oil Price = see Forecast Oil Prices Fixed
OpEx = $446,000 per well per year fixed cost Variable
OpEx = $6.30 per barrel Operating
Days = 365 per year Abandonment
Cost = $100,000 per well Effective
Date = December 31, 2010  Heavy
    Oil Reserves
    
    
    RevenueGas
    
    
    BeforeGross
    
    (Less
    
    
    Tax100%
    Gross
    Net
    Royally
    Gas
    Oil
    Royalty!
    Cap
    Ex
    OpEx
    NPVYear
    (Ml.hl)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (MMcf)
    (M$)
    (M$)
    (M$)
    (M$)
    (M$)2011
    84
    76
    61
    15
    16
    5,428
    43
    272
    1.817
    3,3812012
    71
    64
    51
    13
    14
    4,597
    10
    -
    1,812
    2.8242013
    60
    55
    44
    11
    12
    3,869
    36
    -
    1,819
    2,0862014
    52
    47
    38
    9
    10
    3,321
    32
    -
    1,839
    1,5132015
    45
    41
    33
    8
    9
    2,900
    28
    -
    1.868
    1,0602016
    40
    36
    29
    7
    8
    2.572
    26
    115
    1.906
    5772017
    26
    24
    19
    5
    5
    1.707
    17
    -
    1,317
    4082018
    23
    21
    17
    4
    5
    1.569
    16
    124
    1,350
    1102019
    12
    11
    9
    2
    2
    833
    8
    -
    706
    1352020
    11
    10
    8
    2
    2
    786
    8
    -
    727
    682021
    1
    1
    1
    0
    0
    65
    1
    -
    63
    3Total
    427
    386
    309
    77
    83
    27,647
    254
    510
    15,225
    12.166  NPV of Future Net Revenue

Before
Tax Discounted (in M$) @0%
    5%
    10%
    15%
    20%12.166
    10.850
    9.805
    8,959
    8,263     11
 
  Table
II-4 Guaduas Field Proved Undeveloped Reserve and Net Present Values Working
Interest = 90.6% Royalty
rate = 20% Escalation
Factor = 4% per year based on Colombian Consumer Index Forecast
Oil Price = see Forecast Oil Prices Fixed
OpEx = $446,000 per well per year fixed cost Variable
OpEx = $6.30 per barrel Operating
Days = 365 per year Abandonment
Cost = $100,000 per well Effective
Date = December 31, 2010  Heavy
    Oil Reserves
    
    
    RevenueGas
    
    
    BeforeGross
    
    (Less
    
    
    Tax100%
    Gross
    Net
    Royally
    Gas
    Oil
    Royalty)
    Cap
    Ex
    OpEx
    NPVYear
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (MMcf)
    (M$)
    (M$)
    (M$)
    (M$)
    (M$)2011
    240
    217
    174
    43
    47
    15.502
    122
    5,436
    1,369
    8,8182012
    347
    315
    252
    63
    68
    22,526
    196
    3,298
    2,990
    16,4342013
    233
    211
    169
    42
    45
    14,920
    137
    
    2,400
    12,6572014
    146
    132
    106
    26
    28
    9,311
    89
    -
    1,941
    7,4592015
    92
    83
    67
    17
    18
    5,862
    57
    -
    1,656
    4,2632016
    54
    49
    39
    10
    10
    3,463
    35
    115
    1,188
    2,1952017
    31
    28
    22
    6
    6
    2,032
    20
    -
    788
    1,2642018
    20
    18
    14
    4
    4
    1,327
    13
    -
    736
    6042019
    13
    12
    9
    2
    2
    866
    9
    129
    710
    36Total
    1,175
    1,064
    852
    213
    229
    75,809
    678
    8,977
    13,778
    53,732  NPV
    of Future Net RevenueBefore
    Tax Discounted (in M$) @0%
    5%
    10%
    15%
    20%53,732
    47,851
    43,087
    39,167
    35,892    12
 
  Table
II-5 Cuaduas Field Total Proved Reserve and Net Present Values Working
Interest = 90.6% Royalty
rate = 20% Escalation
Factor = 4% per year based on Colombian Consumer Index Forecast
Oil Price = see Forecast Oil Prices Fixed
OpEx = $446,000 per well per year fixed cost Variable
OpEx = $6.30 per barrel Operating
Days = 365 per year Abandonment
Cost = $100,000 perwell Effective
Date = December 31. 2010  Heavy
    Oil Reserves
    
    
    RevenueGas
    
    
    BeforeGross
    
    (Less
    
    
    Tax100%
    Gross
    Net
    Royalty
    Gas
    Oil
    Royalty)
    CapEx
    OpEx
    NPVYear
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (MMcf)
    (MS)
    (MS)
    (MS)
    (MS)
    (MS)2011
    543
    492
    393
    98
    106
    35,062
    276
    5,896
    7,111
    22,3312012
    604
    547
    438
    109
    118
    39,171
    340
    3,298
    8,224
    27,9892013
    458
    415
    332
    83
    89
    29,377
    271
    -
    7,651
    21,9972014
    346
    314
    251
    63
    67
    22,086
    211
    -
    7,240
    15,0572015
    271
    246
    197
    49
    53
    17,330
    170
    110
    7,029
    10,3612016
    207
    188
    150
    38
    40
    13,304
    133
    344
    6,050
    7,0432017
    152
    137
    110
    27
    30
    9,949
    99
    -
    4,482
    5,5672018
    131
    118
    95
    24
    25
    8,739
    87
    124
    4,503
    4,1992019
    106
    96
    77
    19
    21
    7,222
    72
    258
    3,879
    3,1572020
    77
    70
    56
    14
    15
    5,344
    53
    -
    2,528
    2,8692021
    6
    6
    5
    1
    1
    444
    4
    -
    218
    231Total
    2,900
    2,628
    2,102
    526
    565
    188,029
    1,716
    10,030
    58,914
    120,801  NPV
    of Future Net RevenueBefore
    Tax Discounted (in MS) @0%
    5%
    10%
    15%
    20%120.801

104,701
    92,393
    82,746
    75,009 13
 
   Table
H-6 Guaduas Field Probable Developed Reserve and Net Present Values Working
Interest = 90.6% Royalty
rate = 20% Escalation
Factor = 4% per year based on Colombian Consumer Index Forecast
Oil Price = see Forecast Oil Prices CapEx
= $5,500,000 per deviated well and $3,000,000 per vertical well drilling cost Fixed
OpEx = $446,000 per well per year fixed cost Variable
OpEx = $6.30 per barrel Operating
Days = 365 per year Abandonment
Cost = $100,000 per well Effective
Date = December 30, 2010  Heavy
    Oil Reserves
    
    
    RevenueGas
    
    
    BeforeGross
    (Less
    
    
    Tax100%
         Gross       Net
    Royalty
    Gas
    Oil
            Royalty)
    Capi'.x
    OpEx
    NPVYear
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (MMcf)
    (MS)
    (M$)
    (M$)
    (M$)
    (MS)2011
    69
    62
    50
    12
    13
    4,432
    35
    -
    391
    4,0762012
    60
    54
    43
    11
    12
    3,886
    34
    -
    356
    3,5642013
    53
    48
    38
    10
    10
    3.370
    31
    -
    324
    3,0772014
    47
    42
    34
    8
    9
    2,969
    28
    -
    299
    2.6982015
    42
    38
    30
    8
    8
    2,653
    26
    -
    277
    2,4012016
    37
    34
    27
    7
    7
    2,402
    24
    -
    260
    2,1662017
    34
    30
    24
    6
    7
    2.205
    22
    -
    243
    1,9842018
    31
    28
    22
    6
    6
    2.041
    20
    -
    229
    1.8322019
    28
    25
    20
    5
    5
    1.897
    19
    -
    217
    1,6992020
    26
    23
    18
    5
    5
    1,775
    18
    -
    207
    1,5862021
    2
    2
    1
    0
    0
    146
    1
    -
    17
    130Total
    426
    386
    309
    77
    83
    27,775
    258
    -
    2,821
    25,213  NPV
    of Future Net RevenueBefore
    Tax Discounted (in MS) @0%
    5%
    10%
    15%
    20%25.213
    20.791
    17,607
    15,247
    13,447   14
 
  Table
II-7 Guaduas Field Probable Undeveloped Reserve and Net Present Values Working
Interest - 90.6% Royalty
rate = 20% Escalation
Factor = 4% per year based on Colombian Consumer Index Forecast
Oil Price = see Forecast Oil Prices CapEx
= $5,500,000 per deviated well and $3,000,000 per vertical well drilling cost Fixed
OpEx = $446,000 per well per year fixed cost Variable
OpEx = $6.30 per barrel Operating
Days = 365 per year Abandonment
Cost = $100,000 per well Effective
Date = December 30, 2010  Heavy
Oil Reserve


    
    RevenueGas
    
    
    BeforeGross
    
    (Less
    
    
    Tax100%
    Gross
    Net
    Royalty
    Gas
    Oil
    Royalty)
    Cap Ex
    OpEx
    XPVYear
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (MMcf)
    (M$)
    (M$)
    (M$)
    (M$)
    (M$)2011
    -
    -
    -
    
    -
    -
    -
    -
    -2012
    232
    210
    168
    42
    45
    15,049
    131
    8,951
    2,305
    3,9232013
    362
    328
    263
    66
    71
    23,250
    214
    -
    3,202
    20,2632014
    228
    207
    165
    41
    44
    14,554
    139
    -
    2,468
    12,2242015
    144
    130
    104
    26
    28
    9,190
    90
    -
    2,004
    7,2762016
    91
    83
    66
    17
    18
    5,854
    58
    115
    1,718
    4,0812017
    50
    46
    36
    9
    10
    3,296
    33
    -
    927
    2,4012018
    32
    29
    23
    6
    6
    2,152
    21
    -
    829
    1,3452019
    21
    19
    15
    4
    4
    1,405
    14
    -
    771
    6472020
    13
    12
    10
    2
    3
    920
    9
    -
    742
    1872021
    1
    1
    1
    0
    0
    62
    1
    -
    62
    0Total
    1,175
    1,064
    851
    213
    229
    75,730
    710
    9,066
    15,029
    52,346  NPV
    of Future Net RevenueBefore Tax Discounted (in M$) @0%
    5%
    10%
    15%
    20%52,346
    44,088
    37,634
    32,500
    28,348       15
 
  Table
II-8 Guaduas Field Total Proved + Probable Reserve and Net Present Values Working
Interest = 90.6% Royalty
rate = 20% Escalation
Factor - 4% per year based on Colombian Consumer Index Forecast
Oil Price = see Forecast Oil Prices CapEx
= $5,500,000 per deviated well and $3,000,000 per vertical well drilling cost Fixed
OpEx = $446,000 per well per year fixed cost Variable
OpEx = $6.30 per barrel Operating
Days = 365 per year Abandonment
Cost = $100,000 per well Effective
Date = December 30, 2010  Heavy Oil Reserves
    
    
    RevenueGas
    
    
    BeforeGross
    
    (Less
    
    
    Tax100%
    Gross
    Net
    Royalty
    Gas
    Oil
    Royalty)
    Cap Ex
    OpEx
    NPVYear
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (MMcf)
    (M$)
    (M$)
    (M$)
    (M$)
    (M$)2011
    611
    554
    443
    111
    119
    39,495
    311
    5,896
    7,502
    26,4072012
    896
    812
    649
    162
    175
    58,105
    504
    12,249
    10,885
    35,4762013
    873
    791
    633
    158
    170
    55,997
    516
    
    11,177
    45,3362014
    621
    563
    450
    113
    121
    39,608
    378
    
    10,007
    29,9792015
    457
    414
    331
    83
    89
    29,173
    285
    110
    9,310
    20,0382016
    335
    304
    243
    61
    65
    21,560
    215
    459
    8,027
    13,2902017
    236
    214
    171
    43
    46
    15,450
    154
    -
    5,652
    9,9532018
    193
    175
    140
    35
    38
    12,931
    129
    124
    5,561
    7,3762019
    154
    140
    112
    28
    30
    10,523
    105
    258
    4,867
    5,5032020
    116
    105
    84
    21
    23
    8,039
    80
    -
    3,478
    4,6422021
    9
    8
    7
    2
    2
    652
    7
    -
    298
    361Total
    4,501
    4,078
    3,262
    816
    877
    291,535
    2,685
    19,096
    76,764
    198,360  NPV
    of Future Net RevenueBefore
    Tax Discounted (in MS) @0%
    5%
    10%
    15%
    20%198,360

169,581
    147,635
    130,493
    116,805


16