Report on Exploration Potentialof
Pantera Petroleum Inc. Concessionsin Paraguay
By Energy Consulting International, Inc.June 2007
Pantera Petroleum,Inc. - Summary
• Pantera is U.S company with 2 subsidiaries in Paraguay which together have concessions on 16,000 sq km of land in the Chaco Basin in Northern Paraguay.
• The Chaco Basin covers Southern Bolivia, part of Northern Argentina and Northern Paraguay.
• The Bolivian and Argentine parts of the Chaco Basin have been heavily explored (846 exploration wells) and become major oil and gas producing regions – 2+ BCFD Gas , 50,000+ BOPD and over 80 tcfe of oil and gas reserves discovered.
• But the Paraguay extension is under-explored – only 49 wells in all of Paraguay. Chaco Basin has only 27 wells - one gas field discovered, and 6 wells with oil or gas shows.
• Analysis of the play type, field distribution, performance and geology of the Chaco Basin points to the Paraguayan part of the basin having significant potential. Based on the most likely play type and field analogy the potential is estimated to be 16 tcfe potential oil and gas reserves – and the Pantera concessions have 16% of this – 2.6 tcfe or 433 mmbo.
• Upside potential exists for even higher reserve potential – If the “hydrocarbon richness” is the same as the overall Chaco Basin results, the Paraguayan potential would be 43 tcfe, 6.7 tcfe (1118 mmboe) Pantera share.
• Pantera thus has a large acreage position in a known, but under-explored hydrocarbon basin with the potential for significant new discoveries
100 KM
BRAZIL
BOLIVIA
PARAGUAYARGENTINA
And
ean
Mou
ntai
ns
Gas Field
Oil & Gas Field
CARANDAYTY SUB-BASIN
CHACO BASIN
PIRITY BASIN
CHACO BASIN AND EXTENSIONS INTO PARAGUAY
CENTRAL ARCH
Devonian Outcrop
CURUPAYTY SUB-BASIN
IZOZOG HIGH
APPROX LOCATION PANTERA CONCESSION
HIGHLIGHTS OF REPORT
•BOLIVIAN/ARGENTINE CHACO BASIN EXTENDS TO PARAGUAY
•PARAGUAY UNDEREXPLORED – ONLY 27 WELLS IN CHACO BASIN EXTENSION
•433 MMBO (2.6 TCFE GAS) POTENTIAL PANTERA SHARE RESERVES ; UPSIDE
EVEN HIGHER – 1118 MMBO (6.7 TCFE)
•6 WELL EXPLORATION PROGRAM PROJECTED
•40% CHANCE OF FINDING 8 MMBOE OR MORE
•ATTRACTIVE ECONOMICS
•GAS IMPORT INTO BRAZIL & ARGENTINA EXPANDING
•PRODUCTION COULD START AS EARLY AS 2014
SUMMARY OF REPORT RESULTS•CHACO BASIN CLEARLY EXTENDS TO NORTHERN PARAGUAY
•SHOULD BE ANALAGOUS TO NON-THRUST FAULT FIELDS IN BOLIVIA / ARGENTINA•ONE FIELD ALREADY DISCOVERED (NOT DEVELOPED YET)
•PANTERA CONCESSIONS MORE OIL PRONE, BUT GOOD GAS EXPORT MARKET AVAILABLE IF GAS DISCOVERED
•433 MMBO (OR 2.6 TCFE GAS) POTENTIAL PREDICTED FOR PANTERA CONCESSIONS•UPSIDE POTENTIAL FOR 1118 MMBOE (6.7 TCFE GAS)•FISCAL TERMS REASONABLE
•10 - 15% ROYALTY; 15% DEPLETION ALLOWANCE; 30% INCOME TAX RATE•PROJECTED EXPLORATION PROGRAM
•SEISMIC; 6 EXPLORATION WELLS; 2 APPRAISAL WELLS•6 YEARS ; TOTAL COST $69 MM
•PROJECTED MEAN FIELD SIZE•IF OIL -- 47 MMBO ; 40% SUCCESS CHANCE WITH 6 EXPLORATION WELLS•IF GAS -- 600 BCFE ; 30% SUCCESS CHANCE WITH 6 EXPLORATION WELLS
•DEVELOPMENT PROJECTION•IF OIL -- 22,000 BOPD PEAK RATE ; 13 YEAR LIFE ; $274 MM INVESTMENT•IF GAS -- 150 MMCFD PEAK RATE ; 16 YEAR LIFE ; $357 MM INVESTMENT
•ECONOMIC SUMMARY -- SUCCESS CASE•IF OIL -- 44% ROR ; $1357 MM NET CASH ; $418 MM PV@10%•IF GAS -- 30% ROR ; $1629 MM NET CASH ; $385 MM PV@10%
CHACO BASIN EXPLORATION HISTORY IN BOLVIA & ARGENTINA
• First Exploration success in 1924• 846 exploration wells drilled• 475 new field wildcats drilled• 128 fields discovered• 429 mmbo of oil discovered• 1440 mmbc & 73 tcf of condensate and gas discovered• 27% success rate – all time overall rate• 51% success rate in 1997 – 2006 due to improved seismic techniques• Gas export market to Brazil and Argentina beginning late 1990’s has
increased reserves and new discoveries• Mature successful hydrocarbon basin with 14 bboe (billion barrels of
oil equivalent) reserves proved up.
Recent Activities in Chaco Basin
•Gas Market for export from Bolivia and toBrazil and Argentina available
•Gas Pipeline to Brazil built in 1998-1999•Currently exporting about 1.2 BCFD•Gas Price as high as $5.00 per mmbtu•Gas Reserves increased from 32 tcf in 1996
to 72 tcf in 2007•Oil reserves increased from 1 BBO in 1996
to about 2 BBO in 2007•Activity level has slowed dramatically in 2006
due to new Bolivian Government fiscal terms•Bolivia will be unlikely to meet demand in Brazil and Argentina
CHACO BASIN OIL & GAS PRODUCTION RATESOil Production
0
10
20
30
40
50
60
70
80
90
1929 1939 1949 1959 1969 1979 1989 1999Year
Oil
Prod
uctio
n (1
000
BPD
)
Gas Production
0
500
1000
1500
2000
2500
1929 1939 1949 1959 1969 1979 1989 1999Year
Gas
Pro
duct
ion
( MM
CFD
)
100 KM
BRAZIL
BOLIVIA
PARAGUAYARGENTINA
And
ean
Mou
ntai
ns
IZOZOG HIGH
Gas Field
Oil & Gas Field
CURUPAYTY SUB-BASIN
CARANDAYTY SUB-BASIN
CHACO BASIN
PIRITY BASIN
MAJOR GAS FIELDS AND PIPELINE SYSTEM
MARGARITA
SAN ALBERTO
SABALO
INCAHUSASI
RIO GRANDE
VUELTA GRANDE
NARANJILLOSCARANDA
YAPACANI
COLPA
ITAU
CAMPO DURAN
RAMOS
TRANQUITAS
SAN PERDITO
Gas Pipeline
CENTRAL ARCH
Devonian Outcrop
Chaco Basin in Paraguay
•Chaco Basin extends from Bolivia into northern Paraguay•Izozog High and Central Arch bisect basin extension into two sub-basins
•Carandayty Sub-basin to west•Curupayty Sub-basin to north
•Carandayty Sub-basin exploration•21 exploration wells drilled between 1949 and 1977•One gas field discovered and tested gas in Devonian and Carboniferous•Lack of gas sales market stopped additional exploration/development•CDS started new exploration program in 2005
•Curupayty Sub-basin exploration•6 exploration wells drilled in Paraguay between 1958 and 1995•4 wells in Bolivia in sub-basin•Many hydrocarbon shows, but no oil or gas tests•Oil exploration only, since no gas sales available
CHACO BASIN PETROLEUM SYSTEM ELEMENTS
Source• Devonian and Silurian shales, equivalent to Sub-Andean source• Thickness of source rock section up to 4000m• Geochemical data shows a rich source - TOC’s up to 2 %• Devonian currently in oil window, Silurian in gas window
Reservoir• Primary, Carboniferous Tarija and Tupambi formations, equivalent to sub-
Andean primary reservoirs• Stratigraphic variability in amalgamated channels and fan lobes, but good
porosity (>20%)• Secondary targets in Devonian Huamampampa sheet sands with lateral
continuity and moderate porosity (10-15%); interbedded with source• Further reservoir opportunities as ‘add-ons’ to above targets - Lower
Devonian, Silurian, Upper Carboniferous
CHACO BASIN STRATIGRAPHIC COLUMN
VIBORA FIELDSARA410-438SILURIAN
SANTA ROSA
CAIGUA FIELD LOS MONOS FIELD
TESTED GAS IN MENDOZA #1-RHUAMAMPAMPA
CAMIRI FIELD TORO FIELD CAMBEITI FIELDIQUIRI
355-410DEVONIAN
RIO GRANDE FIELD SANTA CRUZ FIELD TITA FIELD MADREJONES FIELD
TESTED GAS IN MENDOZA #1-RTUPAMBI
LA PENA FIELD CARANADA FIELD
OIL SHOWS IN GOTO #1 LOW
PERMEABILITYTARIJA
RIO GRANDE FIELD LA PENA FIELD ESCARPMENT
290-355CARBONIFEROUS
VILLAMONTES FIELD
ONLY FAR NORTHERN EDGE OF CONCESSION
PROSPECTIVESAN TELMO251-290PERMIAN
NOT PRESENTNOT
PROSPECTIVE205-251TRIASSIC
NOT PRESENTNOT
PROSPECTIVE145-206JURASSIC
NOT PRESENTNOT
PROSPECTIVE65-145CRETACEOUS
TOO SHALLOWNOT
PROSPECTIVE0-65QUATERNARY - TERTIARY
BOLIVIA/ARGENTINE ANALOG
FIELDS
PARAGUAY COMMENTS
PROSPECTIVE RESERVOIR
NAMEAGE Ma
GEOLOGIC STRATA NAME
Seal• Alternating regional and local shales within the Carboniferous• Devonian Los Monos shale
Trap/Structure• Structural: Carboniferous drape over Devonian low-relief fault blocks,
structural highs reactivated during Mesozoic uplift and extension, or Tertiary inversion of older extensional fabrics.
• Stratigraphic: channels and erosional channel/canyon fill, and truncation/onlap relationships near intrabasin highs and unconformities
Generation/Migration• Devonian in oil window and Silurian in gas window, in basin centers
CHACO BASIN PETROLEUM SYSTEM ELEMENTS
Play and Play Risk Analysis
Play Extension into Paraguay• Oil and gas shows in both the Curupayty and Carandayty sub-basins demonstrate
the existence if an active petroleum system; Play already demonstrated in Carandayty with well test
• Play types similar to sub-Andean play in Bolivia• Source, reservoir, and seal are the same; trap style and generation/migration
history differ
Differences & Risks• Subtle low-relief traps with smaller vertical closure may limit reserve size and
number of possible reservoir zones under trap• Source rocks in basin axes are relatively immature compared to the foldbelt and
may not have generated and expelled equivalent volumes of hydrocarbons, while basin margins have high heat flow and risk overmature source
• Migration pathways are also more limited without the influence of Andean thrusting and depend on the network of basement faults or angular truncation of the Devonian source rock section under the Carboniferous
• Many dry holes in eastern Bolivia and the Curupayty and Carandayty sub-basins; could be explained by drilling depth and lack of gas sales potential in 1970’s
100 KM
ALTO del BOQUERON
ALTO del CHACO CENTRAL
Asu
ncio
n A
rch
Brazilian Shield
BRAZIL
BOLIVIA
PARAGUAYARGENTINA
Boomerang Hills Area
And
ean
Mou
ntai
ns
IZOZOG HIGH
CAIMANCITO
CARANDA
CAMIRI
LA PENA
MONTEAGUDO
PALOMA
YAPACANI
SAN PEDRO
COLPA
PATUJUSAL
TATARENDA
TCV-1ROBERE-1
OTQ-1UTZ-1
PANTERA-1
GOTO-1
TORO-1MADREJON-1
CERRO LEON-1
Devonian Outcrop
Exploration Well
Gas Field
Oil & Gas Field
CURUPAYTUY SUB-BASIN
CARANDAYTY SUB-BASIN
CHACO BASIN
PIRITY BASIN
OIL FIELDS HIGHLIGHTED
LAGERENZA-1
RAVELO-1
MENDOZA 1-R
38.7%3051.425.0336.8TOTAL
91.5%4.88.6TATARENDA
85.9%9.69.7PATUJUSAL
6.7%776.711.010.1COLPA
100.0%16.9SAN PEDRO
14.4%745.47.122.0YAPACANI
44.0%188.524.7PALOMA
73.1%75.80.936.8MONTEAGUDO
72.9%81.10.838.4LA PENA
68.5%139.350.4CAMIRI
25.2%925.45.353.8CARANDA
78.9%104.765.4CAIMANCITO
BCFGMMCMMBO
%OILGASCONDOILFIELD
•80% of all oil reserves•Average 39% Oil / 61% Gas•6 Fields without Non-associated Gas
Top 11 Oil Fields in Chaco Basin: Bolivia & Argentina
100 KM
ALTO del BOQUERON
ALTO del CHACO CENTRAL
Asu
ncio
n A
rch
Brazilian Shield
BRAZIL
BOLIVIA
PARAGUAYARGENTINA
Boomerang Hills Area
And
ean
Mou
ntai
ns
IZOZOG HIGH
TCV-1ROBERE-1
OTQ-1UTZ-1
PANTERA-1
GOTO-1
TORO-1MADREJON-1
CERRO LEON-1
Devonian Outcrop
Exploration Well
Gas Field
Oil & Gas Field
CURUPAYTU SUB-BASIN
CARANDAYTY SUB-BASIN
CHACO BASIN
PIRITY BASIN
GAS FIELDS HIGHLIGHTED
LAGERENZA-1
MARGARITA
SAN ALBERTO
SABALO
INCAHUSASI
RIO GRANDE
VUELTA GRANDE
NARANJILLOSCARANDA
YAPACANI
COLPA
ITAU
CAMPO DURAN
RAMOS
TRANQUITAS
SAN PERDITO
RAVELO-1
MENDOZA 1-R
89.0%60910.61151.3102.9TOTAL
81.0%745.47.122.0YAPACANI
86.0%776.711.010.1COLPA
72.3%925.45.353.8CARANDA
72.9%985.060.90.1CAMPO DURAN
83.3%1164.030.68.2TRANQITAS
91.4%1185.018.70.0VUELTA GRANDE
90.1%1279.023.50.0SAN PERDITO
90.3%2686.040.28.0RAMOS
84.9%2874.085.10.0RIO GRANDE
89.5%7000.0137.00.0INCAHUASI
92.0%7943.0114.70.0ITAU
86.8%10513.0266.80.0MARGARITA
90.8%10854.0184.00.0SABALO
92.3%11980.0166.40.8SAN ALBERTO
BCFGMMCMMBO
%GASGASCONDOILFIELD
•90% of all gas reserves•Average 1% Oil / 99% Gas•7 Fields without Oil
Top 14 Gas Fields in Chaco Basin
•82.7 TCFE RESERVES DISCOVERED,VERY GAS PRONE -- 3% OIL / 97% GAS •LARGEST FIELD – 13 TCFE, AVERAGE FIELD SIZE 661 BCFE, MEDIAN FIELD SIZE 41 BCFE•1.16 FIELDS PER 1000 SQ KM, 0.75 BCFE PER SQ KM•LOG NORMAL DISTRIBUTION•0.58 FIELDS PER 1000 SQ KM•50% of FIELDS ABOVE 40 BCFE ECONOMIC LIMIT
•AVERAGE FIELD SIZE 1279 BCFE ; MEDIAN FIELD SIZE 308 BCFE
Chaco Basin Exploration Results
Reserve Distribution
0.01
0.1
1
10
100
1000
10000
100000
1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 103 109 115 121 127
Fields
Tota
l Res
erve
s - B
CFE
100 KM
ALTO del BOQUERON
Asu
ncio
n A
rch
Brazilian Shield
BRAZILBOLIVIA
PARAGUAYARGENTINA
Boomerang Hills Area
And
ean
Mou
ntai
ns
IZOZOG HIGH
TCV-1ROBERE-1
OTQ-1UTZ-1
PANTERA-1
GOTO-1
TORO-1MADREJON-1
CERRO LEON-1
Devonian Outcrop
Exploration Well
Gas Field
Oil & Gas Field
CURUPAYTY SUB-BASIN
PIRITY BASIN
EXPLORED AREA475 NEW FIELD WC’S110,000 SQ KM83 TCFE RESERVES0.75 BCFE/SQ KM4.3 WELLS/1000 SQ KM
CURUPAYTY SUB-BASIN(PARAGUAY PORTION)32,000 SQ KM6 NEW FIELD WC’S0.19 WELLS/1000SQ KM
EXPLORATION ANALYSIS
LAGERENZA-1
RAVELO-1
CARANDAYTY SUB-BASIN(PARAGUAY PORTION)25,000 SQ KM TOTAL21 NEW FIELD WC’S0.84 WELLS/1000 SQ KM
TWO PLAY TYPES IN BOLIVIA / ARGENTINE CHACO BASIN•THRUST FAULT FIELDS
•SUB-ANDEAN, RECENT FAULTING•MULTIPLE THRUST (REVERSE) FAULTS•THICK PAY ZONES•MULTIPLE PAY ZONES
•NON-THRUST FAULT FIELDS•FORELAND (EAST OF ANDEAN MOUNTAINS)•STRUCTURES OVER OLDER FAULTS•STRATIGRAPHIC TRAP COMPONENT OFTEN IMPORTANT•THINER PAY ZONES
PLAY TYPE ANALYSIS
NO THRUST FAULTS IN PARAGUAY•THEREFORE ONLY NON-THRUST FIELDS ANTICIPATED
137111.94.50TITA
180169.42.00EL DORADO
20020000CERRO TUYUNTI
222204.33.120NUPUCO
278262.82.740AGUARAGUE
30281.30.738.4LA PENA
341239.3180KANATA
647581.111.70VIBORA
65456515.70LA PORCELANA
727613.61010.07COLPA
1015798.95.332.9CARANDA
12331131.818.00VUELTA GRANDE
13671164.830.65.3TRANQUITAS
3224275882.60RIO GRANDE
BCFGMMCMMBO
BCFEGASCONDOILFIELD
Top 14 Non-Thrust Fault Fields in Chaco Basin•45 FIELDS TOTAL (OUT OF 128 TOTAL FIELDS)•TOP 14 FIELDS CONTAIN > 90% OF RESERVES•SIMILAR GEOLOGICALLY TO PARAGUAY•BOTH OIL AND GAS FIELDS
100 KM
ALTO del BOQUERON
ALTO del CHACO CENTRAL
Brazilian Shield
BRAZILBOLIVIA
PARAGUAY
ARGENTINA
Boomerang Hills Area
And
ean
Mou
ntai
ns
IZOZOG HIGH
TCV-1ROBERE-1
OTQ-1UTZ-1
PANTERA-1
GOTO-1
TORO-1MADREJON-1
CERRO LEON-1
Devonian Outcrop
Exploration Well
Gas Field
Oil & Gas Field
CURUPAYTU SUB-BASIN
PIRITY BASIN
NON-THRUST FAULT FIELDS45 FIELDS40,000 SQ KM1.12 FIELDS PER SQ KM11.4 TCFE RESERVES0.28 BCFE/SQ KM
CURUPAYTY SUB-BASIN(PARAGUAY PORTION)32,000 SQ KM36 FIELDS PROJECTED9.1 TCFE RESERVES PROJECTED
NON-THRUST FAULT EXPLORATION ANALYSIS
LAGERENZA-1
RAVELO-1
CARANDAYTY SUB-BASIN(PARAGUAY PORTION)25,000 SQ KM TOTAL1 FIELD DISCOVERED – RESERVES UNKNOWN28 FIELDS PROJECTED7 TCFE RESERVES PROJECTED
VIBORA
KANATA
RIO GRANDE
TITA
LA PENA
EL DORADO
COLPA
CARANDA
VUELTE GRANDE
NUPUCO
CERRO TUYUNTI
TRANQUITAS
AGUARAGUE
LA PORCELANA
•45 FIELDS, LOG NORMAL DISTRIBUTION, 0.5 BCFE TO 3.2 TCFE, 11.4 TFCE TOTAL•SMALLER THAN THRUST RELATED FIELDS•40,000 SQ KM AREA ; 1.12 FIELDS PER 1000 SQ KM ; 0.285 BCF PER SQ KM•21 FIELDS > 8 MMBOE (50 BCFE) (ECONOMIC LIMIT IF OIL) ;47% OF TOTAL FIELDS•MEAN FIELD SIZE – 47 MMBOE•15 FIELDS > 170 BCFE (ECONOMIC LIMIT IF GAS) ; 33% OF TOTAL FIELDS•MEAN FIELD SIZE – 600 BCFE
NON-THRUST FAULT RELATED FIELDS
FIELD SIZE DIST - NO LIMIT
0.1
1.0
10.0
100.0
1000.0
10000.0
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45
FIELD RANK
RES
ERVE
S - B
CFE
Summary of Chaco Basin Fields in Bolivia & Argentina
• Mature basin with well established reserves averaging 0.75 bcfe per sq km and 1.16 fields per 1000 sq kms
• Good quality reservoirs -- often enhanced by fractures• Thick Devonian source rock – in gas window• 83 thrust fault related traps – 1.19 fields per 1000 sq km and 1.02 bcfe
per sq km• 45 structural/stratigraphic related traps (non-thrust) - 1.12 fields 1000
sq km and 0.28 bcfe per sq km• Fields typically 5 – 100 sq km• Multiple pays – up to 7 stratigraphic levels per field• 128 fields in total - 47 fields contain both gas and oil• Very gas prone – 97% gas to 3% oil
CONCESSION POTENTIAL ANALYSIS
CHACO BASIN - PARAGUAYCARANDAYTY & CURUPAYTY SUB-BASINS
PANTERA OIL & GAS CONCESSIONS
CURUPAYTY AND CARANDAYTY SUB-BASIN
•VERY LIGHTLY DRILLED – 0.19 COMPARED TO 0.84 WC’S PER 1000 SQ KM
•HYDROCARBON RICHNESS OF SOURCE SIMILAR
•THRUST FAULTS NOT ANTICIPATED
•RESERVOIR QUALITY GOOD IN CARBONBIFEROUS,
BUT PROBABLY NOT ENHANCED WITH NATURAL FRACTURES
•FEWER STRATIGRAPHIC LEVELS PROSPECTIVE
•LESS FAULTING – MORE DIFFICULT MIGRATION PATHWAYS
•GOOD GAS SHOWS – BUT ONLY ONE WELL TESTED HYDROCARBONS
•MORE OIL PRONE IN CURUPAYTY – SOURCE ROCK IN OIL WINDOW
COMPARISON TO BOLIVIAN – ARGENTINE CHACO BASIN
•LOG-NORMAL DISTRIBUTION EXPECTED•45 BOLIVIA / ARGENTINA CHACO BASIN NON-THRUST
FAULT FIELDS IN 40,000 SQ KM EVALUATED•ACTUAL N0N-THRUST FIELDS YIELDED 0.28 BCFE PER SQ KM•CURUPAYTY SUB-BASIN (PARAGUAY PORTION)
PROSPECTIVE AREA 32,000 SQ KM•CURUPAYTY RESERVE POTENTIAL EXPECTED TO BE 9.1 TCFE•CARANDAYTY SUB-BASIN (PARAGUAY PORTION)
PROSPECTIVE AREA 25,000 SQ KM•CARANDAYTY RESERVE POTENTIAL EXPECTED TO BE 7.0 TCFE•SIMILAR TO USGS ESTIMATE FOR NON-THRUST RELATED FIELDS•UPDISE POTENTIAL FOR HIGHER “HYDROCARBON RICHNESS” ; IF SAME AS
OVERALL BOLIVIA / ARGENTINA CHACO ACTUALS, THEN RESERVE POTENTIAL INCREASED FROM 16.1 TCFE TO 42.8 TCFE
Field Size Distribution – Extrapolated into Paraguay
TITA
RIO GRANDE
TECHI
ABEJA
TCV-1
UTZ-1
ROBERE-1
OTQ-1
IZOZOG HIGH
NARANJILLOSPALMAR
LA PENA
RIO SECO
ARGENTINA
PARAGUAY
BOLIVIA
ALTO del CHACO CENTRAL
ALTO del BOQUERON
PIRITY BASIN
CARANDAYTYSUB-BASIN
PANTERA-1
CURUPAYTYSUB-BASIN
Prospective Limits of Basin
Devonian Outcrop
BRAZIL
Gas FieldOil & Gas Field
GOTO-1
TORO-1
MADREJON-1
CERRO LEON-1
LAGERENZA-1
EL DORADO
TACOBOEL ESPINO
TATARENDA
LAGUNILLAS
TAJIBOS
CAMBEITI
CAMIRI
PORVENIR
VUELTA GRANDE
NUPUCO
MARGARITA
SABOLO
SAN ALBERTOMADREJONES
VILLAMONTES
GUAIRUY
Exploration Well
MONTEAGUDO
AGUARGUE
IBIBOBOLA VERTIENTE
SUPUATICAIGUA
SANROQUE
ESCONDIDOLOS SURIS
PALO MARCADO
RAVELO-1
Pantera Concession
PANTERA
TORO
BAHIANEGRA
CERROCABRERA
TAGUA
MENDOZA 1-R
CURUPAYTY SUB-BASIN PROJECTIONS
•USE NON-THRUST ANALOGY
•OIL MORE LIKELY HYDROCARBON, BUT GAS POSSIBLE
•36 FIELDS ANTICIPATED
•PREDICT 9.1 TCFE (1517 MMBOE)TOTAL RESERVE POTENTIAL
•PANTERA PORTION ABOUT 27% OF TOTAL – 2.5 TCFE ( 416 MMBOE)
•UPSIDE POTENTIAL 24 TCFE (4000 MMBOE) – PANTERA PORTION 6.5 TCFE (1080 MMBOE)
•OIL CASE•17 FIELDS > 50 BCFE (8 MMBO)•FIELD SIZE RANGE OF 50 BCFE (8 MMBO)TO ± 2 TCFE (333 MMBO)•MINIMUM DEVELOPABLE FIELD SIZE APPROX 3 SQ KM•MEAN – 280 BCFE (47 MMBOE)
•GAS CASE•12 FIELDS > 170 BCFE (ECONOMIC LIMIT FOR GAS)•MINIMUM DEVELOPABLE FIELD SIZE APPROXIMATELY 10 SQ KM•FIELD SIZE RANGE 170 BCF TO ± 2 TCFE•MEAN – 600 BCFE
•SEISMIC ANALYSIS NEEDED TO DEFINE STRUCTURES•ADVANCED DRILLING / COMPLETION NEEDED WHEN
RESERVOIR QUALITY POOR
CARANDAYTY SUB-BASIN PROJECTIONS
•USE NON-THRUST ANALOGY
•GAS IS LIKELY HYDROCARBON
•28 FIELDS ANTICIPATED, 1 ALREADY DISCOVERED
•PREDICT 7.0 TCFE (1167 MMBOE)TOTAL RESERVES
•PANTERA PORTION ABOUT 1.2% OF TOTAL – 0.1 TCFE
•UPSIDE POTENTIAL 18.8 TCFE (3125 MMBOE) – PANTERA PORTION 0.2 TCFE (38 MMBOE)
•Gas Case
•9 FIELDS > 170 BCFE
•FIELD SIZE RANGE OF 170 BCFE TO ± 2 TCFE
•MEAN – 600 BCFE
•SEISMIC ANALYSIS NEEDED TO DEFINE STRUCTURES
•ADVANCED DRILLING / COMPLETION NEEDED WHEN
RESERVOIR QUALITY POOR
•SMALL CONCESSION INDICATES PARTNERSHIP DRILLING
EXPLORATION AND DEVELOPMENT PROGRAM STRATEGIES
•DRILL WITH EXISTING SEISMIC WHEN POSSIBLE•ADDITIONAL SEISMIC WHEN NECESSARY•SEISMIC GRID SHOULD BE SMALL ENOUGH TO BE ABLE TO IDENTIFY
MINIMUM DEVELOPABLE FIELD SIZES (3-10 SQ KM)•3-D SEISMIC UNLIKELY TO BE NEEDED FOR EXPLORATION•DRILL BEST PROSPECTS IN PRIORITY ORDER•PARTNER WITH OTHER OPERATORS WHEN POSSIBLE•SPACE DRILLING OUT TO TAKE ADVANTAGE OF
LESSONS LEARNED FROM EARLY DRILLING•AFTER 2-3 WELLS REEVALUATE IF ALL PLANNED WELLS SHOULD
BE DRILLED OR CONCESSIONS RETURNED TO GOVERNMENT•DRILL APPRAISAL WELLS TO CONFIRM RESERVES
BEFORE DEVELOPMENT COMMITMENT
PANTERA OIL & GAS EXPLORATION PRIORITIES
•PANTERA LICENSE BEST•CARBONIFEROUS DOWNDIP TO PHILLIPS PANTERA WELL•MULTIPLE STRATIGRAPHIC PROSPECTS LIKELY•MOST LKELY OIL PROSPECTS•DEVONIAN AND SILURIAN ALSO SHOULD BE EVALUATED
•TAGUA LICENSE•CARBONIFEROUS AND DEVONIAN PARGETS•MONITOR OFFSET DRILLING•MAY NEED ADVANCE DRILLING/COMPLETION TECHNIQUES•HIGHEST CHANCE OF GAS
•TORA AND BAHIA NEGRA LICENSE•CARBONIFEROUS OFFSETTING TORO AND GOTO WELLS•POSSIBLE UPPER DEVONIAN PROSPECT•POSSIBLE CARBONIFEROUS / DEVONIAN PROSPECT DOWNDIP TO
MADEREJON WELL•CERRO CABRERA
•POSSIBLE HIGH RISK PROSPECTS ON NORTHERN EDGE OF LICENSE
PROJECTED EXPLORATION PROGRAM
•COLLECT AND REPROCESS EXISTING DATA IMMEDIATELY•MODEL ROCK AND WELL DATA TO DETERMINE SEISMIC REQUIREMENTS•1300 KM FOR NEW AREAS AND INFILL BETWEEN EXISTING LINES•SPECIALITY PROCESSING AS INDICATED BY MODELLING•DRILL 5 EXPLORATION WELLS AND 2 APPRAISAL WELLS IN CURUPAYTY SUB-BASIN•DRILL 1 EXPLORATION WELL IN CARANDAYTY SUB-BASIN
PROJECTED EXPLORATION SCHEDULE & COST
9.01.50.57.0201227.01.50.57.018.0201114.01.50.512.020109.81.52.36.020097.51.56.020081.51.00.52007
Total(MM$)
Overhead(MM$)
Seismic(MM$)
Appraisal Wells(MM$)
Expl Wells(MM$)
EXPLORATION COST ASSUMPTIONS
•WELLS - $50 MM TOTAL COST•2500 METER AVERAGE•EXPLORATION - $6 MM PER WELL •APPRAISAL - $7MM PER WELL ; MORE TESTING
•SEISMIC – $10.3 MM TOTAL COST•1300 KM AT $6000 PER KM FOR ACQUISITION AND
INITIAL PROCESSING•$2.5 MM FOR SPECIALITY PROCESSING OVER 6 YEARS
•OVERHEAD – $8.5 MM TOTAL COST•OFFICE RENTAL, SUPPLIES, COMMUNICATIONS•ADMINISTRATIVE COSTS (ACCOUNTING, FINANCE, HR, ETC)•TECHNICAL WORK (GEOLOGY, GEOPHYSICS, ENGINEERING)•DRILLING MANAGEMENT•GOVERNMENT RELATIONS•GENERAL MANAGEMENT, TRAVEL, ETC
EXPLORATION – DEVELOPMENT CYCLE
•2007 : REPROCESS EXISTING SEISMIC, MODELLING•2008 : ACQUIRE 1000 KM 2D SEISMIC. INTERPRET, MAP PROSPECTS•2009 : ACQUIRE ADDITIONAL 300 KM 2D SEISMIC WHERE NEEDED
DRILL FIRST EXPLORATION WELL•2010 : DRILL 2 EXPLORATION WELLS•2011 : DRILL 3 EXPLORATION WELLS
DRILL 1 APPRAISAL WELLDESIGN FIELD DEVELOPMENT – ISSUE CONSTRUCTION CONTRACT
•2012 : DRILL 1 APPRAISAL WELLBEGIN CONSTRUCTION OF OIL, GAS FACILITIES, PIPELINESDRILL FIRST 1/3 OF DEVELOPMENT WELLS
•2013 : COMPLETE CONSTRUCTION OF OIL, GAS FACILITIES, PIPELINESDRILL SECOND 1/3 OF DEVELOPMENT WELLS
•2014 : START PRODUCTIONDRILL FINAL 1/3 OF DEVELOPMENT WELLS
DEVELOPMENT OF OIL FIELD EXPLORATION SUCCESS
•DISCOVER 47 MMBO IN CARBONIFEROUS (MEAN FIELD SIZE)•75’ PAY, ±20 SQ KM PRODUCTIVE AREA•DEVELOP WITH 44 WELLS, 500 BOPD PER WELL•REINJECT GAS (GAS RESERVES TOO SMALL TO SELL)•CONSTRUCTION/DRILLING STARTS 2012•PRODUCTION STARTS 2014
66.01.075.02014
101.51.53.05.07.017.070.02013
100.51.53.05.08.018.075.02012
6.51.55.02011
TOTAL
(MM$)
OVERHEAD
(MM$)
ENGR DESIGN(MM$)
OIL STORAGE(MM$)
GAS FACILITIES(MM$)
OIL FACILITIES(MM$)
WELLS
(MM$)
PROJECTED DEVELOPMENT COST & SCHEDULE
OIL DEVELOPMENT COST ASSUMPTIONS
•WELLS - $220 MM TOTAL COST•2500 METER AVERAGE, 44 WELLS, 500 BOPD PER WELL•$5 MM PER WELL – INCREASED EFFICIENCY
•OIL, GAS FACILITIES, FLOWLINES, STORAGE– $60 MM TOTAL COST•22,000 BOPD SEPARATION, PROCESSING•GAS PROCESSING AND COMPRESSION FOR INJECTION•500,000 BO STORAGE AND PUMPING STATION•$7/BO FOR TRANSPORTATION TO MARKET
•OVERHEAD – $5.5 MM TOTAL COST ; SAME AS EXPLORATION
•ENGINEERING DESIGN - $11 MM TOTAL COST•PREPARE DESIGN, SPECIFICATIONS, CONTRACTS•INCLUDES PROJECT MANAGEMENT•DRILLING ENGINEERING, SUPPORT
PRODUCTION AND EXPENSE PROFILES
•PRODUCTION STARTS 2014 AT 22,000 BOPD•GAS-OIL RATIO RISES OVER TIME•REINJECT GAS TO REDUCE RESERVOIR PRESSURE DECLINE RATE•NO SIGNIFICANT WATER PRODUCTION ANTICIPATED•NO WATER INJECTION PLANNED•OPERATING EXPENSES 16-18 MM$ PER YEAR•PRODUCTION DECLINES BEGINNING 2016 AT ABOUT 20% PER YEAR DUE TO
INCREASING GAS OIL RATIO•13 YEAR PRODUCING LIFE•30 MM$ ABANDONMENT COST IN 2027
OIL RATE
0.0
5.0
10.0
15.0
20.0
25.0
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
YEAR
OIL
RA
TE -
TBD
INTERNAL RATE OF RETURN = DISCOUNT RATE WHICH YIELDS 0% PVIRR
NET PROFIT CASH FLOW DISCOUNTED @10% DISCOUNT RATEPV@10%
NET REVENUE – COST - TAXESNET PROFIT
INCOME TAXESTAXES
OPEX (EXPL & DEV) + CAPEX (EXPL & DEV)COST
OIL (OR GAS) X PRICE – TRANSPORTATION COST - ROYALTYNET REVENUE
EXPLANATION OF CASH FLOW ECONOMIC CALCULATION
ECONOMIC ANALYSIS ASSUMPTIONS AND RESULTS
•MEAN SIZE OIL FIELD DISCOVERY CASE•FULL EXPLORATION COST BURDENED BY SINGLE FIELD•$58 OIL PRICE ($65 WTI MINUS $7 TRANSPORTATION COST)•NO PRICE OR COST ESCALATION•ROYALTY PER PARAGUAY TERMS (10/12/14%)•15% DEPLETION ALLOWANCE•30% INCOME TAX RATE•EARLY YEAR LOSS TAX CREDITS TAKEN WHEN PRODUCTION BEGINS
44.5%IRR (%)$417.6PV@10% (MM$)$1357.5NET PROFIT (MM$)$439.0TAXES (MM$)$624.9COSTS (MM$)$2421.3NET REVENUE (MM$)
SUCCESS CASE ECONOMICS
OIL SUCCESS CASE ANALYSIS – PER BARREL OF OIL PRODUCED
COMMENTS
OIL SALES LESS TOTAL DEDUCTS$28.98 / BONET PROFIT
TOTAL OF ABOVE 6 ITEMS$36.02 / BOTOTAL DEDUCTS
INCOME TAX PAYABLE TO GOVERNMENT$9.34 / BOTAXES
COST TO ABANDONMENT WELLS AND FACILITIES AFTER DEPLETION
$0.64 / BOABANDONMENT
ONGOING OPERATING COST$4.93 / BOOPEX
TOTAL EXPLORATION AND DEVELOPMENT CAPITAL COST
$7.61 / BOEXPL & DEV
PAYMENT TO GOVERNMENT$6.50 / BOROYALTY
ALLOWANCE FOR 3RD PARTY COST TO TRANSPORT OIL TO MARKET
$7.00 / BOTRANSPORTATION
OIL SALES PRICE DELIVERED TO MARKET$65.00 / BOOIL SALES
DEVELOPMENT OF GAS FIELD EXPLORATION SUCCESS
•DISCOVER 600 BCF IN CARBONIFEROUS (MEAN FIELD SIZE)•75’ PAY, ±40 SQ KM PRODUCTIVE AREA•DEVELOP WITH 30 WELLS, 5 MMCFD PER WELL•PEAK GAS SALES 150 MMCFD•LAY 300 KM, 20” GAS SALES LINE TO EXISTING LINE IN BRAZIL, $20 MM FOR
COMPRESSION, $40,000 PER INCH-MILE PL COST•CONSTRUCTION/DRILLING STARTS 2012•PRODUCTION STARTS 2014
51.01.050.02014
149.01.52.090.017.08.550.02013
151.01.52.090.018.09.550.02012
6.51.55.02011
TOTAL
(MM$)
OVERHEAD
(MM$)
ENGR DESIGN(MM$)
GASPIPELINE(MM$)
GAS FACILITIES(MM$)
OIL FACILITIES(MM$)
WELLS
(MM$)
DEVELOPMENT EXPENDITURE SCHEDULE & COST
GAS DEVELOPMENT COST ASSUMPTIONS
•WELLS - $150 MM TOTAL COST•2500 METER AVERAGE, 30 WELLS, 5 MMCFD PER WELL•$5 MM PER WELL – INCREASED EFFICIENCY
•GAS, OIL FACILITIES, FLOWLINES, STORAGE– $53 MM TOTAL COST•150 MMCFD SEPARATION, PROCESSING, COMPRESSION•3,000 BPD CONDENSATE PROCESSING•100,000 BO STORAGE AND PUMPING STATION•$7/BO FOR TRANSPORTATION TO MARKET
•OVERHEAD – $5.5 MM TOTAL COST ; SAME AS EXPLORATION
•ENGINEERING DESIGN - $9 MM TOTAL COST•PREPARE DESIGN, SPECIFICATIONS, CONTRACTS•INCLUDES PROJECT MANAGEMENT•DRILLING ENGINEERING, SUPPORT
•PIPELINE - $180 MM TOTAL COST•300 KM, 20” AT $40,000 PER INCH-MILE•2 COMPRESSOR STATIONS AT $10 MM PER STATION
PRODUCTION AND EXPENSE PROFILES
•GAS SALES START 2014 AT 150 MMCFD•PRESSURE DEPLETION DRIVE MECHANISM – COMPRESSION REQUIRED•NO SIGNIFICANT WATER PRODUCTION ANTICIPATED•CONDENSATE (OIL) PRODUCTION PROCESSED AT GAS PROCESSING PLANT•OPERATING EXPENSES 16 MM$ PER YEAR•PRODUCTION DECLINES BEGINNING 2020 AT ABOUT 20% PER YEAR DUE TO
PRESSURE DEPLETION•16 YEAR PRODUCING LIFE•30 MM$ ABANDONMENT COST IN 2030
GAS SALES
0
20
40
60
80
100
120
140
160
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
YEAR
GA
S SA
LES
- MM
CFD
GAS CASE - ECONOMIC ANALYSIS ASSUMPTIONS AND RESULTS
•MEAN SIZE GAS FIELD DISCOVERY CASE – 600 BCFE•FULL EXPLORATION COST BURDENED BY SINGLE FIELD•$5.00 PER MCF GAS PRICE DELIVERED TO EXISTING BRAZIL PIPELINE•$58 OIL PRICE ($65 WTI MINUS $7 TRANSPORTATION COST)•NO PRICE OR COST ESCALATION•ROYALTY PER PARAGUAY TERMS (10/12/14% FOR OIL, 15% FOR GAS)•15% DEPLETION ALLOWANCE•30% INCOME TAX RATE•EARLY YEAR LOSS TAX CREDITS TAKEN WHEN PRODUCTION BEGINS
33.3%IRR (%)$414.8PV@10% (MM$)$1691.6NET PROFIT (MM$)$552.8TAXES (MM$)$833.6COSTS (MM$)$3078.0NET REVENUE (MM$)
SUCCESS CASE ECONOMICS
GAS SUCCESS CASE ANALYSIS – PER MCF OF GAS PRODUCED
COMMENTS
GAS SALES INCOME LESS TOTAL DEDUCTS$2.81 / MCFNET PROFIT
TOTAL OF ABOVE 6 ITEMS$3.08 / MCFTOTAL DEDUCTS
INCOME TAX PAYABLE TO GOVERNMENT$0.92 / MCFTAXES
COST TO ABANDONMENT WELLS AND FACILITIES AFTER DEPLETION
$0.05 / MCFABANDONMENT
ONGOING OPERATING COST$0.50 / MCFOPEX
TOTAL EXPLORATION AND DEVELOPMENT CAPITAL COST
$0.78 / MCFEXPL & DEV
PAYMENT TO GOVERNMENT$0.84 / MCFROYALTY
INCLUDED IN DEV COST AND OPEX$0 / MCFTRANSPORTATION
$5.00 / MMBTU ADJUSTED UPWARD FOR CONDENSATE PRODUCTION AND BTU VALUE
$5.89 / MCFGAS SALES
RISK ANALYSIS
•PLAY SUCCESS CHANCE (Pp)•Probability that one well in entire play tests hydrocarbons •Not necessarily in commercial quantities•Estimated to range between 50-100% based on geologic analysis factors
•PROSPECT SUCCESS CHANCE (Pg)•Average probability of all individual prospects testing some hydrocarbons•Not necessarily in commercial quantities•Estimated range of 20%-50% based on Bolivian/Argentine analogy•Play will be tested with multiple wells testing different prospects (#tests)
•PERCENTAGE OF TIME DISCOVERY SIZE EXCEEDS ECONOMIC THRESHOLD (Pt)•Use non-thrust field size distribution analogy•8 MMBOE for oil field discovery – 47%•170 BCFE for gas field discovery – 33%
•PROGRAM CHANCE OF ECONOMIC SUCCESS (Pe)•Chance of one economic discovery in exploration program•Drill multiple wells before “walking away”•Function of Pp, Pg, #tests, Pt
Pe = Pp x [ 1 – (1 – Pg x Pt)#tests ]
Pe X SUCCESS CAST PV@10% + (1 - Pe ) X [PV@10% OF AFTER TAX EXPL COST]
÷Pe X PV@10% OF CAPEX + (1 - Pe ) X [PV@10% OF EXPL COST]
NPVR
IRR OF RISKED CASH FLOW [Pe X SUCCESS CASE NET PROFIT – (1 – Pe) AFTR TAX EXPL COST]IRR
Pe X [SUCCESS CASE PV@10%] – (1 – Pe) X [PV@10% OF AFTER TAX EXPL COST]NPV@10%
Pe X [SUCCESS CAS NET PROFIT] – (1 – Pe) [AFTER TAX EXPL COST]NET PROFIT
EXPLANATION OF RISKED CASH FLOW ECONOMIC CALCULATION
EXPLORATION PROGRAM ANALYSIS
•6 WELL EXPLORATION PROGRAM•Pp = 90%•Pg = 20%•Pt = 47% (OIL PLAY), 47 MMBO MEAN OIL RESERVES DISCOVERED
•Pe = 40.2%
1.36RISKED NPVR
32.7%RISKED IRR
$147.2 MMRISKED NPV@10%
$517.2 MMRISKED NET PROFIT
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