2014 Parex Investor Day: Bogota

Transcription

Parex Resources
Investor Presentation
Bogota
November 17, 2014
Agenda
1.
Vision, Track Record &
Goals
Wayne Foo
CEO
2015 Guidance Overview
Ken Pinsky
Mike
Kruchten
CFO
VP Corporate Planning
& IR
3.
Reserves Summary
Eric Furlan
VP Engineering
5.
Exploration Portfolio
Ryan Fowler
VP Exploration
Operating in Colombia
Lee
DiStefano
President &
Country Manager
Wrap Up
Group Dinner
La Mar Restaurant
2.
6.
7.
2
Parex Vision
1. Create long-term shareholder value
2. Build a portfolio of assets to allow for consistent growth
3. Develop an organization with bench strength to allow
Parex to evolve into the leading LATAM independent
E&P
3
How have we progressed?
2010 – Find something  Kona Field
2011 – Grow Production & Cash  Q4 11,342 bopd & FFO $63 MM
2012 – Diversification  acquire LLA-32, LLA-34 and Cabrestero
2013 – Demonstrate Sustainability  expand RLI > 5 years
2014 – Building the Runway
 develop inventory to double Parex
4
Our “Values”
We are:
1. Team based, respectful and trustworthy
2. Biased to Action, not delay
3. Driven to prove the commercial viability of our concepts
4. Rewarded for creating share value
5. Managed by data whenever possible
6. Clear and objective in our depiction and management of
the risks that are a natural part of our business.
7. Aware of the roles we need to play and accepting of
those requirements
5
History of Creating Shareholder Value (#1)
Value Created from PetroAndina to Parex
$1,000
$900
PetroAndina
shareholders have
realized a 389% return
$800
Millions
$700
260
$600
$500
234
$400
154
$300
$200
378
166
$100
Parex Shares
(Day 1)
Sale - Cash $7.65
Value Added
Total Investment
Shares Issued
Parex Shares
(today
PXT = $10/sh
44
Private
Placements
14
Options
$0
224
Mgt provided a profitable exit to Argentina and a high growth option (PXT)
6
Colombia Focused
Barranquilla
Santa Marta
Cartagena
/BLOCK
Significant land base
2.75 mm gross acres
Working interest in 23 blocks
VIM-1
Covenas
Diversified production base
Experienced operator
~120 wells drilled
VENEZUELA
58 mmbbls in 2P Reserves
COLOMBIA
OBC
Capachos
VMM-9
Medellin
LLA-10
VMM-11
LLA-40
LLA
LLA-16-17
LLA-57
Los
LLA-20
El Porton Ocarros
LLA-24
El Eden
LLA-30
LLA-26
LLA-29
Morpho
Cebucan
LLA-32
BOGOTA
Cerrero
LLA-34
Cabrestero
Single country
concentration  competitive advantage
7
History of Creating Shareholder Value (#2)
Parex Value Created (CAD$ estimate Nov 2014)
$2,000
$1,500
Millions CAD$
751
2190
Current
EV
$1,000
1500
85
182
$500
749
288
48
148
Reserve Report NPV10
AT (3P)
Value Added
Reserve Report NPV10
AT (2P)
Assume CAD/USD 1.13
Total Capital Investment
Debenture
Verano Acquisition
2010 - 2011 brought
deals
PXT Initial @$3.00
PXT Opening
$0
Beginning with Enterprise Value of ~$200 MM, we’ve grown EV > C$1,350 MM (6.8x)
8
Track Record of Consistent Growth
Production Growth Debt Adjusted
100
15,000
120
10,000
80
5,000
40
0
2010
2011
2012
2013
0.60
3P Reserve per share - RHS
60
2P Reserve per share - RHS
0.20
20
0
0.00
2009
2014E
NPV Growth Debt Adjusted
3P NPV10AT (USD) - LHS
$2,000
$8.00
$800
$4.00
$400
$0
$0.00
2009
2010
2011
2012
2012
2013
June 2014
Funds Flow per share
RHS
$3.00
Q4
2014E
$300
Funds Flow ($MM)
$1,200
3P NPV10AT per share
3P NPV10AT ($MM)
$12.00
2011
Funds Flow
LHS
3P NPV10AT per share (USD) - RHS
3P NPV10AT per share (CAD) - RHS
2010
Funds Flow Growth Debt Adjusted
$16.00
$400
$1,600
0.40
40
0
2009
2P - LHS
80
Reserves per share
160
0.80
Possible - LHS
$200
$2.50
$2.00
$1.50
$1.00
$100
$0.50
Funds Flow ($/share)
20,000
200
Production per share
Production (bopd)
Production per share
RHS
Reserves (MMboe)
Production (bopd)
LHS
25,000
Reserve Growth Debt Adjusted
$0
2013 June 2014
2009
($100)
2010
2011
2012
2013
2014E
$0.00
($0.50)
9
Grow & Diversify Production
LLA-16
LLA-20
Los Ocarros
Cabrestero
LLA-32
LLA-34
LLA-30
Other
27
24
Bopd (000) by block
21
18
15
12
9
6
3
0
Q4
2010
Q1
Q2
Q3
2011
Q4
Q1
Q2
Q3
Q4
Q1
2012
Q2
Q3
Q4
2013
Q1
Q2
Q3
Q4
est.
2014
Third Quarter production averaged 25,175 bopd
10
A strong production platform to grow
60,000
50,000
Develop
Base
Target 10% YOY
Target at 20% YOY
2015+
Exploration
BOPD
40,000
30,000
20,000
Develop Existing Reserves1
10,000
Base – Existing Wells2
-
This is a internal production forecast of our existing portfolio. Given our current asset base and
exploration portfolio, we have line of sight to long-term production growth
Parex Management estimates:
1.
Production from existing wells as of September 30,2014. Minor maintenance capex
2.
Production from new wells/recompletions in existing fields as of September 30,2014
11
2015 Guidance: Self Funded 30% Growth
2015 Full Year Average Production
28,500-30,000 bopd
# Wells
Capex (Net $ million)
Gross
Net
Wells
Development/Appraisal (existing fields)
16
9.4
$54
$91
-
$145
Exploration (new prospects)
17
12.9
$120
-
$10
$130
Exploration Appraisal (contingent follow-up)
5
4.3
$21
$9
-
$30
New Concept (Magdalena Basin)
1
1
$5
-
$20
$25
39
27.6
$200
$100
$30
$330
Base (Firm) Total
Facilities Seismic
Total
2015 Capital expenditure program to be fully funded through cash flow
12
Colombia: A Platform for Growth
Brent Oil Price $/bbl
Capex (excluding acquisitions MM USD)
Annual Average Production bopd
Annual Production per basic share
2013
$109
$234
15,854
0.053
2014
~$101
$290
~22,350
0.067
2015 Guidance
$85
$330
28,500-30,000
0.079
Annual Cash Flow (MM USD)
Cash Flow Per Share - Basic
Year End Net Debt (MM USD)
$270
$2.49
$69.50
~$330
$2.70
-
>$330
$2.40 - $2.50
-
Note: Net debt is defined as face value of convertible debenture, working capital and bank debt. For 2014 and 2015 we
expect net debt to be a net surplus. We forecast Q4 2014 Brent oil price of $85/bbl
13
Exploration Prospects 2015
Llanos Basin
Capachos
Magdalena Basin
VIM-1
LLA-10
Middle Magdalena
*Lower Magdalena
LLA-16
3D Seismic
2014/15
Kona
LLA-40
LLA-17
LLA-57
Los Ocarros
VMM-9
Las Maracas
Nare
Palagua
LLA-20
El Porton
VMM-11
Cocorna
El Eden
LLA-24
PP Velasquez
Cusiana
LLA-26
Morpho
LLA-29
Cebucan
Balay
40 km
LLA-30
LLA-32
Cerrero
Meta River
LLA-34
Cabrestero
Parex Oil Fields
Parex Blocks
Selected Oil Pools
14
A look back: 2014 Exploration
Block
Cebucan
LLA-24
LLA-26
LLA-29
LLA-30
LLA-32
Cerrero
LLA-34
Oropendola
LLA-40
LLA-57
Los Ocarros
VMM-11
Total Exploration Drilled
Well
Taringa
Arlequin
Campanilla
Rumba
Arton
Fierro
Restrepo
Lola
Kananaskis
Carmentea
Calona
Chacharo
Katmandu Norte
Mochuela
Tigana Norte
Tigana Sur Oeste
Tilo
Urraca
Ardisia
Begonia
Celtis
Talia
Berbena
Pembina
Terranova
Terranova ST
Zampona
Ermitano
Q1' 2014
Q2' 2014
Q3' 2014
Q4' 2014
To drill
standing
Our original plan was to drill 19
exploration wells:
 ~19 to drill
Defer to 2015
Defer to 2015
Defer to 2015
Social Access
D&A
Defer to 2015
Oil
8 prospects drilled weren’t
in the original budget
Oil
Oil
Oil
Oil
Defer to 2015/16
Oil
Oil
To drill
D&A
D&A
Oil
Oil
Replaced
D&A
Replaced
D&A
D&A
D&A
Legend:
Defer to 2015 (renamed Glauca)
5
10
1
3
2014 Plan & Drilled
Added to 2014 - Drilled
2014 Plan – Not Drilled
15
2015 Exploration and Development
Drilling Program
Block
WI
LLA-10
50%
LLA-17
63%
LLA-20
100%
LLA-26
100%
LLA-30
100%
LLA-32
70%
Cabrestero
100%
Capachos
50%
Cebucan
100%
VMM-11
100%
Total Operated
Numbers of Wells
Exploration Dev/Appr
1
0
1
0
1
0
2
0
2
0
3
1
0
1
2
0
1
0
1
0
14
2
Total
Gross
Net
1
0.5
1
0.6
1
1.0
2
2.0
2
2.0
4
2.8
1
1.0
2
1.0
1
1.0
1
1.0
16
12.9
Tigana LLA-34 55%
0
12
12
6.6
LLA- 34 Other 55%
LLA-34 Expl
55%
Total Non-operated
0
3
3
2
0
14
2
3
17
1.1
1.7
9.4
Expected Follow-Up
Total Parex
6
17
6
Planned Location
Tautaco-1 (Commitment)
Celeus Norte-1 (Commitment)
Zororojo-1 (Commitment)
Rumba-1 (Commitment), Arton-1 (Commitment)
Roxana-1, Matilde-1
Carcayu-1, Guepardo-1, Xoropo-1; Samaria-2
Akira-12
Guad Upside-1 (Commitment); Guad Upside-2 (Commitment)
Taringa-1 (Commitment)
Glauca-1
Tigana-4, Tigana-5, Tigana-6, Tigana Sur-4, Tigana Sur-5, Tigana Sur7, Tigana Sur-8, Tigana Sur-9, Tigana Sur Oeste-2, Tigana Sur Oeste-3,
Tigana Sur Oeste-4, Injector-1
Tua-10, Max-3, Tilo-2
Chiricoca-1, Chenchena-1, Jacana-1;
5.3
16
39
27.6
Locations dependant on
exploration success and
discretionary cash flow
16
2015 Exploration Schedule
Block
LLA-10
LLA-17
LLA-20
LLA-26
LLA-26
LLA-30
LLA-30
LLA-32
LLA-32
LLA-32
Capachos
Capachos
Cebucan
VMM-11
LLA-34
LLA-34
LLA-34
Total Exploration Wells
Well
Q1 2015
Tautaco
Celeus Norte
Zororojo
Rumba
Arton
Roxana
Matilde
Carcayu
Guepardo
Xoropo
Guad Upside-1
Guad Upside-2
Taringa
Glauca
Chiricoca
Chenchena
Jacana
Q2 2015
8
Q3 2015
6
Q4 2015
3
0
Exploration is weighted towards H1 allowing for follow up drilling in H2
but it changes everyday…
17
Operations – After the
Drilling
Success in Online Performance and
Operating Costs
Eric Furlan, VP Engineering
Daniel Ferreiro, VP Operations
18
Extracting the Most Value out of a Discovery
1. Immediately delineate discoveries to understand the potential size and ultimate
development of the discovery.
2. Maximize front end technical work through testing, lab analysis and reservoir
simulation.
• Technical “depth” that would typically be observed in one of the Major Oil
and Gas companies but at a much faster pace.
3. Generate a development plan including facilities design and expected plateau
production rates. Execute on facilities development including water disposal and
treatment as quickly as possible.
Maximizing value out of an asset requires minimizing the time to permanent
facilities so that the reserves base can be produced as efficiently as possible.
This strategy also allows Parex to extract value out of smaller discoveries where
many operators would not be profitable.
19
Las Maracas – Development Efficiency
Las Maracas Development
Plan/Gas Generation
July 2012
Las Maracas 2 Discovery
November 2011
Oil Treatment Plant
Operational
March 2013
Parex farmed in on the
opportunity with a rig on
location. Partners did not
have any follow up surface
locations available which
delayed delineation by 6
months.
Las Maracas 3,4,5 Appraisal
July –Sept 2012
Appraisal drilling at Maracas was delayed as partners had no follow up locations that could be
accessed. After initial delineation commenced, Parex finalized the development plan and executed on
development of the facilities to allow rapid development of the field including a full oil treatment plant
within 6 months of finalizing the initial delineation.
Results:
1. 85% of the oil produced to date at Las Maracas has been produced using the permanent facility.
Temporary rental costs were minimal and the permanent “fit for purpose” facility allowed for very low
cost operation.
2. Water disposal commenced when required and predicted, essentially no trucked water.
3. Gas fired power generation at a cost of 40% less than comparable diesel generation.
20
Competitor – Maniceno Field Development
Maniceno Discovery
July 2012
Water breakthrough. No
facilities or water handling
available
August 2012
Maniceno Injection Well
November 2012
Bandola Follow Up Well
April 2013
Removal of Main Rental
Facilities
August 2013
Removal of Water Disposal
Rental Facilities
September 2014 (Parex)
Results:
1.
2.
3.
A poor initial development plan and lack of facilities created a situation where over 300,000 bbl of water was trucked at very
high cost for disposal prior to installation of facilities. Then operational performance resulted in significant water trucking
even after facilities were in place.
All of the gas produced at the field was flared while truck loads of diesel were brought into location to generate power.
Over most of the field life, facilities were temporary and rented at very high operating cost. The operator installed the
permanent facilities near the final stages of field life (after 71% of the reserves were produced) with the final removal of
rental facilities only after Parex took operatorship.
At a similar level of field maturity, Parex was producing oil at Maracas as $3/bbl while the operator in
this development was incurring costs of $20/bbl. In July 2012 Parex, as a non operator partner,
presented its own development plan to the operator that outlined the immediate need for water
disposal, a second well and gas fired generation that was no accepted.
21
Fluid Handling – The Largest Operating
Component
Maniceno
Las Maracas
25,000
60,000
50,000
20,000
Oil Production BOPD
Oil Production BOPD
Water Production BWPD
Water Production BWPD
Water Injection BWPD
Water Injection BWPD
40,000
BOPD/BWPD
BOPD/BWPD
15,000
30,000
10,000
20,000
5,000
10,000
0
09/2014
08/2014
07/2014
06/2014
05/2014
04/2014
03/2014
02/2014
01/2014
12/2013
11/2013
10/2013
09/2013
08/2013
07/2013
06/2013
05/2013
04/2013
03/2013
02/2013
01/2013
12/2012
11/2012
10/2012
09/2012
08/2012
07/2012
06/2012
05/2012
04/2012
03/2012
02/2012
01/2012
12/2011
11/2011
10/2011
09/2011
08/2011
0
Good initial understanding of the development,
ultimate size and water disposal needs early in the
pool development of Las Maracas meant facilities
were available when water handling was required
and no water was trucked.
Poor initial understanding of expected performance
meant the operator was constantly reacting to
“unexpected” performance. Large amounts of
water was trucked initially and then large amounts
of water was trucked even after installation of rental
facilities as the facilities were poorly designed.
A well thought out and executed development plan is the difference between being a top quartile
performer or a bottom quartile performer.
22
Operating Cost Initiatives - Power
Power generation can represent 40% of total operating costs. This is typical in
water drive reservoirs where a large amount of water has to be pumped.
In addition to utilizing produced gas for power generation in fields, Parex has built
an infrastructure that allows for trucking of gas from its La Casona operations to
all operated fields for power generation where the fields themselves do not
produce sufficient gas to meet power generation needs.
Energy generation costs have been reduced by 48% which has reduced unit
operating costs in all operated fields by about $1.50/bbl.
23
Potential Synergies: Infrastructure Projects
Sending gas or power
from LLA-32 south to
LLA-34 / Akira
Shipping oil north
towards ODL
24
Operating Philosophy
1. Early appraisal of initial discovery
2. Commit early to facility projects – ensure reserves
base produced at lowest cost.
3. Build “fit for purpose” facilities – minimize capex
4. Reduce power costs – use produced gas for power
generation
5. Share best practices on non-operated blocks
25
Reserves and Field
Development
26
Reserves Process
GLJ is the auditor of all Parex reserves including the additional
reserves added from the acquisition of Verano Energy.
Generally Parex presents their own reserves interpretation to GLJ
including:
Mapping and seismic interpretation
Well performance and pressure buildup performance including
interpretation of drive mechanism and recovery factors
Integrated Simulation models (in-house) on all of the major fields
supported by lab analysis of reservoir rock properties.
Historically Parex has been able to predict within a few percent the
outcome from our independent reserves evaluation by GLJ.
27
Reserves Conversion
Track record of progressing reserves from 3P to cash flow
Focus on increasing reserve life index (RLI) & sustainability
Proved + Probable
+ Possible
Proved + Probable
Proved
2P Reserves Life
Index (1) (2)
After Tax PV10(3)
(USD MM)
Reserves* MMboe
31-Dec -09
-
-
-
-
-
31-Dec -10
10.4
5.8
1.1
-
$149
31-Dec-11
17.6
10.7
4.9
2.6x
$344
31-Dec-12
23.1
16.1
10.1
3.5x
$450
30-Jun-13
36.4
23.7
14.1
4.2x
$614
31-Dec-13
49.9
32.0
17.4
5.1x
$832
30-Jun-14
90.6
57.6
31.9
6.7x
$1,326
(1) Year-end RLI calculated using 2P year-end reserves divided by Q4 production annualized
(2) Mid-year RLI calculated using 2P year-end reserves divided by annualized Q2 production at June 30, 2013 and estimated second quarter (Q2) exit rate production of 23,500 bopd annualized at June 30, 2014.
(3) Value based on GLJ ‘s Ice Brent Price Forecast : US $107.50 in 2015 , US $105.00 in 2016 and US $102.50 in 2017
*Gross Reserves are independently evaluated by GLJ Petroleum Consultants Ltd.
28
Reserves Overview
Three key fields represent a significant portion of future:
 Development portfolio
 Reserves additions
1. Akira
2. Tua
3. Tigana
In addition, Parex is evaluating developing the gas and associated
liquids in LLA 32 to monetize the gas and associated liquids and
reduce operating costs
29
Akira Guadalupe Depth Map
Guad OWC -9157’ TVDSS
GLJ Lwr Guad 3P
LLA 34
Cabrestero
Additional Appraisal
Upside
Akira is a 100% working
interest operated property.
Recent wells Akira 9, 10,
and 11 will have a positive
impact on the reserves in
the pool.
Likely 5-10 additional
development wells will
be required in Akira in the
current state of delineation.
Current production
capability in excess of
7,500 BOPD.
Guadalupe
Sands Absent
Presentation 2014
30
Akira Well Productivity
Well
Current Oil
Production
(BOPD)
Current Fluid
Production
(BFPD)
Max Oil Production Max Fluid Production
80% DD
80% DD
(BOPD)
(BFPD)
Potential Oil
Production
(BOPD)
Akira 1
Akira 2
Akira 4
Akira 6
Akira 7
Akira 8*
Akira 9ST
Akira 10
Akira 11
189
0
420
676
0
500
0
0
625
260
0
544
753
0
715
0
0
865
260
300
630
2,300
130
820
1,000
1,450
790
350
450
700
2,500
200
950
1,100
1,530
1,100
71
300
210
1,624
130
320
1,000
1,450
165
TOTAL
2,410
3,137
7,680
8,880
5,270
Akira 8 has just commenced production and is still cleaning up
31
Tua Guadalupe Depth Map
Tua-8 results indicate additional
delineation is required to understand
the pool limits. The well is on
production at +1,500 bopd.
Tua-9 is drilling to delineate
further the southern half of the Tua
pool.
Shown is the field outline of the
Upper Guadalupe reservoir with a
thinner Lower Guadalupe below the
upper that appears to have the same
areal extent.
Tua-9
Tua Guad ODT -9440’ TVDSS
Tua Guad ODT Pre Tua-8
GLJ Guad 3P
GLJ Guad 2P
Likely 10-20 additional development locations (gross) to develop both the Upper and Lower
Guadalupe reservoirs given the current state of delineation.
32
Tua Gross Pool Production
Operational Issue
Production at Tua has essentially been flat for over a year at current facility limitations.
The permanent Tua facility is expected to be commissioned in January, 2015.
33
Tigana Type Well
Multi reservoir pool with tested or
producing oil in the Mirador, Lower
Mirador, Basal Mirador and Guadalupe
Reservoirs.
The most continuous reservoir appears
to be the Guadalupe.
100 ft Scale
34
Tigana Field Structure Section
29 API
20 API
15 API
13-15 API
15 API
15 API
?
15 API
15 API
15 API
?
~5 km
Producing Zone
Tested Zone
35
Tigana Mirador Depth Structure
LLA 32
LLA 34
TILO
Tigana 2 (Upper Mirador A)
Cum ~74 MBO (29 API)
Current Prod = 773 bopd
Current WC = 4.4%
Tigana 1 (Lwr Mirador A)
Current WC = 12%
TIGANA
TAROTARO
TAROTARO
Lower Mirador A Sand
Strat Edge from Time Slice
OWC from Mapped Spill Point
Black = GLJ 3P
TUA
Current ODT
TUA
Oil Test
JACANA
Most Mirador oil wells
are outside mapped
closure
Presentation 2014
Indicated Oil
Water Test
Indicated Wet
36
Tigana Guadalupe Depth Map
Tigana Norte -1 (Guad)
Current WC = 1.95%
LLA 32
LLA 34
TILO
Tigana – 3 (Guad)
Current WC = 0.52%
Tigana Sur-2 (Guad)
On Prod Oct 2014 (15 API)
Current WC = 0.54%
TAROTARO
Tigana Suroeste-1 (Guad)
On Prod Oct 2014 (15 API)
Current WC = 1.51%
Black = GLJ 3P
Tigana Sur 1 (Guad)
Current WC = 0.18%
OWC from Model
ODT from logs
TUA
Oil Test
JACANA
Indicated Oil
Water Test
Indicated Wet
Presentation 2014
37
Tigana Gross Field Production
This field is in the testing
stage only and is facility
constrained with temporary
testing facilities.
Currently 7 wells on production with production limited by temporary testing facilities.
38
Tigana Continued Delineation
Tilo Prospect
Next Steps in
Delineation
Tigana delineation will
continue in 2015 as additional
drilling pads are required to
continue delineation of the
pool North and South along
trend.
Given the multiple reservoir
zones encountered in the field,
30-50 additional development
wells are likely given the
current state of delineation.
Next Steps in
Delineation
39
Une Gas at Kananaskis, Calona and Carmentea
Calona
GDT -10073
Saddle ~-10150
Carmentea
Kananaskis
GDT/Spill -10022
N
GDT highlighted by dashed pink
Presentation 2014
40
LLA 32 Gas - Summary
Testing is currently underway to understand the size and
quality of the gas in LLA 32. The previous operator on the
block was unable to complete testing on the discoveries due
to operational issues. No reserves are currently booked for
the gas or associated liquids.
Plans are moving forward to monetize gas with sales to LLA
34/32/Cabrestero to replace all diesel power generation with
Gas.
Potential to add reserves (BOE) from gas and associated
liquids, in addition to reducing operating costs in the southern
Llanos fields.
41
Summary – Existing Fields
Three key fields provide opportunity to grow reserves and
production.
Development opportunities on existing fields provide several
years of development while the exploration portfolio provides
the feed for the next round of development. The 2015
budget includes development of one third of the GLJ 2P
development locations.
Creative approaches to commercialization of product, like
trucking of the gas from La Casona or generating power in
the southern fields, will allow Parex to commercialize all of
their discoveries.
42
Drilling Operations
Ron MacDonald
VP Drilling & Completions
43
Parex Drilling Group Development
Key drivers of operations success:
Equipment
1. Moved from local rigs to 3 rigs imported (2011)
 Modify equipment to improve efficiencies
People
Parex Drilling
Operations
2. Rigorous Planning, Risk Assessments & Execution
 Organizational buy-in of delivery risk
 Pre-agreed objectives and deliverability's
3. Re-wrote the “How to Drill” for Casanare Basin
Process
4. Development of internal Drilling Engineering skill base
5. Implemented Senior Supervision on all 24 hour operations
Project Deliverables: Assets and Information
44
Time Performance: LLA-16 (2011-2012)
0
1,000
Kona-1
Kona-2a
2,000
Goroka-1
Supermo-1
3,000
Kona-3
Kopi-1
4,000
Kona-4
Kona-6
5,000
Kona-Norte 1
Kona-5
Kona-8
MD (ft)
6,000
Sulawesi-1
Kona-10
7,000
Avg 28 days to get Well TD
Sulawesi-3
Kona-Norte-2
8,000
Kona-11
Avg 37 days to rig release
9,000
Supremo-2
Kona-9
Kona-7
10,000
Merida-1
Kona-12
11,000
Kona-13
Sulawesi-2
12,000
13,000
14,000
0
5
10
15
20
25
30
35
DAYS
40
45
50
55
60
65
70
75
45
Time Performance: LLA-16 (2012-2013)
0
1,000
2,000
SULAWESI-4
KONA-15
JAVA-1
JAVA-2
MALAWI-1
KONA-SUR-1
6,000
KONA-16
MARAGOGI-NORTE-1
7,000
CATURRA-1
3,000
4,000
MD (ft)
5,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
0
5
10
15
20
25
30
35
DAYS40
45
50
55
60
65
70
75
46
Kona-16
Kona-Sur-1
Malawi-1
Java-2
Kona-14
Java-1
Kona-15
Sulawesi-4
Sulawesi-2
Kona-13
Caturra-1
USD
$ 12,000,000
Maragogi-Norte-1
WELLS
Kona-12
Merida-1
Kona-7
Kona-9
Supremo-2
Kona-11
Kona-Norte-2
Sulawesi-3
Kona-10
Kona-3ST2
Sulawesi-1
Kona-8
Kona 3ST
Kona-5
Kona-Norte-1
Kona-6
Kona-4
Kopi-1
Kona-3
Goroka-1
Supremo-1
Kona-2A
Kona-1
MILLIONS
Cost Performance: Block LLA-16
$ 14,000,000
$ 1,000
$ 900
Actual cost (DDR)
$ 800
Cost per ft
$ 10,000,000
$ 700
$ 8,000,000
$ 600
$ 500
$ 6,000,000
$ 400
$ 4,000,000
$ 300
$ 200
$ 2,000,000
$ 100
$0
$0
47
Time Performance: Block Los Ocarros
0
1,000
2,000
MARACAS-3
MARACAS-4
3,000
MARACAS-5
MARACAS-6
4,000
MARACAS-7
5,000
MARACAS-13
MARACAS-8
MD (ft)
6,000
MARACAS-9
7,000
MARACAS-11
MARACAS-10
8,000
MARACAS-12
MARACAS-14
9,000
LA GUIRA-1
LA GUIRA-2
10,000
MARACAS-15
MARACAS-16
11,000
12,000
13,000
14,000
0
5
10
15
20
DAYS
25
30
35
40
48
Cost Performance: Block Los Ocarros
$ 1,000
$14,000,000
$ 950
$ 900
Actual cost (DDR)
$12,000,000
Cost per ft
$10,000,000
$ 850
$ 800
$ 750
$ 700
USD
$ 650
$ 600
$8,000,000
$ 550
$ 500
$ 450
$6,000,000
$ 400
$ 350
$ 300
$4,000,000
$ 250
$ 200
$ 150
$2,000,000
$ 100
$ 50
$-
$0
WELLS
49
Time Performance: Block Cabestrero
0
1,000
KITARO-1
2,000
KITARO-2
AKIRA-1
3,000
AKIRA-2
4,000
AKIRA-3
AKIRA-4
5,000
AKIRA-6
AKIRA-5
MD (ft)
6,000
AKIRA-7
AKIRA-8
7,000
AKIRA-9
AKIRA-9st
8,000
AKIRA-10
AKIRA-11
9,000
10,000
11,000
12,000
13,000
14,000
0
5
10
15
20
25
30
35
40
DAYS
50
Cost Performance: Block Cabestrero
$ 14,000,000
$ 1,000
$ 950
$ 900
$ 12,000,000
Actual cost (DDR)
$ 850
$ 800
Cost per ft
$ 10,000,000
$ 750
$ 700
$ 650
$ 600
$ 8,000,000
$ 550
USD
$ 500
$ 450
$ 6,000,000
$ 400
$ 350
$ 300
$ 4,000,000
$ 250
$ 200
$ 150
$ 2,000,000
$ 100
$ 50
$0
$0
WELLS
51
“Can you continue to apply your drilling
model deeper areas in the Casanare and
new (Magdalena) basins in Colombia?”
 We were a new entrant to Colombia and cost effectively developed 3 large
fields plus exploration programs
We have demonstrated our ability to quickly move from exploration data
gathering to development drilling
We have accessed 18 new blocks and to date have dramatically reduced
operating time and costs on all active blocks with 11 wells in excess of 13,000
ft in portfolio
 El Eden Average 147 Days to 55 to 37 , 16,500/14,650 ft
 Cebucan 55 Days to 45 Days
“We are already doing it through: people, process and equipment.”
52
Exploration Program
Ryan Fowler, VP Exploration
53
What makes Parex different?
Technical Fundamentals
First principles technical – geologists and engineers are
experienced and trained to ask questions and asked and
challenge paradigms
Subsurface technical team had no prior experience in Colombia
and few pre-conceived ideas  open minded
Aggressive Exploration
Acquire 3D seismic early in program  data driven decision
making
A Bias For Action
Drill concepts early…learn faster…become low cost
operator…access more opportunities…grow
Repeat in new basins
54
Parex Exploration History Casanare Experts
49 Independent Prospects
drilled on 14 blocks over 5
years
What is a discovery?
Parex
Discoveries
Capachos
Something that gets put on
production
30 Discoveries
19 Dry
61% Success Rate
Year by Year:
LLA-10
LLA-40
LLA-16
Los
Ocarros
El Porton
LLA17
2010/2011: 4/9
2012: 13/16
2013: 6/11
2014: 9/16
LLA-57
LLA-20
LLA-24
El Eden
Cebucan LLA-26
LLA-29
LLA-30
LLA-32
Cerrero
LLA-34
Cabrestero
• Proven track record
• Diverse experience
• Basin experts
• Still diversifying
55
Parex Exploration Life Cycle
Develop
Concept
Acquire
Land
Test
Concept
Initial
Development
Traditional
3-Ways
Expand
Land
Exploitation
LLA-26, Cebucan
Low Side
Closures
Cabrestero, LLA-32, LLA-34,
Stratigraphic
Traps
LLA-24, LLA-30, Akira, Tigana
New Plays
Magdalena Basin, Llanos Deep, Capachos
Continue to deliver on our strategy to expand the asset base and added
meaningful positions for future sustainable growth
56
Llanos Basin Exploration Progression
Parex
Casanare
Exploration
2009 - 2013
Structural
Traps
Combination
Traps
Stratigraphic Traps
New
Concepts
2014 -
Resource Plays
57
Progressively Larger Discoveries –
Structural Traps
Median Llanos
100 acres
Kona
300 acres
Las Maracas
300 acres
Tua
1000 acres
1. Size
2. Drive
Bottom water drive
Edge water drive
Oil
Water
Sandstone
Edge water drive
Shale
58
Progressively Larger Discoveries –
Combination Traps
Akira
1000 – 1500 acres
1. Size
Tigana
2000+ acres
Current trap
geometry
Trap type at
Tigana is still
under appraisal
2. Drive
Structural
Closure
Current trap geometry exceeds structural closures implying strat components
59
Llanos Basin Conventional
Prospect Summary
Block
LLA 34
Capachos
LLA 32
LLA 26
LLA 10
Cerrero
LLA 30
Cebucan
Other
Total
Working
Interest
Prospects
2015
Drills
6
4
10
5
5
5
5
2
22
64
3
2
3
2
1
0
2
1
2
16
55
50
70
100
50
65
100
100
Note: Capachos Block is pending ANH Conveno
60
New Basins Conventional
Prospect Summary
Block
VMM 9
VIM 1
VMM 11
Morpho
Total
Working
Interest
Prospects
2015
Drills
12
2
4
1
19
0
0
1 (*)
0
1
100
100
100
100
(*) Up to 4 contingent follow ups at Glauca
61
Non-Conventional Potential
Block
Cerrero
Cebucan
El Eden
LLA 26
El Porton
Llanos Sub-Total
Block
VMM 9
VMM Sub-Total
Working
Interest
Gross
Prospective
Area (acres)
65
100
60
100
50
100,000
100,000
90,000
85,000
110,000
485,000
Working
Interest
Prospective
Area (acres)
100
65,000
65,000
62
2015 Exploration Program
63
2015 Llanos Exploration Program
Parex
Exploration
Locations
Capachos
2
LLA-10
LLA-40
LLA-16
Los
Ocarros
LLA17
LLA-57
LLA-20
El Porton
LLA-24
2
El Eden
Cebucan LLA-26
2
LLA-32
Cerrero
Cabrestero
3
LLA-34
3
LLA-29
LLA-30
15 Prospects on 8 different blocks



9 Structural
3 Combination
3 Stratigraphic
Block
LLA-10
LLA-17
LLA-20
LLA-26
LLA-26
LLA-30
LLA-30
LLA-32
LLA-32
LLA-32
Capachos
Capachos
Cebucan
VMM-11
Total
Operated
LLA-34
LLA-34
LLA-34
Total Non-op
Prospect
Tautaco
Celeus Norte
Zoro Rojo
Rumba
Arton
Matilde
Roxana
Xoropo
Carcayu
Guepardo
Guad upside
Guad upside
Taringa
Glauca
WI
50%
63%
100%
100%
100%
100%
100%
70%
70%
70%
50%
50%
100%
100%
14
Chenchena
Chiricoca
Jacana
3
55%
55%
55%
64
Southern Casanare – LLA 34 & LLA 32
Santiago
Maniceño -Bandola
Balay
LLA-32
El Palmar
Carmentea
Los Trompillos
Calona
Kananaskis
Max
Tarotaro
Tigana Sur
Tigana
Tua
LLA-34
Continue to drill
structural closures while
assessing combination
and stratigraphic trap
potential
Attempt first pure
stratigraphic test
Using increasing well
control, apply seismic
inversion technology
Akira
Kitaro
Cabrestero
65
LLA34 Fields & Prospects
Play Types:
 Synthetic Structures
 Guadalupe & Mirador
Stratigraphic & Combo Traps
Chenchena
Chiricoca
MaxNorte
Tilo
2014 Drill
TAROTARO
TIGANA
Chenchena Sur
TUA
Aruco Norte
ARUCO
Jacana
Mochuleo
2015 Drills
PXT-B
X
O
AKIRA
Location
Pads
Prospects
3D Seismic Coverage
2D Seismic Lines
3P Field Evaluations
Guad Faults
66
Evaluating The Tigana Fault Trend
LLA 32
LLA 34
TILO
TAROTARO
TUA
Only about 5 km of
the 15 km Tigana
Fault Trend has
been drilled
The Tilo and
Jacana exploration
locations are drilled
on small structural
closures bracketing
the ends of the fault
trend
Significant
stratigraphic upside
exists along the
entire fault trend
JACANA
Black = GLJ 3P
Red = Current ODT
Blue = Model OWC
67
LLA32 Fields & Prospects
Play Types:
1) Antithetic & Synthetic
Structures
2) Guadalupe & Mirador Strat &
Combo Traps
3) Paleozoic involved 4WC
MANICENO
EL PALMAR
SAMARIA
CARMENTEA
LOS TROMPILLOS
2015 Drills
Carcayu
Taurmenero
Guepardo
CALONA
Groot
Azogue
KANANASKIS
Herradura
Xoropo
Structural Prospects
Stratigraphic Prospects
3D Seismic Coverage
2D Seismic Lines
Guad Faults
Guad Strat Edge
68
Kananaskis & Calona Fields
Kananaskis-1
Mirador Structure
Mirador:
IP = 5000 bopd
30 API
CTD = ~800 MB
(water free)
Valley fill trap with
down dip water – better
fit to well performance
than simple structural
model
LLA 32
Une:
High liquids gas
Further testing
required
LLA 34
Presentation 2014
69
LLA32 Synthetic Prospect –
Guepardo/Carcayu
Guepardo
Mirador Depth Structure
Synthetic structure with
similarity to both Tigana
and Akira
CARMENTEA
Carcayú
CALONA
Guepardo
KANANASKIS
LLA 32
LLA 34
70
Capachos Block: Ecopetrol Farm In
The Capachos Block is in the Arauca Department in
the northern part of the Llanos Basin
Capachos sits at a major corner in the Andean
mountainfront – a focus point for oil migration
Capachos is located along the major north-south
transportation corridor (highways, pipelines) in the
Llanos Basin
71
Capachos and Cano Limon
Cano Limon
Capachos shares a major
strike-slip fault and migration
pathway with the Cano Limon
Field (> 1 Billion Bbls Rec)
Capachos
Block
72
Capachos Field & Prospects
Play Types:
1) Thrusted & Transpressional
Structures
1) Guadalupe
2) Une
3) Mirador?
2) Guadalupe Combo Traps
Critical Success Factors
• Drilling Cost
• Community Relations
Prospects
3D Seismic Coverage
2D Seismic Lines
Guadalupe Closures
Guadalupe Faults
2015 Drills
73
The Future:
New Play Concepts
74
Llanos Plains Structural Pool Sizes (IHS)
Pmean = 3.9 MMBO
P50 = 2.0 MMBO
Good fit to a logarithmic distribution – Mature distribution
40% of discoveries made since 2010
Conforms to Parex Llanos initial assumption
Parex discoveries include Kona, Las Maracas
Parex Structural Discovery (Avg 2P= 2.7 MMBO)
75
Stratigraphic Plays Emerging
(Modified IHS)
Pmean = 30.3 MMBO
P50 = 3.9 MMBO
Poor fit to a logarithmic distribution
Immature distribution (major gaps)
65% of discoveries made since 2010
Parex discoveries include Tigana, Akira, Adalia
Zoomed in on next slide
76
Llanos Stratigraphic Pools
Excluding Rubiales (too big to fit on this chart)
2008 *
Significant gap in the 20 – 90 MMBO Range
1989 *
2010
Largest Pools all discovered post 2010
* Drilled on structural anomalies but now acknowledged to
have a significant strat element
Parex Stratigraphic/Combo Discovery
Avg 2P = 12.3 MMBO
2011
2010
2013
2012
2007 *
Tigana Guadalupe & Mirador
will both fit into this gap
77
Llanos Basin
Conventional
78
LLA 10: Looking for Cano Limonito
CAÑO LIMON
(1.1 BBO)
CARICARE
(31 MMBO)
PXT-A1
Tautaco
Garza Roja
CAPACHOS
PXT - A
Regional Strike Slip Faults
LLA 10
Most of the oil in the
Northern Llanos Basin
is trapped along NESW oriented strike-slip
faults
A couple of significant
strike-slip fault trends
have been identified on
LLA 10
The area around LLA
10 has been identified
as the probable origin
for the light oils in the
north end of the
Casanare productive
area
Good Potential For
Light Oil
79
Stratigraphic Channel Play: LLA-30
ADALIA
38 API
Play Types:
1) C5 Valley Fills
2) C3 Valley Fills
3) Antithetic Structures
Marlena
High Probability
for Light Oil
Discoveries
REMACHE SUR
36 API
Matilde
Roxanne
Matilde
VIREO
35 API
VIVIANA ESTE
Viviana
Coco
2015 Drills
Prospects
3D Seismic Coverage
2D Seismic Lines
C5 Faults
80
Future Parex Exploration Projects
High Probability
Conventional
VIM 1
1. Moving beyond
Casanare
Province
High Impact
Conventional
Non-Conventional
2. Moving beyond
the Llanos Basin
VMM 9
3. Moving beyond
Conventional
Exploration
Capachos
LLA 10
VMM 11
Morpho
Cebucan
LLA 26
LLA 30
LLA 32
Cerrero
LLA 34
81
Magdalena Basin
82
Mid Mag Basin - Play Type Distribution
Conventional
Cretaceous Pools
Pmean = 3.4 MMBO
P50 = 0.8 MMBO
Why The Mid Mag Basin?
Tertiary Structural –
Stratigraphic Pools
Pmean = 34.5 MMBO
P50 = 4.1 MMBO
Larger pool size distributions
Security of operations
Access to infrastructure
Foothills Pools
Pmean = 11.0 MMBO
P50 = 2.0 MMBO
83
Mid Mag Exploration Strategy
3. Eocene
Subcrop
Edge
4. La Luna
Resource Play
OPON
1. Teriatry
Structure
Fairway
(CHOPS)
TECA-NARE
VELASQUEZ
2. Foothills/Subthrust
Plays
Multiple play types, in close
proximity, on the same 3D
seismic volumes
Play Types
1. Tertiary Structure
(CHOPS/Hztl Drills)
2. Foothills/Subthrust
(Light Oil)
3. Eocene Subcrop Plays
(CHOPS/Hztl Drills)
4. Unconventional La Luna
(Hztl Multi-Fracs)
84
VMM Fault Trends
Over 60% of the Mid Mag Basin’s
Reserves have been found
associated with converging strike slip
fault trends at Casabe – La Cira and
Teca/Nare - Velasquez
Casabe-La Cira
Acacia-Veracruz
A similar strike slip fault trend
convergence has been identified on
VMM 9
Middle Magdalena Fault Trend Resource Distribution
Oil (MMbbls)
Area
Velasquez
Teca-NareVelasquez
La CiraCasabe
Percentage
of Basin
Total
Gas (Bcf)
Cum
Production
2P
Reserves
Cum
Production
2P
Reserves
405.3
495.8
128.8
199.0
1,231.4
1,473.3
1,026.4
1,149.0
67.4
62.3
36.0
34.8
Source: IHS
85
VMM 11 Leads & Prospects
Teca-Nare Field
Cum Production: 115
MMboe
2P Resources: 368 Mmboe
Steam Injection EOR
Caipal Field
Producing Field
Cum Production: 5 MMboe
2P Resources: 8 MMboe
Prospect/Lead
Lead 1
Lead 2
Current 3D
Acquisition
Lead 3
Parex Block
VMM 11
Faults
Glauca Prospect
Velasquez/Palagua Field
Cum Production: 199 MMboe
2P Resources: 218 MMboe
Conventional Play Types:
1) Transtensional Structures &
Combo Traps
• Colorado
• Mugrosa
• Eocene
2) Eocene Subcrop Traps
3) Foothills Subthrust
86
VMM 9 Leads
Producing Field
Prospect/Lead
Proposed 3D ~350km2
Proposed 3D
Parex Block
Lead 1
Faults
La Luna
Resource Play Area
Lead 2
Lead 3
Lead 7
Lead 4
Lead 6
Lead 5
Lead 11
Lead 10
Lead 9
Lead 8
Lead 13
Combo Traps
1) Colorado
2) Mugrosa
3) Eocene
2) Eocene Subcrop Traps
3) Foothills Subthrust
Lead 12
87
Veracruz Fault Section
Possible Eocene subcrop edge
Proposed 3D ~350km2
Lead 1
La Luna
Resource Play Area
Lead
2
Lea
d3
Lead 7
Lead 4
Lead 6
Lead 5
Lead
11
Lead
10
Lead 9
Lead 8
Lead
13
Lead
12
88
Middle Magdelena Basin: Morpho Area
Sub-Thrust Light Oil
A’
A
A’
A’
A
Sandstones of the Eocene
and Oligocene get
truncated by an out-ofsequence fault carrying
Cretaceous
Morpho Block
54,000 acres
Cordoba
Syncline
Cretaceous
triangle zone
89
Mid Mag/Upper Mag Basins – Sub Thrust
Pools
Known Sub-Thrust Pools
Pmean = 46 MMBO
* Includes Opon as a 36 MMBOE
field (extremely conservative)
Sub-Thrust pools exist all
along the eastern edge of the
Middle and Upper Mag Basins:
Nutria - Oligocene
Opon – Eocene / Oligocene
Morpho – Oligocene / Eocene?
Guaduas - Cretaceous
Guando - Cretaceous
90
Morpho Eocene Potential
Zeus-1
Oligocene Colorado
& Mugrosa
Oligocene Colorado
2600’ Interbedded SS & Shale
Net SS = 500’, Tested Oil
Zeus-1
Eocene Esmeraldas? or La Paz?
3200’ Clean, Blocky SS
Net SS = 2600’ (Oil show at top)
Eocene Esmeraldas
& La Paz
Eocene La Paz? Or Paleocene Lisama?
2600’ Serrated SS
Net SS = 2000’
91
VIM - Regional Framework
El Dificil
VIM 1
The Miocene Porquero Fm is the
acknowledged source rock for the
Lower Mag Basin (Gas Prone)
VIM 1 is located on the NW
margin of the Plato Sub-Basin
The Plato Sub-Basin has all of
the VIM oil accumulations around
its margin
Cicuco
Cicuco, Boquete, El Dificil
Mean 2P Oil = 26.3 MMBO
Mean 2P Total = 60.4 MMBOE
Boquete
The Plato Sub-Basin is deeper
than the San Jorge Sub-Basin
May contain older (Paleocene,
Cretaceous), oil prone (Like all the
rest of the Colombian Basins)
source rocks preserved in the
bottom of the basin
92
Lower Magdalena Basin Play Types

El Dificil Field (2P Oil = 11.5 MMBO)



 Cicuco Field (2P Oil = 48 MMBO)
 Structural basement high
 Oligocene Clastic and/or Caliza on
Basement
 Caliza deposition is highly variable
Structural basement high
Oligocene Caliza on Basement
very thick Calizas across the structure)
Boquete Field (2P Oil = 19.5 MMBO)
Synthetic structural trap
Oligocene Calizas and/or Clastics
Combo Structural/Stratigraphic trap in
Miocene turbidite sands
93
VIM 1 Prospects & Leads
Boquete Style A: 675 acres
Boquete Style B: 1000 acres
Apure Porquero (combo Struct/Strat): 6000 acres
Boquete Style C: 650 acres
Apure CDO (El Dificil Style): 53000 acres
Combo Traps (Oligocene SS)
2) Oligocene Carbonates
3) Miocene Porquero Tubidites
Main Lead
3D Seismic Planned
2D Seismic Lines
CDO Leads
Porquero Leads
CDO Faults
94
Apure Area Ananlogies – Cicuco /
Boquete
Boquete Style
Leads
Apure
Boquete Style
Leads
Apure
Cicuco
48 MMBO
Boquete
20 MMBO
Cicuco
48 MMBO
Boquete
20 MMBO
95
Non-Conventional
Exploration
96
Lower Gacheta Resource Play (EIA)
97
Basal Gacheta Exploration Wells
Proposed
Park
Une faults
La Casona-2
On structure
Core with oil
saturation (1st
core in basin)
Flowed oil & gas
Arlequin-1
Off structure
Core with oil
saturation
Recovered oil
Katmandu Norte-1
Off structure
Core with oil
saturation
Flowed oil & gas
Early Generation
Main Generation
Late Generation
PXT Area of Interest
98
Lower Gacheta Project Progression
Bookable
Resource and
Reserves
Identify
Source Rock
“Proof of
Concept”
Horizontal
Multi-Stage
Evaluate
Geochemical
Data and Trap
Production
Test
Estimate
EUR’s
99
La Luna Resource Play (EIA)
Approximate location of
VMM 9
No direct geochemical data
100
Veracruz Fault Section
Proposed 3D ~350km2
Lead 1
La Luna
Resource Play Area
Lead
2
Lea
d3
Lead 7
Lead 4
Lead 6
Lead 5
Lead
11
Lead
10
Lead 9
Lead 8
Lead
13
Lead
12
101
VMM 9 Prospective Shale Area
Approximately 100 Sq. Miles
(64,000 acres or 2 townships) is
prospective for the Cretaceous
Resource Play
La Luna
Resource Play Area
102
Parex Exploration Portfolio Summary
1. Solid portfolio of low-to-moderate risk exploration
prospects in core Casanare region through 2016
Upside potential on emerging combination and stratigraphic
plays
2. Current focus on expanding portfolio to New Basins
containing larger moderate and high risk opportunities
3. Established material land position in two
Non-Conventional Plays:
Lower Gacheta play in the Llanos
La Luna play in the Mid Mag
103
Operating in Colombia
Lee DiStefano
President/Country Manager
104
Trending Topics
1. Requirement for increased production
2. Increased community disruptions
3. Environmental records
4. Permitting hurdles
5. Security
6. Marketing & Transportation
105
Lower oil prices require incremental
production to maintain balance
106
Existing royalty distribution leads to
social unrest and industry disruptions
•New distribution to double returns to Casanare and Meta
•Intent to reduce social delays
107
Action to reduce environmental permitting
time, expedite the license process
Licensing period to be reduced to 5 months from current 14 months average
108
Parex Average Licensing Time is 9 months
Parex submits quality applications:
no license applications have been rejected
109
Environment Record of Colombia Operators
Industry leading health & safety transportation performance
Parex
110
CSR: Our Process
1. Work with community through numerous consultations
• Regular senior management presence in field
2. Work with local government, communities and land owners to address
their concerns:
a) Perceived environmental damage to local water sources
b) Damage to road surfaces during mob-demob of operations
3. Give-back to communities for social development
111
Community Engagement
Presentation of the project to the land
owners of La Graciela Village
Tour in the paved route with
representatives from the mayor and
community leaders
03-06-2014
Presentation of the project to the local
authorities of Aguazul 04-05-2014
Presentation “EIA” Llanos 26 with
Aguazul authorities04-07-2014
112
Stephen Benoit
Andean Region Rep
Export Dev. Canada
Canadian Ambassador to Colombia
Carmen Sylvain
Mayor Eduardo Duarte
San Luis de Palenque
“Personalize the relationships, not the differences among us”
113
Parex Security Support
Private Security
K9 SUPPORT WHEN
NECCESARY
PREVENTIVE MOBILE
SURVEILLANCE
EARLY WARNING
SYSTEMS
SECURITY GUARDS AND
ACCESS CONTROL
CONTROL AND
COMMUNICATIONS CENTER
GPS BASED LOCATION MONITORING
ELECTRONIC
SURVEILLANCE
CONTROL THE FLOW OF PEOPLE
AND GOODS
114
Marketing
Transportation
115
Marketing Distribution 2014: 26K BOPD via
Ocensa
Costa
Crude Type
Color
Light
Heavy
Blend
Vasconia
Aguazul Blending
Station
LIGHT OIL
•
Central Blending Station
(Aguazul) 12Kbopd capacity
operational March 2014.
Expanding to 17K bopd in
2015
•
Good heavy crude (<18 API)
contracts in Guaduas &
Vasconia
•
BiCentenario NOT dependable
(due to Cano Limon bombings)
• Send or pay contract
creates Ocensa access for
Parex
Monterrey/Cusiana
Guaduas
La Casona Blending Station
HEAVY OIL
Akira Blending Station
Babillas
116
Marketing Distribution 2015 Initiatives
Capachos
Tie-in (4 km) to OBC
Aguazul Blending and
Tie-in (1 km) to Ocensa
Carmentea Blending &
Tie-in (10 km) to ODL
Flow line Akira/Tigana/Carmentea
117
Wrap-Up: 2015 Key Deliverables
1. Expand reserves and understanding of the
emerging stratigraphic plays
2. Invest in Magdalena Basin with objective to:
• Establish production and reserves in 2015
• Develop drilling inventory for 2016
3. Focus on cash costs and capital efficiencies to
drive balance sheet strength:
a) Transportation; b) opex; c) drilling capex
118
Parex Value Proposition
1. Structured with financial strength to succeed in a low price environment
2. Built an opportunity portfolio based on option value. We can:
a) maintain or grow at development risk; and/or
b) invest in new plays to increase production and/or extend RLI
according to prices and market signals
3. Positioned to access significant opportunities to expand our opportunity
base
4. Ability to combine opportunities and financial capability with the people
to make it work - this is not a one man or a five man enterprise
119
Forward-Looking Statements and FOFI
This presentation and its contents are confidential and may not be reproduced or forwarded to any other person, or published (in whole or in part) for any purpose. This presentation is provided for
informational purposes only as of the date hereof, is not complete, and may not contain certain material information about Parex Resources Inc. ("Parex" or the "Company"), including important disclosures and risk factors
associated with an investment in Parex. This presentation does not take into account the particular investment objectives or financial circumstances of any specific person who may receive it.
Certain information regarding Parex set forth in this document contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words "plan", "expect",
“prospective”, "project", "intend", "believe", "should", "anticipate", "estimate" or other similar words, or statements that certain events or conditions "may" or "will" occur are intended to identify forward-looking statements.
Such statements represent Parex' internal projections, estimates or beliefs concerning, among other things, future growth, results of operations, production, future capital and other expenditures (including the amount,
nature and sources of funding thereof), plans for and results of drilling activity, business prospects and opportunities. These statements are only predictions and actual events or results may differ materially. Although the
Company’s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations
are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Parex' actual results to differ materially from those expressed or implied
in any forward-looking statements made by, or on behalf of, Parex.
In particular, forward-looking statements contained in this document include, but are not limited to, statements with respect to the performance characteristics of the Company's oil properties; the Company's vision,
strategy and values; Parex' estimated year end production for 2014; the Company's anticipated 2015 capital investment program, including the amount thereof; the Company's 2015 capital budget, including the expected
allocation of such budget to the number of wells and capital expenditures for each of development/appraisal in existing fields, exploration, exploration appraisal and new play concepts; the Company's forecasted 2015
average production range; the Company's planned capital program, including anticipated amounts focused on existing discoveries and the appraisal programs and the timing of drilling key exploration prospects, seismic
programs and development drilling; anticipated cash flow, cash flow per share and funds flow from operations for 2015; the Company's exploration, development and appraisal program for 2015, including anticipated
number of wells, drill ready prospects, the focus of development/appraisal drilling and the potential for drilling of additional follow-up appraisal wells and facilities in 2015; exploration prospects; the Company's exploration
schedule; the Company's production forecast and CAGR from 2014 to 2019; the Company's drilling plans and production capability/potential at Akira; anticipated drilling locations , timing of completion of facility and
production potential at Tua; the Company's delineation and drilling plans at Tigana; the Company's plans for LLA-26; the Company's plans to target additional growth opportunities; Parex' anticipated debt levels; financial
and business prospects and financial outlook; and activities to be undertaken in various areas. Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment,
based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future.
These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to, the impact of general economic conditions in Canada and Colombia; industry conditions including changes in
laws and regulations including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced, in Canada and Colombia; competition; lack of availability of qualified personnel;
the results of exploration and development drilling and related activities; risks related to obtaining required approvals of regulatory authorities, in Canada and Colombia and partner and community approvals in Colombia;
risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities; volatility in market prices for oil; fluctuations in foreign exchange or interest rates;
environmental risks; changes in income tax laws, tax rates and/or incentive programs relating to the oil industry; changes to pipeline capacity; ability to access sufficient capital from internal and external sources; risks
related to the lawsuit brought in Texas against Parex and certain foreign subsidiaries; failure of counterparties to perform under the terms of their contracts; and other factors, many of which are beyond the control of the
Company. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could effect Parex' operations and financial results are included in reports on file
with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
Although the forward-looking statements contained in this document are based upon assumptions which Management believes to be reasonable, the Company cannot assure investors that actual results will be consistent
with these forward-looking statements. With respect to forward-looking statements contained in this document, Parex has made assumptions regarding, among other things: current commodity prices and royalty regimes;
availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the price of oil, including the anticipated Brent oil price; the impact of increasing competition; conditions in general economic
and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; receipt of partner, regulatory and community approvals; royalty rates; future operating costs; effects of
regulation by governmental agencies; uninterrupted access to areas of Parex' operations and infrastructure; recoverability of reserves and future production rates; the status of litigation; timing of drilling and completion of
wells; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; that Parex will have sufficient cash flow, debt or equity sources or other
financial resources required to fund its capital and operating expenditures and requirements as needed; that Parex' conduct and results of operations will be consistent with its expectations; that Parex will have the ability
to develop it's oil and gas properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that
the estimates of Parex' reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that Parex will be able to obtain contract extensions
or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; and other matters.
Management has included the above summary of assumptions and risks related to forward-looking information provided in this document in order to provide shareholders with a more complete perspective on Parex'
current and future operations and such information may not be appropriate for other purposes. Parex' actual results, performance or achievement could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits Parex will derive.
These forward-looking statements are made as of the date of this document and Parex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future
events or results or otherwise, other than as required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified by this cautionary statement.
This document contains Future Oriented Financial Information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by Parex’s management to provide an outlook of the Company's
activities and results. The FOFI has been prepared based on a number of assumptions including the assumptions discussed above and assumptions with respect to the costs and expenditures to be incurred by the
Company, capital equipment and operating costs, foreign exchange rates, taxation rates for the Company, general and administrative expenses and the prices to be paid for the Company's production. Management does
not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI or assurance that such operating results will be achieved and, accordingly, the complete
financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results will likely vary from the
amounts set forth in the analysis presented in this presentation, and such variation may be material. The Company and its management believe that the FOFI has been prepared on a reasonable basis, reflecting the best
estimates and judgments, and represent, to the best of management's knowledge and opinion, Parex's expected expenditures and results of operations. However, because this information is highly subjective and subject
to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Parex undertakes no obligation to update such
FOFI and forward-looking statements and information.
120
Forward-Looking Statements and FOFI
Oil and Gas Information
The estimates of Parex' June 30, 2014 reserves set forth in this presentation have been prepared by GLJ Petroleum Consultants Ltd. ("GLJ") as of June 30, 2014 with a preparation date of July 10, 2014 in accordance with
National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluations Handbook (the "COGEH") and using GLJ's forecast prices and costs as at June 30,
2014. The estimates of Parex' December 31, 2013 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2013 with a preparation date of February 20, 2014 in accordance with NI 51-101
and the COGEH and using GLJ's forecast prices and costs as at January 1, 2014. The estimates of Parex' December 31, 2012 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2012
with a preparation date of February 28, 2013 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2013. The estimates of Parex' December 31, 2011 reserves set forth
in this presentation have been prepared by GLJ as of December 31, 2011 with a preparation date of [], 2012 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2012.
The estimates of Parex' December 31, 2010 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2010 with a preparation date of [], 2011 in accordance with NI 51-101 and the COGEH
and using GLJ's forecast prices and costs as at January 1, 2011. The estimates of Parex' December 31, 2009 reserves set forth in this presentation have been prepared by GLJ as of December 31, 2009 with a preparation
date of [], 2010 in accordance with NI 51-101 and the COGEH and using GLJ's forecast prices and costs as at January 1, 2010.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved
plus probable plus possible reserves.
Estimates of the net present value of the future net revenue from Parex' reserves do not represent the fair market value of Parex' reserves. The estimates of reserves and future net revenue from individual properties or
wells may not reflect the same confidence level as estimates of reserves and future net revenue for all properties and wells, due to the effects of aggregation. In this presentation NPV10 represents the net present value of
net income discounted at 10% and NPV20 represents the net present value of net income discounted at 20%.
"BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf: 1 bbl) is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the
energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
All of Parex’ crude oil reserves are located in Colombia’s Llanos Basin. The Company does not have any heavy oil, coalbed methane or natural gas liquid production or reserves and had an immaterial amount of natural gas
reserves. The recovery and reserve estimates of crude oil reserves provided in this document are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may
eventually prove to be greater than, or less than, the estimates provided herein. All evaluations and reviews of future net revenue contained in GLJ's reports are stated prior to any provision for interest costs or general and
administrative costs and after the deduction of royalties, development costs, production costs, well abandonment costs and estimated future capital expenditures for wells to which reserves have been assigned.
Unless otherwise expressly stated, the information in this presentation pertaining to future drilling locations or drilling inventories is based solely on internal estimates made by management and such locations have not
been reflected in any independent reserve or resource evaluations prepared pursuant to NI 51-101. Similarly, unless otherwise expressly stated, the information in this presentation pertaining to targeted reserve volumes
from future drilling is intended to indicate that in making its internal drilling decisions, the Company seeks to target drilling locations that, based on previous drilling results and its own internal assessments, it believes will on
average ultimately generate the indicated volumes.
Certain information in this document may constitute "analogous information" as defined in NI 51-101. Such information includes production estimates, drilling results, test rates, reserves estimates and other information
retrieved from the continuous disclosure record of certain industry participants from www.sedar.com or other publically available sources. Management of Parex believes the information is relevant as it may help to define
the reservoir characteristics and production profile of lands in which Parex may hold an interest. Parex is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor and is
unable to confirm that the analogous information was prepared in accordance with NI 51-101. Such information is not an estimate of the production, reserves or resources attributable to lands held or to be held by Parex
and there is no certainty that the production, reserves or resources data and economic information for the lands held or to be held by Parex will be similar to the information presented herein. The reader is cautioned that the
data relied upon by Parex may be in error and/or may not be analogous to such lands held or to be held by Parex.
Certain other information contained in this presentation has been prepared by third-party sources, which information has not been independently audited or verified by Parex. No representation or warranty, express or
implied, is made by Parex as to the accuracy or completeness of the information contained in this document, and nothing contained in this presentation is, or shall be relied upon as, a promise or representation by Parex.
This presentation contains references to type well production and economics, which are derived, at least in part, from available information respecting the well economics of other companies and, as such, there is no
guarantee that Parex will achieve the stated or similar results, capital costs and return costs per well.
References in this presentation to initial production test rates, initial "flow" rates, initial flow testing, and "peak" rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the
rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered "load oil" fluids used in
well completion stimulation. While encouraging, investors are cautioned not to place reliance on such rates in calculating the aggregate production for Parex. Parex has not conducted a pressure transient analysis or welltest interpretation on the wells referenced in this presentation. As such, all data should be considered to be preliminary until such analysis or interpretation has been done.
Other Matters
This presentation is provided for informational purposes only and does not constitute an offer to sell or a solicitation of an offer to buy any security in Canada, the United States or any other jurisdiction. Parex does not
intend to solicit and is not soliciting, any action with respect to any security or any other contractual relationship with Parex.
The contents of this presentation have not been approved or disapproved by any securities commission or regulatory authority in Canada, the United Sates or any other jurisdiction, and Parex expressly disclaims any duty
on Parex to make disclosure or any filings with any securities commission or regulatory authority, beyond that imposed by applicable laws. The contents of this presentation are neither sufficient for, nor intended by Parex to
be used in connection with, any decision relating to the purchase or sale of any existing or future securities. Parex does not intend to provide financial, investment, tax, legal, or accounting advice. Persons considering the
purchase or sale of any securities should consult with their own independent professional advisors.
121

2014 Parex Investor Day: Bogota

Transcription

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