Solid Foundation
Building New Platforms
www.parexresources.com | TSX:PXT
Corporate Presentation | February 2017
Corporate Snapshot
OPERATING RESULTS
2016E
2017E
Production (bopd) Full Year
~29,715
34,000-36,000
US $110-$120
US $200-$225
Exploration Drilling (# prospects)
5
14
Appraisal (# wells)
4
13-18
Development Drilling (# wells)
6
14
Capital Expenditures(1) (million)
RESERVES (2016 Year End)
2P Reserves (Dec. 31)(2)
2P Reserve Life Index (RLI)
112 Mmboe
10 years
CAPITAL STRUCTURE
Net Working Capital(3)
US $175MM Credit Facility
Market Capitalization(4)
~US $93 MM
Undrawn – No Debt
~ CAD $2.5 Billion
Common Shares Outstanding (TSX listed)
Basic(5)
Fully Diluted(6)
(1)
(2)
(3)
(4)
(5)
(6)
153 MM
163 MM
Assuming $50/bbl Brent oil price in 2017
Parex’ working interest, as per the independent reserve reports prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2016
Company’s unaudited estimate at December 31, 2016
Assuming $16 share price
As at December 31, 2016
Diluted shares include the effects of common shares and in-the-money stock options outstanding at December 31, 2016; closing stock price at the end of the period was C$16.90.
Corporate Presentation | February 2017
2
2017 Guidance: Cash Flow Funded Growth
Assumptions
Oil (Brent)
FFO netback
Production
US $50/bbl
US $17/boe
34,000-36,000 bopd
Capital Expenditure
US $200-225MM
FFO
US $211-223MM
YOY Production growth/share
Annualized CF/Basic Share
Exploration
Capex
Maintenance
Capex
16-21%
US $1.42 (C$1.92)
14 wells
2,000-3,000
boe/d
$85-90MM
Capex
Allocation
14 wells
30,000 boe/d
$45-55MM
Appraisal
Capex
13-18 wells
2,000-3,000 boe/d
$70-80MM
Corporate Presentation | February 2017
3
2017 Drilling Program
Basin & Block
H1/2017
H2/2017
Total Wells
Exploration Dev/Appraisal Exploration Dev/Appraisal
Llanos
LLA-34
Capachos
Other Llanos
5
3
4
1
-
2
-
8
2
2
19
3
5
Magdalena
Aguas Blancas
VMM-11
Other Magdalena
2
-
9
-
1
1
1-6
-
10-15
3
1
Total
10
14
4
13-18
41-46
Corporate Presentation | February 2017
4
Parex Cash Netback*
2017 Target Cash Netbacks
$55
Realized Price (USD/boe)
$50
$45
$40
$35
$30
Brent
$45.12
($7.5)
($4.9)
Brent
$45
Transportation
($11.2)
G&A-Fin.
($4.9)
Tax ($1.5)
$20
($4.3)
($0.5)
$10
$0
Royalties
($3.4)
Brent
$50
($3.2)
($11.6)
$5
Differential
($6.3)
Brent
$55
Opex
($4.9)
$25
$15
Brent
$51.13
Cash
Netback
$13.2
2016FY Est.**
Cash
Netback
$18.9
Q4 2016 Est**
Note:
* cash netback is defined as funds flow from operations
* *Company’s unaudited expected results
$14
$17
$20
2017 Guidance
(excluding hedges)
Corporate Presentation | February 2017
5
Consistent Growth: Path to 50,000 Barrels
40
Average Daily Production
(Mboe/d)
36
34,000-36,000
32
29,715
28
27,434
24
22,526
20
16
15,854
12
8
11,407
4
0
2012
2013
2014
2015
2016E
2017E
Q1 2017 Guidance 32,000 boe/d
Corporate Presentation | February 2017
6
Solid Foundation Supports Growth
Track record of progressing reserves* from 3P to cash flow
Proved +Probable
+ Possible
Proved + Probable
Proved
(mmboe)
(mmboe)
(mmboe)
Annual
Production
2P Reserve
Life Index
(mmboe)
based on annualized
Q4 Production
31-Dec-11
18
11
5
2
3 years
31-Dec-12
23
16
10
4
4 years
31-Dec-13
50
32
17
6
5 years
31-Dec-14
104
68
40
8
7 years
31-Dec-15
125
82
46
10
8 years
31-Dec-16
169
112
64
11
10 years
31-Dec-15
31-Dec-16
Gross 2P Development
Locations (#)
102
157
FDC ($US MM)
318
347
99% oil
*Per the independent reserve reports prepared by GLJ Petroleum Consultants Ltd. effective December 31 of the reported year
Corporate Presentation | February 2017
7
Conventional Oil Reserves: Industry Leading Results
$18
FD&A $/boe
*
2016
PDP
1P
3 Year
2P
2P
$6.53
$7.02
$3.43 $7.70
Recycle Ratio
PDP
1P
2P
2P
FD&A
2.8x
2.6x
5.4x
2.5x
Per the independent reserve reports prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31, 2014; Dec. 31, 2015 and Dec. 31, 2016,
including Future Development Cost (FDC). Recycle Ratio is calculated using unaudited Q4 2016 Funds Flow from Operations per barrel
divided by annual F&D or FD&A, except for 3 Year which uses 3 year average funds flow from operations
$15
2P FD&A (USD/boe)
Total Company*
$12
$9
$6
$3
$0
2014
1 Year $/boe
2015
2016
3 Year $/boe
Corporate Presentation | February 2017
8
Southern Llanos: Foundation for Growth
FAULTS
Cabrestero (100% WI, Operator)
Akira: swing producer
Bacano-2 producing ~500 bopd
Added 2 appraisal wells in H1/17
Carmentea
GLJ 3P (YE 2016)
New Pads
LLA-32
Calona
Kananaskis
Max
Chachalaca
Chiricoca
LLA-34
Tilo
Tigana
LLA -34 (55% WI, Non-operated)
Chiricoca-1 exploration discovery (Mirador)
Drill 7 exploration wells and 12
development wells in 2017
Objective in 2017 to test extent of JacanaTigana trend to South West
Tarotaro
Tua
Jacana
Aruco
Akira
Bacano
Cabrestero
As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31/16
Explore core position, appraise & develop discoveries, and
leverage Parex’ costs and exploration strengths
Corporate Presentation | February 2017
9
Block LLA-34: Test Extent & Field Development
2017 Exploration
2017 Appraisal
2017 Dry Season Pads
Guadalupe Stratigraphic Edge
CHIRICOCA
Tarotaro
Field
(Parex’ WI)
Tigana
Year End
Tua
SINSONTE
Aruco
Jacana
CURUCUCU
JACAMAR
Jacana Sur-2
Jacana Sur-1
LLA-34
Jacana-12
Jacana-11
Bacano 3
Bacano
GLJ 3P Reserves
(MMBO)
GLJ 2P Reserves
(MMBO)
2015
2016
2015
2016
Tigana Guadalupe
41
51
28
34
Jacana Guadalupe
14
45
5
30
Other LLA 34
41
33
27
23
LLA 34 TOTAL
96
129
60
87
Cabrestero
8
18
6
11
Akira
2015 GLJ 3P Outlines
2016 GLJ 3P Outlines
Cabrestero
As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31, 2016
Corporate Presentation | February 2017
10
Tigana Guad Trend – Production History
5,000
Producing Day BOPD
4,500
Tigana-4
4,000
Jacana-1
Jacana-5
Tigana Sur-1
3,500
3,000
IP Range: 500-3,500 bopd
Flat production profile
Low decline
Tigana Norte-1
Jacana-4
2,500
Tigana-3
Jacana-2
2,000
Trend Average
1,500
Tigana Sur-2
1,000
Tilo-1
Jacana-3
Tigana Sur Oeste-1
Tilo-2
500
Jacana-6
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Producing Months
As per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective Dec. 31/16
Corporate Presentation | February 2017
11
Capachos Development & Exploration Potential
2017 Plan
Guadalupe Depth Structure
o Drill 2 firm development wells (Capachos–2 &
Capachos Sur–2) to earn 50% in the block.
o Disposal well
o Development wells are targeting proven structural
compartments that have produced ~2 mmbbls.
o Targeting ~34 API Oil in the Guadalupe Formation.
Norteste-1 Exploration
Noreste
Norte-1 Exploration
Norte
Centro
Future exploration targets at Capachos Norte
and Capachos Noreste targeting the Guadalupe
and Une formations.
Sur
Capachos-2
Capachos Sur-2
Corporate Presentation | February 2017
12
Magdalena Basin: Next Growth Platform
2017 Activities
VIM-1
Aguas Blancas(1)
Light oil opportunity
Drill 10-15 wells
Playon(1)
Boranda-1: drilled & cased; ongoing testing Q1
VMM-11
3 exploration wells
De
Playon
Sogamoso
Mares(1)
Re-enter & test Coyote-1
VIM-1
Interpreting 525 km2 of new 3D seismic
1 exploration well
De Mares
Aguas Blancas
VMM-9
VMM-11
VMM-9
Environmental Impact Assessment underway
Acquire 290 km2 of 3D Seismic in 2017
(1) Farm-in
on Ecopetrol
Morpho
Pipeline
Oi fields
Gas fields
Corporate Presentation | February 2017
13
Aguas Blancas Objectives
1. Identify oil in place
2. Develop production strategy
3. Understanding waterflood potential
AB-5
1. Achieve Unstimulated IP Rates = 50-200 bopd
 Target stimulated rates 1.5x to 2x
2. Primary Recovery per well = 100 – 250 mbbls
3. Increase Recovery Factor from current primary of
10% to waterflood recovery > 25%
4. Demonstrate Development Phase Capital
 Per well cost: $1.2 million
 Fully loaded capex per producing well: $2.0 million
570’
Definition of Success
Drilled 1960
700’
2017 Program
AB-9
Drilled 2016
Mugrosa C Reservoir
Corporate Presentation | February 2017
14
Aguas Blancas: Identifying Reserve* Potential
Drilled
Footwall
“B” Area
2P Area
(ac)
2P OOIP
(MMBO)
2P Reserves
(MMBO)
YE 2015
789
33.5
3.4
YE 2016
832
34.7
3.5
H1/2017 Location
H2/2017 Location
Legacy Wells
GLJ 2015 2P
AB-26
GLJ 2016 2P
Min Potential Area
Footwall
“C” Area
2P Area
(ac)
2P OOIP
(MMBO)
2P Reserves
(MMBO)
YE 2015
0
0
0
YE 2016
847
32.7
AB-14
Max Potential Area
AB-9
AB-32
AB-34
3.3
*2P Primary Recovery at 10%
AB-15
Total Field
Potential Area
(ac)
2P Area
(ac)
2P OOIP
(MMBO)
2P Reserves
(MMBO)
YE 2015
5800 - 8400
1055
40
YE 2016
5800 - 8400
2388
82
4
Hanging
Wall Area
2P Area
(ac)
2P OOIP
(MMBO)
2P Reserves
(MMBO)
8.2
YE 2015
266
6.5
0.7
YE 2016
709
14.7
1.5
Prospective Resource Area
* Per the independent reserve report prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2016
Corporate Presentation | February 2017
15
Transportation
Trucking
Parex Blocks
Pipeline
River
Parex’ Transportation Alternatives:
1. Export Cargo – 60% Volume
Barranquilla
Cartagena
TERMINAL COVENAS
Truck/Pipeline – Tender process
2. Magdalena River - 35% Volume
Truck/Barge
Wellhead sale to Trafigura
3. Casanare Refinery - 5% volume
Multiple Evacuation Routes
Surplus Take-away Capacity
Barrancabermeja
VASCONIA
HIDROCASANARE
CUSIANA
MONTERREY
Corporate Presentation | February 2017
16
Summary: Excel at What We Do
Core Competencies
1. Identify and acquire large
prospective resources.
2. Engage stakeholders.
3. Focus on being a low cost
operator.
Corporate Presentation | February 2017
17
Appendix – Block Summary
#
Block
Operated/Non-Operated
Working Interest
Partners
Gross Acres(1)
Basin
1
LLA-10
Operated
50%
Gran Tierra
189,544
Llanos
2
LLA-16
Operated
100%
N/A
11,736
Llanos
3
LLA-20
Operated
100%
N/A
2,891
Llanos
4
LLA-24
Operated
100%
N/A
147,100
Llanos
5
LLA-26
Operated
100%
N/A
184,061
Llanos
6
LLA-29
Operated
100%
N/A
69,915
Llanos
7
LLA-30
Operated
100%
N/A
117,322
Llanos
8
LLA-32
Operated
70%
Geopark & Pluspetrol
57,040
Llanos
9
LLA-34
Non-Operated
55%
Geopark
68,382
Llanos
10
LLA-40
Operated
50%
Pluspetrol
83,465
Llanos
11
LLA-57
Operated
100%
N/A
52,285
Llanos
12
Cabrestero
Operated
100%
N/A
29,562
Llanos
13
Capachos(2)
Operated
50%
Ecopetrol
64,073
Llanos
14
Cebucan
Operated
100%
N/A
109,185
Llanos
15
Cerrero
Operated
100%
N/A
83,903
Llanos
16
El Eden
Operated
100%
N/A
6,397
Llanos
17
Los Ocarros
Operated
100%
N/A
31,066
Llanos
18
VIM-1
Operated
100%
N/A
223,651
Lower Magdalena
19
Aguas Blancas(2)
Operated
50%
Ecopetrol
13,386
Middle Magdalena
20
De Mares(2)
Operated
50%
Ecopetrol
174,387
Middle Magdalena
21
Morpho(3)
Operated
100%
N/A
51,420
Middle Magdalena
22
Playon(2)
Operated
50%
Ecopetrol
43,200
Middle Magdalena
23
Sogamoso
Operated
100%
N/A
3,695
Middle Magdalena
24
VMM-9
Operated
100%
N/A
152,412
Middle Magdalena
25
VMM-11
Operated
100%
N/A
116,826
Middle Magdalena
1) Exploration properties deemed non-commercial will be relinquished in due course. Accordingly, the gross acres described above may decrease as non-commercial lands are relinquished
2) Working interests are subject to regulatory approval.
3) Morpho is subject to a 4% Net Profit Interest.
Corporate Presentation | February 2017
18
Appendix – Summary of Quarterly Results
(Unaudited Results)
2016
2015
2014
Q3
Q2
Q1
FY
Q4
Q3
Q2
Q1
FY
Q4
Q3
Q2
Q1
29.8
29.1
28.9
27.4
28.6
27.4
27.0
26.7
22.5
26.5
25.2
19.9
18.4
Brent Price ($/bbl)
Average realized prices, prior to hedging ($/boe)
Royalty ($/boe)
Opex ($/boe)
Transportation ($/boe)
Operating Netback ($/boe)
47
40
3
5
12
21
47
40
3
5
12
20
35
27
2
5
12
8
54
47
4
7
14
22
45
37
3
7
13
15
51
45
4
7
13
21
64
56
5
8
14
30
55
49
4
8
16
22
100
88
11
11
17
48
77
60
7
11
17
25
104
94
11
12
18
53
110
105
15
11
16
62
108
103
15
10
18
61
Funds Flow Netback ($/boe)
16
13
5
13
12
5
20
14
37
21
39
46
45
45
0.30
6.8
0.04
43
132
118
(118)
26
32
0.21
(0.2)
(0.00)
30
94
98
(98)
14
16
0.10
(8)
(0.05)
6
92
80
(80)
5
130
0.90
(45)
(0.31)
170
95
77
(77)
126
34
0.22
(4)
(0.02)
36
95
77
(77)
24
14
0.09
(27)
(0.18)
41
75
63
(63)
38
50
0.35
2
0.01
52
104
90
(90)
37
33
0.24
(16)
(0.12)
41
33
10
30
27
294
2.44
(109)
(0.90)
340
39
3
32
297
50
0.37
(147)
(1.09)
45
39
3
32
84
89
0.70
17
0.13
114
34
45
(3)
57
77
0.70
11
0.10
84
63
31
110
95
77
0.70
10
0.09
97
40
37
52
62
153
152
152
145
151
150
144
135
120
135
126
111
109
17.40
12.00
16.65
547
14.61
10.50
12.51
678
11.96
7.73
10.95
970
11.55
5.97
10.16
821
11.55
9.07
10.16
729
10.57
7.15
9.25
742
11.10
8.05
10.47
906
9.24
5.97
8.07
907
15.49
6.07
7.58
872
12.88
6.07
7.58
1,140
15.49
11.98
12.45
982
13.25
9.33
12.55
808
9.50
6.57
9.50
553
OPERATING
Production (thousands of boe/d)
FINANCIAL
(millions of USD, except per share amounts)
Funds flow from operations
Per share – basic
Net income (loss)
Per share – basic
EBITDA
Cash and cash equivalents
Working Capital
Net Debt (Surplus)
Capital Expenditures
Weighed average shares outstanding
TRADING STATISTICS (CAD) – PXT
(based on intra-day trading)
High
Low
Close (end of period)
Average daily volume (thousands)
Notes:
•
•
Per boe and per boe figures have been round up or down to the nearest dollar
Net Debt is defined as Bank Debt + Convertible Denture Face Value ( C$ 85 million) - Working Capital. Current Borrowing limit of US $175 million ($200 million at March 31, 2016 and December 31, 2015; $175 million at December 31, 2014). convertible debentures with a face value of Cdn$85 million with a conversion
price of Cdn$10.15 per share were fully redeemed on September 25, 2014.
Corporate Presentation | February 2017
19
Colombia – Current Land Base
LOWER
MAGDALENA
Corporate Presentation | February 2017
20
Legal Advisory
Certain statements in this document are “forward-looking statements”. Forward-looking statements are frequently characterized
by words such as “prospective”, “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “forecast”, or other similar
words, or statements that certain events or conditions “may” or “will” occur. Forward-looking statements are not based on
historical facts but rather on the expectations of management of the Company ("Management") regarding the Company's future
growth, results of operations, production, plans for and results of drilling activity, business prospects and opportunities. Such
forward-looking statements reflect Management's current beliefs and assumptions and are based on information currently
available to Management. In particular, this document contains forward-looking statements regarding, but not limited to, the
Company's expected production rates and Parex' drilling plans. Forward-looking statements involve significant known and
unknown risks and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in
the forward-looking statements including the risks associated with negotiating with foreign governments as well as country risk
associated with conducting international activities, competition, the ability to generate revenue and exploit operating margins,
capital resources, the use of certain technologies and materials, annual impairment tests, labour relations, insurance, damage
from weather and other disasters, operating and maintenance risks and environmental risks, new information regarding
reserves, changes in demand for and volatility of commodity prices of oil and natural gas, failure to receive all required regulatory
approvals for acquisition, the risk that the acquisition may not be completed as contemplated or at all, legislative, regulatory and
political changes, the risks discussed under "Risk Factors" in Parex' annual information form (“AIF”) and other factors, many of
which are beyond the control of the Company. The risks outlined should not be construed as exhaustive. Although the forwardlooking 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. These forwardlooking statements are made as of the date hereof, and the Company assumes no obligation to update or revise them to reflect
new events or circumstances, except as required by law.
Statements relating to “reserves” are by their nature forward-looking statements, as they involve the implied assessment, based
on certain estimates and assumptions that the reserves described can be profitably produced in the future. With respect to
forward-looking statements contained in this presentation, the Company has made assumptions regarding: future exchange
rates; the price of oil and natural gas; the impact of increasing competition; conditions in general economic and financial
markets; availability of equipment; availability of skilled labour; current technology; cash flow; commodity prices; production
rates; timing and amount of capital expenditures; royalty rates; effects of regulation by governmental agencies; future operating
costs; receipt of all required regulatory approvals for the acquisition; successful completion of the acquisition; and the
Company's ability to obtain financing on acceptable terms. Management has included the above summary of assumptions and
risks related to forward-looking information provided in this presentation in order to provide shareholders with a more complete
perspective on the Company's future operations and such information may not be appropriate for other purposes.
How to Reach Us
Parex Resources Inc.
2700 Eighth Avenue Place, West Tower
585 8th Av SW Calgary
AB T2P 1G1 Canada
Tel: 403-265-4800
Fax: 403-265-8216
Email: [email protected]
Website: www.parexresources.com
Mike Kruchten
Vice President, Corporate Planning & Investor Relations
This is not an offer to sell or a solicitation of an offer to purchase securities by Parex. Before making an investment, investors
should refer to the Offering Documents for more complete information, including investment risks, fees and expenses and should
also thoroughly and carefully review Parex' public disclosure documents available on SEDAR at www.sedar.com with their
financial, legal and tax advisors to determine whether an investment is suitable for them.
Corporate Presentation | February 2017
21