GTE - Investor Village

Transcription

Research Report – June 10, 2013
Gran Tierra Energy Inc. (GTE-T, C$6.53)
Rating
Target Price
Return
Buy
C$9.25
42%
Alan Knowles, CFA, CMA403-509-1931[email protected]
(+$1.25)
Analyst Certification: See page 33; Important Information and Legal Disclaimers: See page 32
Bretana – A Potential Company Maker
Overall Risk Rating
Medium High
Forecast Risk
(Moderate) 5
Financial Risk
(Low) 2
Valuation Risk
(Moderate) 6
Political Risk
(High) 9
Risk Profile Definitions: See page 34
Valuation  Our target price of C$9.25 represents a 6.7x multiple to our 2013F and
6.2x to 2014F diluted CFPS and provides for an EV/DACF multiple of 5.8x relative to
C$6.94/C$4.10 2013F and 5.1x to 2014F.
19% Impact – Positive  While there is work to be done to firm up development plans
N/A
for Bretana, the Company has already stated that Bretana is a commercial discovery.
282M (basic)/
52-Week High/Low
YTD Performance
Dividend Yield
Shares O/S
298M (F/D)
Market Capitalization
$1.8B
Working Capital
$0.2B
Debt, including convertible
$0.0B
Net Working Capital
$0.2B
Enterprise Value
$1.6B
Daily Volume
996,000
Currency
US$ unless noted
Company Profile
Website – www.grantierra.com
CEO – Dana Coffield
About the Company – Gran Tierra is a South
American oil and gas exploration company.
It holds interests in producing and
exploration assets in Colombia, Peru, Brazil
and Argentina.
Estimates
Prod'n - boe/d
% Liquids
CFPS - diluted $C
P/CF
EV/DACF
Capex E&D US$mm
Debt/CF
Net Debt (Cash)
EPS - diluted
CFPS - basic
Cash Flow ($mm)
Event  The Bretana discovery in Peru has potential to more than double the
reserves of Gran Tierra. Following a field trip to Peru, we have provided a detailed
review of the discovery and the potential impact to Gran Tierra.
2012
2013F
2014F
'14/'13
23,610
28,295
29,053
3%
97%
98%
98%
0%
$1.14
5.7x
0.0x
313.2
n/m
(220.3)
$0.35
$1.15
$1.39
4.7x
3.9x
363.0
n/m
(305.4)
$0.63
$1.39
$1.50
4.4x
3.3x
380.0
n/m
(417.9)
$0.71
$1.52
8%
-7%
-15%
5%
324
394
430
9%
12%
9%
Price Performance (C$)
 Discovery Already Commercial – Based on the available data, Gran Tierra
believes the 18.5° API discovery (which meets pipeline specs) is already
commercial. Subject to results from the long term production test and appraisal
drilling, the Company believes the Bretana discovery is potentially at the high end
of the June 2012 resource estimate which was: 1C – 11.5 mmbbls; 2C - 31.6
mmbbls; 3C - 88.1 mmbbls. The mid case (2C) represents 43% of the YE12 2P
booked reserves, and the high case (3C) 121%.
 First Production by H2/17 – An early production scenario for Bretana would see
the 2014 long term test produce 2,500 to 3,000 bbls/day; a test of the appraisal
well would follow in 2015; first production of approximately 10,000 bbls/day
would commence in H2/17 and sustainable (five to six years) peak production of
40,000 bbls/day would commence in 2020.
 Netbacks Strong and CF Impact Material – Netbacks would be $51 to $55 per bbl
assuming Brent of $100. 10,000 bbls/day would add, on a proforma basis for
illustrative purposes, 50% to our 2014F CFPS, and at 40,000 bbls/day, 185%. Even
after tax (which wouldn’t initially be the case given the capital expenditures) the
increase would be 35% and 130%, respectively.
 Forecast – We have included net operating revenue from the planned long term
test of Bretana in 2014 (and smaller updates), resulting in our CFPS increasing to
$1.50 (diluted) from $1.39 previously.
 Target Price & Rating – We maintain our Buy rating, and increase our target price
to C$9.25 from C$8.00 previously.
Risks  Gran Tierra has an overall Medium High risk rating. Country risk exposure as
it relates to disruptions in the OTA pipeline operations is the greatest risk we have
identified, however contingency marketing arrangements have resulted in the
Company recently being able to market all of its produced oil through trucking.
Catalysts  Drilling results from Moqueta 10 are expected in late June; Mayalito 1
will spud in June; Miraflor Oeste 1 will spud in early July; and horizontal drilling on
Brazil continues. The Company expects to release a resource/reserve update for the
Bretana discovery in Q4/13.
Source: Capital IQ and Haywood Securities
Member of the Canadian Investor Protection Fund
Please see rating structure, disclaimers, and notes on pages 32-35.
Gran Tierra Energy Inc. (GTE-T)
Gran Tierra Energy Inc.
Dividend:
6/10/13
TSX : GTE; AMEX: GTE
C$ 0.00
Price C$ 6.53
Target:C$ 9.25
The addition of Moqueta, an early discovery in a larger exploration program, supports the Company’s strategy. 2012 Brazil Reconcavo exploration could result in meaningful
growth for Gran Tierra.
Capital Structure (C$, mm's)
Price History
Alpha:
Investment Highlights
Shares O/S
Options
Warrants
• Acquistion of Petrolifera - In January 2011, Gran Tierra announced an offer to acquire all of the common shares of Petrolifera, which
• Strong Balance Sheet - Gran Tierra has consistently maintained a conservative balance sheet. At March 31, 2013 the Company had
net positive working capital of $246 million including $236 million in cash, and no debt outstanding.
had an all-in cost of US$195 million. Gran Tierra issued 18 million common shares and assumed US$41 million in net debt in connection
with this transaction.
• Presence in Peru - Gran Tierra has an interest in 3 blocks in the Maranon Basin of NE Peru and 2 blocks in the Ucayali Basin, all of
which could materially impact the Company with exploration success. The first exploration well, Kanatari 1, was drilled on Block 128 in
Q1/11 but did not encounter any hydrocarbons and was plugged and abandoned and the block was subsequently relinquished. The
Company is planning to drill one exploration well in Peru in 2013, Bretana Norte, on Block 95, which was successful.
• Brazil Farm-In - In August 2010, the Company farmed in to four exploration blocks located in the onshore Reconcavo Basin of Brazil
and in September 2011 farmed in to two offshore blocks in the Camamu-Almada Basin. In December 2011 the first well was drilled on
the offshore block, BM-CAL-10, but was dry and abandoned, and it relinquished its interest in that block. A well on the second offshore
block is not expected until late 2013. Onshore in the Reconcavo Basin the blocks have the potential to be a meaningful resource
development play if early evaluation proves positive. Three more Reconcavo blocks were acquired in the 2013 bid round.
• Moqueta Discovery - At YE12 the Moqueta discovery had been assigned net 3P reserves of 19.9 mmbbls, up from 9.9 mmbbls at
YE11. Production from Moqueta is expected to increase in 2013/14, offsetting any declines from Costayaco and providing for a
continued stable production profile in Colombia.
% dil'n
5%
0%
5%
Fully Diluted
Liquidity (90dMA)
D&O % Owned
FMR
Amber Capital Mgmt
Market Capitilization
Net Debt (Wkg Cap)
Enterprise Value
282.2
15.4
0.0
15.4
297.6
996,000
2.6%
9.2%
7.0%
$1,842.8
($246.1)
$1,596.7
115%
-15%
100%
52 wk H/L
$6.95/$4.10
$7.00
Revenue - net royalties
Operating Costs
Net Operating Revenue
Cash Flow
D&D
Note: Based on gross sales production.
$67.00
$9.70
$57.30
$35.98
$25.98
$67.48
$14.45
$53.02
$37.46
$21.07
$71.88
$16.05
$55.83
$37.63
$21.83
$73.66
$16.52
$57.14
$38.87
$21.25
CFPS - US$
2013F
2014F
Cash Flow Sensitivity
WTI (US$1.00)
US/CD f/x
Oil (1,000 bbls/d)
Valuation Parameters
Price/CF - Basic
Price/CF - Diluted
Target Price/CF - Basic
Target Price/CF - Diluted
- CFPS for above calculation converted to C$
EV/DACF
Target EV/DACF
EV/boe/d (C$)
Target EV/boe/d (C$)
Prod/mm shs
2%
3%
2%
3%
-3%
($0.070)
($0.099)
($0.043)
-1.0%
-3.0%
0.9%
2011
2012
2013F
2014F
5.6x
5.8x
7.9x
8.2x
5.7x
5.7x
8.0x
8.1x
4.6x
4.7x
6.6x
6.7x
4.3x
4.4x
6.1x
6.2x
$67,626
$100,137
83.7
3.9x
5.8x
$56,430
$83,558
100.3
3.3x
5.1x
$54,957
$81,377
103.0
$6.00
Assumptions
2011
2012
2013F
WTI (US$/bbl)
Brent (US$/bbl)
F/X (US/CD)
$95.11
$111.05
$1.01
$94.15
$111.92
$1.00
$90.00
$105.00
$0.99
Revenue (US$mm's)
500
NPV10 Before Tax - ($mm)
Proved
2P
-4.6% 3P
-6.5%
-2.8% Contingent Resources (Block 95, Peru)
% Chg '14/'13 1C
-8%
2C
-7%
3C
-8%
-7%
$5.50
5.0
$5.00
4.0
$4.50
3.0
$4.00
2.0
$3.50
1.0
$3.00
Jun-12
Dana Coffield
James Rozon
Shane O'Leary
Duncan Nightingale
Julio Moriera
2014F % Chg '14/'13 Carlos Monges
$90.00
0%
Rafael Orunesu
$105.00
0%
$1.00
1%
40,000
$1.50
30,000
$1.00
20,000
Company Website:
Company Head Office:
2014F
2011
2,833
424
3,065
15
6,337
2011
2012 % Chg '12/'11
3,587
598
6,368
61
10,614
% of Total
27%
41%
108%
308%
67%
34%
6%
60%
1%
100%
2012 % Chg '11/'10 % Chg '12/'11
20%
21%
20%
14%
18%
-13%
5%
15%
0%
$180.6
76.0%
24.0%
76.5%
23.5%
80.8%
19.2%
1%
-2%
6%
-18%
1,127.5
1,573.0
2,513.0
1,418.1
1,632.6
2,284.9
26%
4%
-9%
-100%
-100%
-100%
11,500
31,600
88,100
n.m.
n.m.
n.m.
n.m.
n.m.
n.m.
President & CEO
CFO
COO
President, Colombia
President, Brazil
President, Peru
President, Argentina
2012
2013F
www.grantierra.com
403-265-3221
Jeffrey Scott - Chairman
Ray Antony
Dana Coffield
Verne Johnson
Nick Kirton
Gerry Macey
Scott Price
Analyst Ratings
Tgt: Rge. & Avg.
0
2013F
0.0
Jun-13
Mar-13
15%
-19%
3%
2%
3%
-10%
-3%
2%
-3%
10,000
2012
Dec-12
GLJ
37,171
14,922
52,093
20,608
72,701
38,603
111,304
56,296
86,989
Daily Production (boe/d)
$2.00
$0.00
2014F
Sep-12
Directors
-15%
-13%
-3%
-3%
3%
$0.50
0
2013F
Country Split - 2P Only
Colombia
Argentina/Other
Cash Flow per Share (US$)
1,000
6.0
50dMA
GLJ
31,021
12,347
43,368
18,068
61,436
44,547
105,983
48,915
86,558
Management
$65,488
$96,972
86.4
7.0
Price
Areas of Operation
% Chg CFPS
2013F
2014F
($0.015)
($0.043)
$0.012
8.0
Volume
$6.50
Colombia - The Costayaco discovery of mid 2007 is still the
Company's primary asset, with Moqueta providing increased
production stability in 2013/14.
• 2013 Guidance - Gran Tierra has announced planned capital expenditures in 2013 of $363 million. $224 million is allocated for drilling
Peru - The Bretana Norte exploration well on Block 95 was
up to 19 wells (16.3 net) including 6 development and 4 exploration wells in Colombia, 5 development and 1 exploration well in
successful setting up a multi-year development program of a
Argentina, 2 exploration wells in Brazil and 1 exploration well in Peru. 2013 gross production is expected to average 27,000 boe/d and
material, but not fully defined discovery. Other material
20,000 boe/d net after royalties.
Financial (US$mm's)
2011
2012
2013F
2014F % Chg '14/'13 prospects have been partially derisked by this discovery.
Brazil - Two wells are planned for the onshore blocks located in
Revenue, Net After Royalties
596.2
583.1
751.9
814.6
8%
the Reconcavo Basin ain 2013. The first offshore well was
Cash Flow
319.0
323.8
393.7
429.9
9%
drilled in December but was dry and abandoned.
CFPS Basic
$1.17
$1.15
$1.39
$1.52
9%
Argentina - 1 exploration and 5 development wells are planned
CFPS Diluted
$1.13
$1.14
$1.37
$1.50
9%
for 2013.
CFPS Basic ($CD)
$1.17
$1.15
$1.41
$1.52
8%
CFPS Diluted ($CD)
$1.13
$1.14
$1.39
$1.50
8%
Consensus
$1.39
$1.52
9%
Earnings
126.9
99.7
181.6
202.8
12%
Undeveloped Land
2010
EPS Basic
$0.46
$0.35
$0.64
$0.72
12%
(000's net acres)
EPS Diluted
$0.45
$0.35
$0.63
$0.71
12%
Colombia
2,125
EPS Basic ($CD)
$0.46
$0.35
$0.65
$0.72
11%
Argentina
1,077
EPS Diluted ($CD)
$0.45
$0.35
$0.64
$0.71
10%
Peru
5,545
Capital Expenditures - E&D
327.6
313.2
363.0
380.0
5%
Brazil
19
Reinvestment Ratio
1.0x
1.0x
0.9x
0.9x
-4%
Total
8,766
Capital Expenditures - incl. acq. & disp.
508.2
313.2
363.0
380.0
5%
Reserves (mboe)
2010 PF
Net Debt (Working Capital)
(210.4)
(220.3)
(305.4)
(417.9)
37%
Independent Engineers:
GLJ
Net Debt/CF
n/m
n/m
n/m
n/m
Proved Producing
27,002
Production
2011
2012
2013F
2014F % Chg '14/'13 Proved Non-Prod & PUD's
15,176
Colombia (bbl/day)
21,082
19,312
23,030
24,562
7%
Total Proved
42,178
Argentina / Brazil (bbl/day)
2,661
3,568
4,597
3,824
-17%
Probable
17,692
Total (bbls/day)
23,743
22,880
27,627
28,386
3%
2P
59,870
Argentina (mcf/day)
3,825
4,383
4,004
4,004
0%
Possible
49,411
Total (boe/day)
24,381
23,610
28,295
29,053
3%
3P
109,281
Total (boe/day) - Net After Royalties
17,408
18,071
22,751
24,760
9%
Net - 2P
47,911
Netbacks (US$/boe)
2011
2012
2013F
2014F % Chg '14/'13 Net - 3P
89,078
2012
Rating: Buy
Implied All-in Return: 42%
2014F
Sector Outperform
Sector Perform
Sector Underperform
Potential Upside
$6.00-$11.50
$9.43
No. Analysts
19
1
0
20
44%
Analyst: Alan Knowles, CFA, CMA - [email protected], 403-509-1931
Source: Gran Tierra and Haywood Securities
Page 2
6/10/13
Investment Thesis
Gran Tierra presents an opportunity to invest in a well-managed, focused, and disciplined South
American producer. The Company’s success at Costayaco, followed by Moqueta, has provided it with
the ability to deliver relatively static production out of Colombia at current rates for one more year,
and perhaps longer. While still in the preliminary evaluation stages, early indications from the
Bretana Norte discovery in Peru suggest that this could also become a meaningful contribution to
the Company’s production after 2013. Gran Tierra has established a multi-faceted opportunity base
including: exploration in Colombia and Peru; development in Colombia (Moqueta); exploitation in
Argentina (the Puesto Morales and Puesto Morales Norte fields); and a potential onshore resource
play in Brazil. We believe the depth of the opportunities, potential impact, and varied risk associated
with each represents a strong and valuable asset base for the Company.
Gran Tierra reports in US$. All amounts below are in US$ unless otherwise noted.
Gran Tierra follows the U.S. convention of reporting its production and reserves volumes after royalties
(Net After Royalties or NAR). Before royalty volumes, as per the Canadian convention, are also provided.
Risks
Significant Investment Risks
The investment to which this report relates carries various risks, which are reflected in our Overall
Risk Rating. We consider the following to be the most significant of these investment risks:
Gran Tierra’s primary producing operations are in the Putumayo Basin of Colombia. In the past the FARC have
attacked the primary pipeline in the area (OTA), which has in some cases resulted in the Company having to shut in
production for varying periods. To mitigate the exposure, partners in the pipeline have recently expanded the
storage capacity at the pipeline terminus. In addition, Gran Tierra has now been able to contract trucks on an asneeded basis (previously only available on a firm basis) which, while more expensive than transporting oil on a
pipeline, will allow the Company to continue producing and not have to shut in due to storage capacity
constraints.
Our Risk Profile Parameters ratings and Overall Risk Rating are set out on the cover page and are
explained in our Rating Structure section under “Overall Risk Rating” and “Risk Profile Parameters”.
These ratings are an integral part of our Report.
Page 3
6/10/13
Valuation
Commodity Price Sensitivity
Our target price of C$9.25 represents a 6.7x multiple to our 2013F and 6.2x to 2014F diluted CFPS
and provides for an EV/DACF multiple of 5.8x relative to 2013F and 5.1x to 2014F.
Gas Price ($US/mcf)
Gran Tierra - 2013F Cash Flow Sensitivity (C$ CFPS - Diluted)
WTI ($US/bbl)
$75.00
$80.00
$85.00
$90.00
$1.66
$1.17
$1.24
$1.31
$1.39
$2.16
$1.17
$1.24
$1.31
$1.39
$2.66
$1.17
$1.24
$1.31
$1.39
$3.16
$1.17
$1.24
$1.31
$1.39
$3.66
$1.17
$1.24
$1.31
$1.39
$4.16
$1.17
$1.24
$1.31
$1.39
$4.66
$1.17
$1.24
$1.31
$1.39
Gas Price ($US/mcf)
Gran Tierra - 2014F Cash Flow Sensitivity (C$ CFPS - Diluted)
WTI ($US/bbl)
$75.00
$80.00
$85.00
$90.00
$2.00
$1.26
$1.34
$1.42
$1.50
$2.50
$1.26
$1.34
$1.42
$1.50
$3.00
$1.26
$1.34
$1.42
$1.50
$3.50
$1.26
$1.34
$1.42
$1.50
$4.00
$1.26
$1.34
$1.42
$1.50
$4.50
$1.26
$1.34
$1.42
$1.50
$5.00
$1.26
$1.34
$1.42
$1.50
GTE-T, GTE-A
$95.00
$1.46
$1.46
$1.46
$1.46
$1.46
$1.46
$1.46
$100.00
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$1.53
$105.00
$1.61
$1.61
$1.61
$1.61
$1.61
$1.61
$1.61
GTE-T, GTE-A
$95.00
$1.58
$1.58
$1.58
$1.58
$1.58
$1.58
$1.58
$100.00
$1.66
$1.66
$1.66
$1.66
$1.66
$1.66
$1.66
$105.00
$1.74
$1.74
$1.74
$1.74
$1.74
$1.74
$1.74
Source: Haywood Securities
Net Asset Value
Gran Tierra’s current share price of C$6.53 approximately, but lower than the Core NAV on a proved
basis of $6.86. Given the Company’s strong balance sheet and asset base (nil to nominal decline
against the existing producing assets through 2014), and the Bretana discovery (which will take time
to more fully evaluate and bring on production, but is already considered a material commercial
discovery by the Company) the 2P Identified Exploration NAV of $9.17, and the Risked NAV of $9.77
(which includes a higher risked upside for Bretana, but we note not fully valued pending the results
of the long term production test and development plans), as detailed in the table below, present a
more realistic picture of the value of the Company.
We would also point out that historically the Company has successfully converted the possible
reserves (i.e. included in the 3P total) to 2P providing support to a valuation above the 2P amounts in
a ‘more friendly’ investment climate for international E&P companies. The 3P Identified Exploration
NAV is $12.21 per outstanding share.
Page 4
6/10/13
Gran Tierra – Net Asset Value
NPV10 Per Share
Proved
2P
Per Outstanding Share
Producing Assets
Undeveloped Land
Working Capital
Core NAV
Contingent Resource
Bretana - Best Case (2C)
Identified Exploration NAV
Bretana - Risked Potential
Post Discovery Upside
Risked NAV
Per Fully Diluted Share
3P
NPV10 $mm's
Proved
2P
3P
$
$
$
$
5.59
0.48
0.79
6.86
$
$
$
$
7.80
0.48
0.79
9.06
$
$
$
$
10.83
0.48
0.79
12.10
1,576
134
223
1,932
2,198
134
223
2,554
3,054
134
223
3,410
$
$
0.11
6.97
$
$
0.11
9.17
$
$
0.11
12.21
32
1,964
32
2,586
32
3,442
$
$
0.60
7.56
$
$
0.60
9.77
$
$
0.60
12.81
168
2,132
168
2,754
168
3,610
$
7.44
$
9.53
$
12.41
2,211
2,833
3,689
Shares Outstanding
Shares - Fully Diluted
Potential Dilution
281.9 mm
297.3 mm
5.5%
Peer Comparison
Due to the strong reservoir performance at Costayaco, and the increased production from Moqueta
(both in the Putumayo Basin of Colombia) in 2014 and following, the Company has a minimal
exposure to corporate production declines – a significant advantage to its peer group. The fact that
the majority of the Company’s production base is not located in the Llanos Basin, which tend to be
smaller reservoirs than in the Putumayo, has resulted in the Company’s RLI being better than other
Colombian producers, currently at 8.2 years.
Gran Tierra has historically maintained a very conservative balance sheet, essentially not carrying
any debt and having a substantial working capital position comprised largely of cash, again providing
it with a material advantage to its peer group. This financial flexibility will allow the Company to
finance the early stage development at Bretana without having to dilute, in the early stages, its
working interest position in this very large discovery.
Given the Gran Tierra’s comparatively stronger balance sheet and producing asset base, combined
with the upside potential and exposure to an exploration portfolio (including Bretana) that can
materially impact the Company, the Company is currently undervalued relative to its peer group.
Page 5
6/10/13
Gran Tierra – Peer Group Comparison
Colombia
CNE (3)
Canacol
Gran Tierra
GTE
Parex
PXT
Petrominerales
PMG
Average Colombia
Other
Bankers
BNK
Transglobe
TGL
Average All
Production (1)
2013
'13/'12
(boe/day)
Market
Cap
($mm's)
2012A
(boe/day)
244
1,750
462
531
11,661
24,370
11,407
29,134
6,800
27,280
14,852
21,908
-42%
12%
30%
-25%
-6%
718
541
15,021
17,496
17,420
21,925
16%
25%
3%
D/EV
D/CF
2013
2P RLI (2)
'14/'13
% Liquids
2013
8,931
28,900
15,281
21,561
31%
6%
3%
-2%
10%
77%
76%
100%
100%
88%
19,850
28,064
14%
28%
13%
100%
100%
92%
EV/2P
Most
Recent
Netback
2014
(boe/day)
EV/Production
2013
2014
($/boe)
Colombia
CNE (3)
Canacol
Gran Tierra
GTE
Parex
PXT
Petrominerales
PMG
Average Colombia
Other
Bankers
BNK
Transglobe
TGL
Average All
21%
-16%
16%
58%
19%
1.2
(0.7)
0.4
1.8
0.7
4.7
8.2
3.5
4.5
5.2
2%
-43%
6%
0.1
(1.0)
0.3
38.3
7.0
11.0
$
$
$
$
$
45,309
55,128
36,971
57,153
48,640
$
$
$
$
$
34,498
52,038
35,934
58,072
45,135
$
$
$
$
$
17.32
20.69
34.11
30.32
25.61
$
$
$
$
$
35.40
59.89
67.03
60.02
55.59
$ 42,130
$ 17,241
$ 42,322
$
$
$
36,972
13,469
38,497
$ 3.25
$ 7.76
$ 18.91
$
$
$
48.96
25.90
49.53
(1) Consensus forecast, before royalties.
(2) Most recent YE 2P reserves / most recent Q4 production
(3) Canacol - includes tariff (deemed) and net revenue interest reserves and production.
Source: Company Reports and Haywood Securities
Catalysts/Opportunities
Drilling results from Moqueta 10 are expected in late June; Mayalito 1 (LLA 22) will spud in June;
Miraflor Oeste 1 (Guayuyaco) will spud in early July; and horizontal drilling on Block 155 in Brazil
continues, with results expected through June and into Q3/13. The Company expects to release a
resource/reserve update for the Bretana discovery in Q4/13. Should the Bretana Norte discovery
establish reserves in the mid-range of the pre-drill resource estimate it could result in an almost 50%
increase in the Company’s reserves.
Page 6
6/10/13
Bretana Discovery – Commercial Today, With Upside as Work Continues
Gran Tierra – Bretana Norte Drilling Location, Block 95, Peru
Source: Gran Tierra
Bretana is a material discovery for Gran Tierra, potentially more than doubling the Company’s reserves pending the
outcome of planned production tests and appraisal drilling. Given this potential we have, in this report, provided a detailed
review of the discovery and the potential it holds for the Company. In summary, the Bretana highlights detailed in this report
and potential impact to Gran Tierra include:
Test results from the vertical well yielded 1,994 bbls/day of 18.5° API oil; from the follow up sidetrack, 3,095 bbls/day, both
with a 0% water cut. A long term production test (at least six months) is planned for early 2014 and the first appraisal well in
late 2014. The Company has stated that based on the data to date the Bretana discovery is commercial. The oil already meets
pipeline specifications.
The Company believes the Bretana discovery is potentially at the high end of the June 2012 resource estimate which was: 1C –
11.5 mmbbls; 2C - 31.6 mmbbls; 3C - 88.1 mmbbls. The mid case (2C) represents 43% of the YE12 2P booked reserves, and
the high case (3C) 121%.
An early production scenario for Bretana would see the 2014 long term test produce 2,500 to 3,000 bbls/day; a test of the
appraisal well would follow in 2015; first production of approximately 10,000 bbls/day would commence in H2/17 and
Page 7
6/10/13
sustainable (five to six years) peak production of 40,000 bbls/day would commence in 2020. Under this scenario the field
would produce approximately 100 mmbbls in the ten years following first production.
While the crude is 18.5° API, the netbacks would be $51 to $55 per bbl assuming Brent of $100. 10,000 bbls/day would add,
on a proforma basis for illustrative purposes, 50% to our 2014F CFPS, and at 40,000 bbls/day, 185%. Even after tax (which
wouldn’t initially be the case given the capital expenditures) the increase would be 35% and 130%, respectively.
The Company has several marketing options, including barging using double hulled barges, and tieing into the existing pipeline
system.
At March 31, 2013 Gran Tierra had cash of $236 million and an undrawn $100 million bank line. These funds, plus continued
cash flow, will support the Company’s Bretana development plans through 2014 as well as the capital budget for other assets.
We estimate full development could cost up to $1.5 billion. The Company would likely be able to fund a large portion of this
development with debt after a reserve report is available. Alternatively, the Company may choose to farmout a portion of its
interest following the generation of the reserve report, or potentially after the long term production test.
There remain other significant prospects on Block 95, including Lead C, which could be larger than Bretana. In addition, while
in the early exploration stages, the potential on Blocks 123 and 129 immediately northwest of Block 95 has been partially
derisked in the immediate area of the block by third party drilling and on a trend basis by the Bretana success and existing
success and production in Ecuador.
Page 8
6/10/13
Peru – Oil and Gas Block Map
Source: Perupetro, Gran Tierra and Haywood Securities
Page 9
6/10/13
Bretana Discovery Impactful With 100% Ownership
Two Step Acquisition of 100% WI of Block 95
Gran Tierra has a 100% WI in Block 95 located in the Maranon Basin of north-eastern Peru. In
December 2010 Gran Tierra farmed into Global Energy Development PLC to earn a 60% WI and
assumed operatorship by paying 100% of the costs of an exploration well to a maximum of $15
million and $2 million with respect to costs incurred to that time. In June 2012 the Company
acquired the remaining 40% WI from Global for $5.4 million to hold 100% WI.
Block 95 covers an area of 1.27 million acres. The block was in force majeure until December 2012
due to delays in receiving environmental approvals. The third exploration phase was extended to
June 27, 2013 and the commitments for this phase were completed by the drilling of the Bretana
Norte exploration well. Gran Tierra is currently in the fourth of six exploration phases.
Gran Tierra – Maranon Basin, Peru Blocks and Bretana Detail (Block 95)
Source: Gran Tierra & Haywood Securities
Prior to Gran Tierra’s Bretana Norte well, seven wells had been drilled on the block, three of which
encountered oil. The 1974 Amoco Bretana 1 (Bretana 10-16-1X) well was considered a discovery.
It is located on the northern portion of the structure (and the block) and flowed 807 bbls/day (no
pump) from the Vivian formation during a six hour test.
Page 10
6/10/13
Gran Tierra – Block 95 Drilling Activity
Source: Perupetro and Haywood Securities
The Bretana Norte Success
Gran Tierra spudded the Bretana Norte 95-2-1XD well December 15, 2012, which reached TD of
10,844 feet MD (measured depth) or 10,284 TVD (true vertical depth) on January 24, 2013. The well
discovered 18.5° API oil in the target Vivian formation.
Based on logs and other sampling the Company identified an oil bearing sandstone reservoir in the
target Vivian formation commencing at 9,408 feet MD, or 8,851 feet TVD. A gross oil column 99
feet thick, with net oil pay of 53 feet, was identified.
Data available from the original 1974 well was inconclusive with respect to the oil quality, with a
potential range of between 13.1° API and 17.6° API based on various original data sources. A
discovery at the high end of this potential range would be commercial, but at the low end would
likely not have been. With the test yielding an oil quality above the potential range, plus other data
on both the reservoir quality and oil characteristics coming in better than the pre-drill expectations,
the Bretana Norte discovery is commercial, and in fact a material, discovery.
Page 11
6/10/13
While drilling Bretana Norte Gran Tierra recovered 119 feet of core. The core was oil saturated over
most of the identified oil column, plus it extended into the underlying water column. In association
with the logs and testing data (below) the Company has a high comfort level that Bretana is a very
large discovery.
Test of Vertical Well Bore Yields 1,984 bbls/day
In February 2013 two short term tests were conducted on a 29 foot interval of the Vivian formation
in the vertical well.

Test 1: A DST of a 29 foot interval flowed 1,170 bbls/day (19.65 hours; 46/64-inch choke)
with a 0% water cut.

Test 2: A second shorter test flowed 1,984 bbls/day (1.5 hours; 64/64 inch choke), also with
a 0% water cut.
Testing was suspended once the onsite storage capacity was reached, however the oil flow rate was
increasing when the test was discontinued. It speaks to Gran Tierra’s environmental stewardship
that despite having regulatory approval to flare/burn the test oil the Company chose to limit its
testing to the onsite storage capacity.
The oil characteristics and reservoir qualities identified suggest that the recovery factor from this
field could be robust, likely 25% to 30%, and could potentially reach 50% due to the active water
drive.
Gran Tierra – Bretana Norte Overview
Vertical
10,844
10,284
119
Measured Depth - MD
True Vertical Depth - TVD
Cores
ft
ft
ft
Horizontal Sidetrack
ft
Top of Vivian fm. MD
Top of Vivian fm. TVD
Gross Pay
Net Pay
ft
ft
ft
ft
9,408
8,851
99
53
mD
18.5
24%
3,169
<0.5%
0%
API
Porosity
Average Permeability
Sulphur Content
Water
Sidetrack
1,595
1,283
22.8%
Horizontal Tests 3,095 bbls/day
Following testing of the vertical well, Gran Tierra drilled a 1,595 foot horizontal sidetrack into what
were believed to be high quality sands (which was confirmed by the test results). In May 2013 two
short term tests were completed over the length of the horizontal sidetrack which had penetrated
25 vertical feet near the top of the Vivian formation. Based on logs, net pay of 1,283 feet in the
sidetrack, and average porosity of 22.8%, has been identified between 10,735 and 12,262 feet MD.

Test 1: using a 32/64 inch choke, a final rate of 1,699 bbls/day of oil with a 0% water cut was
achieved.
Page 12

6/10/13
Test 2: using a 64/64 inch choke, the well flowed 3,095 bbls/day with a 0% water cut.
Again, the test period was limited to the onsite oil storage capability. We were not expecting test
rates to vary materially from those in the vertical well tests as the purpose of this test was to gain
additional reservoir quality data that will aid in designing a development program. It is likely there
was damage to the wellbore due to the previous drilling and testing activity, which would have
negatively impacted the test results.
Gran Tierra – Bretana Norte Production Test Results
Perforated
(feet)
Top of Vivian fm
Vertical Well Bore
Test 1
Test 2
29
29
Sidetrack, 1,595 feet
Test 1
Test 2
25
25
MD Interval Tested
(feet)
(feet)
9,408
9,409
9,409
9,438
9,438
Choke Test Rate
(inches) (bbls/day)
Cum
(bbls)
Water Cut
Flow/Pump
Duration When
(hours)
46/64
64/64
1,170
1,984
}
1,082
0%
0%
Flowing
Flowing
19.65 Feb 2013
1.50 Feb 2013
32/64
64/64
1,669
3,095
}
3,552
0%
0%
Flowing
Flowing
n/a May 2013
n/a May 2013
Long Term Production Test in Q1/14
Gran Tierra is planning to conduct a long-term production test of the horizontal leg, likely starting in
Q1/14, but subject to facilities upgrade and execution of crude oil transportation and delivery
agreements. This test will be conducted over a period of six months at rates estimated to range
between 2,500 and 3,000 bbls/day.
The test could extend longer provided associated water production remains low as the Company
would have to store and transport by barge any produced water. As with the short term oil tests,
while the Company does have regulatory approval to dispose of produced water in the adjacent
Puinahua River it has chosen not to. Produced oil, and water if any, from this test will likely be
transported by a double hauled barge to PetroPeru’s refinery at Iquitos.
Next Bretana Well in Late 2014
In early May Gran Tierra increased its 2013 capital budget, largely due to the success at Bretana
Norte. Included in the increase are the Company’s plans to acquire 382 sq km of high density 2D
seismic in Q3/12 over the Bretana structure in order to provide additional data for selecting the next
drilling location.
The Company is preparing and will file a comprehensive EIA (Environmental Impact Assessment) that
will seek blanket approval to conduct seismic, drilling and development operations over the field.
The Company will propose three drilling pads, from which it could drill a total of 24 wells. The wells
would be drilled directionally, and from these pads all of the potential bottom hole targets can be
accessed.
The EIA is expected to be approved in H2/14, after which the Company plans to drill its first appraisal
well. Using the seismic data, and ultimately drilling data, the Company is attempting to identify the
optimum drilling locations along the crest of the anticline (noted by the strike line in the diagram at
right below). The well will be drilled directionally from Location 3 targeting a bottom hole location in
the bright spot to the south.
Page 13
6/10/13
The cost of acquiring the seismic, preparing the drilling location and other field related activity, plus
of course drilling the appraisal well, will cost Gran Tierra approximately $100 million. The final
drilling cost estimate is dependent on the well design.
A long term production test would be conducted on the appraisal well. Assuming the well is
successful and the test results support a development, development drilling would commence in
2015.
Gran Tierra – Bretana Structure, Block 95, Peru
Source: Gran Tierra and Haywood Securities.
Based on data obtained from the older Envidia 1 well south of Bretana the oil water contact is
believed to be relatively static the length of the structure. If the second well is successful, the
reserves assigned to Bretana could increase materially from the existing estimates.
Reserves Likely Higher than 2012 Resource Estimate
In mid-2012, based on the available seismic and data from the original 1974 Amoco well Bretana 1,
GLJ estimated the contingent recoverable resource (pre-drill) at Bretana Norte at:

1C – 11.5 mmbbls;

2C – 31.6 mmbbls;

3C – 88.1 mmbbls.
Page 14
6/10/13
The 2C case represents 43% of the Company’s YE12 2P reserves – hence a discovery of this potential
would be very material to Gran Tierra.
The areal extent of the field is potentially very significant. Gran Tierra’s Bretana Norte and the 1974
Amoco Bretana well are almost 6 km apart. Assuming the field extends to Gran Tierra’s Location 4
(see diagram below) it would be almost 16 km long.
Gran Tierra – Bretana Structural Cross Section
The reservoir and oil quality encountered in the Bretana Norte well were much better than
expected before drilling based on the 1974 Amoco well data. Based on the current analysis of the
Bretana Norte data Gran Tierra believes the pre-drill contingent resource estimate to be
conservative. The Company has commenced preparation of a pre-FEED engineering study, which
will support a development plan and reserve bookings, likely in 2013.
Gran Tierra – Block 95, Peru Contingent Resource Estimate
Contingent Resources (GLJ)
Block 95, Peru (as of June 1, 2012)
% of YE12 Reserves - Proved
% of YE12 Reserves - 2P
% of YE12 Reserves - 3P
Corporate Reserves (GLJ)
YE 2012
1C
11.5
22%
16%
10%
2C
31.6
61%
43%
28%
3C
88.1
169%
121%
79%
Proved
52.1
2P
72.7
3P
111.3
Page 15
6/10/13
Development Scenario Has Several Marketing Options
Assuming Gran Tierra proceeds with development of Bretana, development drilling would
commence in 2015, first production in 2017 and a five to six year sustained peak reached in 2020.
The Company expects that first production of approximately 10,000 bbls/day could commence in
H2/17. Additional drilling, and maturing of the transportation options, would result in the field
reaching peak production of 40,000 bbls/day by 2020, which could be sustained for five to six
years. Under this scenario the field would produce approximately 100 mmbbls in the ten years
following first production.
Clearly Bretana could be a significant addition to Peru’s total crude production, and depending on
the progress of other developments, could be the discovery that moves the country to selfsufficiency, or alternatively, sustains a self-sufficiency peak. As with the Block 67 discovery (see
Appendix 2), the Government of Peru may be moved to declare the Bretana discovery of national
interest, which may expedite various regulatory approvals for the development of Bretana.
While it is premature to determine exactly how produced oil at Bretana would be transported to
market, the Company has several options available. Several of these options include:

Iquitos Refinery - Oil produced during the long term test period will likely be barged to the
PetroPeru refinery at Iquitos. Perenco is also delivering its initial production, before a
pipeline is constructed, to the Iquitos refinery (see Appendix 2). The Selva Refinery has
current capacity of 10,000 bbls/day, and there is discussion of expanding it to 14,000
bbls/day, although there is not yet a definitive timeline. Currently the refinery is processing
8,000 bbls/day, much of which is currently imported up the Amazon River, through Brazil.

Pipeline Only Option - A pipeline from the Bretana field, north approximately 100 km to tie
into Pump Station No. 1 on the Northern Pipeline to the coast. This option is the shortest;
however the route passes through swampy areas and a national preserve that could result
in the cost of laying the pipeline more expensive than other options. Note that a third party
would likely build and own the pipeline, not Gran Tierra.
Oleoducto Nor Peruano (Northern Peru Pipeline) transports oil from the Maranon Basin to
the marine terminal at Bayovar. The total length is 852 km, transporting crude from
Andoas to the north (to which Block 67 will be tied in) and San Jose De Saramuro to the
east at Station 1 (to which Block 95 could potentially be tied in). The current capacity is
250,000 bbls/day.
Page 16
6/10/13
Peru – Oleoducto Nor Peruano Route
Source: Barrett Resources and Haywood Securities

Combination Pipeline/Barge Option - A pipeline would be built south from Bretana to the
Ucayali River, approximately 200 km, and from there barged to Pump Station No. 1. This
route cuts the required barge traffic in half compared to the option below, and greatly
reduces the environmental exposure.

Barge Only Option - Barge all of the oil to Pump Station No. 1. While physically possible, at
40,000 bbls/day this would result in a significant increase in barge traffic on the river (the
rivers of the Amazon area are the highways and transportation of most goods occurs on the
river system). In addition, the risk of an oil leak or accident increases with more barges on
the river. Barging may be acceptable in the early days of production from the field;
however we expect the Company would ultimately opt for one of the above pipeline
options.
Early production will likely be barged to the Petroperu Selva Refinery in Iquitos, including the test oil
from the most recent tests. The Bretana oil has a high salt content and will need to be diluted
initially in order to meet the refinery specifications. Should volumes increase after testing is
complete the Company would wash the oil on location to reduce the salt content, which is a
relatively simple and inexpensive process. Current capacity of the refinery is 10,000 bbls/day, but is
running at 8,000 bbls/day. There is an intention to expand the capacity to 14,000 bbls/day, although
these plans are not definitive.
Page 17
6/10/13
Petroperu – Selva Refinery, Iquitos
There is a barge construction facility on the Amazon River in Iquitos, called SIMA, which is a state
owned facility that also constructs barges for the private sector and vessels for the navy, as
required. A barge capable of transporting 8,000 bbls (which would be the limit due to the river flow
rates) would take approximately four months to construct. The facility is capable of building six
barges a year. Should Gran Tierra pursue the barge option additional barges could be constructed
lower on the Amazon River in Brazil where other similar companies are located.
Page 18
6/10/13
SIMA – Barge Construction Facility, Iquitos
Netback Scenario – Potential For Material Cash Flow Impact
$100 Brent Yields $51 to $55 Netback
Again, it is premature to determine a definitive netback for Bretana crude. However, based on the
price received for other similar crudes in Peru, and the royalty structure, we can provide a
reasonable expectation.
Crude in Peru is priced at a discount to Brent, depending on the oil quality. Based on the price
received for other crude produced in Peru that is 18° API Bretana crude would likely receive Brent
less 18% to 20%.
The royalty rate in Peru is quite attractive. As set out in the table below, up to 5,000 bbls/day the
royalty rate is 5%, increasing on a sliding scale basis to 20% when production reaches 100,000
bbls/day, and 20% for production above this level. At 10,000 bbls/day Bretana would attract a
royalty of 5.8%, and at 40,000 bbls/day 10.5%.
Page 19
6/10/13
Peru – Royalty Overview
Example Royalty
bbls/day
Royalty
1,000
5.00%
2,000
5.00%
3,000
5.00%
4,000
5.00%
5,000
5.00%
6,000
5.16%
7,000
5.32%
8,000
5.47%
9,000
5.63%
10,000
5.79%
20,000
7.37%
30,000
8.95%
40,000
10.53%
50,000
12.11%
60,000
13.68%
70,000
15.26%
80,000
16.84%
90,000
18.42%
100,000
20.00%
110,000
20.00%
120,000
20.00%
130,000
20.00%
Overview
Production
Royalty Rate
<5,000 bbls/day
5%
5,000 to 100,000 bbls/day
5%-20% Sliding Scale
>100,000 bbls/day
20%
Source: Government of Peru and Gran Tierra
Transportation costs could vary, depending on weather a pipeline, barge, or combination
pipeline/barge option is chosen. Assuming all oil is barged; the cost would be $12 to $15 per bbl and
lower with a pipeline option.
Operating costs of $10 per bbl would not be unreasonable, but still quite early to estimate.
Based on the above assumption, at the first commercial production level of 10,000 bbls/day Bretana
oil would generate a netback of $55.08 per bbl. At the sustainable peak rate of 40,000 bbls/day the
operating netback would be $51.05 per bbl. The 40,000 bbls/day scenario results in a netback only
11% below the forecast 2014 corporate netback of $57.48.
Peak Production Would Increase Proforma 2014 Cash flow 185%
The impact to the Company’s cash flow would be material (in comparison to our 2014 forecast, to
provide a reference point). Even the initial commercial production level of 10,000 bbls/day would
increase cash flow 50%. A 40,000 bbls/day project would almost triple CFPS, increasing it 185%.
The income tax rate in Peru is 30%. There is also a tax stability guarantee in the contract that
ensures that the tax rate will not change from the rate in force at the time the contract was granted.
Assuming there were no capital pool deductions, the most conservative view, the after tax impact
would continue to be material with 10,000 bbls/day increasing cash flow 35%; and 40,000 bbls/day
adding 130% to the Company’s after tax cash flow.
Page 20
6/10/13
Gran Tierra – Potential Annual Cash Flow Impact of Bretana Development
bbls/day
Brent
Discount
Block 95 Price
$
Royalty Rate
Royalty
Transportation
Operating
Operating Netback
2,500
5,000
100.00 $
15%
85.00
100.00 $
15%
85.00
5.0%
5.0%
$
4.25
15.00
10.00
55.75
$millions
Operating Cash Flow
Per Share
$
Current 2014F CFPS
$
10,000
5.8%
$
4.25
15.00
10.00
55.75
50.9
0.18
$
1.42
$
20,000
100.00 $
15%
85.00
7.4%
$
4.92
15.00
10.00
55.08
101.7
0.36
$
1.42
$
40,000
100.00 $
15%
85.00
100.00
15%
85.00
10.5%
$
6.26
15.00
10.00
53.74
$
8.95
15.00
10.00
51.05
201.0
0.71
$
392.3
1.39
$
745.4
2.63
1.42
$
1.42
$
1.42
Potential Bretana
Impact to 2014F
13%
25%
50%
98%
185%
Tax Rate
30%
30%
30%
30%
30%
Net After Tax per share
$
Potential After Tax Bretana
Impact to 2014F
0.13
9%
$
0.25
$
18%
0.50
$
35%
0.97
68%
$
1.84
130%
Funding Bretana Development
Given that work on the FEED has only just commenced, it is very preliminary to estimate the capital
costs to bring the field to production and ultimately to the peak rate discussed. Our preliminary
estimate of the cost of full field development could ultimately be $1.2 to $1.5 billion.
Gran Tierra currently has cash of $236 million and an undrawn bank line of $100 million. Certainly
the planned activity through 2014 can be internally funded by the Company from the above noted,
plus cash flow generated over this period.
The Company may choose to farmout a portion of its interest to mitigate the financial risk. We
expect there would be interested parties for such an offer, especially given that there are other
material prospects on the block, however such a transaction may not occur prior to the end of the
extended production test on Bretana Norte.
A discovery such as Bretana would, after appraisal drilling, support a higher line of credit should the
Company opt for that option. Repayment could be achieved within two to three years of peak
production. However, the Company has previously maintained a very conservative approach with
respect to incurring debt (having said this, the Bretana discovery is an above average opportunity).
Block 95 Holds Other Exploration Potential
Several other large leads have been identified on Block 95, two of which have been firmed up.
Pursuing these opportunities is of course longer term, but could be drilled before Bretana production
moves to peak levels. The prospects are both very large, with Lead C having the potential to exceed
Bretana.
Page 21
6/10/13
Gran Tierra – Block 95 Prospectivity
Page 22
6/10/13
Other Peruvian Blocks Have Material Prospect Exposure
Peru has been Gran Tierra’s ‘elephant hunting’ territory. The exploration blocks in Peru each cover
an extensive area. As a result Gran Tierra’s Peruvian land position of 6.37 million acres (all 100% WI)
represents 60% of the Company’s total net land position.
Gran Tierra – Company Land Position With Peru Detail
Acres
Gross
No. Blks
Net
WI %
% Total
Peru
Maranon Basin
Block 95
Block 123
Block 129
Ucayali Basin
Block 107
Block 133
1,274,399
2,323,831
1,167,409
1,274,399
2,323,831
1,167,409
100%
100%
100%
12.0%
21.9%
11.0%
% Peru
20.0%
36.5%
18.3%
5
623,504
978,663
6,367,806
623,504
978,663
6,367,806
100%
100%
100%
5.9%
9.2%
59.9%
9.8%
15.4%
100.0%
23
4,460,187
3,586,609
80%
33.7%
11
1,268,028
598,310
47%
5.6%
7
1
8
47
47,733
337,561
385,294
12,481,315
47,733
33,756
81,489
10,634,215
100%
10%
21%
85%
0.4%
0.3%
0.8%
100.0%
Colombia
Argentina
Brazil
Onshore
Offshore
The Company’s first Peruvian exploration initiative was to pursue higher risk, but high reward
exploration potential on Blocks 122 and 128 on the Iquitos Arch in the northeast portion of the
Maranon Basin where it had identified exploration potential of 160 mmbbls. The Kanatari 1
exploration well, drilled in Q1/11, did not have oil or gas shows and the reservoir was wet. Both
blocks were subsequently abandoned.
Block 95 became the next focal area for the Company, which has exploration exposure, in addition to
Bretana, that could exceed 100 mmbbls.
In addition to Block 95, Gran Tierra now has a 100% WI in Blocks 123 and 129, also in the Maranon
Basin located northwest of Block 95, after acquiring its partner’s interests in the blocks in October
2012 (80% in each for a total of $7.1 million). The two blocks cover an area of 2.32 and 1.17 million
acres, respectively. The Company is acquiring 567 km of 2D seismic over the two blocks which will
complete the work commitments for the current exploration phases.
In the Ucayali Basin of south central Peru the Company has a 100% WI in Blocks 107 and 133 which
cover an area, respectively, of 0.62 and 0.98 million acres. These blocks were acquired with the 2011
Petrolifera acquisition. Block 107 is in the fourth and final exploration phase, but currently under
force majeure. When force majeure ends the Company will apply for a 12 month extension to the
exploration period which requires the drilling of one well and 300 units of work. The block is in the
second of four exploration phases, however PeruPetro froze this block until June 7, 2013. The
Company intends to acquire airborne gravity and magnetic surveys over the block and has requested
approval for this to satisfy the specified work commitment of acquiring 150 km of 2D seismic.
Page 23
6/10/13
Subandean Basin Heavy Oil Trend – Exposure Continues Into Peru
Source: LACPEC 10 Conference 2010 and Haywood Securities
Bretana Reserves/Resource Potential
Through two transactions Gran Tierra acquired 100% ownership of Block 95 in the Maranon Basin of
Peru. In December 2010 Gran Tierra agreed to farm-in to earn 60% of Global Energy Development
PLC’s (which operates under the name Harken in South America) 100% interest in Block 95. To earn
its interest Gran Tierra assumed the drilling cost of an exploration well, to a cap of $15.0 million, as
well as its share of past costs incurred with respect to the well. Costs were to be split on a pro-rata
basis after reaching the $15.0 million cap. At the time the well was expected to be drilled by the end
of 2011. In June 2012 Gran Tierra announced that it had acquired the remaining 40% WI in Block 95
from Harken to own 100% of the block. In January 2013 the regulator approved the second
acquisition by Gran Tierra. The original contract for Block 95 was executed in April 2005.
Harken Reserves Estimate for Bretana
At YE11 Harken’s independent engineers, Ralph E. Davis Associates Inc. out of Houston, Texas
prepared a reserves report for the Bretana discovery under both a Canadian (NI 51-101; constant
and forecast pricing) and UK basis. While the assumptions and methodology are undoubtedly
different than if Gran Tierra’s independent engineers, GLJ, had prepared the estimate, the results do
provide an example of the order of magnitude that the Bretana discovery could have to Gran Tierra.
Page 24
6/10/13
The reserves estimates assumed, on a 100% basis, the following:
 Total Proved Undeveloped reserves of 12.5 mmbbls;
 Total 2P Undeveloped reserves of 22.1 mmbbls; and
 Total 3P Undeveloped reserves of 67.2 mmbbls.
Under the Canadian disclosure format the constant oil price assumed was $89.38 per bbl (net after
royalty), and the forecast oil price average for the first ten years was $87.88. The UK disclosure
format assumed a higher forecast oil price, averaging $112.91 in the first ten years of the forecast.
Under the Canadian based forecasts the NPV20 (using a 20% discount rate) of the 2P reserves was
$501 million under the constant price case and $436 million under the forecast price case –
equivalent to $1.78 and $1.54 per share, respectively.

The NPV15 values were $623 and $542 million, respectively, equivalent to $2.21 and $1.92,
respectively.
Global Energy (Harken) – Bretana Reserves Estimate YE11
Independent Engineers:
Ralph E. Davis Associates Inc., Houston, TX; as at December 31, 2011
Gross Harken 40%
(mbbls)
(mbbls)
Canadian Basis - Constant Net Oil Price
All Years $89.38
Proved Undeveloped
12,480.3
4,735.0
Probable Undeveloped
9,658.0
3,652.0
2P
22,138.3
8,387.0
Effective Royalty
5.3%
Net CF
($mm's)
15%
($mm's)
20%
($mm's)
25%
($mm's)
299.5
235.1
534.6
155.9
93.2
249.0
129.2
71.2
200.4
108.3
55.3
163.6
Canadian Basis - Forecast Net Oil Price
Proved Undeveloped
12,480.3
9,658.0
2P
22,138.3
Effective Royalty
Yr 1 $89.50; 5 yr Avg $86.12; 10 yr Avg $87.88
4,735.0
266.3
138.7
3,652.0
200.7
78.1
8,387.0
467.0
216.8
5.3%
115.1
59.2
174.3
96.6
45.6
142.2
UK Basis - Forecast Net Oil Price
Proved Undeveloped
2P
Possible Undeveloped
3P
Effective Royalty
Yr 1 $94.29; 5 Yr Avg $103.00; 10 yr Avg $112.91
4,735.0
386.0
201.8
3,652.0
314.3
125.7
8,387.0
700.4
327.5
16,898.9
1,280.1
271.5
25,285.9
1,980.5
598.9
6.0%
167.7
96.2
264.0
174.7
438.7
141.2
74.8
216.0
115.9
331.9
12,480.3
9,658.0
22,138.3
45,095.4
67,233.7
Implied 100% Values and Potential Impact to Gran Tierra
2P
22,138.3
1,336.4
622.6
501.0
409.1
2P
22,138.3
1,167.6
541.9
435.7
355.5
2P
3P
22,138.3
67,233.7
1,750.9
4,951.2
818.7
1,497.4
659.9
1,096.7
539.9
829.7
Implied 100% Value per FD Gran Tierra Share
2P
$
4.49
$
2.09
$
1.68
$
1.37
2P
$
3.92
$
1.82
$
1.46
$
1.19
2P
3P
$
$
5.88
16.64
$
$
2.75
5.03
$
$
2.22
3.69
$
$
1.81
2.79
Source: Global Energy and Haywood Securities
Page 25
6/10/13
Peru – Country Backgrounder
Oil and Gas Business
Peru could be characterized as ten years behind Colombia as far as level of oil and gas drilling activity
and infrastructure in place. The other side of the coin is that as there has been less exploration
drilling there remains the potential for very large discoveries yet to be made. This is the basis for
Gran Tierra’s involvement in the country, which we have characterized above as its ‘elephant
hunting’ territory. The Bretana discovery, which following appraisal drilling has the potential to be as
large as 100 mmbbls, plus the other prospects on this block alone provide support for this argument.
In 2012 there were only 13 exploration wells drilled in Peru, down from 15 in 2011. Prior to 2011
between 5 and 8 exploration wells had been drilled in each of the prior 7 years, and fewer prior to
2004.
Peru – Oil and Gas Drilling 2002-2012
2002
12
0
5
17
Development
Confirming
Exploration
2003
28
0
3
31
2004
34
0
5
39
2005
69
0
5
74
2006
78
0
8
86
2007
177
2
7
186
2008
185
2
5
192
2009
147
6
6
159
2010
214
3
6
223
2011
222
5
15
242
2012
200
2
13
215
While liquids production has increased over the last ten years, the increase has been driven by
liquids production associated with increased natural gas production, primarily due to the giant
Camisea gas development project. Crude oil production has declined year over year in all but two of
the last ten years. Over the next few years the country is counting on development of the Block 67
oil discoveries (see Appendix 2) and planned growth from other discoveries in the Maranon Basin to
move it up to a self sufficient position and eliminate the need for importing crude. The Bretana
discovery on Block 95 provides Peru with an opportunity to maintain self sufficiency, which could
otherwise potentially be threatened in the next decade.
Peru – Liquids and Gas Production 2002-2012
Oil
NGL
Liquids
% Oil
(mbbls/day)
(mbbls/day)
(mbbls/day)
2002
92.7
4.0
96.7
96%
2003
87.3
4.0
91.3
96%
2004
79.9
14.2
94.1
85%
2005
75.4
35.8
111.2
68%
2006
77.5
38.0
115.5
67%
2007
77.1
36.8
113.8
68%
2008
76.5
43.5
120.0
64%
2009
71.0
74.3
145.3
49%
2010
72.7
84.5
157.2
46%
Gas
(mmcf/day)
42.7
50.6
82.9
146.7
171.7
258.9
327.7
336.1
700.3
0%
3%
0%
19%
-6%
0%
-6%
19%
-8%
255%
3%
64%
-6%
152%
18%
77%
% Change
Oil
NGL
Liquids
Gas
3%
6%
4%
17%
-1%
-3%
-1%
51%
-1%
18%
5%
27%
-7%
71%
21%
3%
2%
14%
8%
108%
2011
69.6
83.2
152.7
46%
1,099.1
-4%
-2%
-3%
57%
2012
66.7
86.3
153.0
44%
1,144.3
-4%
4%
0%
4%
Camisea
Peru’s largest hydrocarbon discovery is the prolific Camisea field in the southern portion of the
Ucayali Basin, which commenced production in 2004. The development area expands over two
blocks, Block 88 (booked reserves of 10 tcf) and Block 56 (2.3 tcf). Pluspetrol is the operator and
partners include Hunt Oil SK Energy and Repsol among others. Current production from the two
blocks is approximately 1.1 bcf/day and 102 mbbls/day of liquids. In 2010 Netherland Sewell
estimated, on a best case basis, that the field had 15.9 tcf of recoverable resource (range of 11.2 to
18.6 tcf). In June 2010 Peru commissioned South America’s first LNG facility at Pampa Melchorita,
Page 26
6/10/13
which sources Camisea gas. The facility’s capacity is 4.4 million tonnes per year. Also in 2010 Peru
signed an agreement to supply Mexico with 4 tcf of natural gas over the next 18 years.
Canada and Peru
Next to Mexico, Peru is Canada’s second largest bilateral trading partner in Latin America (including
the Caribbean). Canada and Peru signed a free trade agreement in 2009. In 2011 Canada imported
$4.5 billion of goods from Peru (primarily precious metals and mineral ores) and Canadian exports to
Peru were $0.5 billion (cereals, machinery, paper).
The Canadian International Development Agency (CIDA) has been involved in programs in Peru since
1968. In late May 2013 Prime Minister Harper, International Trade Minister Ed Fast, and five senior
Canadian business executives (including Dana Coffield, President of Gran Tierra, and representatives
of mining and agriculture) completed a business development trip to Peru. During his trip Harper
announced a five year, $53 million aid package for the country (in the form of CIDA projects) to
support development initiatives, including:

Improving environmental management of mining and energy activities in Peru.

Promoting competitiveness and economic diversification in Peru’s extractive regions.

Strengthening natural resource management in key regions of Peru.

Strengthening management of the education sector in Peru.
Both countries are members of the Trans-Pacific Partnership (11 members; a meeting was held in
Lima in May 2013) and Organization of American States, and Canada is currently has observer status,
but is approved to become a member, of the Pacific Alliance (four members – Chile, Colombia,
Mexico, Peru; a meeting was held during Harper’s visit in Colombia in May 2013).
Page 27
6/10/13
Republic of Peru
World
Rank
As Of
General
Capital
Lima
Area
20
1.29 mm sq km
Comparison
Ontario (1.08 mm sq km)
Population
42
Religions
July 2013
29.8 mm
Roman Catholic
81%
Evangelical
13%
Political
Government
Constitutional Republic
Independence
Legal System
July 1821 (from Spain)
Civil Law
Chief of State
President
Current
Ollanta HUMALA Tasso
Since
June 2011
Next Election
April 2016
Transparency International Ranking
83/178
Comparison Ranking
2012
Canada 9; US 19; Colombia 94; Brazil 69
World Bank Ease of Doing Business Ranking
43/185
Comparison Ranking
2012
Canada 17; US 4; Colombia 45; Brazil 130
Economic
GDP
US$B
Real Growth Rate
Per Capita
US$
40
2012
47
2012
$325.4
6.0%
110
2012
Unemployment Rate
87
2012
7.7%
Inflation Rate
100
2012
3.6%
Oil and Gas
$10,700
2009
2010
2011
Oil - Production
mbbls/day
45
145
157
153
Oil - Consumption
mbbls/day
62
176
186
203
Oil - Proved Reserves
Bbbls
49
0.8
1.2
1.2
Gas - Production
bcf/day
29
0.3.
0.7
1.1
Gas - Proved Reserves
tcf
38
10.6
12.5
12.5
Member of OPEC
No
Source: CIA, Perupetro, Transparency International, World Bank, Haywood Securities
Page 28
6/10/13
Appendix 1: Peru – Southeast Maranon Basin Stratigraphic Chart
Source: Pacific Stratus, Petrotech and Haywood Securities
Page 29
6/10/13
Appendix 2: The Block 67, a Heavy Oil Development Example
Block 67 is located in the northern portion of the Maranon Basin, in the Amazon drainage south of
the Ecuador border. The discoveries on Peru’s Block 67 extend the heavy oil trend from the giant
Ecuadorean ITT complex (Ishpingo, Tambococha, Tiputini) and other Ecuadorean discoveries.
Three discoveries drilled in 1998 by Barrett Resources, Dorado (71 feet of oil pay; 14 to 16° API;
Pirana (84 ft of oil pay; 12 to 21° API; and Paiche (179 feet of oil pay; 12 to 13° API), were the basis
for the Block 67 development. The oil price at the time meant these heavy oil discoveries were not
commercial. In 2006, with higher oil prices, Barrett drilled delineation wells at Dorado and Paiche.
The company commenced preparing a comprehensive development program after these wells were
drilled. Wells were drilled to between 7,000 and 7,500 feet and tested oil from the Basal Tena,
Vivian and Basal Chonta formations.
In January 2008 Perenco acquired 100% of Block 67 from Barrett. The Plan of Development,
approved in July 2007 prior to Perenco’s acquisition, contemplated first oil in January 2011; a $1.5
billion development cost and the potential for peak production levels of 100,000 bbls/day.
Prior to the acquisition of Block 67 by Perenco, Barrett had estimated the 2P contingent resource at
346.8 mmbbls (Paiche being the largest at 198.4 mmbbls) and the 3P resource at 804.0 mmbbls
(Paiche at 426.9 mmbbls). Netherland Sewell prepared the contingent resource estimates.
In 2009 the government of President Alan Garcia passed a statute declaring the Block 67
development to be of national interest. In June 2009 the EIA approving the drilling of 14 delineation
wells from seven platforms, which at the time was estimated to cost $185 million. Total investment
on the block was at this time estimated to be $2.0 billion.
In August 2012 the regulator approved the Block 67 EIA with respect to development, which had
been submitted earlier in the year. Development contemplates drilling up to 200 wells, including 15
water injection wells, from 18 platforms. First production of 7,000 bbls/day is expected before the
end of 2013, which will be transported by barge to Petroperu’s refinery at Iquitos. A 270 km pipeline
will be constructed from Block 67 to Anodas Station, the current northern terminus of the North
Peuvian Pipeline. Commencing in 2017 production of 60,000 bbls/day will be transported by pipeline
to the port of Bayovar. Diluent, which is shipped from the coast to Andoas by a separate 12 inch
pipeline, will be added to blend the Block 67 heavy crude to the required 18° API pipeline
specification.
Page 30
6/10/13
Peru Block 67 – Locator Map in Maranon Basin, Northern Peru on Heavy Oil Trend
Source: Barrett Resources and Haywood Securities
Page 31
6/10/13
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Page 32
6/10/13
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Important Disclosures
Of the companies included in the report the following Important Disclosures apply:
 The Analyst(s) preparing this report (or a member of the Analysts' households) have a financial interest in Bankers
Petroleum Ltd. (BNK-T).
 Haywood Securities, Inc. has reviewed lead projects of Bankers Petroleum Ltd. (BNK-T), Gran Tierra Energy Inc. (GTE-T),
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 n/a
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Page 33
6/10/13
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temporary or permanent loss of some of their investment capital.
Risk Profile Parameters – Oil and Gas Sector
Forecast Risk: High (7-10) – The company has a history of missing targets and/or Haywood expects guidance to be lowered.
Limited hedging increases commodity risk beyond peers. Higher commodity prices or production is ahead of guidance is
required to raise expectations. The company is in the earlier stages of exploration drilling and/or asset delineation whereby
type curves and/or production profiles are not yet reliably established. Properties are located in an area(s) with limited access
or require infrastructure. Moderate (4-6) – Haywood forecasts are generally in line with guidance. The Company has a history
of meeting or exceeding guidance. Forecasts are consistent with current commodity pricing and production guidance. Hedging
practices are in line with peers. The company has taken steps to de-risk its main producing or soon to be producing assets and
has reasonably reliable type curves and production profiles. Properties are located in an area(s) with access and some
infrastructure. Low (1-3) – Haywood forecasts exceed guidance. The Company has a history of meeting or exceeding guidance.
Forecasts allow for modestly lower commodity pricing or production levels. Commodity hedging lowers volatility relative to
peers. The company has de-risked the majority of its main producing properties and has established reliable type curve and
production profiles. Properties are located in accessible areas with available infrastructure.
Financial Risk: High (7-10) – The capital expenditure program in the current year or the next forecast year is not fully funded
with a combination of existing debt facilities, cash on hand and/or cash flow and execution of the program depends in part on
equity financing. Existing and/or forecast levels of leverage are above average relative to their peers. Moderate (4-6) – The
capital expenditure program in the current year or the next forecast year is fully funded with a combination of available debt
facilities, cash on hand and/or cash flow. Existing and/or forecast levels of leverage are in-line with peers. Low (1-3) – The
capital expenditure program in the current year or the next forecast year is fully funded with a combination of cash flow
and/or cash on hand. Existing and/or forecast levels of leverage are below the peer group.
Political Risk: High (7-10) – An environment unfriendly to the industry makes obtaining permits to drill or produce
hydrocarbons challenging. Significant government or local opposition exists. Important oil and gas production sharing
agreements or exploration permits are not in hand there is at least some uncertainty regarding their issuance. The region or
country has had a history of regulatory instability. Moderate (4-6) – An environment friendly to the industry makes obtaining
permits relatively straightforward. All levels of government are considered indifferent to hydrocarbon activity. Import oil and
gas production sharing agreements or exploration permits are not in hand but there is reasonably certainty that they will issue
Page 34
6/10/13
in the ordinary course. The region or country has historically had a reasonably stable regulatory environment. Low (1-3) –
Proper Oil and gas production sharing agreements or exploration permits are in hand. Governments of all levels support the
sector. The region or country has historically had regulatory stability.
Valuation Risk: High (7-10) – The current valuation is at a premium to peers. The valuation reflects continued above average
production growth and/or continuing strong commodity prices for further appreciation. Moderate (4-6) – The current
valuation is generally consistent with peers. The valuation reflects reasonable production growth and/or commodity price
appreciation. Low (1-3) – The current valuation is at the low end of historic ranges and/or at a discount to peer valuations.
The valuation reflects limited production growth and/or commodity price appreciation.
Distribution of Ratings (as of June 10, 2013)
Distribution of Ratings
%
#
Buy
51.7%
74
Hold
7.7%
11
Sell
0.0%
0
Tender
0.0%
0
UR (Buy)
18.2%
26
UR (Hold)
1.4%
2
UR (Sell)
0.7%
1
dropped (TTM)
20.3%
29
IB Clients
(TTM)
61.5%
7.7%
0.0%
0.0%
30.8%
0.0%
0.0%
0.0%
Price Chart, Rating and Target Price History (as of June 10, 2013)
B: Buy; H: Hold; S: Sell; T: Tender; UR: Under Review
Source: Capital IQ and Haywood Securities
Page 35

GTE - Investor Village

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