PetroMagdalena Energy Corp. presented its investor presentation for January 2012. The presentation focused on staying the course with their strategy by increasing production and reserves through exploration success at Cubiro in 2011 and increased development activity in 2012 in the Llanos Basin. Their goals are to improve operating cash flow by enhancing netbacks, reducing costs, and increasing efficiency across their diversified portfolio. They achieved an 86% increase in reserves at Cubiro in 2011 and expect production to increase from 2,800 boed in 2011 to a range of 4,300-4,700 boed in 2012, which would generate an estimated $82 million in operating cash flow for the year.

1. PMD - TSXV
Staying The Course
JANUARY 2012
INVESTOR PRESENTATION

2. Forward-looking statement 2
All monetary amounts in U.S. dollars unless otherwise stated.
This presentation contains certain “forward-looking statements” and “forward-looking information” under applicable Canadian securities laws
concerning the business, operations and financial performance and condition of PetroMagdalena Energy Corp. Forward-looking statements
and forward-looking information include, but are not limited to, statements with respect to estimated production and reserve life of the various
oil and gas projects of PetroMagdalena Energy; synergies and financial impact of completed acquisitions; the benefits of the acquisitions and
the development potential of the properties of PetroMagdalena Energy; the future price of oil and natural gas; the estimation of oil and gas
reserves; the realization of oil and gas reserve estimates; the timing and amount of estimated future production; costs of production; success of
exploration activities; ANH/ Ecopetrol approval of transfer of title and operatorship of joint ventures; and currency exchange rate fluctuations.
Except for statements of historical fact relating to the company, certain information contained herein constitutes forward-looking
statements. Forward-looking statements are frequently characterized by words such as “plan,” “expect,” “project,” “intend,” “believe,”
“anticipate”, “estimate” and other similar words, or statements that certain events or conditions “may” or “will” occur. Forward-looking
statements are based on the opinions and estimates of management at the date the statements are made, and are based on a number of
assumptions and subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially
from those projected in the forward-looking statements. Many of these assumptions are based on factors and events that are not within the
control of PetroMagdalena Energy and there is no assurance they will prove to be correct. Factors that could cause actual results to vary
materially from results anticipated by such forward-looking statements include changes in market conditions, risks relating to international
operations, fluctuating oil and gas prices and currency exchange rates, changes in project parameters, the possibility of project cost overruns
or unanticipated costs and expenses, labour disputes and other risks of the oil and gas industry, failure of plant, equipment or processes to
operate as anticipated, acquisitions not being integrated successfully or such integration proving more difficult, time consuming or costly than
expected as well as those risk factors discussed or referred to in PetroMagdalena Energy’s public filings with the securities regulatory authorities
in the provinces of Canada and available at www.sedar.com. Although PetroMagdalena Energy has attempted to identify important factors
that could cause actual actions, events or results to differ materially from those described in forward-looking statements, there may be other
factors that cause actions, events or results not to be anticipated, estimated or intended. There can be no assurance that forward-looking
statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such
statements. PetroMagdalena Energy undertakes no obligation to update forward-looking statements if circumstances or management’s
estimates or opinions should change except as required by applicable securities laws. The reader is cautioned not to place undue reliance on
forward-looking statements. Statements concerning oil and gas reserve estimates may also be deemed to constitute forward-looking
statements to the extent they involve estimates of the oil and gas that will be encountered if the property is developed. Comparative market
information is as of a date prior to the date of this presentation.
Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 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. The management estimates of
resources presented herein are arithmetic sums of multiple estimates of remaining recoverable resources (unrisked), which statistical principles
indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes
of resources and appreciate the differing probabilities of recovery associated with each class. Estimates of remaining recoverable resources
(unrisked) include prospective resources that have not been adjusted for risk based on the chance of discovery or the chance of development
and contingent resources that have not been adjusted for risk based on the chance of development. It is not an estimate of volumes that may
be recovered. Actual recovery is likely to be less and may be substantially less or zero.
Although PetroMagdalena has closed the acquisitions of its working interests in Carbonera, Catguas, Rio Magdalena, Arrendajo, Yamu,
Topoyaco, and Mecaya, it is currently in the process of completing the required approvals from ANH/ Ecopetrol, as applicable, for the formal
transfer of title and or operatorship.

3. Focus on Value Creation
1. Focus on organic cash flow opportunities in our portfolio
2. Enhance netbacks, reduce costs, increase efficiency
3. Exploration success at Cubiro in 2011 now leading to increased
development activity in 2012 in the Llanos Basin
4. Maximizing value from assets in our portfolio – leverage
relationships with strong partners
IMPROVING HIGH
EXPERIENCED POTENTIAL DRIVING
OPERATING
LEADERSHIP EXPLORATION VALUE
CASH FLOW ASSETS
Goal is to increase production and reserves 3

4. Diversified
portfolio
MAGDALENA Basin
•Las Quinchas CATATUMBO Basin
•Rio Magdalena •Santa Cruz (1)
•Carbonera-La Silla(1)
•Carbonera
•Catguas
RED blocks: LLANOS Basin
2010 ANH E&P •Cubiro(2)
blocks •Arrendajo
•La Punta
•Yamu
Agreements subject to ANH or
Ecopetrol approval
PUTUMAYO Basin
(1) Operated by Mompos Oil and
Gas, a wholly owned subsidiary. •Topoyaco
(2) Operated by Alange Energy
•Mecaya
Corp. a wholly owned subsidiary. 4

5. Achievements Q1 through Q3 2011
Achieved Ongoing
Reduced G&A per boe by 54% Q3 2011 vs 2010
average 
Increased Operating Netback by 49% 2011 YTD
(9 months) from FY2010 average 
Increased reserves at Cubiro by 86% * 
Drilling program at Cubiro O
Exploration at Cubiro O
Spud Yaraqui-1X at Topoyaco – D, August 31, 2011 
Farm-out 30% of Santa Cruz 
Spud Santa Cruz-1 on November 20, 2011 
Farm-out Carbonera and Catguas to YPF ** 
Sale and/or farm-out of other assets (Cerrito, Dec ‘11) O
* Petrotech report on Cubiro block, September 30, 2011
** Subject to ANH approval
5

6. 86% increase in 2P reserves at Cubiro
Technical Report dated September 30, 2011:
• Updated 2P reserves at Cubiro to 10.8 mmbls – an increase of 5.0 mmbls,
or 86%, compared to December 2010 report
• Updated 1P reserves at Cubiro to a total of 3.0 mmbls, or 73% increase
compared to December 2010 report
• Oil discoveries at Cubiro demonstrate exploration potential
• Production growth funds ongoing work plan for Cubiro
Cubiro L & M Oil Reserves (Mbbls)
100% Gross Net
Proved Developed
Producing 1,981 1,216 1,119
Proved Undeveloped 2,776 1,734 1,595
Total Proved 4,757 2,950 2,714
Probable 13,076 7,873 7,243
Total 2P 17,833 10,823 9,957
6
Source: Petrotech Engineering Ltd. report on Cubiro block, September 30, 2011

7. Cubiro 2P Reserves Changes in 2011
September 30, 2011
12,000
10,823
10,000 1,831
1,233
8,000
Mbbls
2,079
6,000 5,831
1,123
972
4,000
2,570
2,000
0
Dec 2009 Dec 2010 2011 Cubiro Purchase Petirrojo Copa B Copa A Sur
Reserve Reserve Production 32% of Discovery Discovery Discovery
Report Report & Technical Cubiro 'C'
Revisions
7
Source: Petrotech Technical reports: September 30, 2011, December 31, 2010 and 2009

8. Daily Average Production 2010-2011
PetroMagdalena’s Gross Working Interest
4500
Copa A Sur-1
4000
3500 Copa B-1
3000
Petirrojo Field
2500
boed
2000 Yamu
1500 32.13% Cubiro Block C
1000 acquired
Arauco5/ Careto 13H
500
0 2010 base wells
Year Q1 Q2 Q3 Q4 Dec
2010 2011 2011 2011 2012 2011 *
• Daily average for month of December
2011
• Petirrojo 2 & 3 put on production in
December.
8

9. Strengthening operating cash flow
• Re-capitalized balance sheet in February 2011 through equity financing
• Reduced debt by $31 million to $10 million, freeing up $1.0 million
per month of operating cash flow to fund capital investments in core
assets; working capital deficit reduced by $44 million since
December 31, 2010
• Enhancing operating netback from Cubiro production
• New oil marketing contract in conjunction with Pacific Rubiales
• Implementing initiatives to reduce opex
• Cost reductions generating positive trend in G&A per barrel produced
$60.00 $35.00
G &A per barrel
$50.00 $30.00
Netback per
$25.00
$40.00
$20.00
barrel
$30.00
$15.00
$20.00
$10.00
$10.00 $5.00
$- $-
Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2- 2011 Q3 - 2011
Operating Netback per barrel G&A per barrel
9

10. Enhancing Cubiro’s netback
• New 3-year conventional oil marketing agreement signed with
Pacific Rubiales effective February 1, 2011
• Three potential delivery points to Colombian pipeline infrastructure
Illustrative summary of potential netbacks from crude oil sales
from Cubiro production (1) (US$ per barrel)
Rubiales / Guaduas / Araguaney /
Delivery Point / Reference Price
WTI Vasconia Vasconia (2)
WTI (Nymex : January 12, 2012) $99.10 $99.10 $99.10
+8.00 +7.35 (3) +7.35 (3)
Benchmark Quality Adjustment
Royalties (7.00) (7.00) (7.00)
Net Revenue $100.10 $99.45 $99.45
Production costs (Q3 - 2011) 14.50 14.50 14.50
Transportation & pipeline 16.50 22.50 10.00
Operating Netback $69.10 $62.45 $74.95
(1) Management estimates, as of November 2011, for Netback per Barrel sold.
(2) Agreement in place – delivery volumes only on availability
(3) Vasconia as of January 12, 2016 priced at WTI + $7.35/bbl 10

11. 2011 Work Program
Estimated 2011 capital investment: $41 million(1)
Property Work Program 2011(1) Approximate timing
Exploration Plan
Cubiro • 4 wells(2 Block B, 2 Block C) • 3 drilled, 3 discoveries
(Yopo-1X discovery well) • Yopo well, Q4-2011
Arrendajo • 1 well (Azor -1X discovery well) • Azor-1X, TD on Jan 5th 2012
La Punta • 1 well (LP-4 dry) • LP-4 drilled, Q2-2011
Topoyaco • 1 well (Yaraqui-1X . . • Yaraqui-1X, Q4-2011
. non commercial)
Santa Cruz • 1 well • Spud Nov. 20th, 2011 - drilling
Development Plan
Cubiro • 4 wells + 1 WO + facilities, • 2 wells completed in Q1-2011
including storage • Petirrojo-3 dev well in Q4-2011
• Petirrojo-2 dev well in Q4-2011
• 1 WO in Q4-2011
(1) Management estimate, subject to change
11

12. 2012 Work Program Overview
2012 Work Program Overview
• Capital expenditure program estimated at $50 to $60 million, excluding
commitments funded by farm-ins (Carbonera, Catguas).
• 65% to be directed to light oil exploration and development in Cubiro and
Arrendajo.
• 6 Llanos exploration wells planned, 4 in Q1, 1 in Q2, and 1 Q4.
• 10 Llanos development wells planned, 1 in Q1, 3 in each subsequent.
• 2012 Llanos exploration program:
Management estimate of light oil recoverable prospective resources,
company’s working interest share would be close to doubling 2P Llanos
reserves Un-Risked or approximately + 40% Risked
• Capital intended to be funded from cash and internally generated cash flow.
• No near term financing extpected to be required to fund 2012 work plan.
• Cash flow estimate for 2012 includes no production volumes for any of the
exploration wells currently being drilled or to be drilled in 2012.
12

13. 2012 Work Program
Estimated 2012 capital investment: $50 million - $60 million (1)
Property Work Program 2012(1) Approximate timing - 2012
Exploration Drilling
Cubiro • 4 wells in Area ‘B’ • 4 in Q1, 1 Q2, 1 Q4
• 1 well in Area ‘C’
• 1 contingent wells ( Area ‘C’)
Arrendajo • 1 well (Arrendajo Norte-1X) • 1 well in Q1-2012
Carbonera • 1 well • 1 well in TD in Q2-2012
Development Drilling
Cubiro • 7 wells • 1 well spud in Q1-2012
• 3 contingent wells • 3 wells each subsequent qtr.
(1) Management Estimate, subject to change
13

14. Annual Cash Flow (1)
2011E 2012E
Average daily production for the year (gross before royalties)(4) 2,800 boed 4,300-4,700 boed
Cash flow from operating netbacks (2) $58M $82M
Less: G&A $15M $16M
Less: Debt service (principal & interest) (3) $18M $20M
Less: Equity tax instalments $2M $ 2M
Net cash flow from operations $23M $44M
Cash position, beginning of year $6M $15M
Cash available from equity financing for work program $35M -
Other sources/ (uses), including working capital changes and
$(8M) $ 7M
cash from asset dispositions (4)
Total cash available to fund annual work program $56M $66M
Annual work program expenditures (4) $41M $50-$60M
(1) Management estimate, 2012E calculated with an $80/bbl WTI pricing.
(2) Represents estimated revenues less royalties, production and transportation/pipeline costs based upon average daily
production of 2,800 boed for 2011E and 4,500 boed (mid-point of management guidance range)for 2012E.
(3) Includes interest of $3M and funds being set aside from cash flow for principal repayments of senior notes in May 2012 and
May 2013. The 2012E amount is net of $4M in a trust account as of December 2011 to be used toward the first annual principal
repayment in May 2012 of the senior notes (TSX-V: PMD.DB).
14
(4) Management estimate; subject to change.

15. Llanos Basin – Cubiro
Operator: Alange Energy Corp. (1)
WI: A:60.5% B:70% C:57.13%
Contract: ANH
Product: L/M Oil
Area: 61,295 acres
2P Reserves: 10.8 MMbbl (2)
Production: 2010 A (Year Avg): 1,905 bopd
2011 A (Year Avg): 2,138 bopd
About Cubiro
• Most prolific hydrocarbon basin in Colombia
• Currently producing from 21 wells in the Careto,
Arauco, Barranquerro, Petirrojo, Yopo and Copa fields
• 86% increase in 2P reserves (Sept 2011 vs Dec 2010) (2)
• 2011 Exploration program with four discoveries:
Petirrojo, Copa B, Copa AS and Yopo.
• Sept 30th 2011 update from three discoveries with 5.1
MMbbl of recoverable reserves (2P) (2)
(1) A wholly owned subsidiary of PetroMagdalena
(2) Petrotech Report dated Sept. 30, 2011, PetroMagdalena
share, gross before royalties
15

16. Llanos Basin - Cubiro
Highlights
Field
Prospect • Operated by PetroMagdalena
Palmarito
C7
• All production is subject to the sliding
40 °API scale royalty rates of ANH and a 3%
overriding royalty on total production
from the Block.
Careto
Turpial
Q1 -2012 Yopo, Q4-2011
Arauco
Barranquero
Sirenas • The Cubiro Block has been under an
C5
Petirrojo
37 °API Exploration and Production (E&P)
Petirrojo Sur Contract with ANH since October 8,
2004, exploration phases followed by a
Q2 - 2012
Cernicalo
Q1-2012
Canario Sirenas 25 year production period.
Sur
Guanapalo Copa • Currently, there are eight producing oil
C7
30 °API
Tijereto Sur Copa A Norte fields: Careto, Arauco, Barranquero,
Q1-2012 Q4-2012 Petirrojo, Yopo, Copa, Copa B and
Copa A Sur
Copa A Sur.
Copa B
Jordán
C7 Altair Copa C, Q1-2012 Caño Gandul
• Currently producing from Carbonera C-
29 °API C7 C5-C7
38 °API
5, C-7 and Gacheta formations.
• Four new fields discovered at Petirrojo,
Copa B, Copa A Sur and Yopo in 2011.
Polygon A : Polygon B : Polygon C :
Development Area Exploration Area Exploration Area
60.5% W.I. 70% W.I. 57.13% W.I.
16

17. Petirrojo Field, Petirrojo South & Yopo
Prospects
Carbonera C7
TWT Seismic Map
• Yopo discovery well spud on December
11th, 2011, and drilled to a final depth of
6,790 feet (MD). The well initially tested at
a stabilized rate of 752 bopd with 4.7%
BS&W for 6.5 hours at an average
wellhead pressure of 265 psi.
Yopo Field
• Petirrojo-1 encountered 32 ft of net pay
with porosities averaging 29%.
• Petirrojo-2 encountered 31 ft of net pay
with porosities averaging 29%.
• Petirrojo-3ST encountered 29 ft of net pay
with porosities averaging 29%.
• Petirrojo South will be drilled when civil
work has been completed, Q2-2012 Petirrojo Field
CURRENT TECHNICAL REPORT (1)
2P RESERVES Petirrojo-1
(Mbbls)
Petirrojo 2,036
(1) Company share, Sept 30, 2011 technical report
Petirrojo South Prospect
1 Km
17

18. Copa B Field, Copa A Sur & Copa AN Prospect
Carbonera C7
• Copa B-1 exploration well encountered 41 ft TWT Seismic Map
of net pay. Daily average production during
October has averaged 765 bopd
(Company share 437 bopd). ESP stopped Copa AN Prospect
working October 20th; the well went back
on production Nov 9th .
• Copa A Sur-1 exploration well successfully
drilled with Initial 4-day test rate of 1,114
bopd (Company share, 636 bopd) of 38.4° Copa ASur Field
API light oil on natural flow.
• Copa A Sur-1 went on production Nov 6th .
• The Copa C structure to the south of Copa Copa ASur-1
B will be drilled in Q1-2012
CURRENT TECHNICAL REPORT (1)
Copa B Field
2P Reserves
(Mbbls)
Copa B 1,230 Copa B -1
1 Km
Copa A Sur 1,831
(1) Company share, September 30, 2011 technical report
18

19. Cubiro ‘C’ Area – Copa Upside
Carbonera C7 TWT Seismic Map
Copa Field
Copa A Norte 2P RESERVES Sept 30, 2011 Technical Report
(Mbbls) 100% Gross Net
Copa A Sur
Copa Field 3,008 1,718 1,582
Copa A Sur 3,205 1,831 1,684
Copa B 2,153 1,230 1,142
Copa B
8,366 4,779 4,408
Copa C
Producing
Exploration 2012
Copa D
Development
19

20. Yaguazo Llanos Basin – Arrendajo
Mirla Negra
ARRENDAJO Azor
Mirla
Q4-2011 Highlights
Mirla
Oeste
Blanca
Arrendajo Norte • Arrendajo is 7 km NE of the Cubiro block
Q1-2012
• Operated by Pacific Rubiales Energy
• 120 km2 of 3D survey completed in April 2011,
interpretation shows 6 light oil prospects on
trend with producing oil fields
• Azor discovery in Jan. 2012 will be followed by
the Arrendajo Norte-1X in Q1 2012.
Arrendajo Sur
• Five exploration prospects in the Carbonera
CUBIRO formation have been identified: Yaguazo,
Arrendajo Norte, Arrendajo Sur, Mirla Blanca,
and Mirla Oeste
• PetroMagdalena acquiring 32.5% working
interest in December, 2011, from Pacific
Rubiales, subject to ANH approval, for $10
Operator: Pacific Stratus Energy Colombia (1) million to be paid out of production.
WI: 67.5%
Contract: subject to ANH approval
Product: Light Oil
Area: 78,102 acres
Resources: 8,259 Mbbl (2)
Stage: Exploration
(1) A wholly owned subsidiary of Pacific Rubiales Energy.
(2) Petrotech Engineering report April 2010, adjusted for the 32.5% interest being acquired from Pacific Rubiales.
20

21. Azor and Petirrojo Trends - Upside
Carbonera C7 TWT Seismic Map
• Azor discovery well spud on December
24th, 2011, and drilled to a final depth
of 7,225 feet (MD). The well initially
tested 752 bopd with a 1% BS&W over
an initial 8 hour period of natural flow.
Yaguazo
• Arrendajo-1X will be drilled after testing
Producing and completion is completed on Azor,
Exploration 2012 civil work has been completed.
Exploration 2013
Development
Mirla Negra
• 3D seismic evaluation identified four
new prospects on the Azor trend.
Azor
• Mirla Negra-1X was drilled in 2008 and
tested oil in the C5 but was not
declared commercial
Arrendajo
Norte

22. Putumayo Basin
About Putumayo
• Putumayo Basin is located in southwest Colombia
• High potential exploration targets
Highlights
• Partnered with experienced operators.
• PetroMagdalena has a beneficial 43% working
interest in the Mecaya Block, subject to ANH
approval, with no overrriding royalty and will pay 85%
of the cost of the first 3D and well.
• PetroMagdalena Energy has a 50% working interest in
the Topoyaco Block, subject to the ANH approval,
with a 6% overriding royalty to Trayectoria. In
Topoyaco & Mecaya addition, there is a 3.5% profit interest payable to
Contracts: ANH Grant Geophysical for the seismic work.
Operator:
Topoyaco – Pacific Rubiales
WI: 50%, subject to ANH approval
Mecaya – Gran Tierra
WI: 42%, subject to ANH approval
Product: L/M oil exploration potential
Production: Nil
22

23. Catatumbo Basin
VENEZUELA About Putumayo
• Putumayo Basin is located in northwest
Catguas Block Colombia and is the western extension of
the very prolific Maracaibo basin in
Carbonera La Silla
Venezuela
• High potential exploration targets
Highlights
• Partnered with experienced operators.
Santacruz Block
• PetroMagdalena has a beneficial 100%
Carbonera Block
working interest in the Carbonera Block,
subject to ANH approval.
• PetroMagdalena has a 70% working
Catguas, Santa Cruz and Carbonera interest in the Santa Cruz Block, and is
Contracts: ANH drilling the Santa Cruz-1X well.
Operator: • PetroMagdalena has a 58% working
Catguas – Solana (1) interest in the Carbonera La Silla Block,
WI: 50% N, 15% S, subject to ANH approval an Ecopetrol association contract.
Santa Cruz – Mompos Oil and Gas (2) • PetroMagdalena has a beneficial 50%
WI: 70% working interst in the northern area of
Carbonera – Well Logging Catguas and a beneficial 15% working
WI: 100%, subject to ANH approval interest in the southern area. Gran Tierra is
Product: L/M oil exploration potential the operator.
Production: Nil
(1) Wholly owned Subsidiary of Gran Tierra Energy
(2) Wholly owned subsidiary of PetroMagdalena.

24. Maximize Value From
Catatumbo Assets
Actions Taken
Farm Out Agreement for Santa Cruz:
• Retain Operatorship
• Retain 70% Working Interest
• Pay 40% of first well in Q4 – 2011, 55% of second well, 70% thereafter
Farm Out Agreement for Carbonera (1):
• YPF becomes Operator, bring extensive gas experience
• Retain 40% Working Interest
• Carried through US$23 million work program
Farm Out Agreement for Catguas:
• YPF will lead exploration program
• Retain working interests of 15% in North area and 4.5% in South area
• Carried through 2012 work program
(1) Farm Out Agreement for Carbonera in process and subject to ANH approval
24

25. Catatumbo Basin – Santa Cruz-1
Santa Cruz – 2, TD Q1 - 2013
Total of • Santa Cruz-1 is being drilled, and
spud on Nov. 20th, 2011, in the A
3480 acres C: 700 Block which has an area of 750
acres acres with a primary target (Mirador)
thickness of over 300 ft of high
porosity & permeability SS reservoir.
A: 750
acres F: 420 • The Santa Cruz Block has several faulted
acres structures assigned prospective resources
based on the 3D seismic interpretations
and information from the offset Rio Zulia
B: 800 E: 580 field
acres acres
• A contingent exploration location has
been identified in the C Block to the north
D: 230 of the Santa Cruz-1X well.
acres
Santa Cruz – 1, TD Q1 - 2012
Operator: Mompos Oil and Gas (1)
WI: 70%
25

26. Capitalization
Cash position (December 31st , 2011): $15.0 million
Debt (December 31st , 2011):
Factoring Loan (maturing Oct 2012) $5.1 million
Bank term loans (maturing May/ Aug 2013) $6.6 million
9% Senior Notes ( $10.4MM maturing May 2014) CA$31.1 million
Share price (January 16, 2011): CA$1.08
Shares outstanding: 142.3 million
Options outstanding ($2.17 average) 13.5 million
Warrants outstanding ($3.50) 19.0 million
Fully diluted: 174.8 million
Market capitalization - undiluted (January 16, 2011): CA$153.7 million
26

27. Leadership team
Management Directors
Luciano Biondi Jaime Perez Branger
Chief Executive Officer Executive Chairman
Gregg K. Vernon, P.Eng Miguel de la Campa
Chief Operating Officer
Serafino Iacono
Michael Davies, C.A.
Chief Financial Officer Ian Mann
Francisco Bustillos, M.Sc. Robert Metcalfe
Colombian Finance &
Administration Manager Luis Miguel Morelli
Jesus Aboud
Exploration Manager
Peter Volk, LL.B.
General Counsel & Secretary
27

28. Appendix
28

29. Assets in the most prolific basins
(1) (3)
Area Operator Gross Acres WI Contract Stage Product Status
Llanos Basin
Cubiro PMD 61,295 60.5-70-57.13% ANH E&P Light Oil Core Asset
Arrendajo Pacific Stratus 78,102 67.5% ANH Exploration Light Oil Near Cubiro*
La Punta Vetra 19,313 Up to 6% ECP E&P Light Oil Under review
Yamu WOGSA 18,194 10% ANH Prod & Exp Light Oil Producing
Catatumbo Basin
Carbonera Well Logging 63,727 100% ANH E&P Oil & Gas Farm-Out
15% / 50%
Catguas Gran Tierra 330,355 (2) ANH Exploration Oil & Gas Farm-Out
S N
Santa Cruz Mompos 40,058 70% ANH Exploration Light Oil Exploration
Carbonera – La 3D seismic work plan
Mompos 12,558 58% ECP E&P Light Oil
Silla in place
Magdalena Basin
Las Quinchas Pacific Stratus 124,493 24.5% ECP E&P H Oil To Be Sold
Gas/Cond/
Rio Magdalena Gran Tierra 36,156 56% ECP E&P JV or Farm-Out
Oil
Putumayo Basin
Topoyaco Trayectoria 60,035 50% ANH Exploration L/M Oil Under Review
Mecaya Gran Tierra 74,128 43% ANH Exploration L/M Oil 3D seismic planned
(1) See Slide 2. (2) After Farm Out WI retained is 4.5% S/15% N. (3) Subject to ANH /ECOPETROL approvals.
* Working interest reflects acquisition of PRE’s 32%, subject to ANH approval. Yellow background = Core portfolio assets
29

30. 2012 Exploration Program
2012
Well name
Quarter
Cubiro Block
Cernicalo-1ST 1
Tijereto Sur-1X 1
Copa C-1X 1
Turpial-1X 1
Petirrojo Sur-1X 2
Copa A Norte-1X 4
Arrendajo Block
Arrendajo Norte-1X 1
Carbonera Block
San Roque-1X (MBOE) 1
30

31. 2010 ANH Bid Round
Six E&P Assets
• Agreement for funding the
exploration commitment,
resulting in PetroMagdalena
VMM 35 holding a 10% Working Interest.
VMM 11 LLA 41
COR 33
VSM 12
VSM 13
MIDDLE MAGDALENA VALLEY BASIN
CORDILLERA BASIN
UPPER MAGDALENA VALLEY BASIN
LLANOS BASIN
31

32. Colombian Pipeline Infrastructure
32