1. PMD - TSXV
Building On Our Success
FEBRUARY 2012
INVESTOR PRESENTATION

2. Forward-looking statement
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.
2

3. Focus on Value Creation
1. Focus on organic cash flow opportunities in our portfolio
2. Enhance netbacks, reduce costs, increase efficiency
3. Increase development activity in 2012 in the Llanos Basin from
exploration success
4. Maximize value from assets in our portfolio – leverage
relationships with strong partners
5. Identify near term production growth opportunities in Colombia
IMPROVING HIGH
EXPERIENCED POTENTIAL DRIVING
OPERATING
LEADERSHIP EXPLORATION VALUE
CASH FLOW ASSETS
Goal is to increase production and reserves 3
3

4. Building On Our Success
PetroMagdalena Today:
Exploration
 Unrecognized upside potential
 Significant success in the light oil Llanos exploration program
 Catatumbo exploration drilling program has started
Production
 Light Oil development drilling in Llanos– 10 development wells in
2012
 Production doubles over last year
 Light oil pricing tracking Brent pricing
With the growth in reserves and production, expand portfolio
where opportunities leverage expertise and logistics
4

5. 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, Corp. a
•Mecaya
wholly owned subsidiary.
5

6. Investment Environment – Opportunities Exist
• Increasing number of oil and gas operations in Colombia, 150 companies in 2011
vs. 158 in 2012, with the potential of more junior companies entering through 2012
Ronda auctions.
• Today, approximately 13% of Exploration and Production (E&P) and TEA blocks
are listed as suspended or non-compliant, many fail to deliver (source: ANH)
• International E&Ps are trading at compressed multiples relative to Canadian E&P
companies, creates value gap
These factors combined demonstrate an investment environment for successful
operators with exploration success and organic cash flow to acquire, or farm in to
assets that are under-funded with exploration upside
Exploratory Drilling in Colombia Financing
150 80% $400 10
Number of Companies
Number of Wells
Success Factor
$300 8
60%
Millions
100 6
$200
40% 4
50 $100 2
20%
$0 0
0 0%
Q4 2010 Q1 2011 Q2 2011 Q3 2011
2004 2005 2006 2007 2008 2009 2010 2011
Total Success Factor Total Gross Equity Capital Raised
• Consistently high exploration success • Public market financing on declines, farm-
factors in Colombia have encouraged ins and acquisitions with current cash flow
investments that are key success factors are important means to growth for
for future opportunities Colombian E&Ps 6

7. 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
1,981 1,216 1,119
Producing
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
7
Source: Petrotech Engineering Ltd. report on Cubiro block, September 30, 2011

8. Cubiro 2P Reserves Changes in 2011
Source: Petrotech Technical reports: September 30, 2011, December 31, 2010 and 2009 8

9. 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
'10 Q1 '11 Q2 '11 Q3 '11 Q4 '11Dec '11 *
* Daily average for month of December 2011
* Petirrojo 2 & 3 put on production in December. 9

10. Strengthening Operating Cash Flow
• Enhancing operating netback from Cubiro production
• Oil marketing contract in conjunction with Pacific Rubiales
• Ongoing opex reduction programs
• Efficiencies 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
10

11. Cubiro’s Netback
• A 3-year conventional oil marketing agreement signed with Pacific
Rubiales effective February 1, 2011.
• Bicentenario pipeline is scheduled to be commissioned mid
2012, potential to reduce trucking costs by up to US$ 7.00/bbl.
Illustrative summary of potential netbacks from crude oil sales from Cubiro production (1)
(US$ per barrel)
Delivery Point / Reference Price Guaduas / Vasconia (2)
WTI (Nymex: February 21, 2012) 105,84
Benchmark Quality Adjustment (February 21, 2012) 12,75
Royalties (7,00)
Net Revenue 111,59
Production Costs (Q4 - 2011) 14,50
Transportation & pipeline 22,50
Operating Netback 74,59
(1) Management estimates, as of February 2012
(2) Vasconia as of February 21, 2012 priced at WTI +12.75/bbl
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 expected 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
• 4 wells in Area ‘B’
Cubiro • 1 well in Area ‘C’ • 4 in Q1, 1 Q2, 1 Q4
• 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
Santa Cruz • 1 well • Q4 2012
Development Drilling
• 7 wells • 1 well spud in Q1-2012
Cubiro
• 3 contingent wells • 3 wells each subsequent qtr.
(1) Management Estimate, subject to change
13

14. Annual Cash Flow (1)
2012E
Average daily production for the year (gross before royalties)(4) 4,300-4,700 boed
Cash flow from operating netbacks (2) $82M
Less: G&A $16M
Less: Debt service (principal & interest) (3) $20M
Less: Equity tax instalments $ 2M
Net cash flow from operations $44M
Cash position, beginning of year $15M
Cash available from equity financing for work program -
Other sources/ (uses), including working capital changes and
$ 7M
cash from asset dispositions (4)
Total cash available to fund annual work program $66M
Annual work program expenditures (4) $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).
(4) Management estimate; subject to change.
14

15. Llanos Basin – Cubiro
Operator: Alange, 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 30, 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
40 °API
• All production is subject to the sliding
scale royalty rates of ANH and a 3%
overriding royalty on total production
from the Block.
Careto
Alondro
Q1 -2012 Yopo, Q4-2011
Arauco
Barranquero
Sirenas • The Cubiro Block has been under an E&P
C5
Petirrojo
37 °API Contract with ANH since October 8,
Petirrojo Sur 2004, exploration phases followed by a
25 year production period.
Q2 - 2012
Cernicalo
Q1-2012
Canario Sirenas
Sur • Currently, there are nine producing oil
Guanapalo Copa fields: Careto, Arauco, Barranquero,
C7
30 °API
Tijereto Sur Copa A Norte Petirrojo, Yopo, Copa, Copa B, Copa A
Q1-2012 Q4-2012 Sur and Cernicalo.
Copa A Sur
Copa B • Currently producing from Carbonera C-
Jordán
C7 Altair Copa C, Q3-2012 Caño Gandul
5, C-7 and Gacheta formations.
C7 C5-C7
29 °API
38 °API • 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 1X 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 970
bopd with 4.7% BS&W for 6.5 hours at an
average wellhead pressure of 385 psi.
Yopo Field
• Petirrojo South will be drilled in Q2-
2012, civil work to be completed in
Feb, 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 Prospects
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
Mirla
Q4-2011 Highlights
Blanca
Oeste 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 on permanent
Arrendajo Sur production Feb. 25th, 2012.
CUBIRO
• Five more exploration prospects in the
Carbonera formation have been identified:
Yaguazo, Arrendajo Norte, Arrendajo Sur, Mirla
Blanca, and Mirla Oeste
• PetroMagdalena acquiring 32.5% working
interest, from Pacific Rubiales, subject to ANH
approval, for $10 million to be paid out of
Operator: Pacific Stratus Energy Colombia (1) 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. Arrendajo Block Azor discovery - Upside
Carbonera C7 TWT Seismic Map
• Azor-1X well drilling has been
completed and was put on
production on January 31, 2012. It will
add 587 bopd to our gross working
interest production.
• 3D seismic evaluation identified four
Yaguazo new prospects on the Azor trend.
Producing • Mirla Negra-1X was drilled in 2008 and
Exploration 2012 tested oil in the C5 but was not
Exploration 2013 declared commercial
Development
Mirla Negra
Azor
Arrendajo
Norte
21

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 overriding royalty and will pay 85%
of the cost of the first 3D and well.
• PetroMagdalena has a 50% working interest in the
Topoyaco Block, subject to the ANH approval, with a
6% overriding royalty to Trayectoria. In addition,
Topoyaco & Mecaya there is a 3.5% profit interest payable to Grant
Contracts: ANH Geophysical for the seismic work.
Operator:
Topoyaco – Pacific Rubiales
WI: 50%, subject to ANH approval
Mecaya – Gran Tierra
WI: 43%, subject to ANH approval
Product: L/M oil exploration potential
Production: Nil
22

23. Catatumbo Basin
VENEZUELA About Catatumbo
• Catatumbo 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 interest 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 23
(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
• Expected to be 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 spud on Nov.
3480 acres C: 700 20th, 2011, and casing run over the
acres Mirador Fomation on Feb. 24th, 2012.
The A Block which has an area of
750 acres with a primary target
A: 750 (Mirador) thickness of over 300 ft of
high porosity & permeability SS
acres F: 420
reservoir.
acres
• The Santa Cruz Block has several
B: 800 E: 580 faulted structures assigned
acres acres prospective resources based on the
3D seismic interpretations and
information from the offset Rio Zulia
D: 230 field
acres
Santa Cruz – 1, TD Q1 - 2012 • A contingent exploration location
has been identified in the C Block to
Operator: Mompos Oil and Gas (1) the north of the Santa Cruz-1X well.
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 (February 21, 2012): CA$1.51
Shares outstanding: 147.07 million
Options outstanding ($2.17 average) 13.5 million
Warrants outstanding ($3.50) 19.0 million
Fully diluted: 174.8 million
Market capitalization - undiluted (February 21, 2012): CA$220.7 million
26

27. Share price performance vs peer index
vs TSX energy index (Last 6 months)
PMD vs Peers Index* & Benchmark (Normalized)
190
170 Company Percentage
increase
150 PetroMagdalena 48.51%
Energy
130 Peer Index* 8.81%
TSX Energy Index 10.99%
110
90 PMD Price Volume Graph
$1.95 2,000,000
70 $1.75
1,500,000
$1.55
50
Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 $1.35 1,000,000
PetroMagdalena Energy Corp Peer Index* TSX Energy Index $1.15
500,000
$0.95
TSX.V: PMD
6 months: High - Low $1.80 – $0.86 $0.75 0
Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12
6 months: Average Volume 203,511 Volume PetroMagdalena Energy Corp
52 week: High - Low $2.35 – $0.93 27
* Peer Index: 5 TSX listed E&P companies with production above 1,000 barrels per day

28. 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
28

29. Appendix
29

30. Assets in the most prolific basins
(2) (2)
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 (1) 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) After Farm Out WI retained is 4.5% S/15% N. (2) Subject to ANH /ECOPETROL approvals.
* Working interest reflects acquisition of PRE’s 32%, subject to ANH approval. Yellow background = Core portfolio assets 30

31. Achievements Q1 2011 through Q1 2012
Achieved Ongoing
Operations
Reduced G&A per boe by 54% Q3 2011 vs 2010 average 
Increased Operating Netback by 49% 2011 YTD

(9 months) from FY2010 average
Production
Achieved 98% of guidance for 2011 at 2,758 boepd 
Increased reserves at Cubiro by 86% * 
4 discoveries at Cubiro: Petirrojo, Copa B, Copa A Sur &

Yopo
Spudded Azor-1X at Arrendajo with upside potential for

block
Spudded Cernicalo-1ST in Cubiro 
Spudded Arrendajo Norte-1X in Arrendajo 
* Petrotech report on Cubiro block, September 30, 2011
31

32. Achievements Q1 2011 through Q1 2012
Achieved Ongoing
Exploration
6 exploration wells for 2012 in Cubiro O
1 exploration well for Arrendajo Norte 1X 
1 exploration well for Carbonera O
Santa Cruz well in testing phase O
10 development wells planned in Cubiro O
Portfolio
Farm-out 30% of Santa Cruz 
Farm-out Carbonera and Catguas to YPF * 
Sale and/or farm-out of other assets (Cerrito, Dec ‘11) O
* Subject to ANH approval
32

33. 2012 Exploration Program
Exploration overview 2012
• 6 exploration wells planned for Cubiro
• 1 exploration well for Arrendajo
• 1 exploration well for Carbonera
• 1 exploration well for Santa Cruz
2012
Well name
Quarter
Cubiro Block
Cernicalo-1ST (formerly named Cernicalo-2X) 1
Tijereto Sur-1X 1
Alondra-1X (formerly named Turpial-1X) 1
Petirrojo Sur-1X 2
Copa C-1X 3
Copa A Norte-1X 4
Arrendajo Block
Arrendajo Norte-1X 1
Carbonera Block
Cantaclaro-1X (formerly named San Roque-1X) 1
Santa Cruz Block
Santa Cruz-2X 4 33

34. 2010 ANH Bid Round
Six E&P Assets
• Agreement for funding the
exploration
commitment, resulting in
PetroMagdalena holding a 10%
VMM 35 Working Interest.
VMM 11 LLA 41
COR 33
VSM 12
VSM 13
MIDDLE MAGDALENA VALLEY BASIN
CORDILLERA BASIN
UPPER MAGDALENA VALLEY BASIN
LLANOS BASIN
34

35. Colombian Pipeline Infrastructure
35