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

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

4. Diversified Portfolio
LLANOS BASIN
•Cubiro(1)
•Arrendajo(2) CATATUMBO BASIN
•LLA 47 •Santa Cruz (3)
•Yamu •Carbonera
•La Punta •Catguas
•Carbonera-La Silla(2)
RED blocks:
2010 ANH E&P blocks
PUTUMAYO BASIN
•Mecaya (4)
•Topoyaco
Agreements subject to ANH or Ecopetrol
approval
(1)Operated by Alange, Corp. a wholly
owned subsidiary.
(2)Operated by Pacific Stratus., a wholly
owned subsidiary of Pacific Rubialas
(3) Operated by Mompos Oil and Gas, a
wholly owned subsidiary.
(4) Operated by Gran Tierra
4

5. 43% increase in 2P oil reserves
$145 Million increase in 2P NPV (1)
2011 provided High Profit, light oil, reserves growth
2P Light Oil reserves increased by 4 MM Bbls
37% increase in 2P NPV(1), up $145 million
Before Tax Net Present Value
2P Reserves (MM boe) (2)
Discounted at 10% (1)
$600,000 35
538,985
30
$400,000 394,039 25
358,884
20
15
$200,000 10
5 13.3
6.6 9.3
$0 0
2009 2010 2011 2009 2010 2011
2P NPV10BT OIL Gas Nat. Gas Liquids
(1) Before Tax Net Present Value Discounted at 10%
(2) Source: NI 51-101 Technical Report, Petrotech Engineering, December 2009, December 2010 and December 2011.
Reserves before royalties based on working interest
5

6. Cubiro 2P oil reserves up 96% in 2011
December 31, 2011
14,000
11,432
12,000
1,831
10,000
2,374
M Bbls
8,000
1,415
6,000 5,831
1,225 1,569
4,000
2,570
2,000
0
Dec 2009 Dec 2010 Less 2011 Petirrojo Yopo Copa A Sur Copa B
Reserve Reserve Production Discovery Discovery Discovery Discovery
Report Report & Technical
Revisions
Source: NI 51-101 Technical Reports, Petrotech Engineering dated: December 31, 2009, December 31, 2010 and December 31, 2011 6

7. Daily Average Production 2010-2012
PetroMagdalena’s Gross Working Interest
4,500
4,000 Azor-1X
3,500 Cernicalo-1ST
3,000 Yopo-1X
boed
2,500 Copa A Sur-1X
2,000 Copa B-1X
1,500 Petirrojo Field
1,000 Yamu
500 2010 base wells
0
* Cernicalo-1ST put on production February 25th, 2012
* Azor-1X put on production January 31st, 2012. 7

8. It’s All About Brent Now
150
130
Q1 2012 Avg. sales price = $116
110
90
US$
70
50 Vasconia linked to
Brent
30
Source: Bloomberg Brent WTI Vasconia
• Brent 96% correlated with Vasconia over the last 6 months. Leveraging
marketing strategy to capture positive premium to WTI.
• 4th quarter premium to WTI was approximately $14 per barrel. Increased
revenue to $109 per barrel sold.
8
• Average Q1 2012 sales price was $116 at Cubiro 8

9. Cubiro’s Netback
• A 3-year conventional oil marketing agreement signed with Pacific
Rubiales effective February 1, 2011
• Lower Trucking costs would be expected for deliveries to Cusiana or
Bicentenario would positively impact net back between US$3.00/bbl and
US$ 7.00/bbl. Projects to be completed in second half of 2012.
Illustrative summary of potential netbacks from crude oil sales from Cubiro production
(US$ per barrel)
Delivery Point / Reference Price : Guaduas / Vasconia
Q4 2011 A APRIL 12, 2012 (1)
WTI Average (Nymex) 93.23 103.64
Benchmark Quality Adjustment 14.14 12.60
Royalties (2) (8.21) (8.74)
Net Revenue 99.16 107.50
Production Costs (3) (19.20) (19.20)
Transportation & pipeline (3) (18.63) (18.63)
Operating Netback 61.33 69.67
(1) Management Estimate
(2) Royalty presented on barrel of oil sold. ANH royalty oil is taken in kind at the wellsite 9
(3) Production Costs and Transport & Pipeline costs presented are the average for Q4, 2011

10. Strengthening Operating Cash Flow
• Enhancing operating netback
• Oil marketing contract in conjunction with Pacific Rubiales
• Ongoing opex reduction program
• Price of Colombian light oil moves to Brent reference
• Efficiencies generating positive trend in G&A per barrel produced
$70.00 $35.00
Netback per barrel
$60.00 $30.00
G &A per barrel
$50.00 $25.00
$40.00 $20.00
$30.00 $15.00
$20.00 $10.00
$10.00 $5.00
$- $-
Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2 - 2011 Q3 - 2011 Q4 - 2011
Operating Netback per barrel G&A per barrel 10

11. 2012 Work Program Overview
2012 Work Program Overview
• Original capital expenditure program estimated at $50 to $60 million, excluding
commitments funded by farm-ins
• Capital expected to be funded from cash and internally generated cash flow
• No near term financing expected to be required to fund 2012 work plan.
• 65% planned to be directed to light oil exploration and development in Cubiro and
Arrendajo
• 3 more Llanos exploration wells and 10 development wells planned for the balance of
2012, 5 exploration wells drilled
• 2012 Llanos exploration program:
Management estimate of company’s working interest share of recoverable
prospective light oil resources would be almost a double 2P Llanos reserves on an
Un-Risked or approximately + 40% on a Risked basis
Exploration Success – Expanded Work Program
• Revised budget with capital expenditure estimated at $70 to $80 million(1) planned to be
presented in May 2012
(1) Management estimate, subject to change, subject to board approval
11

12. Q2 – Q4 Cubiro Drilling Schedule(1)
Production modelling for Development wells:
• Average Cubiro Development well, first 6 months = 585 bopd (1)
Q1 Q2 Q3 Q4
Feb Mar
WELL TYPE Apr May Jun Jul Aug Sep Oct Nov Dec
5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53
Development C C C B C C B C B C
Exploration B C C
• Exploration wells
• Petirrojo Sur-1X
• Copa C-1X
• Copa A Norte-1X
(1) Management Estimate, subject to change
(2) 7 development wells in Area ‘C’,3 development wells in Area ‘B’
12
(3) Revised budget and work program planned to be presented to Board in May 2012

13. Annual Cash Flow
2011A 2012E (1)
Average daily production for the year (gross before 2,761
4,300-4,700 boed
royalties) boed
Cash flow from operating netbacks(4) $54.3 M(3) $82M(2)
Less: G&A $14.7M $16M
Less: Debt service (principal & interest) $18.4M $20M(5)
Less: Equity tax instalments $2.1M $ 2M
Net cash flow from operations $19.1M $44M
Cash position, beginning of year $6.5M $14M
Cash available from equity financing for work program $35.0M -
Other sources/ (uses), including working capital
$10.4M $ 7M (1)
changes and cash from asset dispositions
Total cash available to fund annual work program $71.0M $66M
ANNUAL WORK PROGRAM EXPENDITURES $56.9M(6) $50-$60M
(1) Management estimate, subject to change.
(2) Management estimate, 2012E calculated with an $80/bbl WTI pricing.
(3) Based on 2011 daily average sales of 2,664 boe at average netback of $55.84 per boe
(4) 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.
(5) 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).
(6) Includes $6.0M of seismic and other costs charged to exploration expense, $35.3M additions to exploration and evaluation assets and $15.6M additions to oil & gas properties,
plant & equipment. 13

14. Llanos Basin
Yopo-1X
CUBIRO RESERVES
Reserve Category Gross BOGOTA
L&M Crude Oil (Mbbl) (1)
Proved 5,564
Probable 5,870
Total 2P 11,432
Most prolific hydrocarbon basin in Colombia
(1) Reserves before royalties based on working interest
Source: NI 51-101 Technical Report, Petrotech Engineering, December 2011
14

15. Llanos Basin - Cubiro
CUBIRO
Highlights
Producing Field
• Operated by PetroMagdalena
Prospect Palmarito
C7
40 °API • 4 discoveries in 2011, 1 YTD 2012
• The Cubiro Block has been under an
Careto
Alondra
Q1 -2012 Yopo, Q4-2011 E&P Contract with ANH since October
Arauco
Barranquero
Petirrojo
Sirenas
C5
8, 2004. Exploration phase followed
37 °API
Petirrojo Sur
by a 25 year production period.
Q2 - 2012
Cernicalo
Q1-2012 MAIN FACILITY AT CARETO
Canario Sirenas
Sur
Guanapalo Copa
C7
Tijereto Sur Copa A Norte
30 °API
Q1-2012 Q4-2012
Copa A Sur
Copa B
Jordán
Altair Copa C, Q3-2012 Caño Gandul
C7
29 °API C7 C5-C7
38 °API
Polygon A : Polygon B : Polygon C :
Development Exploration Exploration
Area Area Area
60.5% W.I. 70% W.I. 57.13% W.I.
15

16. Petirrojo & Yopo Fields, Petirrojo Sur Prospect
Carbonera C7 TWT Seismic Map
DEVELOPMENT
• Two development wells in 2012, one in
Petirrojo and one in Yopo.
• Petirrojo-1X cumulative production block Yopo Field
over 240,000 bbls 40 API oil produced
• Engineering plans being developed to
replace rented facilties to reduce Opex,
estimated payout in 1.5 years.
EXPLORATION
• Petirrojo Sur-1X exploration well will be
drilled in Q2-2012, civil work is completed
2012. Petirrojo Field
CURRENT TECHNICAL REPORT
2P RESERVES
(Mbbls)
(1) Petirrojo-1
Petirrojo 1,569
Yopo 1,415 Petirrojo Sur-1X Prospect
1 Km
Source: NI 51-101 Technical Report, Petrotech Engineering, December 2011 16
(1) Reserves before royalties based on working interest

17. Copa, Copa A & Copa AS Fields
Carbonera C7 TWT Seismic Map
DEVELOPMENT
• Copa-4 was drilled NW of Copa-1X at the Copa-4
projected OWC and found the reservoir sands
≈ 20 ft higher - additional drilling further west COPA FIELD
is planned to determine reservoir limits.
• Copa-5 to be drilled in Q2-2012 Copa-1X
EXPLORATION
• The Copa C structure is to the south of Copa Copa AN Prospect
B, an exploration well is planned for Q4-2012.
• The Copa A Norte structure is between two
producing fields, Copa and Copa A Sur, an
exploration well is planned for Q4-2012.
CURRENT TECHNICAL REPORT
COPA ASUR FIELD
2P Reserves Copa ASur-1
(Mbbls) (1)
Copa 1,710
Copa B 1,379 Copa B -1
Copa A Sur 2,375 COPA B FIELD
1 Km
(1) Reserves before royalties based on working interest 17
Source: NI 51-101 Technical Report, Petrotech Engineering, December 2011

18. Cubiro ‘C’ Area – Copa Upside
Carbonera C7 TWT Seismic Map 2P RESERVES Dec 31, 2011 Technical Report
(Mbbls) 100% Gross Net
Copa Field
Copa Field 2,991 1,709 1,572
Copa A Sur 4,157 2,375 2,185
Copa A Norte Copa B 2,570 1,468 1,352
Q4-2012 9,718 5,552 5,109
Copa A Sur
Copa Field Main Facility
Copa B
Copa C
Q4-2012
Producing
Exploration 2012 Copa D
Development Q1-2013
Treatment Capacity = 12,000 bfpd Storage Capacity = 10,000 bbls
18

19. Azor average Production Yaguazo Llanos Basin – Arrendajo
March 2012 870 bopd Mirla Negra
ARRENDAJO Azor
Highlights
Q4-2011
Mirla
Oeste
Mirla
Blanca • Arrendajo is 7 km NE of the Cubiro block
• Operated by Pacific Rubiales Energy
3D seismic proposed for
2013 program • 120 km2 of 3D survey completed in April
2011, interpretation shows 6 light oil
Producing Field prospects on trend with producing oil fields
Prospect
3D Seismic
• Azor discovered in January 2012 and was
Arrendajo Sur
initially put on production on January 31,
CUBIRO
2012.
• Four exploration prospects in the
Carbonera formation have been identified
for Drilling: Yaguazo, Arrendajo Sur, Mirla
Blanca, and Mirla Oeste
Operator: Pacific Stratus Energy Colombia (1) • 3D seismic required to map complete
WI: 67.5%
trend, to be acquired in 2013.
Contract: subject to ANH approval
Product: Light Oil • PetroMagdalena acquired 32.5% additional
Area: 78,102 acres working interest, from Pacific Rubiales in
Stage: Exploration November 2011, subject to ANH approval,
for $10 million to be paid out of
19
(1) A wholly owned subsidiary of Pacific Rubiales Energy . production.

20. Arrendajo Block Azor discovery - Upside
Carbonera C7 TWT Seismic Map
• Azor-1X well was drilled and completed on
January 31, 2012. The well tested at 870
bopd. Average production for March 2012 was
830 bopd natural flow adding 560 bopd to
PetroMagdalena’s gross working interest
production.
Yaguazo
• Two exploration prospects defined by 3D
Producing seismic north of the Azor discovery, Yaguazo
Exploration 2012 and Yaguazo Norte.
Exploration 2013
• Mirla Negra-1X was drilled in 2008 and tested
Development
Mirla Negra oil in the C5 but was not declared commercial
Road to the Azor Wellsite
Azor
20

21. LLA-47 Block – Exploration Potential
Highlights
• PetroMagdalena signed a binding letter of
intent with Interoil Colombia E&P Inc. in
respect of a 50% participation to farm in
• Expansion of current Llanos exploration play –
LLA-47 covers an area of 447 km2 south and on
trend with the company’s main Cubiro block
and other producing blocks in the basin
• Two additional years of active drilling
• Interoil has a 100% of the working interest on
the block and is the current operator.
• The Company has agreed to undertake a $30
million work program commitment in the three
years of Phase 1 of the E&P contract with the
ANH.
• Transaction is subject to approval by the ANH.
In addition, the Company shall pay a $2 million
signing fee upon receipt of ANH approval.
21

22. Catatumbo Basin
VENEZUELA About Catatumbo
Catguas • Catatumbo Basin is located in northwest
Block Colombia and is the western extension of the
Carbonera La very prolific Maracaibo basin in Venezuela
Silla
• High potential exploration targets
Santacruz
Highlights
Block • PetroMagdalena has a beneficial 100%
Carbonera Block working interest in the Carbonera Block,
subject to ANH approval.
• PetroMagdalena has a 70% working interest in
Catguas, Santa Cruz and Carbonera the Santa Cruz Block, the Santa Cruz-1X well
Contracts: ANH is the first exploration well on the block.
Operator:
• PetroMagdalena has a 58% working interest
Catguas – Solana (1)
in the Carbonera La Silla Block, an Ecopetrol
WI: 50% N, 15% S, subject to ANH approval
association contract.
Santa Cruz – Mompos Oil and Gas (2)
WI: 70% • PetroMagdalena has a beneficial 50% working
Carbonera – Well Logging interest in the northern area and 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 • MOU signed with YPF to farm out 60% of
Carbonera and 70% of the Catguas WI.
(1) Wholly owned Subsidiary of Gran Tierra Energy
(2) Wholly owned subsidiary of PetroMagdalena.
22

23. Catatumbo Basin – Santa Cruz-1
Santa Cruz – 2, TD Q1 - 2013
Total of About Santa Cruz
3480 acres C: 700 • 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
A: 750 field
acres F: 420 • High potential exploration targets
acres Highlights
• Santa Cruz-1 spudded on November 20,
B: 800 E: 580 2011, and casing run over the Mirador
acres acres Formation end of February, 2012. The A
Block with an area of 750 acres has the
Mirador as the primary target, a high
D: 230 porosity & permeability Sandstone
acres reservoir. A contingent exploration
location has been identified in the C Block
Santa Cruz – 1, TD Q1 - 2012
to the north of the Santa Cruz-1X well.
Operator: Mompos Oil and Gas (1) • Santa Cruz 2X targeted for exploration Q4
WI: 70% 2012 (pending Santa Cruz 1X results)
(1) Wholly owned subsidiary of PetroMagdalena. 23

24. Catatumbo Basin – Cantaclaro-1X
About Cantaclaro
• The Cantaclaro-1X exploration well, on
the Carbonera Block, spudded on March
Catatumbo
15, 2012, and was drilled to the top of
Mito Juan
the target La Luna formation at a depth
of 4,560 feet MD where intermediate 9-
5/8 inch casing was set .
Highlights
• After setting Intermediate 9-5/8 inch
casing the next operation is to install
underbalanced drilling equipment.
Colon
• The La Luna target formation will then
be drilled, highly deviated, and the well
is estimated to reach TD at the base of
La Luna the La Luna Formation at a measured
Cogollo depth of 5,480 feet MD.
• PetroMagdalena has signed an MOU to
farm-out 60% of the Carbonera block to
YPF as part of a $23 million work
program, subject to ANH approval. 24

25. 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.
Topoyaco & Mecaya
Contracts: ANH • PetroMagdalena has a 50% working interest in
Operator: the Topoyaco Block, subject to the ANH
Topoyaco – Pacific Rubiales approval, with a 6% overriding royalty to
WI: 50%, subject to ANH approval
Trayectoria. In addition, there is a 3.5% profit
Mecaya – Gran Tierra
WI: 43%, subject to ANH approval interest payable to Grant Geophysical for the
Product: L/M oil exploration potential seismic work.
Production: Nil
25

26. Capitalization
Cash position (December 31, 2011): $14 million
Debt (December 31, 2011):
Factoring Loan (maturing October 2012) $5.1 million
Bank term loans (maturing May/ August 2013) $6.6 million
9% Senior Notes ( $10.4MM maturing May CA$31.1 million
2014)
Share price (April 10, 2012): CA$1.48
Shares outstanding: 147.1 million
Options outstanding ($2.16 average) 13.7 million
Warrants outstanding ($3.50) 19.0 million
Fully diluted: 174.8 million
Market capitalization - undiluted (April 10, 2012): CA$217.7 million
26

27. PetroMagdalena is in the right country,
focused in the right basin
120 80% Oil opportunities are significant, proven reserves of
Success Factor
100
60% over 2 billion barrels
80 July 2011
60 40% 500% increase in exploration activity – 50% success
40
20% Consistently high exploration success in Colombia
20
0 0% has encouraged investment - key success factor for
future opportunities
2011
2004
2005
2006
2007
2008
2009
2010
Most secure Latin American country to do business (1)
Number of Wells
(2) (1) World Bank, Doing Business 2010 and 2011 Reports
Number of wells Success factor (2) ANH Report
27

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 Nelson Ortiz
Exploration Manager
Peter Volk, LL.B.
28
General Counsel & Secretary

29. Appendix
29

30. Valuation Gap
Colombian E&Ps are trading at compressed multiples relative to
160 International E&P companies = growing value gap 150
140 130
120 110
Index Level
WTI Spot
100 90
80 70
60 50
40 30
WTI Spot Colombian E&P* International E&P** S&P/ TSX Energy Index S&P/ TSX Composite Index
Value Gap
Source: Bloomberg; January 4, 2011 – April 10, 2012
*Colombian E&P: Azabache Energy Inc, Anatolia Energy Corp, Brownstone Energy Inc, C&C Energia Ltd, Canacol Energy Ltd, Sintana Energy Inc, Gran Tierra Energy Inc, Loon
Energy Corp, Pacific Rubiales Energy Corp, Parex Resources Inc, Petro Andina Resources Inc, Petrodorado Energy Ltd, Petrolifera Petroleum Ltd, PetroMagdalena Energy Corp,
Abacan Resource Corp PetroNova Inc, Petro Vista Energy Corp, Quetzal Energy Ltd, Sagres Energy Inc, Stetson Oil and Gas Ltd, Shear Diamonds Ltd, Talisman Energy Inc, Vast
Exploration Inc, and Petroamerica Oil Corp.
**International E&P: Antrim Energy Inc, Enhanced Oil Resources, Inc Bankers Petroleum Ltd, Bengal Energy Ltd, BNK Petroleum Inc, Candax Energy Inc, Caspian Energy Inc, Caza
Oil & Gas Inc, Coastal Energy Co, Falcon Oil & Gas Ltd, Encana Corp, Epsilon Energy Ltd/Canada, Heritage Oil PLC, Husky Energy Inc, Ithaca Energy Inc, Ivanhoe Energy Inc, Jura
Energy Corp, Energulf Resources Inc, Niko Resources Ltd, NiMin Energy Corp, TAG Oil Ltd, TransAtlantic Petroleum Ltd, TransGlobe Energy Corp, Vermilion Energy Inc, East West
Petroleum Corp, Eco Atlantic Oil & Gas Inc, Emerald Bay Energy Inc, Patriot Petroleum Corp, and North Sea Energy Inc. 30

31. Assets in the most prolific basins
(2) (2)
Area Operator Gross Acres WI Contract Stage Product Status
Llanos Basin
Cubiro PMD 61,509 60.5-70-57.13% ANH E&P Light Oil Core Asset
Arrendajo Pacific Stratus 60,252 67.5% ANH Exploration Light Oil Near Cubiro*
La Punta Vetra 18,913 Up to 6% ECP E&P Light Oil Under review
Yamu WOGSA 15,534 10% ANH Prod & Exp Light Oil Producing
Catatumbo Basin
Carbonera Well Logging 41,506 100% ANH E&P Oil & Gas Farm-Out
15% / 50%
Catguas Gran Tierra 330,354 (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 in
Mompos 12,558 58% ECP E&P Light Oil
Silla place
Magdalena Basin
Las Quinchas Pacific Stratus 124,493 24.5% ECP E&P H Oil To Be Sold
Rio Magdalena Gran Tierra 36,131 56% ECP E&P Gas/Cond/ Oil JV or Farm-Out
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 32.5%, subject to ANH approval. Yellow background = Core portfolio assets 31

32. PMD Today
Track Record of
Focused on
Cash Flow Positive Discoveries and
Earnings Quality
Production Growth
• Doubling of revenues: $86 • 4 discoveries at Cubiro in • Increase in NPV (1), at
million in 2011 up from 2011 Cubiro of 180% to $383
$44 million in 2010 • 1 discovery at Cubiro YTD million
• 100% funded 2012 2012 • 55% improvement in
exploration program • Increase in 2011 exit rate netbacks year over year
(4,181 boed) production of • 4 quarters of production
76% over 010 (2,374 boed) and netback increases
32
(1)NPV before taxes discounted at 10%

33. Planned Exploration Program 2012
Exploration overview 2012
• 6 exploration wells planned for Cubiro, 3 drilled in Q1 – Cernicalo-1ST on production
• 1 exploration well for Arrendajo, Arrendajo Norte – dry hole
• 1 exploration well for Carbonera , Cantaclaro-1X
• 1 exploration well for Santa Cruz
2012
Well name
Quarter
Cubiro Block
Cernicalo-1ST (formerly named Cernicalo-2X) 1 – on production
Tijereto Sur-1X 1 - testing
Alondra-1X (formerly named Turpial-1X) 1 – dry hole
Petirrojo Sur-1X 2
Copa C-1X 4
Copa A Norte-1X 4
Arrendajo Block
Arrendajo Norte-1X 1 – dry hole
Carbonera Block
Cantaclaro-1X (formerly named San Roque-1X) 1
Santa Cruz Block
Santa Cruz-1X 2 - testing
Santa Cruz-2X (contingent) 4 33

34. 2012 Development Program
Development overview 2012
• 10 Llanos development wells planned for Cubiro
2012
Well name
Quarter
Cubiro Block
Well Type WI
COPA-4 Single 57.13% Q2
COPA-5 Dual 57.13% Q2
PETIRROJO-4 Single 70.00% Q2
COPA-ASUR2 Dual 57.13% Q2
COPA-B2 Dual 57.13% Q3
COPA-B3 Dual 57.13% Q3
YOPO-2 Dual 70.00% Q3
COPA-ASUR3 Dual 57.13% Q4
PETIRROJO-5H Horizontal 70.00% Q4
COPA-6 Single 57.13% Q4 34

35. 2010 ANH Bid Round - Six E&P Assets
• Agreement for funding the exploration
commitment, resulting in PetroMagdalena
holding a 6% Working Interest on COR 33,
VMM 11 and VMM 35 and 5% Working
VMM 35 Interest on the other three in place.
VMM 11 LLA 41
COR 33
VSM 12
VSM 13
MIDDLE MAGDALENA VALLEY BASIN
CORDILLERA BASIN
UPPER MAGDALENA VALLEY BASIN
LLANOS BASIN
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36. Colombian Pipeline Infrastructure
36