1. PetroMagdalena
Investor Presentation TSX-V: PMD
June 2012 www.petromagdalena.com

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 “to be”, “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 POTENTIAL DRIVING
OPERATING
LEADERSHIP EXPLORATION VALUE
CASH FLOW
ASSETS
Goal is to increase production and reserves 3
3

4. PetroMagdalena is in the right country,
focused in the right basin
Oil opportunities are significant, proven reserves of
over 2 billion barrels(1)
500% increase in exploration activity – +50% success(1)
Consistently high exploration success in Colombia has
encouraged investment - key success factor for future
opportunities
Most secure country in Latin American in which to do
business (1)
120 70%
Number of Wells Drilled
100 60% (2)
Success Factor
50%
80
40%
60
30%
40 20%
20 10%
0 0%
2004 2005 2006 2007 2008 2009 2010 2011
(1) World Bank, Doing Business 2010 and 2011 Reports
(2) ANH Report
Number of wells Success factor 4

5. 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 2011 • Increase in NPV (1), at Cubiro
million in 2011 up from $44 • 1 discovery at Cubiro and 1 at of 180% to $383 million
million in 2010 Arrendajo YTD 2012 • Q1 2012 is the 4th
• 100% funded 2012 exploration • Increase in 2011 exit rate(2) consecutive quarter of
program (4,181 boed) production of production improvement
76% over 2010
• Q1 2012 is the 5th
consecutive quarter of
netback improvement
(1) NPV before taxes discounted at 10%. Source: NI 51-101 Technical Report, Petrotech Engineering, December 2009, December 2010 and December
2011. Reserves before royalties based on working interest 5
(2) Exit rate presented is the average production rate for December, being the last month of the year.

6. Diversified Portfolio
CATATUMBO BASIN
• Santa Cruz (3)
• Carbonera
• Catguas (4)
LLANOS BASIN • Carbonera-La Silla (2)
• Cubiro (1)
• Arrendajo (2)
• LLA 47
• Yamu
• La Punta
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 Rubiales
BLUE blocks:
(3) Operated by Mompos Oil and Gas, a 2010 ANH E&P blocks
wholly owned subsidiary.
(4) Operated by Gran Tierra
6

7. 43% increase in 2P oil reserves
$145 Million increase in 2P NPV (1)
2011 provided higher 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
394,039 25
$400,000 358,884
20
15
$200,000 10 13.3
5 9.3
6.6
$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
7

8. Production
2012 guidance of 4,300 – 4,700 boed
6,000 4,300 –
Production (BOEPD)
4,700 boed
4,000
3624 3847
2713
2,000 2286 2410
0
Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 2012
Production Production Forecast
* Cernicalo-1ST put on production February 25th, 2012
* Azor-1X put on production January 31st, 2012
8

9. It’s All About Brent Now
$150
$130
Q1 2012 Avg. oil sales price =
$110
$113.50 per barrel
USD
$90
$70
$50 Brent linked to
Vasconia
$30
Source: Bloomberg
Brent WTI Vasconia
• Leveraging marketing strategy to capture positive premium to WTI.
• 1st quarter 2012 premium to WTI was approximately $10 per barrel.
9

10. Cubiro’s Netback
• A 3-year conventional oil marketing agreement signed with Pacific Rubiales on Feb. 1st, 2011
• A six (6) month oil sales purchase agreement signed with Ecopetrol on May 4th, 2012
• Lower Trucking costs expected for deliveries to Cusiana or Bicentenario, would positively impact
netback 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)
Client - Delivery Point / Reference Price : Rubiales/ Araguaney / Guaduas / Vasconia
Q4 - 2011 Q1 - 2012 (3) MAY 2012 (1)
WTI Average (Nymex) 93.23 102.16 92.21
Benchmark Quality Adjustment 14.14 11.13 10.80
Royalties (2) -8.21 -7.06 -7.00
Net Revenue 99.16 106.23 96.01
Production Costs -19.20 -11.81 -12.00
Transportation & pipeline -18.63 -14.19 -21.00
Operating Netback 61.33 80.23 63.01
(1) Management estimates, as of May 29th, 2012.
(2) Royalties presented on a per barrel of oil basis. ANH royalty oil is taken in kind at the wellsite.
(3) Production Costs and Transportation & Pipeline Costs presented are the average for Q1 2012. 10

11. 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
Operating Netback per G&A per barrel sold
barrel
$100.00 $25.00
$90.00
$80.00
43% $20.00 39%
$70.00 $74.66 $18.40
$60.00 $15.00
$50.00
$52.27
$40.00 $10.00 $11.20
$30.00
$20.00 $5.00
$10.00
$- $- 11
Q1 - 2011 Q1 - 2012 Q1 - 2011 Q1 - 2012

12. 2012 Work Program Overview
• Revised budget with capital expenditure estimated in range of $75 to $80 million
• 65% planned to be directed to light oil exploration and development in Cubiro and
Arrendajo
• 2012 Work program to be funded from cash from operations, cash balances, proceeds
from non-core assets dispositions and banking facilities to manage working capital as
required
• Facility program to replace rental facilities and reduce OPEX. Preparing to install low
cost natural gas generator for generating field power and replacing diesel
• To date in 2012, drilled 5 exploration wells and 1 development well
• 10 development wells planned for the balance of 2012, with 3 exploration wells in Q4
in the Llanos Basin
• The next 6 months are focussed on development drilling to grow production
12

13. Annual Cash Flow
2011A 2012E (1)
2,761
Average daily production for the year (gross before royalties) 4,300-4,700 boed
boed
Cash flow from operating netbacks (4) $54.3M (3) $102M (2)
Less: G&A $14.7M $18M
Less: Debt service (principal & interest) $18.4M $24 (5)
Less: Equity tax instalments $2.1M $ 2M
Net cash flow from operations $19.1M $58M
Cash position, beginning of year $6.5M $14M
Cash available from equity financing for work program $35.0M -
New Cash Financing $15M (7)
Other sources/ (uses), including working capital changes and
$10.4M - (1)
cash from asset dispositions
Total cash available to fund annual work program $71.0M $87M
ANNUAL WORK PROGRAM EXPENDITURES $56.9M (6) $75 - $80M
(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)
13
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.
(7) Includes $11million borrowed in March 2012 and additional $10 million potential borrowing in 2012, net of amount to be replaced in 2012

14. Llanos Basin
Recoverable Oil
More than 1,500 MMbbl of recoverable
Arrendajo
oil has been officially documented in
this basin (2)
Cubiro Reserves Cubiro
Reserve Category Gross
L&M Crude Oil (Mbbl) (1)
Proved 5,564 LLA-47
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
(2) ANH 14

15. Llanos Basin - Cubiro
CUBIRO
Producing Field
Prospect Palmarito
Highlights
C7
40 API • Operated by PetroMagdalena
• 4 discoveries in 2011, 1 YTD 2012
Careto
Alondra
Q1 -2012 Yopo, Q4-2011 • The Cubiro Block has been under an E&P Contract
Arauco
Barranquero
Petirrojo
Sirenas
C5
with ANH since October 8, 2004. Exploration phase
37 API
followed by a 25 year production period.
Petirrojo Sur
Q2 - 2012
Cernicalo
Q1-2012
Sirenas
Canario
Sur MAIN FACILITY AT CARETO
Guanapalo Copa
C7
Tijereto Sur Copa A Norte
30 API
Q1-2012 Q4-2012
Copa A Sur
Copa B
Jordán
Altair Copa C, Q4-2012 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.
Yopo Field
• Petirrojo-1X cumulative production
block over 240,000 bbls 40 API oil
produced
• Developed a plan in order to replace
rented facilties to reduce Opex
EXPLORATION
• Petirrojo Sur-1X exploration well will be
drilled in Q4-2012, civil work was
completed in Q1 2012. Petirrojo Field
CURRENT TECHNICAL REPORT
2P RESERVES
(Mbbls)
(1) Petirrojo-1
Petirrojo 1,569
Yopo 1,415 Petirrojo Sur-1X Prospect
1 Km
(1) Reserves before royalties based on working interest 16
Source: NI 51-101 Technical Report, Petrotech Engineering, December 2011

17. Copa, Copa A & Copa B 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 is COPA FIELD
planned to determine reservoir limits.
• Copa-5 planned 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
Copa B 1,379
COPA B FIELD
Copa A Sur 2,375 1 Km
(1) Reserves before royalties based on working interest 17
Source: NI 51-101 Technical Report, Petrotech Engineering, December 2011

18. Copa, Copa A & Copa AS Fields
Carbonera C7 TWT Seismic Map
2P RESERVES Dec 31, 2011 Petrotech Technical Report
(Mbbls) 100% Gross Net
Copa Field
Copa Field 2,991 1,709 1,572
Copa A Norte
Q4-2012 Copa A Sur 4,157 2,375 2,185
Copa B 2,570 1,468 1,352
Copa A Sur
9,718 5,552 5,109
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. Llanos Basin – Arrendajo
Highlights
• Arrendajo is 7 km NE of the Cubiro block
• Operated by Pacific Rubiales Energy Corp.
• 120 km2 of 3D survey completed in April 2011,
interpretation shows 6 light oil prospects on trend
with producing oil fields
• Azor discovered in January 2012 and was initially
put on production on January 31, 2012.
• Four exploration prospects in the Carbonera
formation have been identified for Drilling:
Yaguazo, Arrendajo Sur, Mirla Blanca, and Mirla
Oeste
• 3D seismic required to map complete trend,
expected to be acquired in 2013.
Operator: Pacific Stratus Energy Colombia (1) • PetroMagdalena acquired 32.5% additional
WI: 67.5% working interest, from Pacific Rubiales in
Contract: subject to ANH approval November 2011, subject to ANH approval, for $10
Product: Light Oil million to be paid out of production.
Area: 78,102 acres 19
(1) A wholly owned subsidiary of Pacific Rubiales Energy Corp.

20. Arrendajo Block Azor discovery - Upside
Highlights
• Azor-1X was drilled and completed on January 31,
2012. The well tested at 870 bopd. Average
production for March and April 2012 was 830 bopd
natural flow adding 560 bopd to PetroMagdalena’s
gross working interest production.
• Three development locations identified on the
Azor structure planned to be drilled in the second
half of 2012.
• Mirla Negra-1X drilled in 2008, tested oil and water
in the C5 but was not declared commercial.
• Azor Sur exploration prospect identified south of
Azor and north of the low quality sands
encountered in Arrendajo Norte-1X and Arrendajo
Norte-1ST.
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 on the LLA-47 Block
• 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 expected
• 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. Update map
Catatumbo Basin
Catatumbo Basin
About Catatumbo
Located in northwest Colombia, the Catatumbo Basin
Catguas has high potential exploration targets. It is the
western extension of the very prolific Maracaibo
basin in Venezuela
Highlights
Carbonera
La Silla Carbonera: 100% working interest, subject to ANH
approval. MOU signed with YPF to farm out 60%.
Santa Cruz: 70% working interest.
Carbonera La Silla Block: 58% working interest, an
Carbonera
Ecopetrol association contract. Mompos is the
operator.
Santa Cruz Catguas: MOU signed with YPF to farm out 70%.
Northern area: 50% working interest.
Southern area: 15% working interest;
Gran Tierra is the operator.
(1) Wholly owned Subsidiary of Gran Tierra Energy 22
(2) Wholly owned subsidiary of PetroMagdalena.

23. To be summarized and
Putumayo Basin - Mecaya organized like slide 24
About Putumayo
• Putumayo Basin is located in southwest
Colombia
• High potential exploration targets
Highlights
• Partnered with experienced operators.
Mecaya • PetroMagdalena has a beneficial 58% 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
• PetroMagdalena has a 50% working interest in
Contracts: ANH
Operator: the Topoyaco Block, subject to the ANH
Mecaya – Gran Tierra approval, with a 6% overriding royalty to
WI: 43%, subject to ANH approval Trayectoria. In addition, there is a 3.5% profit
Topoyaco – Pacific Rubiales
WI: 50%, subject to ANH approval
interest payable to Grant Geophysical for the
Product: L/M oil exploration potential seismic work.
Production: Nil 23

24. Capitalization
Cash position (March 31, 2012): $3.7 million
Debt (March 31, 2012):
Factoring Loan (maturing October 2012) $4.1 million
Bank term loans (maturing June/September 2013) $6.2 million
Bank term loan (maturing March 2015) $11.2 million
9% Senior Notes (maturing May 2014) C$31.1 million(1)
Share price (June 4, 2012): C$1.25
Shares outstanding: 149.2 million
Options outstanding ($2.16 average) 13.7 million
Warrants outstanding ($3.50) 19.0 million
Fully diluted: 174.8 million
Market capitalization - undiluted (May 30, 2012): C$163 million
(1) $10.4 million repaid in May 2012. 24

25. Leadership Team
Head office Management Directors
333 Bay Street, Suite 1100 Luciano Biondi Jaime Perez Branger
Toronto, Ontario M5H 2R2 Chief Executive Officer Executive Chairman
Gregg K. Vernon, P. Eng. Robert Metcalfe
Colombia office Chief Operating Officer Lead Independent Director
Calle 95 No. 13-35/43 Piso 4 Michael Davies, C.A. Miguel de la Campa
Bogota, D.C., Colombia Chief Financial Officer
Serafino Iacono
Francisco Bustillos, M.Sc.
Investor Relations Colombian Finance & Ian Mann
Investorrelations@ Administration Manager Luis Miguel Morelli
petromagdalena.com
Jesus Aboud Nelson Ortiz
Exploration Manager
Peter Volk, LL.B.
General Counsel & Secretary 25

26. Appendix
26

27. Valuation Gap
Colombian E&Ps are trading at compressed multiples relative to
140 International E&P companies = growing value gap 140
120 120
100 100
WTI Spot
80 80
Index
60 60
40 40
20 20
0 0
Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12
Colombia E&P* International E&P** S&P/ TSX Energy Index S&P/ TSX Composite WTI Spot Value Gap
Source: Bloomberg; January 4, 2011 – May 23, 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. 27

28. Assets in the most prolific basins
(2) Gross (2)
Area Operator WI Contract Stage Product Status
Acres
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
LLA-47 Interoil 44,676 50% ANH Prod & Exp Light Oil Near Cubiro
Catatumbo Basin
Carbonera Well Logging 41,506 100% ANH E&P Oil & Gas Under Review
15% / 50%
Catguas Gran Tierra 330,354 (1) ANH Exploration Oil & Gas Under Review
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
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 58% ANH Exploration L/M Oil 3D seismic planned
(1) After Farm Out to YPF WI retained would be 4.5% S/15% N. (2) Subject to ANH /ECOPETROL approvals.
28
* Working interest reflects acquisition of PRE’s 32.5%, subject to ANH approval. Yellow background = Core portfolio assets

29. 2010 ANH Bid Round - Six E&P Assets
• Agreement with third party for funding the
exploration commitment, resulting in
PetroMagdalena holding a 6%
Working Interest on COR 33, VMM 11 and
VMM 35
VMM 35 and 5% Working Interest on the
other three blocks.
VMM 11 LLA 47
COR 33
VSM 12
VSM 13
MIDDLE MAGDALENA VALLEY BASIN
CORDILLERA BASIN
UPPER MAGDALENA VALLEY BASIN
LLANOS BASIN
29

30. Colombian Pipeline Infrastructure
30