1. PMD - TSXV
Staying The Course
DECEMBER 2011
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, Cerrito, Rio Magdalena, Arrendajo, 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 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 Catatumbo Basin
•Las Quinchas Panamá CATGUAS
CARBONERA LA SILLA
•Santa Cruz
•Rio Magdalena
SANTACRUZ
CARBONERA
CERRITO •Cerrito
•Carbonera-La
VALLE MEDIO
LLANOS
41 Silla
VALLE MEDIO
MAGDALENA 35
DEL MAGDALENA 11
•Carbonera
YAMU
ARRENDAJO •Catguas
RIO CUBIRO
MAGDALENA
LA PUNTA
RED blocks: CORDILLERA 33
Llanos Basin
2010 ANH E&P VALLE SUPERIOR
•Cubiro
blocks
MAGDALENA 12 VALLE SUPERIOR
MAGDALENA 13
•Arrendajo
•La Punta
TOPOYACO •Yamu
MECAYA
Brasil
Putumayo Basin
•Topoyaco
•Mecaya
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 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
Source: Petrotech Engineering Ltd. report on Cubiro block, September 30, 2011 6

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
Source: Petrotech Technical reports: September 30, 2011, December 31, 2010 and 2009 7

8. Daily Average Production 2010-2011
4000
Copa A Sur-1
3500
3000 Copa B-1
2500 Petirrojo-1
boed
2000
Yamu
1500
32.13% Cubiro Block C
1000 acquired
500 Arauco5/ Careto 13H
0 2010 base wells/
Year Q1 2011 Q2 2011 Q3 2011 Nov working interests
2010 2011 *
• Daily average for month of
November 2011
• Petirrojo 2 & 3 to be 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 : November 29, 2011) $99.79 $99.79 $99.79
+8.00 +6.85 (3) +6.85 (3)
Benchmark Quality Adjustment
Royalties (7.00) (7.00) (7.00)
Net Revenue $100.79 $99.64 $99.64
Production costs (Q3 - 2011) 14.50 14.50 14.50
Transportation & pipeline 16.50 22.50 10.00
Operating Netback $69.79 $62.64 $75.14
(1) Management estimates, as of November 2011
(2) Agreement in place – delivery volumes only on availability (only 6,200 bbls to Dec 1, 2011)
(3) Vasconia as of November 29, 2011 priced at WTI + $6.85/bbl
10

11. 2011 Work Program
Estimated 2011 capital investment budget: $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 well, Q4-2011
La Punta • 1 well (LP-4 dry) • LP-4 drilled Q2
Topoyaco • 1 well (Yaraqui-1X) • Spud August 31st ; preparing
to test
Santa Cruz • 1 well • Spud November 20th, 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
• Capital expenditure program estimated at $50 to $60 million,
excluding commitments funded by farm-ins (Carbonera, Catguas).
• 65% directed to light oil exploration and development in Cubiro and
Arrendajo.
• 6 Llanos exploration wells, 4 in Q1, 1 in Q2 and 1 Q3.
• 10 Llanos development wells, 1 in Q1, 3 in each subsequent quarter
• 2012 Llanos exploration program:
Management estimate of light oil recoverable prospective resources,
company‟s working interest share is 9.1 million barrels Un-Risked and 3.8
million barrels Risked
• Capital funded from cash and internally generated cash flow.
• No near term financing 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 budget: $50 million - $60 million (1)
Property Work Program 2012(1) Approximate timing
Exploration Drilling
Cubiro • 4 wells (3 Block B, 1 Block C) • 3 in Q1, 1 Q2, 1 Q3
• 1 contingent well (Block C)
Arrendajo • 1 well • 1 well in Q1-2012
Santa Cruz • 1 well, spud Nov, 2011 • Well will TD in Q1-2012
Carbonera • 1 well • 1 well in Q1-2012
Development Drilling
Cubiro • 7 wells • 1 well in Q1-2012
• 3 contingent wells • 3 wells each subsequent qtr.
Carbonera • 1 well • 1 well Q2-2012
(1) Management Estimate, subject to change
13

14. Annual Cash Flow (4)
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 $24M
Less: Equity tax instalments $2M $ 2M
Net cash flow from operations $23M $41M
Cash position, beginning of year $6M $17M
Cash available from equity financing for work program $35M -
Other sources/ (uses), including working capital changes and
$(6M) $ 7M
cash from asset dispositions (4)
Total cash available to fund annual work program $58M $64M
Annual work program expenditures (4) $41M $50-$60M
(1) Management estimate, 2012 estimate 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 2011 and 4,500 boed (mid-point of management guidance
range)for 2012
(3) Includes funds being set aside for May 2012 & May 2013 annual principal repayment of senior notes
(4) Management Estimate 14

15. Llanos Basin – Cubiro
Operator: PetroMagdalena Energy
WI: A:60.5% B:70% C:57.13%
Contract: ANH
Product: L/M Oil
Area: 61,295 acres
2P Reserves: 10.8 MMbbl (1)
Production: 2010 A (Year Avg): 1,905 boe/d
2011E (Year Avg): 2,100 boe/d – 2,300 boe/d(2)
About Cubiro
• Most prolific hydrocarbon basin in continental
Colombia
• Currently producing from 18 wells in the Careto,
Arauco, Barranquerro and Copa fields
• 86% increase in 2P reserves (Sept 2011 vs Dec 2010) (1)
• Improved marketing contract (Pacific Rubiales) and
reduced opex has significantly improved the netback
per barrel vs 2010
• 2011 Exploration program with three discoveries with
5.1 MMbbls (3) of recoverable reserves (2P) (1)
(1) Petrotech Report dated Sept. 30, 2011, PetroMagdalena
share, gross before royalties
(2) Management Estimates
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
Yopo, Q4-2011
Arauco
Barranquero
Sirenas • The Cubiro Block has been under an
Exploration and Production (E&P)
Petirrojo C5
37 °API
Cernicalo Petirrojo Sur Contract with ANH since October 8,
Q1-2012
2004, exploration phases followed by a
Canario Sirenas 25 year production period.
Sur
Guanapalo Copa • Currently, there are seven producing oil
C7
30 °API
Tijereto Sur fields: Careto, Arauco, Barranquero,
Q1-2012
Petirrojo, Copa, Copa B and Copa A
Copa ASur Sur.
Copa B
Jordán
Altair Copa C, Q1-2012 Caño Gandul
• Currently producing from Carbonera C-
C7
29 °API C7 C5-C7
38 °API
5, C-7 and Gacheta formations.
• Acquired an additional 32.13% of the
Cubiro C eastern area on April 15, 2011.
• Three new fields discovered at Petirrojo,
Polygon A : Polygon B : Polygon C : Copa B and Copa A Sur in Q3 2011
Development Area Exploration Area Exploration Area
60.5% W.I. 70% W.I. 57% W.I.
16

17. Petirrojo Field, Petirrojo South & Yopo
Prospects
• Petirrojo-1 encountered 32 ft of net pay.
Carbonera C7
After an initial test rate of 1,545 bopd of TWT Seismic Map
40 API light oil the well averaged 1,849
bopd (Company share, 1,294 bopd) over
the next 15 days and remains on
production. Yopo Prospect
• 2nd well (Petirrojo-3 dev well) has been
drilled and cased from the same location
Q4-2011, 3rd well (Petirrojo-2 dev well) is
currently drilling.
• Yopo exploration well planned to be
drilled when civil work is completed, Q4-
2011. Petirrojo Dev. Locations
• Petirrojo South will be drilled when civil
work has been completed, Q2-2012
2P RESERVES (1)
Petirrojo Field
(Mbbls)
Petirrojo 2,036
Petirrojo-1
RESOURCES (2)
(Mbbls)
Petirrojo South 1,100
Yopo 1,700 Petirrojo South Prospect
1 Km
(1) Company share, Sept 30, 2011 technical report
(2) Company share, Management estimate, not yet certified

18. Copa B Field, Copa A Sur & Copa AN Prospect
Carbonera C7
• Copa B-1 exploration well encountered 41 ft
of net pay. Daily average production during
TWT Seismic Map
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
2P RESERVES Sept 30, 2011 Technical Report
(Mbbls) 100% Gross Net
Copa Field
Copa Field 3,008 1,718 1,582
Copa A Sur 3,205 1,831 1,684
Copa A Norte Copa B 2,153 1,230 1,142
8,366 4,779 4,408
Copa A Sur
RESOURCES Mgmt Volumetric Estimates: C7, C5, C3
(Mbbls) 100% Gross COS Risked
Copa B % Gross
Copa A North 3,363 1,920 60 1,152
Copa C 3,509 2,004 40 802
Copa C
Copa D 2,340 1,336 40 534
9,212 5,260 47 2,488
Producing
Exploration 2012
Copa D
Development
19

20. Yaguazo Llanos Basin – Arrendajo
Mirla Negra
ARRENDAJO
Highlights
Azor
Mirla Q4-2011
Mirla
• Arrendajo is 7 km NE of the Cubiro block
Blanca
Oeste Arrendajo Norte
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
• Drilling two wells, starting in Dec. 2011
Arrendajo Sur • Six prospects in the Carbonera formation have
been identified: Azor, Yaguazo, Arrendajo
CUBIRO Norte, Arrendajo Sur, Mirla Blanca, and Mirla
Oeste
• Management estimates prospective resources
of ~ 11 MMbbl unrisked, with addition of the
new 3D seismic survey, ~ 4.5 MMbbl risked as
the companies working interest share before
royalties
Operator: Pacific Rubiales • PetroMagdalena acquiring 32.5% working
WI: 67.5% interest from Pacific Rubiales, subject to ANH
Contract: subject to ANH approval, for $10 million to be paid out of
Product: Light Oil production and paying all costs for Pacific
Area: 78,102 acres Rubiales go forward.
Resources: 8,259 Mbbl (1)
Stage: Exploration
(1) Petrotech Engineering report April 2010, adjusted for the 32.5% interest being acquired from Pacific Rubiales.
20

21. Putumayo Basin
About Putumayo
• Putumayo Basin is located in southwest Colombia
• High potential exploration targets
Highlights
• Partnered with experienced operators.
• The possibility of finding a large field and on trend
with Costayaco
• PetroMagdalena Energy has a 50% working interest in
the Topoyaco Block, subject to the ANH approval,
with a 6% overriding royalty to Trayectoria. In
addition, there is a 3.5% profit interest payable to
Grant Geophysical for the seismic work.
• PetroMagdalena has a beneficial 43% working
interest in the Mecaya Block, subject to ANH
Topoyaco & Mecaya approval, with no overrriding royalty and will pay 85%
Contracts: ANH of the cost of the first 3D and well.
Operator:
Topoyaco - Pacific Rubiales (1)
WI: 50%, subject to ANH approval Exploration Plan
Mecaya – Gran Tierra
WI: 42%, subject to ANH approval • One exploration well, Yaraqui -1X, (Prospect D)
Product: L/M oil exploration potential commenced drilling on August 31
Production: Nil
(1) Contract assignment in process subject to approval by ANH
21

22. Putumayo Basin – Topoyaco
Yaraqui-1X well spud
August 31, 2011, in the
central part of the
block.
Well: Yaraqui-1X The well reached total
Prospect: D depth of 10,651 feet
MD, targeting the
Cretaceous Villeta
and Caballos
formations, in a sub-
thrust structure called
Prospect “D”.
Testing is currently
being conducted.
Prospect ‘D; Resource Estimate -100% (mbbls)
PROSPECT LOW BEST HIGH
„D‟ 15,808 46,907 147,119
Gross
PetroMagdalena
7,904 23,453 73,560
Source: April 30, 2010 Petrotech Report (available at
www.petromagdalena.com)
22

23. 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:
• 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
23

24. Catatumbo Basin – Santa Cruz-1
Total of • Santa Cruz-1 is being drilled, and spud on
Nov. 20th, 2011, in the A Block which has
3480 acres C: 700 an area of 750 acres with a primary target
acres (Mirador) thickness of over 300 ft of high
porosity & permeability SS reservoir.
• The well reached 3,905 ft in November,
A: 750 the 13 3/8 inch casing point.
acres F: 420 • The Santa Cruz Block prospective resources are
acres based on the 3D seismic interpretations and
surrounding analog fields.
• The Santa Cruz Block has several faulted
B: 800 E: 580 structures assigned prospective resources based
acres acres on the 3D seismic interpretations and
information from the offset Rio Zulia field
Santa Cruz-1 Resource Estimate -100% (m bbls)
D: 230
PROSPECT LOW BEST HIGH
acres
„A‟ 17,000 73,000 308,000
Santa Cruz – 1, Q4 - 2011 Gross
PetroMagdalena
11,900 51,100 215,600
Operator: PetroMagdalena
Source: Management Estimate
WI: 70%
Source: Management estimate of recoverable resources based
on the 3D interpretation and are reported gross of royalties.
24

25. Capitalization
Cash position (September 30, 2011): $12.3 million
Debt (September 30, 2011):
Factoring Loan (maturing Oct 2012) $6.6 million
Bank term loans (maturing May/ Aug 2013) $7.9 million
9% Senior Notes (maturing May 2014) CA$31.1 million
Share price (December 1, 2011): CA$1.60
Shares outstanding: 142.3 million
Options outstanding ($2.17 average) 13.5 million
Warrants outstanding ($3.50) 19 million
Fully diluted: 174.8 million
Market capitalization - undiluted (December 1, 2011): CA$227.7 million
25

26. 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
26

27. Appendix
27

28. Assets in the most prolific basins
(1)
Area Operator Gross Acres WI Contract Stage Product Status
Llanos Basin
Cubiro PMD 61,295 60-70-57% ANH E&P Light Oil Core Asset*
Contract under
La Punta Vetra 19,313 Up to 6% ECP E&P Light Oil
review
Arrendajo PRE 78,102 67.5% ANH Exploration Light Oil Near Cubiro
Yamu WOGSA 18,194 10% ANH Prod & Exp Light Oil Producing
Catatumbo Basin
Carbonera PMD 63,727 96% ANH E&P Oil & Gas
Joint Venture
Cerrito PRE 10,165 76-81% ECP E&P Gas or
15%/50% Farm-Out
Catguas GTE 330,355 (2) ANH Exploration Oil & Gas
S N
Santa Cruz PMD 40,058 100% ANH Exploration Light Oil Farmed out 30% WI
Carbonera – La E&P 3D seismic work plan
PMD 12,558 58% ECP Light Oil
Silla in place
Magdalena Basin
Las Quinchas PRE 124,493 24.5% ECP E&P H Oil To Be Sold
Gas/Cond/
Rio Magdalena GTE 36,156 56% ECP E&P JV or Farm-Out
Oil
Putumayo Basin
Topoyaco PRE 60,035 50% ANH Exploration L/M Oil PRE now Operates
Mecaya GTE 74,128 43% ANH Exploration L/M Oil 3D seismic planned
(1) See Slide 2. (2) Option to acquire additional 10% S/ 30% N.
* Working interest reflects post-acquisition of Jaguar E&P CPR Consultants, S.A Yellow background = Core portfolio assets
28

29. 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
29

30. Colombian Pipeline Infrastructure
30