1. PMD - TSXV
Staying The Course
NOVERMBER 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. PetroMagdalena today
1. Focused on organic cash flow opportunities in the portfolio
2. Enhanced netbacks, reduced costs, increased efficiency
3. Exploration success at Cubiro in 2011 now leading to increased
development activity in 2012 in that block
4. Maximizing value from other assets in the portfolio - 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
•La Punta
MAGDALENA 13
•Arrendajo
TOPOYACO
•Yamu
MECAYA
Brasil
Putumayo Basin
•Topoyaco
•Mecaya
4

5. Achievements Q1 through Q3
Achieved Ongoing
Reduced G&A by 29% Q2 2011 vs 2010 Qtrly average 
Increased Netback by 47% H1 2011from FY2010 average 
Increased reserves at Cubiro by 86% *** 
Drilling program at Cubiro O
Exploration at Cubiro O
Spud Yaraqui-1X at Topoyaco – D, Aug 31st, 2011 
Received environmental permit for Santa Cruz 
Farm out of Santa Cruz 
Spudding of Santa Cruz * O
Farm out Carbonera and Catguas to YPF** 
Sale and/or farm out of other assets O
* Civil works completed and rig has been mobilized
** Subject to ANH approval
*** Petrotech report on Cubiro block, September 30, 2011
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 test
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 Oct working interests
2010 2011 *
* October, 2011 daily average;
Copa A Sur-1 based on 75 flowing hours
during initial 4-day production test
8

9. Strengthened 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
• 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
G &A per barrel
$60 $35
$30
Netback per
$50
$25
$40
barrel
$20
$30
$15
$20
$10
$10 $5
$- $-
Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2- 2011
Operating Netback G&A
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
Vasconia Vasconia Vasconia (2)
WTI (Nymex) $80 $80 $80
Benchmark Quality Adjustment +8 +20 +20
Net revenue 88 100 100
Production costs (2011E; year
avg) 13 13 13
Transportation & pipeline 16 23 10
Netback $57 $64 $77
(1) Management estimates, as of September 2011
(2) Signing agreement in process – delivery volumes on availability 10

11. 2011E Cash flow (1)
Operating cash flow from netbacks (2) $58 million
Less: G&A (including one-time costs in Q1) $15 million
Less: Debt service ongoing (principal & interest) (3)
$18 million
Net cash flow from operations $25 million
Cash available from equity financing $35 million
Total sources to fund 2011 capex plan and
$60 million
working capital
2011E capex plan $40-$50 million
(1) Management estimate
(2) Represents estimated revenues less royalties, production and transportation costs based upon average
daily production of 2,800 boe/d for the year.
(3) Includes funds being set aside for May 2012 annual principal repayment of senior notes
11

12. 2011 Work program
Estimated 2011 capital investment budget: $40 million - $50 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) • Driling, spud August 31st
Santa Cruz • 1 well • Spud Q4-2011, rig mobilizing
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
12

13. 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
13

14. Llanos Basin - Cubiro
Highlights
Field
• Operated by PetroMagdalena
Prospect
• All production is subject to the sliding
scale royalty rates of ANH and a 3%
Palmarito
C7
40 °API
overriding royalty on total production
Careto from the Block.
Turpial
Yopo, Q4-2011
• The Cubiro Block has been under an
Exploration and Production (E&P)
Arauco Sirenas
Barranquero
Petirrojo C5
37 °API
Contract with ANH since October 8,
Cernicalo
Q1-2012
Petirrojo Sur
2004, exploration phases followed by a
25 year production period.
Sirenas
• Currently, there are seven producing oil
Canario
Sur
Guanapalo Copa fields: Careto, Arauco, Barranquero,
C7
30 °API
Tijereto Sur
Q1-2012
Petirrojo, Copa, Copa B and Copa A
Sur.
Copa ASur
Copa B • Currently producing from Carbonera C-
5, C-7 and Gacheta formations.
Jordán
Altair Copa C, Q1-2012 Caño Gandul
C7
29 °API C7 C5-C7
38 °API
• Acquired an additional 32.13% of the
Cubiro C eastern area on April 15, 2011.
• Three new fields discovered at Petirrojo,
Copa B and Copa A Sur in Q3 2011
Polygon A : Polygon B : Polygon C :
Development Area Exploration Area Exploration Area
60.5% W.I. 70% W.I. 57% W.I.
14

15. 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

16. 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
16

17. 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
17

18. 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
18

19. Putumayo Basin – Topoyaco
Yaraqui-1X well spud
August 31, 2011, in the
central part of the
block.
Well: Yaraqui-1X The well plan is to
Prospect: D reach a total depth of
10,509 feet MD, or
9,402 feet TVD,
targeting the
Cretaceous Villeta
and Caballos
formations, in a sub-
thrust structure called
Prospect “D”.
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)
19

20. 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
20

21. Catatumbo Basin – Santa Cruz-1
Total of • Santa Cruz-1 will be drilled in Q4-2011, in
the A Block, with an area of 750 acres and
3480 acres C: 700 an expected primary target (Mirador)
acres thickness of over 300 ft of high porosity
and permeability sandstone reservoir.
• Location being prepared, rig being
A: 750 mobilized.
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.
21

22. Capitalization
Cash position (June 30, 2011): $26.5 million
Debt (June 30, 2011):
Bank term loans $9.5 million
18-month factoring Loan $8.6 million
3-year 9% Senior Notes CA$31.1 million
Share price (Nov 11th, 2011): CA$1.60
Shares outstanding: 142.3 million
Options outstanding ($2.52 average) 9.5 million
Warrants outstanding ($3.50) 19 million
Fully diluted: 170.8 million
Market capitalization - undiluted (Nov 11th, CA$227.7 million
2011):
22

23. 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
23

24. Appendix
24

25. 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 35% 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
25

26. 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
26

27. Llanos Basin – Arrendajo
Highlights
• Arrendajo is 7 km NE of the Cubiro block
• Operated by Pacific Rubiales Energy
• Several light oil prospects on trend with
Sector A: 3% ORR
producing oil fields
• 120 km2 of 3D survey completed in April 2011,
currently being evaluated
• Five prospects in the Carbonera formation
have been identified: Mirla Blanca, Yaguazo,
Tigua, Buho and Babillas
ARRENDAJO • Mirla Negra-1 well tests on the C-5 over the
Sector B: 3% ORR
perforated interval of 5,506 - 5,510 feet MD
Cubiro showed a daily rate of 130 barrels of oil at 34.5°
API with a 69% water cut.
Petirrojo
20 • Management estimates resources of ~ 5
Operator: Pacific Rubiales MMbbl with addition of the new 3D seismic
WI: 35% survey
Contract: subject to ANH • PetroMagdalena acquired overriding royalties
Product: Light Oil of 4% and 3% in the A and B sectors,
Area: 78,102 acres respectively, on the block in April 2011.
Resources: 3,059 Mbbl (1)
Stage: Exploration
(1) Petrotech Engineering report April 2010
27

28. Colombian Pipeline Infrastructure
28