Investor Presentation - September 2011 (English)

1. PMD - TSXV
Staying The Course
SEPTEMBER 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. Leadership team focused on strategy execution
2. Enhancing netbacks, reducing costs, increasing
efficiency
3. Focus on core oil assets – exploration and
development
4. Maximize value from other assets in the portfolio -
with strong partners
IMPROVING HIGH
EXPERIENCED POTENTIAL
OPERATING DRIVING VALUE
LEADERSHIP EXPLORATION
CASH FLOW ASSETS
Goal is to increase production and reserves
3

4. Focus on core oil assets
Catatumbo Basin
•Santa Cruz
•Cerrito
Magdalena Basin •Carbonera-La
•Las Quinchas Silla
•Rio Magdalena •Carbonera
•Catguas
Llanos Basin
•Cubiro
•La Punta
•Arrendajo
•Yamu
Putumayo Basin
•Topoyaco
•Mecaya
4

5. Achievement scorecard
On Target Ongoing
Reduced G&A by 29% Q2 2011 vs 2010 Qtrly average 
Increased Netback by 47% H1 2011from FY2010 average 
Increasing production and reserves O
Drilling program at Cubiro 
Exploration at Cubiro 
Spudding of Topoyaco – D 
Received environmental permit for Santa Cruz 
Spudding of Santa Cruz * O
Funded work plan in place 
Farm out Carbonera and Catguas to YPF** 
Sale of Las Quinchas & farm out of other non-core assets O
PetroMagdalena is staying the course with achievable milestones
* Civil and other works have begun to prepare the field
** Subject to ANH approval 5

6. 2P Reserves*
Crude Oil Natural Gas NGL Total
(mmbbl) (mmcf) (mmbbl) (mmBOE)
December 31, 2010:
Total Proved (P1) 2.77 27.78 0.71 8.12
Total Proved +
9.33 99.78 4.37 30.33
Probable (2P)
Change in 2P vs
2.72 (19.86) (0.73) (1.33)
December 2009
Focus on Core Oil Assets:
• Game changer at Cubiro: added 1 MMbbls at Cubiro C (from acquisition)
and exploration success at Petirojo +1.87 MMbbls and Copa B +1.28
MMbbls (mgmt estimate; not yet certified)
• Company’s gross 2P oil reserves increased by 41% in 2010
• Cubiro key driver fuelling recent 2P oil reserve growth
• Increased 126% in 2010 to 5.8 MMbbls
• Represents 62% of 2P oil reserves
*December 2010 and 2009 Petrotech Reports (available at www.petromagdalena.com and www.sedar.com);
represents PetroMagdalena’s gross share before deduction of royalties.
6

7. Daily Average Production 2010-2011
4500
4000
3500 Copa B-1 (3-day test)
3000
Petirrojo-1
2500
boed
Yamu
2000
1500 32.13% Cubiro Block C
acquired
1000
Arauco5/ Careto 13H
500
0 2010 base wells/
working interests
Year 2010 Q1 2011 Q2 2011 Current *
* September 1-11, 2011 daily average
7

8. 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
$60 $35
G &A per barrel
$50 $30
$25
$40
Netback
$20
$30
$15
$20
$10
$10 $5
$- $-
Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2- 2011
Operating Netback G&A
8

9. 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 9

10. 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) $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.
10

11. 2011 Work program
Estimated 2011 capital investment budget: $40 million - $50 million (1)
Property Work Program 2011(1) Approximate timing
Exploration Plan
Cubiro • 3 wells (1 Block B, 2 Block C) • 2 drilled, 2 discoveries
• Yopo well added to program • Yopo well, Q4-2011
(Block B)
La Punta • 2 wells (LP-4 dry) • LP-4 drilled Q2, LP-5 Q4
Topoyaco • 1 well (Yaraqui-1X) • Spud August 31st
Santa Cruz • 1 well • Spud Early Q4-2011
Development Plan
Cubiro • 3 wells + 3 WOs + facilities, • 2 wells completed in Q1-
including storage 2011
• 1 well in Q3, WO’s in Q4-2011
• 1 well added to program • Petirrojo-2 well in Q4-2011
(Block B)
(1) Management Estimate, subject to change
11

12. 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: 5.8 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
• 126% increase in 2P reserves (Dec 2010 vs Dec 2009)
• April 15, 2011 acquisition (Jaguar) represents
incremental 1.0 MMbbls in 2P reserves as of Dec 31,
2010
• Improved marketing contract PRE and reduced
opex has significantly improve the netback per
Petrotech Dec 31, 2010 Report , PetroMagdalena share,
(1)
barrel vs 2010 gross before royalties
• 2011 Exploration program two discoveries with Mgmt Management estimate , including impact of April 15,. 2011
(2)
estimate of 3.1 MMbbls (3) of recoverable reserves. Jaguar acquisition
(3) Company share, not yet certified
12

13. Llanos Basin - Cubiro
Highlights
Field
• Operated by PetroMagdalena Energy
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, followed by a 25 year production
period.
Sirenas
• Currently, there are six producing oil
Canario
Sur
Guanapalo Copa fields: Careto, Arauco, Barranquero,
C7
30 °API
Tijereto Sur
Q1-2012
Copa, Copa B and Petirrojo.
Copa AS • Currently producing from Carbonera C-
Copa B 5, C-7 and Gacheta formations.
Jordán
Copa C, Q1-2012
C7
29 °API
Altair
C7
Caño Gandul
C5-C7 • Acquired an additional 32.13% of the
38 °API
Cubiro C eastern area on April 15, 2011.
• Two new fields discovered at Petirrojo
and Copa B 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.
13

14. 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
• Petirrojo-2 development well will be drilled
from the same location Q4-2011.
• Yopo exploration well to be drilled when
civil work is completed, Q4-2011.
• Petirrojo South will be drilled when civil
work has been completed, Q2-2012 Petirrojo Dev. Locations
CURRENT MGMT. ESTIMATES (1)
Recoverable
Reserves
(MM Bbls) Petirrojo Field
Petirrojo 1,870
RESOURCES Petirrojo-1
(MM Bbls)
Petirrojo South 1,100
Yopo 1,700 Petirrojo South Prospect
1 Km
(1) Company share, not yet certified

15. Copa B Field, Copa AS & Copa AN Prospect
Carbonera C7
• Copa B-1 exploration well encountered 41 TWT Seismic Map
ft of net pay. Initial 3-day test rate of 1,045
bopd (Company share, 597 bopd) of 39.3°
Copa AN Prospect
API light oil. The well will be put on test in 2
zones for approximately 6 weeks and then
a full testing program on all zones will be
completed.
• Copa AS-1 exploration well will be drilled Copa AS Prospect
from the same location in Q3-2011.
• The Copa C structure to the south of Copa
B will be drilled in Q1-2012
Copa AS-1
CURRENT MGMT. ESTIMATES (1)
Recoverable
Reserves
(MM Bbls) Copa B Field
Copa B-1 1,260
RESOURCES
(MM Bbls)
Copa B -1
Copa AS-1 1,002 1 Km
(1) Company share, not yet certified
15

16. Cubiro ‘C’ Area – Copa Upside
RESERVES COPA (MM Bbls)
Petrotech Dec 2010 Gross
100% 25% 57.13%
Copa Field Proved 1,592 398 910
Probable 1,599 400 914
2P 3,192 798 1,825
Copa A North
RESERVES COPA B (MM Bbls)
Management Estimate Gross
Copa A South 100% 25% 57.13%
Recoverable
2,210 553 1,260
Reserves
Copa B
RESOURCES Mgmt Volumetric Estimates: C7, C5, C3 (MM bbls)
100% 25% 57% COS Risked
% 57%
Copa C Copa A North 3,363 841 1,920 60 1,152
Copa A South 2,925 731 1,670 60 1,002
Exploration 2011 Copa C 3,509 877 2,004 40 802
Exploration 2012
Copa D 2,340 585 1,336 40 534
Copa D 12,137 3,034 6,930 200 3,490
Development
@ 25% WI @ 57% WI Change
COPA 2P Reserves (MM bbl) 798 1,825 1,027
COPA B Recoverable (MM bbl) 553 1,260 708
COPA Exp. Risked Upside (MM bbl) 1,528 3,490 1,962 16

17. 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.
• PetroMagdallena Energy has a 42% working interest
in the Mecaya Block, subject to ANH approval, with
Topoyaco & Mecaya no overrriding royalty and will pay 85% of the cost of
Contracts: ANH the first 3D and well.
Operator:
Topoyaco - Pacific Rubiales (1)
WI: 50%, subject to ANH approval Capital Investment Plan
Mecaya – Gran Tierra
WI: 42%, subject to ANH approval • One exploration well, at Prospect D on Topoyaco, will
Product: L/M oil exploration potential be drilled in Q3 of 2011
Production: Nil
(1) Contract assignment in process subject to approval by ANH
17

18. Putumayo Basin – Topoyaco
Yaraqui-1X well spud
August 31, 2011, in the
central part of the
block. The well plan is
Well: Yaraqui-1X to reach a total depth
Prospect: D 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)
18

19. 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 led exploration program
• Retain working interests of 15% in North area and 4.5% in South area
• Carried through 2012 work program
19

20. Catatumbo Basin – Santa Cruz-1
Total of 3480 • Santa Cruz-1 will be drilled in Q4-2011, in
the A Block, with an area of 750 acres and
acres C: 700 an expected primary target (Mirador)
acres thickness of over 300 ft of high porosity
and permeability sandstone reservoir.
• The environmental permit has been issued
A: 750 and civil work has started on the location.
F: 420
acres • 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.
20

21. 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 (Sept 6, 2011): CA$0.95
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 (Sept 6, 2011): CA$135.2 million
21

22. 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
22

23. Appendix
23

24. Assets in the most prolific basins
(1) Gross
Area Operator WI Contract Stage Product Status
Acres
Llanos Basin
Cubiro PMD 61,295 60-70-57% ANH E&P Light Oil Core Asset*
La Punta Vetra 19,313 Up to 6% ECP E&P Light Oil Drilling Q4
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 Farm out potential
Carbonera – E&P 3D seismic Work
PMD 12,558 58% ECP Light Oil
La Silla plan 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
24

25. Llanos Basin – Arrendajo
Highlights
• Operated by Pacific Rubiales Energy
• Several light oil prospects on trend with
producing oil fields
Sector A: 3% ORR
• 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
• Mirla Negra-1 well tests on the C-5 over the
ARRENDAJO perforated interval of 5,506 - 5,510 feet MD
Sector B: 3% ORR showed a daily rate of 130 barrels of oil at 34.5°
Cubiro API with a 69% water cut.
• Management estimates resources of ~ 5
Petirrojo
20 MMbbl with addition of the new 3D seismic
survey
Operator: Pacific Rubiales
WI: 35% • PetroMagdalena acquired overriding royalties
Contract: ANH of 4% and 3% in the A and B sectors,
Product: Light Oil respectively, on the block in April 2011.
Area: 78,102 acres • Arrendajo is 7 km NE of the Cubiro block
Resources: 3,059 Mbbl (1)
Stage: Exploration
(1) Petrotech Engineering report April 2010
25

26. 2010 ANH Bid Round
Six New E&P Assets
Agreement for funding the
exploration commitment
resulting in PetroMagdalena
holding a 10% Working Interest.
VMM 35
VMM 11 LLA 41
COR 33
VSM 12
VSM 13
MIDDLE MAGDALENA VALLEY BASIN
CORDILLERA BASIN
UPPER MAGDALENA VALLEY BASIN
LLANOS BASIN
26

27. Colombian Pipeline Infrastructure
27

28. Valuation metrics
As at September 6, 2011
$120,000 $60,000,000
$114,122x
$49,559,154x
Market Capitalization / Reserves (mmBOE)
Market Capitalization / Production (boed)
$100,000 $50,000,000
$80,000 $40,000,000
$64,338x
$60,000 $30,000,000
$40,000 $20,000,000
$14,488,295x
$20,000 $10,000,000
$- $-
PetroMagdalena Energy Peer* PetroMagdalena Energy Peer*
Corp Corp
Source: Bloomberg & Company 2011 Q2 MD&A Reports
*Peer: Gran Tierra, Canacol, Parex, Petrodorado & C&C Energia
28