SEPTEMBER 2011

INVESTOR PRESENTATION

PMD - TSXV

Staying The Course

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 lawsconcerning 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 variousoil and gas projects of PetroMagdalena Energy; synergies and financial impact of completed acquisitions; the benefits of the acquisitions andthe development potential of the properties of PetroMagdalena Energy; the future price of oil and natural gas; the estimation of oil and gasreserves; the realization of oil and gas reserve estimates; the timing and amount of estimated future production; costs of production; success ofexploration 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-lookingstatements. 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-lookingstatements 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 materiallyfrom those projected in the forward-looking statements. Many of these assumptions are based on factors and events that are not within thecontrol of PetroMagdalena Energy and there is no assurance they will prove to be correct. Factors that could cause actual results to varymaterially from results anticipated by such forward-looking statements include changes in market conditions, risks relating to internationaloperations, fluctuating oil and gas prices and currency exchange rates, changes in project parameters, the possibility of project cost overrunsor unanticipated costs and expenses, labour disputes and other risks of the oil and gas industry, failure of plant, equipment or processes tooperate as anticipated, acquisitions not being integrated successfully or such integration proving more difficult, time consuming or costly thanexpected as well as those risk factors discussed or referred to in PetroMagdalena Energy’s public filings with the securities regulatory authoritiesin the provinces of Canada and available at www.sedar.com. Although PetroMagdalena Energy has attempted to identify important factorsthat 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-lookingstatements will prove to be accurate, as actual results and future events could differ materially from those anticipated in suchstatements. PetroMagdalena Energy undertakes no obligation to update forward-looking statements if circumstances or management’sestimates or opinions should change except as required by applicable securities laws. The reader is cautioned not to place undue reliance onforward-looking statements. Statements concerning oil and gas reserve estimates may also be deemed to constitute forward-lookingstatements to the extent they involve estimates of the oil and gas that will be encountered if the property is developed. Comparative marketinformation 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 conversionmethod 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 principlesindicate 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 developmentand contingent resources that have not been adjusted for risk based on the chance of development. It is not an estimate of volumes that maybe 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 andMecaya, it is currently in the process of completing the required approvals from ANH/ Ecopetrol, as applicable, for the formal transfer of title

and operatorship.

2

3

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

EXPERIENCED LEADERSHIP

IMPROVING OPERATING CASH FLOW

HIGH POTENTIAL

EXPLORATION ASSETS

DRIVING VALUE

PetroMagdalena today

Goal is to increase production and reserves

Focus on core oil assets

Catatumbo Basin•Santa Cruz•Cerrito

•Carbonera-La Silla•Carbonera•Catguas

Llanos Basin•Cubiro•La Punta•Arrendajo•Yamu

Putumayo Basin•Topoyaco•Mecaya

Magdalena Basin•Las Quinchas•Rio Magdalena

4

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

5

PetroMagdalena is staying the course with achievable milestones

Achievement scorecard

* Civil and other works have begun to prepare the field

** Subject to ANH approval

2P Reserves*

Crude Oil(mmbbl)

Natural Gas (mmcf)

NGL (mmbbl)

Total(mmBOE)

December 31, 2010:

Total Proved (P1) 2.77 27.78 0.71 8.12

Total Proved + Probable (2P)

9.33 99.78 4.37 30.33

Change in 2P vs

December 20092.72 (19.86) (0.73) (1.33)

*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

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

7

Daily Average Production 2010-2011

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Year 2010 Q1 2011 Q2 2011 Current *

bo

ed

Copa B-1 (3-day test)

Petirrojo-1

Yamu

32.13% Cubiro Block C acquired

Arauco5/ Careto 13H

2010 base wells/ working interests

* September 1-11, 2011 daily average

8

• 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

Ne

tba

ck

G &

A p

er b

arre

lStrengthened operating cash flow

$-

$5

$10

$15

$20

$25

$30

$35

$-

$10

$20

$30

$40

$50

$60

Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2- 2011

Operating Netback G&A

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

(1) Management estimates, as of September 2011(2) Signing agreement in process – delivery volumes on availability

Illustrative summary of potential netbacks from crude oil sales from Cubiro production (1)

(US$ per barrel)

Delivery PointRubiales/

Vasconia

Guaduas/

Vasconia

Araguaney/

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

10

(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.

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

working capital$60 million

2011E capex plan $40-$50 million

2011E Cash flow (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 (Block B)

• Yopo well, Q4-2011

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, including storage

• 2 wells completed in Q1-2011

• 1 well in Q3, WO’s in Q4-2011

• 1 well added to program (Block B)

• Petirrojo-2 well in Q4-2011

11

(1) Management Estimate, subject to change

Estimated 2011 capital investment budget: $40 million - $50 million (1)

2011 Work program

12

Operator: PetroMagdalena EnergyWI: A:60.5% B:70% C:57.13%Contract: ANH

Product: L/M OilArea: 61,295 acres2P Reserves: 5.8 MMbbl (1)

Production: 2010 A (Year Avg): 1,905 boe/d2011E (Year Avg): 2,100 boe/d – 2,300 boe/d(2)

Llanos Basin – Cubiro

(1) Petrotech Dec 31, 2010 Report , PetroMagdalena share,

gross before royalties

(2) Management estimate , including impact of April 15,. 2011

Jaguar acquisition

(3) Company share, not yet certified

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

barrel vs 2010

• 2011 Exploration program two discoveries with Mgmt estimate of 3.1 MMbbls (3) of recoverable reserves.

13

Llanos Basin - Cubiro

Polygon A :

Development Area

60.5% W.I.

Polygon B :

Exploration Area

70% W.I.

Polygon C :

Exploration Area

57% W.I.

Field

Prospect

C537 °API

PalmaritoC7 40 °API

Caño GandulC5-C738 °API

Careto

Arauco Sirenas

Guanapalo

C7

30 °API

BarranqueroPetirrojo

Altair

Copa

C7

Cernicalo

Q1-2012

CanarioSirenas

Sur

Turpial

Tijereto Sur

Q1-2012

Yopo, Q4-2011

Petirrojo Sur

Copa B

Copa AS

Jordán

C7

29 °API

Copa C, Q1-2012

Highlights

• Operated by PetroMagdalena Energy

• All production is subject to the sliding scale royalty rates of ANH and a 3% overriding royalty on total production from the Block.

• The Cubiro Block has been under an Exploration and Production (E&P)

Contract with ANH since October 8, 2004, followed by a 25 year production period.

• Currently, there are six producing oil fields: Careto, Arauco, Barranquero,

Copa, Copa B and Petirrojo.

• Currently producing from Carbonera C-5, C-7 and Gacheta formations.

• Acquired an additional 32.13% of the Cubiro C eastern area on April 15, 2011.

• Two new fields discovered at Petirrojoand Copa B in Q3 2011

Petirrojo Field, Petirrojo South & Yopo

Prospects• Petirrojo-1 encountered 32 ft of net pay.

After an initial test rate of 1,545 bopd of

40 API light oil the well averaged 1,849 bopd (Company share, 1,294 bopd) over the next 15 days and remains on production.

• 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

Recoverable

Reserves

(MM Bbls)

Petirrojo 1,870

RESOURCES

(MM Bbls)

Petirrojo South 1,100

Yopo 1,700

CURRENT MGMT. ESTIMATES (1)

(1) Company share, not yet certified

Yopo Prospect

Petirrojo Field

1 Km

Petirrojo-1

Carbonera C7

TWT Seismic Map

Petirrojo Dev. Locations

Petirrojo South Prospect

Recoverable

Reserves

(MM Bbls)

Copa B-1 1,260

RESOURCES

(MM Bbls)

Copa AS-1 1,002

CURRENT MGMT. ESTIMATES (1)

Copa B Field, Copa AS & Copa AN Prospect

• Copa B-1 exploration well encountered 41 ft of net pay. Initial 3-day test rate of 1,045 bopd (Company share, 597 bopd) of 39.3°

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

from the same location in Q3-2011.

• The Copa C structure to the south of Copa B will be drilled in Q1-2012

Carbonera C7

TWT Seismic Map

Copa B Field

Copa B -1

Copa AS Prospect

Copa AS-1

1 Km

Copa AN Prospect

15

(1) Company share, not yet certified

Cubiro ‘C’ Area – Copa Upside

16

@ 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

RESOURCES

100% 25% 57% COS Risked

% 57%

Copa A North 3,363 841 1,920 60 1,152

Copa A South 2,925 731 1,670 60 1,002

Copa C 3,509 877 2,004 40 802

Copa D 2,340 585 1,336 40 534

12,137 3,034 6,930 200 3,490

Mgmt Volumetric Estimates: C7, C5, C3 (MM bbls)

RESERVES

Petrotech Dec 2010

100% 25% 57.13%

Proved 1,592 398 910

Probable 1,599 400 914

2P 3,192 798 1,825

Gross

COPA (MM Bbls)

RESERVESManagement Estimate

100% 25% 57.13%

2,210 553 1,260

COPA B (MM Bbls)

Gross

Recoverable

Reserves

Copa Field

Copa A North

Copa A South

Copa B

Copa C

Copa D

Exploration 2011

Exploration 2012

Development

17

Topoyaco & MecayaContracts: ANH

Operator:Topoyaco - Pacific Rubiales (1)

WI: 50%, subject to ANH approvalMecaya – Gran Tierra

WI: 42%, subject to ANH approvalProduct: L/M oil exploration potentialProduction: Nil

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 no overrriding royalty and will pay 85% of the cost of the first 3D and well.

Capital Investment Plan

• One exploration well, at Prospect D on Topoyaco, will be drilled in Q3 of 2011

Putumayo Basin

(1) Contract assignment in process subject to approval by ANH

18

Well: Yaraqui-1X

Prospect: D

Putumayo Basin – Topoyaco

Prospect ‘D; Resource Estimate -100% (mbbls)

PROSPECT LOW BEST HIGH

‘D’ 15,808 46,907 147,119

Gross

PetroMagdalena7,904 23,453 73,560

Source: April 30, 2010 Petrotech Report (available at

www.petromagdalena.com)

Yaraqui-1X well spud

August 31, 2011, in the

central part of the

block. The well plan is

to 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”.

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

20

• Santa Cruz-1 will be drilled in Q4-2011, in

the A Block, with an area of 750 acres and

an expected primary target (Mirador)

thickness of over 300 ft of high porosity

and permeability sandstone reservoir.

• The environmental permit has been issued

and civil work has started on the location.

• The Santa Cruz Block prospective resources are based on the 3D seismic interpretations and surrounding analog fields.

• The Santa Cruz Block has several faulted

structures assigned prospective resources based on the 3D seismic interpretations and information from the offset Rio Zulia field

Source: Management estimate of recoverable resources based

on the 3D interpretation and are reported gross of royalties.

Catatumbo Basin – Santa Cruz-1

Operator: PetroMagdalenaWI: 70%

Santa Cruz-1 Resource Estimate -100% (m bbls)

PROSPECT LOW BEST HIGH

‘A’ 17,000 73,000 308,000

Gross

PetroMagdalena11,900 51,100 215,600

Source: Management Estimate

C: 700 acres

Total of 3480 acres

F: 420 acres

E: 580 acres

D: 230 acres

A: 750 acres

B: 800 acres

Santa Cruz – 1, Q4 - 2011

21

Cash position (June 30, 2011): $26.5 million

Debt (June 30, 2011):

Bank term loans

18-month factoring Loan

3-year 9% Senior Notes

$9.5 million

$8.6 million

CA$31.1 million

Share price (Sept 6, 2011): CA$0.95

Shares outstanding: 142.3 million

Options outstanding ($2.52 average)

Warrants outstanding ($3.50)

9.5 million

19 million

Fully diluted: 170.8 million

Market capitalization (Sept 6, 2011): CA$135.2 million

Capitalization

22

Leadership team

Luciano Biondi

Chief Executive Officer

Gregg K. Vernon, P.Eng

Chief Operating Officer

Michael Davies, C.A.

Chief Financial Officer

Francisco Bustillos, M.Sc.

Colombian Finance &

Administration Manager

Jesus Aboud

Exploration Manager

Peter Volk, LL.B.

General Counsel & Secretary

Management

Jaime Perez Branger

Executive Chairman

Miguel de la Campa

Serafino Iacono

Ian Mann

Robert Metcalfe

Luis Miguel Morelli

Directors

Appendix

23

Assets in the most prolific basins

Area Operator(1) Gross

Acres WI Contract Stage Product Status

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 & GasJoint Venture

or

Farm-Out

Cerrito PRE 10,165 76-81% ECP E&P Gas

Catguas GTE 330,35515%/50%

S N (2) ANH Exploration Oil & Gas

Santa Cruz PMD 40,058 100% ANH Exploration Light Oil Farm out potential

Carbonera –

La SillaPMD 12,558 58% ECP

E&P Light Oil

3D seismic Work

plan in place

Magdalena Basin

Las Quinchas PRE 124,493 24.5% ECP E&P H Oil To Be Sold

Rio Magdalena GTE 36,156 56% ECP E&P Gas/Cond/

OilJV or Farm-Out

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 assets24

25

Highlights

• Operated by Pacific Rubiales Energy

• Several light oil prospects on trend with 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

• Mirla Negra-1 well tests on the C-5 over the perforated interval of 5,506 - 5,510 feet MD showed a daily rate of 130 barrels of oil at 34.5°API with a 69% water cut.

• Management estimates resources of ~ 5 MMbbl with addition of the new 3D seismic

survey

• PetroMagdalena acquired overriding royalties of 4% and 3% in the A and B sectors, respectively, on the block in April 2011.

• Arrendajo is 7 km NE of the Cubiro block

Llanos Basin – Arrendajo

20Petirrojo

Cubiro

Sector B: 3% ORR

Sector A: 3% ORR

ARRENDAJO

(1) Petrotech Engineering report April 2010

Operator: Pacific Rubiales WI: 35%

Contract: ANHProduct: Light Oil Area: 78,102 acresResources: 3,059 Mbbl (1)

Stage: Exploration

26

VSM 12

VMM 35

COR 33

VSM 13

LLA 41VMM 11

MIDDLE MAGDALENA VALLEY BASIN

CORDILLERA BASIN

UPPER MAGDALENA VALLEY BASIN

LLANOS BASIN

2010 ANH Bid Round

Six New E&P Assets

Agreement for funding the

exploration commitment

resulting in PetroMagdalena

holding a 10% Working Interest.

27

Colombian Pipeline Infrastructure

As at September 6, 2011

28

$64,338x

$114,122x

$-

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

PetroMagdalena Energy

Corp

Peer*

Ma

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t C

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liza

tio

n /

Pro

du

ctio

n (

bo

ed

)

Source: Bloomberg & Company 2011 Q2 MD&A Reports *Peer: Gran Tierra, Canacol, Parex, Petrodorado & C&C Energia

$14,488,295x

$49,559,154x

$-

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

PetroMagdalena Energy

Corp

Peer*

Ma

rke

t C

ap

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liza

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Re

serv

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(mm

BO

E)

Valuation metrics