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FEBRUARY 2012
INVESTOR PRESENTATION
Building On Our Success
PMD - TSXV
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 statementsand 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 gas
reserves; 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 ofassumptions 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 to
operate 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 otherfactors 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 ofresources 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 classesof 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, 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 formaltransfer of title and or operatorship.
2
3
1. Focus on organic cash flow opportunities in our portfolio
2. Enhance netbacks, reduce costs, increase efficiency
3. Increase development activity in 2012 in the Llanos Basin from exploration success
4. Maximize value from assets in our portfolio – leverage
relationships with strong partners
5. Identify near term production growth opportunities in Colombia
EXPERIENCED LEADERSHIP
IMPROVING OPERATING CASH FLOW
HIGH POTENTIAL
EXPLORATION ASSETS
DRIVING VALUE
Focus on Value Creation
Goal is to increase production and reserves3
PetroMagdalena Today:
Exploration
Unrecognized upside potential
Significant success in the light oil Llanos exploration program
Catatumbo exploration drilling program has started
Production
Light Oil development drilling in Llanos– 10 development wells in
2012
Production doubles over last year
Light oil pricing tracking Brent pricing
With the growth in reserves and production, expand portfolio
where opportunities leverage expertise and logistics
4
Building On Our Success
Diversified portfolio
CATATUMBO Basin•Santa Cruz (1)
•Carbonera-La Silla(1)
•Carbonera •Catguas
LLANOS Basin•Cubiro(2)
•Arrendajo •La Punta •Yamu
PUTUMAYO Basin•Topoyaco•Mecaya
MAGDALENA Basin•Las Quinchas•Rio Magdalena
RED blocks: 2010 ANH E&P
blocks
Agreements subject to ANH or
Ecopetrol approval
(1) Operated by Mompos Oil and
Gas, a wholly owned subsidiary.
(2) Operated by Alange, Corp. a
wholly owned subsidiary.5
Investment Environment – Opportunities Exist
• Increasing number of oil and gas operations in Colombia, 150 companies in 2011
vs. 158 in 2012, with the potential of more junior companies entering through 2012
Ronda auctions.
• Today, approximately 13% of Exploration and Production (E&P) and TEA blocks
are listed as suspended or non-compliant, many fail to deliver (source: ANH)
• International E&Ps are trading at compressed multiples relative to Canadian E&P
companies, creates value gap
These factors combined demonstrate an investment environment for successful
operators with exploration success and organic cash flow to acquire, or farm in to
assets that are under-funded with exploration upside
0%
20%
40%
60%
80%
0
50
100
150
2004 2005 2006 2007 2008 2009 2010 2011
Succ
ess
Fac
tor
Nu
mb
er
of
We
lls
Exploratory Drilling in Colombia
Total Success Factor
• Consistently high exploration success
factors in Colombia have encouraged
investments that are key success factors
for future opportunities
0
2
4
6
8
10
$0
$100
$200
$300
$400
Q4 2010 Q1 2011 Q2 2011 Q3 2011
Nu
mb
er
of
Co
mp
anie
s
Mill
ion
s
Financing
Total Gross Equity Capital Raised
• Public market financing on declines, farm-
ins and acquisitions with current cash flow
are important means to growth for
Colombian E&Ps 6
7
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
Producing1,981 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
8
Cubiro 2P Reserves Changes in 2011
Source: Petrotech Technical reports: September 30, 2011, December 31, 2010 and 2009
Daily Average Production 2010-2011
0
500
1000
1500
2000
2500
3000
3500
4000
4500
'10 Q1 '11 Q2 '11 Q3 '11 Q4 '11Dec '11 *
bo
ed
Copa A Sur-1
Copa B-1
Petirrojo Field
Yamu
32.13% Cubiro Block C acquired
Arauco5/ Careto 13H
2010 base wells
PetroMagdalena’s Gross Working Interest
* Daily average for month of December 2011
* Petirrojo 2 & 3 put on production in December. 9
• Enhancing operating netback from Cubiro production
• Oil marketing contract in conjunction with Pacific Rubiales
• Ongoing opex reduction programs
• Efficiencies generating positive trend in G&A per barrel produced
Ne
tba
ck
pe
r
ba
rre
lG
&A
pe
r ba
rrel
Strengthening Operating Cash Flow
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2- 2011 Q3 - 2011
Operating Netback per barrel G&A per barrel
10
(1) Management estimates, as of February 2012
(2) Vasconia as of February 21, 2012 priced at WTI +12.75/bbl
• A 3-year conventional oil marketing agreement signed with Pacific
Rubiales effective February 1, 2011.
• Bicentenario pipeline is scheduled to be commissioned mid
2012, potential to reduce trucking costs by up to US$ 7.00/bbl.
Illustrative summary of potential netbacks from crude oil sales from Cubiro production (1)
(US$ per barrel)
Delivery Point / Reference Price Guaduas / Vasconia (2)
WTI (Nymex: February 21, 2012) 105,84
Benchmark Quality Adjustment (February 21, 2012) 12,75
Royalties (7,00)
Net Revenue 111,59
Production Costs (Q4 - 2011) 14,50
Transportation & pipeline 22,50
Operating Netback 74,59
Cubiro’s Netback
11
2012 Work Program Overview
2012 Work Program Overview
• Capital expenditure program estimated at $50 to $60 million, excludingcommitments funded by farm-ins (Carbonera, Catguas).
• 65% to be directed to light oil exploration and development in Cubiro andArrendajo.
• 6 Llanos exploration wells planned, 4 in Q1, 1 in Q2, and 1 Q4.
• 10 Llanos development wells planned, 1 in Q1, 3 in each subsequent.
• 2012 Llanos exploration program:Management estimate of light oil recoverable prospective resources,
company’s working interest share would be close to doubling 2P Llanosreserves Un-Risked or approximately + 40% Risked
• Capital intended to be funded from cash and internally generated cash flow.
• No near term financing expected to be required to fund 2012 work plan.
• Cash flow estimate for 2012 includes no production volumes for any of theexploration wells currently being drilled or to be drilled in 2012.
12
Property Work Program 2012(1) Approximate timing - 2012
Exploration Drilling
Cubiro
• 4 wells in Area ‘B’
• 1 well in Area ‘C’• 1 contingent wells ( Area ‘C’)
• 4 in Q1, 1 Q2, 1 Q4
Arrendajo • 1 well (Arrendajo Norte-1X) • 1 well in Q1-2012
Carbonera • 1 well • 1 well in TD in Q2-2012
Santa Cruz • 1 well • Q4 2012
Development Drilling
Cubiro• 7 wells• 3 contingent wells
• 1 well spud in Q1-2012• 3 wells each subsequent qtr.
13
(1) Management Estimate, subject to change
Estimated 2012 capital investment: $50 million - $60 million (1)
2012 Work Program
14
(1) Management estimate, 2012E 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 2011E and 4,500 boed (mid-point of management guidance range)for 2012E.
(3) 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).
(4) Management estimate; subject to change.
2012E
Average daily production for the year (gross before royalties)(4) 4,300-4,700 boed
Cash flow from operating netbacks (2) $82M
Less: G&A $16M
Less: Debt service (principal & interest) (3) $20M
Less: Equity tax instalments $ 2M
Net cash flow from operations $44M
Cash position, beginning of year $15M
Cash available from equity financing for work program -
Other sources/ (uses), including working capital changes and cash from asset dispositions (4) $ 7M
Total cash available to fund annual work program $66M
Annual work program expenditures (4) $50-$60M
Annual Cash Flow (1)
15
Operator: Alange, Corp. (1)
WI: A:60.5% B:70% C:57.13%Contract: ANH
Product: L/M OilArea: 61,295 acres2P Reserves: 10.8 MMbbl (2)
Production: 2010 A (Year Avg): 1,905 bopd2011 A (Year Avg): 2,138 bopd
Llanos Basin – Cubiro
(1) A wholly owned subsidiary of PetroMagdalena
(2) Petrotech Report dated Sept. 30, 2011, PetroMagdalena share, gross before royalties
About Cubiro
• Most prolific hydrocarbon basin in Colombia
• Currently producing from 21 wells in theCareto, Arauco, Barranquerro, Petirrojo, Yopo andCopa fields
• 86% increase in 2P reserves (Sept 2011 vs Dec 2010) (2)
• 2011 Exploration program with four discoveries:
Petirrojo, Copa B, Copa AS and Yopo.
• Sept 30, 2011 update from three discoveries with 5.1MMbbl of recoverable reserves (2P) (2)
16
Llanos Basin - Cubiro
Polygon A :
Development Area
60.5% W.I.
Polygon B :
Exploration Area
70% W.I.
Polygon C :
Exploration Area
57.13% W.I.
Highlights
• Operated by PetroMagdalena
• All production is subject to the sliding
scale royalty rates of ANH and a 3%overriding royalty on total productionfrom the Block.
• The Cubiro Block has been under an E&PContract with ANH since October 8,2004, exploration phases followed by a25 year production period.
• Currently, there are nine producing oilfields: Careto, Arauco, Barranquero,Petirrojo, Yopo, Copa, Copa B, Copa ASur and Cernicalo.
• Currently producing from Carbonera C-5, C-7 and Gacheta formations.
• Four new fields discovered at Petirrojo,Copa B, Copa A Sur and Yopo in 2011.
Field
Prospect
C537 °API
PalmaritoC7 40 °API
Caño GandulC5-C738 °API
Careto
Arauco Sirenas
GuanapaloC730 °API
BarranqueroPetirrojo
Altair
Copa
C7
Canario Sirenas Sur
AlondroQ1 -2012
Tijereto SurQ1-2012
Yopo, Q4-2011
Petirrojo SurQ2 - 2012
Copa B
Copa A Sur
JordánC729 °API
Copa C, Q3-2012
Copa A Norte Q4-2012
CernicaloQ1-2012
17
Petirrojo Field, Petirrojo South & Yopo Prospects
• Yopo 1X discovery well spud on
December 11th, 2011, and drilled to afinal depth of 6,790 feet (MD). The wellinitially tested at a stabilized rate of 970bopd with 4.7% BS&W for 6.5 hours at anaverage wellhead pressure of 385 psi.
• Petirrojo South will be drilled in Q2-2012, civil work to be completed in
Feb, 2012.
(1) Company share, Sept 30, 2011 technical report
1 Km
Yopo Field
Petirrojo Field
Petirrojo-1
Carbonera C7TWT Seismic Map
Petirrojo South Prospect
2P RESERVES
(Mbbls)
Petirrojo 2,036
CURRENT TECHNICAL REPORT (1)
2P Reserves
(Mbbls)
Copa B 1,230
Copa A Sur 1,831
CURRENT TECHNICAL REPORT (1)
Copa B Field, Copa A Sur & Copa AN Prospects
• Copa B-1 exploration well encountered 41 ftof net pay. Daily average production duringOctober has averaged 765 bopd(Company share 437 bopd). ESP stoppedworking October 20th; the well went backon production Nov 9th .
• Copa A Sur-1 exploration well successfully
drilled with Initial 4-day test rate of 1,114bopd (Company share, 636 bopd) of 38.4°
API light oil on natural flow.
• Copa A Sur-1 went on production Nov 6th .
• The Copa C structure to the south of CopaB will be drilled in Q1-2012
Carbonera C7TWT Seismic Map
Copa B Field
Copa B -1
Copa ASur Field
1 Km
Copa AN Prospect
(1) Company share, September 30, 2011 technical report
Copa ASur-1
18
Cubiro ‘C’ Area – Copa Upside
2P RESERVES
(Mbbls) 100% Gross Net
Copa Field 3,008 1,718 1,582
Copa A Sur 3,205 1,831 1,684
Copa B 2,153 1,230 1,142
8,366 4,779 4,408
Sept 30, 2011 Technical Report
Copa Field
Copa A Norte
Copa A Sur
Copa B
Copa C
Copa D
Producing
Exploration 2012
Development
Carbonera C7 TWT Seismic Map
19
20
Highlights
• Arrendajo is 7 km NE of the Cubiro block
• Operated by Pacific Rubiales Energy
• 120 km2 of 3D survey completed in April 2011,interpretation shows 6 light oil prospects ontrend with producing oil fields
• Azor discovery in Jan. 2012 on permanent
production Feb. 25th, 2012.
• Five more exploration prospects in theCarbonera formation have been identified:Yaguazo, Arrendajo Norte, Arrendajo Sur, MirlaBlanca, and Mirla Oeste
• PetroMagdalena acquiring 32.5% workinginterest, from Pacific Rubiales, subject to ANH
approval, for $10 million to be paid out ofproduction.
Llanos Basin – Arrendajo
(1) A wholly owned subsidiary of Pacific Rubiales Energy.
(2) Petrotech Engineering report April 2010, adjusted for the 32.5% interest being acquired from Pacific Rubiales.
Operator: Pacific Stratus Energy Colombia (1)
WI: 67.5%Contract: subject to ANH approvalProduct: Light Oil Area: 78,102 acresResources: 8,259 Mbbl (2)
Stage: Exploration
ARRENDAJO
CUBIRO
Arrendajo NorteQ1-2012
Yaguazo
MirlaOeste
AzorQ4-2011
Arrendajo Sur
Mirla Blanca
Mirla Negra
Arrendajo Block Azor discovery - Upside
Producing
Exploration 2012
Exploration 2013
Development
Arrendajo Norte
Yaguazo
Azor
Mirla Negra
Carbonera C7 TWT Seismic Map
• Azor-1X well drilling has been
completed and was put on
production on January 31, 2012. It will
add 587 bopd to our gross working
interest production.
• 3D seismic evaluation identified four
new prospects on the Azor trend.
• Mirla Negra-1X was drilled in 2008 and
tested oil in the C5 but was not
declared commercial
21
22
Topoyaco & MecayaContracts: ANH
Operator:Topoyaco – Pacific Rubiales
WI: 50%, subject to ANH approvalMecaya – Gran Tierra
WI: 43%, 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.
• PetroMagdalena has a beneficial 43% workinginterest in the Mecaya Block, subject to ANHapproval, with no overriding royalty and will pay 85%of the cost of the first 3D and well.
• PetroMagdalena has a 50% working interest in the
Topoyaco Block, subject to the ANH approval, with a6% overriding royalty to Trayectoria. In addition,there is a 3.5% profit interest payable to GrantGeophysical for the seismic work.
Putumayo Basin
VENEZUELA
Carbonera Block
Santacruz Block
Carbonera La Silla
Catguas Block
About Catatumbo
• Catatumbo Basin is located in northwestColombia and is the western extension ofthe very prolific Maracaibo basin inVenezuela
• High potential exploration targets
Highlights
• Partnered with experienced operators.
• PetroMagdalena has a beneficial 100%
working interest in the Carbonera Block,subject to ANH approval.
• PetroMagdalena has a 70% workinginterest in the Santa Cruz Block, and isdrilling the Santa Cruz-1X well.
• PetroMagdalena has a 58% working
interest in the Carbonera La Silla Block,an Ecopetrol association contract.
• PetroMagdalena has a beneficial 50%working interest in the northern area ofCatguas and a beneficial 15% workinginterest in the southern area. Gran Tierra isthe operator.
Catatumbo Basin
Catguas, Santa Cruz and CarboneraContracts: ANH
Operator:Catguas – Solana (1)
WI: 50% N, 15% S, subject to ANH approvalSanta Cruz – Mompos Oil and Gas (2)
WI: 70%Carbonera – Well Logging
WI: 100%, subject to ANH approval
Product: L/M oil exploration potentialProduction: Nil
(1) Wholly owned Subsidiary of Gran Tierra Energy
(2) Wholly owned subsidiary of PetroMagdalena.23
24
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(1):
• 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
• Expected to be carried through 2012 work program
(1) Farm Out Agreement for Carbonera in process and subject to ANH approval
25
• Santa Cruz-1 spud on Nov.
20th, 2011, and casing run over the
Mirador Fomation on Feb. 24th, 2012.
The A Block which has an area of
750 acres with a primary target
(Mirador) thickness of over 300 ft of
high porosity & permeability SS
reservoir.
• 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
• A contingent exploration location
has been identified in the C Block to
the north of the Santa Cruz-1X well.
Catatumbo Basin – Santa Cruz-1
Operator: Mompos Oil and Gas (1)
WI: 70%
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, TD Q1 - 2012
Santa Cruz – 2, TD Q1 - 2013
26
Cash position (December 31st , 2011): $15.0 million
Debt (December 31st , 2011):
Factoring Loan (maturing Oct 2012)
Bank term loans (maturing May/ Aug 2013)
9% Senior Notes ( $10.4MM maturing May 2014)
$5.1 million
$6.6 million
CA$31.1 million
Share price (February 21, 2012): CA$1.51
Shares outstanding: 147.07 million
Options outstanding ($2.17 average)
Warrants outstanding ($3.50)
13.5 million
19.0 million
Fully diluted: 174.8 million
Market capitalization - undiluted (February 21, 2012): CA$220.7 million
Capitalization
Share price performance vs peer index
vs TSX energy index (Last 6 months)
27
50
70
90
110
130
150
170
190
Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12
PMD vs Peers Index* & Benchmark (Normalized)
PetroMagdalena Energy Corp Peer Index* TSX Energy Index
Company Percentage
increase
PetroMagdalena
Energy
48.51%
Peer Index* 8.81%
TSX Energy Index 10.99%
* Peer Index: 5 TSX listed E&P companies with production above 1,000 barrels per day
0
500,000
1,000,000
1,500,000
2,000,000
$0.75
$0.95
$1.15
$1.35
$1.55
$1.75
$1.95
Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12
PMD Price Volume Graph
Volume PetroMagdalena Energy Corp
TSX.V: PMD
6 months: High - Low $1.80 – $0.86
6 months: Average Volume 203,511
52 week: High - Low $2.35 – $0.93
28
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
29
Assets in the most prolific basins
Area Operator (2)
Gross Acres WI (2)
Contract Stage Product Status
Llanos Basin
Cubiro PMD 61,295 60.5-70-57.13% ANH E&P Light Oil Core Asset
Arrendajo Pacific Stratus 78,102 67.5% ANH Exploration Light Oil Near Cubiro*
La Punta Vetra 19,313 Up to 6% ECP E&P Light Oil Under review
Yamu WOGSA 18,194 10% ANH Prod & Exp Light Oil Producing
Catatumbo Basin
Carbonera Well Logging 63,727 100% ANH E&P Oil & Gas Farm-Out
Catguas Gran Tierra 330,35515% / 50%
S N (1) ANH Exploration Oil & Gas Farm-Out
Santa Cruz Mompos 40,058 70% ANH Exploration Light Oil Exploration
Carbonera – La
SillaMompos 12,558 58% ECP E&P Light Oil
3D seismic work plan
in place
Magdalena Basin
Las Quinchas Pacific Stratus 124,493 24.5% ECP E&P H Oil To Be Sold
Rio Magdalena Gran Tierra 36,156 56% ECP E&P Gas/Cond/
OilJV or Farm-Out
Putumayo Basin
Topoyaco Trayectoria 60,035 50% ANH Exploration L/M Oil Under Review
Mecaya Gran Tierra 74,128 43% ANH Exploration L/M Oil 3D seismic planned
(1) After Farm Out WI retained is 4.5% S/15% N. (2) Subject to ANH /ECOPETROL approvals.
* Working interest reflects acquisition of PRE’s 32%, subject to ANH approval. Yellow background = Core portfolio assets 30
Achieved Ongoing
Operations
Reduced G&A per boe by 54% Q3 2011 vs 2010 average
Increased Operating Netback by 49% 2011 YTD (9 months) from FY2010 average
Production
Achieved 98% of guidance for 2011 at 2,758 boepd
Increased reserves at Cubiro by 86% *
4 discoveries at Cubiro: Petirrojo, Copa B, Copa A Sur & Yopo
Spudded Azor-1X at Arrendajo with upside potential for block
Spudded Cernicalo-1ST in Cubiro
Spudded Arrendajo Norte-1X in Arrendajo
31
Achievements Q1 2011 through Q1 2012
* Petrotech report on Cubiro block, September 30, 2011
Achieved Ongoing
Exploration
6 exploration wells for 2012 in Cubiro O
1 exploration well for Arrendajo Norte 1X
1 exploration well for Carbonera O
Santa Cruz well in testing phase O
10 development wells planned in Cubiro O
Portfolio
Farm-out 30% of Santa Cruz
Farm-out Carbonera and Catguas to YPF *
Sale and/or farm-out of other assets (Cerrito, Dec ‘11) O
Achievements Q1 2011 through Q1 2012
* Subject to ANH approval
32
Well name2012
Quarter
Cubiro Block
Cernicalo-1ST (formerly named Cernicalo-2X) 1
Tijereto Sur-1X 1
Alondra-1X (formerly named Turpial-1X) 1
Petirrojo Sur-1X 2
Copa C-1X 3
Copa A Norte-1X 4
Arrendajo Block
Arrendajo Norte-1X 1
Carbonera Block
Cantaclaro-1X (formerly named San Roque-1X) 1
Santa Cruz Block
Santa Cruz-2X 4
2012 Exploration Program
Exploration overview 2012
• 6 exploration wells planned for Cubiro
• 1 exploration well for Arrendajo
• 1 exploration well for Carbonera
• 1 exploration well for Santa Cruz
33
34
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 E&P Assets
• Agreement for funding the
exploration
commitment, resulting in
PetroMagdalena holding a 10%
Working Interest.
35
Colombian Pipeline Infrastructure