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DECEMBER 2011
PMD - TSXV
INVESTOR PRESENTATION
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 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.
2
3
1. Focus on organic cash flow opportunities in our portfolio
2. Enhance netbacks, reduce costs, increase efficiency
3. Exploration success at Cubiro in 2011 now leading to increased
development activity in 2012 in the Llanos Basin
4. Maximizing value from assets in our portfolio – leverage
relationships with strong partners
EXPERIENCED LEADERSHIP
IMPROVING OPERATING CASH FLOW
HIGH POTENTIAL
EXPLORATION ASSETS
DRIVING VALUE
Focus on Value Creation
Goal is to increase production and reserves
Diversified
portfolio
4
CATGUAS
CARBONERA
CARBONERA LA SILLA
SANTACRUZ
CERRITO
CORDILLERA 33
VALLE MEDIO
DEL MAGDALENA 11
RIOMAGDALENA
VALLE MEDIOMAGDALENA 35
VALLE SUPERIOR
MAGDALENA 12 VALLE SUPERIORMAGDALENA 13
TOPOYACO
MECAYA
CUBIRO
ARRENDAJO
LA PUNTA
LLANOS41
Panamá
Brasil
YAMU
Catatumbo Basin •Santa Cruz •Cerrito
•Carbonera-La Silla •Carbonera •Catguas
Llanos Basin
•Cubiro
•Arrendajo •La Punta •Yamu
Putumayo Basin •Topoyaco
•Mecaya
Magdalena Basin •Las Quinchas •Rio Magdalena
RED blocks: 2010 ANH E&P
blocks
Achieved Ongoing
Reduced G&A per boe by 54% Q3 2011 vs 2010 average
Increased Operating Netback by 49% 2011 YTD (9 months) from FY2010 average
Increased reserves at Cubiro by 86% *
Drilling program at Cubiro O
Exploration at Cubiro O
Spud Yaraqui-1X at Topoyaco – D, August 31, 2011
Farm-out 30% of Santa Cruz
Spud Santa Cruz-1 on November 20, 2011
Farm-out Carbonera and Catguas to YPF **
Sale and/or farm-out of other assets O
5
Achievements Q1 through Q3 2011
* Petrotech report on Cubiro block, September 30, 2011
** Subject to ANH approval
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
7
Cubiro 2P Reserves Changes in 2011
Source: Petrotech Technical reports: September 30, 2011, December 31, 2010 and 2009
2,570
5,831 1,123
972
2,079
1,233
1,831
0
2,000
4,000
6,000
8,000
10,000
12,000
Dec 2009 Reserve Report
Dec 2010 Reserve Report
2011 Cubiro Production & Technical Revisions
Purchase 32% of
Cubiro 'C'
Petirrojo Discovery
Copa B Discovery
Copa A Sur Discovery
Mb
bls
September 30, 2011
10,823
8
Daily Average Production 2010-2011
0
500
1000
1500
2000
2500
3000
3500
4000
Year 2010
Q1 2011 Q2 2011 Q3 2011 Nov 2011 *
bo
ed
Copa A Sur-1
Copa B-1
Petirrojo-1
Yamu
32.13% Cubiro Block C acquired
Arauco5/ Careto 13H
2010 base wells/ working interests
• Daily average for month of
November 2011
• Petirrojo 2 & 3 to be on production
in December.
9
• Re-capitalized balance sheet in February 2011 through equity financing
• Reduced debt by $31 million to $10 million, freeing up $1.0 million
per month of operating cash flow to fund capital investments in core
assets; working capital deficit reduced by $44 million since
December 31, 2010
• Enhancing operating netback from Cubiro production
• New oil marketing contract in conjunction with Pacific Rubiales
• Implementing initiatives to reduce opex
• Cost reductions generating positive trend in G&A per barrel produced
Ne
tba
ck
pe
r
ba
rre
l G
&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
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 November 2011 (2) Agreement in place – delivery volumes only on availability (only 6,200 bbls to Dec 1, 2011) (3) Vasconia as of November 29, 2011 priced at WTI + $6.85/bbl
Illustrative summary of potential netbacks from crude oil sales
from Cubiro production (1) (US$ per barrel)
Delivery Point / Reference Price Rubiales /
WTI
Guaduas /
Vasconia
Araguaney /
Vasconia (2)
WTI (Nymex : November 29, 2011) $99.79 $99.79 $99.79
Benchmark Quality Adjustment +8.00 +6.85 (3) +6.85 (3)
Royalties (7.00) (7.00) (7.00)
Net Revenue $100.79 $99.64 $99.64
Production costs (Q3 - 2011) 14.50 14.50 14.50
Transportation & pipeline 16.50 22.50 10.00
Operating Netback $69.79 $62.64 $75.14
Property Work Program 2011(1) Approximate timing
Exploration Plan
Cubiro • 4 wells (2 Block B, 2 Block C) • 3 drilled, 3 discoveries
• Yopo well, Q4-2011
La Punta • 1 well (LP-4 dry) • LP-4 drilled Q2
Topoyaco • 1 well (Yaraqui-1X) • Spud August 31st ; preparing
to test
Santa Cruz • 1 well • Spud November 20th, drilling
Development Plan
Cubiro • 4 wells + 1 WO + facilities, including storage
• 2 wells completed in Q1-2011 • Petirrojo-3 dev well in Q4-2011 • Petirrojo-2 dev well in Q4-2011
• 1 WO in Q4-2011
11
(1) Management Estimate, subject to change
Estimated 2011 capital investment budget: $41 million (1)
2011 Work Program
• Capital expenditure program estimated at $50 to $60 million,
excluding commitments funded by farm-ins (Carbonera, Catguas).
• 65% directed to light oil exploration and development in Cubiro and
Arrendajo.
• 6 Llanos exploration wells, 4 in Q1, 1 in Q2 and 1 Q3.
• 10 Llanos development wells, 1 in Q1, 3 in each subsequent quarter
• 2012 Llanos exploration program:
Management estimate of light oil recoverable prospective resources,
company‟s working interest share is 9.1 million barrels Un-Risked and 3.8
million barrels Risked
• Capital funded from cash and internally generated cash flow.
• No near term financing required to fund 2012 work plan.
• Cash flow estimate for 2012 includes no production volumes for any
of the exploration wells currently being drilled or to be drilled in 2012.
12
2012 Work Program Overview
Property Work Program 2012(1) Approximate timing
Exploration Drilling
Cubiro • 4 wells (3 Block B, 1 Block C)
• 1 contingent well (Block C)
• 3 in Q1, 1 Q2, 1 Q3
Arrendajo • 1 well • 1 well in Q1-2012
Santa Cruz • 1 well, spud Nov, 2011 • Well will TD in Q1-2012
Carbonera • 1 well • 1 well in Q1-2012
Development Drilling
Cubiro • 7 wells
• 3 contingent wells • 1 well in Q1-2012
• 3 wells each subsequent qtr.
Carbonera • 1 well • 1 well Q2-2012
13
(1) Management Estimate, subject to change
Estimated 2012 capital investment budget: $50 million - $60 million (1)
2012 Work Program
14
(1) Management estimate, 2012 estimate calculated with an $80/bbl WTI pricing
(2) Represents estimated revenues less royalties, production and transportation/pipeline costs based upon
average daily production of 2,800 boed for 2011 and 4,500 boed (mid-point of management guidance
range)for 2012
(3) Includes funds being set aside for May 2012 & May 2013 annual principal repayment of senior notes
(4) Management Estimate
2011E 2012E
Average daily production for the year (gross before royalties)(4) 2,800 boed 4,300-4,700 boed
Cash flow from operating netbacks (2) $58M $82M
Less: G&A $15M $16M
Less: Debt service (principal & interest) (3) $18M $24M
Less: Equity tax instalments $2M $ 2M
Net cash flow from operations $23M $41M
Cash position, beginning of year $6M $17M
Cash available from equity financing for work program $35M -
Other sources/ (uses), including working capital changes and
cash from asset dispositions (4) $(6M) $ 7M
Total cash available to fund annual work program $58M $64M
Annual work program expenditures (4) $41M $50-$60M
Annual Cash Flow (4)
15
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)
Llanos Basin – Cubiro
(1) Petrotech Report dated Sept. 30, 2011, PetroMagdalena
share, gross before royalties
(2) Management Estimates
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)
16
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
C5 37 °API
Palmarito C7 40 °API
Caño Gandul C5-C7 38 °API
Careto
Arauco Sirenas
Guanapalo
C7
30 °API
Barranquero Petirrojo
Altair
Copa
C7
Cernicalo
Q1-2012
Canario Sirenas
Sur
Turpial
Tijereto Sur
Q1-2012
Yopo, Q4-2011
Petirrojo Sur
Copa B
Copa ASur
Jordán
C7
29 °API
Copa C, Q1-2012
Highlights
• Operated by PetroMagdalena
• 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, exploration phases followed by a 25 year production period.
• Currently, there are seven producing oil
fields: Careto, Arauco, Barranquero, Petirrojo, Copa, Copa B and Copa A Sur.
• 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.
• Three new fields discovered at Petirrojo, Copa B and Copa A Sur 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.
• 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 South will be drilled when civil work has been completed, Q2-2012
2P RESERVES (1)
(Mbbls)
Petirrojo 2,036
RESOURCES (2)
(Mbbls)
Petirrojo South 1,100
Yopo 1,700
(1) Company share, Sept 30, 2011 technical report
(2) Company share, Management estimate, not yet certified
Yopo Prospect
Petirrojo Field
1 Km
Petirrojo-1
Carbonera C7
TWT Seismic Map
Petirrojo Dev. Locations
Petirrojo South Prospect
2P Reserves
(Mbbls)
Copa B 1,230
Copa A Sur 1,831
CURRENT TECHNICAL REPORT (1)
Copa B Field, Copa A Sur & Copa AN Prospect
• Copa B-1 exploration well encountered 41 ft of net pay. Daily average production during
October has averaged 765 bopd (Company share 437 bopd). ESP stopped 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° API light oil on natural flow.
• Copa A Sur-1 went on production Nov 6th .
• 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 ASur Field
Copa ASur-1
1 Km
Copa AN Prospect
18 (1) Company share, September 30, 2011 technical report
Cubiro ‘C’ Area – Copa Upside
19
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
RESOURCES
(Mbbls) 100% Gross COS Risked
% Gross
Copa A North 3,363 1,920 60 1,152
Copa C 3,509 2,004 40 802
Copa D 2,340 1,336 40 534
9,212 5,260 47 2,488
Sept 30, 2011 Technical Report
Mgmt Volumetric Estimates: C7, C5, C3
Copa Field
Copa A Norte
Copa A Sur
Copa B
Copa C
Copa D
Producing Exploration 2012 Development
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 on trend with producing oil fields
• Drilling two wells, starting in Dec. 2011
• Six prospects in the Carbonera formation have been identified: Azor, Yaguazo, Arrendajo Norte, Arrendajo Sur, Mirla Blanca, and Mirla
Oeste
• Management estimates prospective resources of ~ 11 MMbbl unrisked, with addition of the new 3D seismic survey, ~ 4.5 MMbbl risked as the companies working interest share before royalties
• PetroMagdalena acquiring 32.5% working interest from Pacific Rubiales, subject to ANH approval, for $10 million to be paid out of production and paying all costs for Pacific Rubiales go forward.
Llanos Basin – Arrendajo
ARRENDAJO
(1) Petrotech Engineering report April 2010, adjusted for the 32.5% interest being acquired from Pacific Rubiales.
Operator: Pacific Rubiales WI: 67.5% Contract: subject to ANH Product: Light Oil Area: 78,102 acres
Resources: 8,259 Mbbl (1)
Stage: Exploration
CUBIRO
Arrendajo Norte
Q1-2012
Arrendajo Sur
Mirla Negra
Yaguazo
Mirla
Blanca Mirla
Oeste
Azor
Q4-2011
21
Topoyaco & Mecaya Contracts: ANH
Operator: Topoyaco - Pacific Rubiales (1)
WI: 50%, subject to ANH approval
Mecaya – Gran Tierra WI: 42%, subject to ANH approval Product: L/M oil exploration potential Production: 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.
• PetroMagdalena has a beneficial 43% 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.
Exploration Plan
• One exploration well, Yaraqui -1X, (Prospect D) commenced drilling on August 31
Putumayo Basin
(1) Contract assignment in process subject to approval by ANH
22
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
PetroMagdalena 7,904 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 reached total
depth of 10,651 feet
MD, targeting the
Cretaceous Villeta
and Caballos
formations, in a sub-
thrust structure called
Prospect “D”.
Testing is currently
being conducted.
23
Maximize Value From
Catatumbo Assets
Actions Taken
Farm Out Agreement for Santa Cruz:
• Retain Operatorship
• Retain 70% Working Interest
• Pay 40% of first well in Q4 – 2011, 55% of second well, 70% thereafter
Farm Out Agreement for Carbonera:
• YPF becomes Operator, bring extensive gas experience
• Retain 40% Working Interest
• Carried through US$23 million work program
Farm Out Agreement for Catguas: • YPF will lead exploration program
• Retain working interests of 15% in North area and 4.5% in South area
• Carried through 2012 work program
24
• Santa Cruz-1 is being drilled, and spud on
Nov. 20th, 2011, in 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 well reached 3,905 ft in November,
the 13 3/8 inch casing point.
• 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: PetroMagdalena
WI: 70%
Santa Cruz-1 Resource Estimate -100% (m bbls)
PROSPECT LOW BEST HIGH
„A‟ 17,000 73,000 308,000
Gross
PetroMagdalena 11,900 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
25
Cash position (September 30, 2011): $12.3 million
Debt (September 30, 2011):
Factoring Loan (maturing Oct 2012)
Bank term loans (maturing May/ Aug 2013)
9% Senior Notes (maturing May 2014)
$6.6 million
$7.9 million
CA$31.1 million
Share price (December 1, 2011): CA$1.60
Shares outstanding: 142.3 million
Options outstanding ($2.17 average)
Warrants outstanding ($3.50)
13.5 million
19 million
Fully diluted: 174.8 million
Market capitalization - undiluted (December 1, 2011): CA$227.7 million
Capitalization
26
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
27
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 Contract under
review
Arrendajo PRE 78,102 67.5% ANH Exploration Light Oil Near Cubiro
Yamu WOGSA 18,194 10% ANH Prod & Exp Light Oil Producing
Catatumbo Basin
Carbonera PMD 63,727 96% ANH E&P Oil & Gas Joint Venture
or
Farm-Out
Cerrito PRE 10,165 76-81% ECP E&P Gas
Catguas GTE 330,355 15%/50%
S N (2) ANH Exploration Oil & Gas
Santa Cruz PMD 40,058 100% ANH Exploration Light Oil Farmed out 30% WI
Carbonera – La
Silla PMD 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/
Oil JV 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 assets 28
29
VSM 12
VMM 35
COR 33
VSM 13
LLA 41 VMM 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.
30
Colombian Pipeline Infrastructure