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Pmd -investor_presentation-december_2011

  2. 2. Forward-looking statement 2All 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 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 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 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 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, 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 titleand operatorship.
  3. 3. Focus on Value Creation1. Focus on organic cash flow opportunities in our portfolio2. Enhance netbacks, reduce costs, increase efficiency3. Exploration success at Cubiro in 2011 now leading to increased development activity in 2012 in the Llanos Basin4. Maximizing value from assets in our portfolio – leverage relationships with strong partners IMPROVING HIGH EXPERIENCED POTENTIAL DRIVING OPERATING LEADERSHIP EXPLORATION VALUE CASH FLOW ASSETS Goal is to increase production and reserves 3
  4. 4. Diversified portfolioMagdalena Basin Catatumbo Basin •Las Quinchas Panamá CATGUAS CARBONERA LA SILLA •Santa Cruz •Rio Magdalena SANTACRUZ CARBONERA CERRITO •Cerrito •Carbonera-La VALLE MEDIO LLANOS 41 Silla VALLE MEDIO MAGDALENA 35 DEL MAGDALENA 11 •Carbonera YAMU ARRENDAJO •Catguas RIO CUBIRO MAGDALENA LA PUNTA RED blocks: CORDILLERA 33 Llanos Basin 2010 ANH E&P VALLE SUPERIOR •Cubiro blocks MAGDALENA 12 VALLE SUPERIOR MAGDALENA 13 •Arrendajo •La Punta TOPOYACO •Yamu MECAYA Brasil Putumayo Basin •Topoyaco •Mecaya 4
  5. 5. Achievements Q1 through Q3 2011 Achieved OngoingReduced G&A per boe by 54% Q3 2011 vs 2010average Increased Operating Netback by 49% 2011 YTD(9 months) from FY2010 average Increased reserves at Cubiro by 86% * Drilling program at Cubiro OExploration at Cubiro OSpud 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* Petrotech report on Cubiro block, September 30, 2011** Subject to ANH approval 5
  6. 6. 86% increase in 2P reserves at CubiroTechnical Report dated September 30, 2011:• Updated 2P reserves at Cubiro to 10.8 mmbls – an increase of 5.0 mmbls, or 86%, compared to December 2010 report• Updated 1P reserves at Cubiro to a total of 3.0 mmbls, or 73% increase compared to December 2010 report• Oil discoveries at Cubiro demonstrate exploration potential• Production growth funds ongoing work plan for Cubiro Cubiro L & M Oil Reserves (Mbbls) 100% Gross Net Proved Developed Producing 1,981 1,216 1,119 Proved Undeveloped 2,776 1,734 1,595 Total Proved 4,757 2,950 2,714 Probable 13,076 7,873 7,243 Total 2P 17,833 10,823 9,957 Source: Petrotech Engineering Ltd. report on Cubiro block, September 30, 2011 6
  7. 7. Cubiro 2P Reserves Changes in 2011 September 30, 2011 12,000 10,823 10,000 1,831 1,233 8,000Mbbls 2,079 6,000 5,831 1,123 972 4,000 2,570 2,000 0 Dec 2009 Dec 2010 2011 Cubiro Purchase Petirrojo Copa B Copa A Sur Reserve Reserve Production 32% of Discovery Discovery Discovery Report Report & Technical Cubiro C RevisionsSource: Petrotech Technical reports: September 30, 2011, December 31, 2010 and 2009 7
  8. 8. Daily Average Production 2010-2011 4000 Copa A Sur-1 3500 3000 Copa B-1 2500 Petirrojo-1boed 2000 Yamu 1500 32.13% Cubiro Block C 1000 acquired 500 Arauco5/ Careto 13H 0 2010 base wells/ Year Q1 2011 Q2 2011 Q3 2011 Nov working interests 2010 2011 * • Daily average for month of November 2011 • Petirrojo 2 & 3 to be on production in December. 8
  9. 9. Strengthening 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; 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 $60.00 $35.00 G &A per barrel $50.00 $30.00Netback per $25.00 $40.00 $20.00 barrel $30.00 $15.00 $20.00 $10.00 $10.00 $5.00 $- $- Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2- 2011 Q3 - 2011 Operating Netback per barrel G&A per barrel 9
  10. 10. Enhancing Cubiro’s netback • New 3-year conventional oil marketing agreement signed with Pacific Rubiales effective February 1, 2011 • Three potential delivery points to Colombian pipeline infrastructure Illustrative summary of potential netbacks from crude oil sales from Cubiro production (1) (US$ per barrel) Rubiales / Guaduas / Araguaney /Delivery Point / Reference Price WTI Vasconia Vasconia (2)WTI (Nymex : November 29, 2011) $99.79 $99.79 $99.79 +8.00 +6.85 (3) +6.85 (3)Benchmark Quality AdjustmentRoyalties (7.00) (7.00) (7.00)Net Revenue $100.79 $99.64 $99.64Production costs (Q3 - 2011) 14.50 14.50 14.50Transportation & pipeline 16.50 22.50 10.00Operating Netback $69.79 $62.64 $75.14 (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 10
  11. 11. 2011 Work Program Estimated 2011 capital investment budget: $41 million (1)Property Work Program 2011(1) Approximate timingExploration PlanCubiro • 4 wells (2 Block B, 2 Block C) • 3 drilled, 3 discoveries • Yopo well, Q4-2011La Punta • 1 well (LP-4 dry) • LP-4 drilled Q2Topoyaco • 1 well (Yaraqui-1X) • Spud August 31st ; preparing to testSanta Cruz • 1 well • Spud November 20th, drillingDevelopment PlanCubiro • 4 wells + 1 WO + facilities, • 2 wells completed in Q1-2011 including storage • Petirrojo-3 dev well in Q4-2011 • Petirrojo-2 dev well in Q4-2011 • 1 WO in Q4-2011(1) Management Estimate, subject to change 11
  12. 12. 2012 Work Program Overview• 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
  13. 13. 2012 Work Program Estimated 2012 capital investment budget: $50 million - $60 million (1)Property Work Program 2012(1) Approximate timingExploration DrillingCubiro • 4 wells (3 Block B, 1 Block C) • 3 in Q1, 1 Q2, 1 Q3 • 1 contingent well (Block C)Arrendajo • 1 well • 1 well in Q1-2012Santa Cruz • 1 well, spud Nov, 2011 • Well will TD in Q1-2012Carbonera • 1 well • 1 well in Q1-2012Development DrillingCubiro • 7 wells • 1 well in Q1-2012 • 3 contingent wells • 3 wells each subsequent qtr.Carbonera • 1 well • 1 well Q2-2012(1) Management Estimate, subject to change 13
  14. 14. Annual Cash Flow (4) 2011E 2012EAverage daily production for the year (gross before royalties)(4) 2,800 boed 4,300-4,700 boedCash flow from operating netbacks (2) $58M $82MLess: G&A $15M $16MLess: Debt service (principal & interest) (3) $18M $24MLess: Equity tax instalments $2M $ 2MNet cash flow from operations $23M $41MCash position, beginning of year $6M $17MCash available from equity financing for work program $35M -Other sources/ (uses), including working capital changes and $(6M) $ 7Mcash from asset dispositions (4)Total cash available to fund annual work program $58M $64MAnnual work program expenditures (4) $41M $50-$60M(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 14
  15. 15. Llanos Basin – CubiroOperator: PetroMagdalena EnergyWI: A:60.5% B:70% C:57.13%Contract: ANHProduct: L/M OilArea: 61,295 acres2P Reserves: 10.8 MMbbl (1)Production: 2010 A (Year Avg): 1,905 boe/d 2011E (Year Avg): 2,100 boe/d – 2,300 boe/d(2) About Cubiro • Most prolific hydrocarbon basin in continental Colombia • Currently producing from 18 wells in the Careto, Arauco, Barranquerro and Copa fields • 86% increase in 2P reserves (Sept 2011 vs Dec 2010) (1) • Improved marketing contract (Pacific Rubiales) and reduced opex has significantly improved the netback per barrel vs 2010 • 2011 Exploration program with three discoveries with 5.1 MMbbls (3) of recoverable reserves (2P) (1) (1) Petrotech Report dated Sept. 30, 2011, PetroMagdalena share, gross before royalties (2) Management Estimates 15
  16. 16. Llanos Basin - Cubiro Highlights Field Prospect • Operated by PetroMagdalena Palmarito C7 • All production is subject to the sliding 40 °API scale royalty rates of ANH and a 3% overriding royalty on total production from the Block. Careto Turpial Yopo, Q4-2011 Arauco Barranquero Sirenas • The Cubiro Block has been under an Exploration and Production (E&P) Petirrojo C5 37 °API Cernicalo Petirrojo Sur Contract with ANH since October 8, Q1-2012 2004, exploration phases followed by a Canario Sirenas 25 year production period. Sur Guanapalo Copa • Currently, there are seven producing oil C7 30 °API Tijereto Sur fields: Careto, Arauco, Barranquero, Q1-2012 Petirrojo, Copa, Copa B and Copa A Copa ASur Sur. Copa BJordán Altair Copa C, Q1-2012 Caño Gandul • Currently producing from Carbonera C-C729 °API C7 C5-C7 38 °API 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, Polygon A : Polygon B : Polygon C : Copa B and Copa A Sur in Q3 2011 Development Area Exploration Area Exploration Area 60.5% W.I. 70% W.I. 57% W.I. 16
  17. 17. Petirrojo Field, Petirrojo South & Yopo Prospects• Petirrojo-1 encountered 32 ft of net pay. Carbonera C7 After an initial test rate of 1,545 bopd of TWT Seismic Map 40 API light oil the well averaged 1,849 bopd (Company share, 1,294 bopd) over the next 15 days and remains on production. Yopo Prospect• 2nd well (Petirrojo-3 dev well) has been drilled and cased from the same location Q4-2011, 3rd well (Petirrojo-2 dev well) is currently drilling.• Yopo exploration well planned to be drilled when civil work is completed, Q4- 2011. Petirrojo Dev. Locations• Petirrojo South will be drilled when civil work has been completed, Q2-2012 2P RESERVES (1) Petirrojo Field (Mbbls) Petirrojo 2,036 Petirrojo-1 RESOURCES (2) (Mbbls) Petirrojo South 1,100 Yopo 1,700 Petirrojo South Prospect 1 Km (1) Company share, Sept 30, 2011 technical report (2) Company share, Management estimate, not yet certified
  18. 18. Copa B Field, Copa A Sur & Copa AN Prospect Carbonera C7• Copa B-1 exploration well encountered 41 ft of net pay. Daily average production during TWT Seismic Map October has averaged 765 bopd (Company share 437 bopd). ESP stopped Copa AN Prospect working October 20th; the well went back on production Nov 9th .• Copa A Sur-1 exploration well successfully drilled with Initial 4-day test rate of 1,114 bopd (Company share, 636 bopd) of 38.4° Copa ASur Field API light oil on natural flow.• Copa A Sur-1 went on production Nov 6th .• The Copa C structure to the south of Copa Copa ASur-1 B will be drilled in Q1-2012 CURRENT TECHNICAL REPORT (1) Copa B Field 2P Reserves (Mbbls) Copa B 1,230 Copa B -1 1 Km Copa A Sur 1,831 (1) Company share, September 30, 2011 technical report 18
  19. 19. Cubiro ‘C’ Area – Copa Upside 2P RESERVES Sept 30, 2011 Technical Report (Mbbls) 100% Gross Net Copa Field Copa Field 3,008 1,718 1,582 Copa A Sur 3,205 1,831 1,684 Copa A Norte Copa B 2,153 1,230 1,142 8,366 4,779 4,408 Copa A Sur RESOURCES Mgmt Volumetric Estimates: C7, C5, C3 (Mbbls) 100% Gross COS Risked Copa B % Gross Copa A North 3,363 1,920 60 1,152 Copa C 3,509 2,004 40 802 Copa C Copa D 2,340 1,336 40 534 9,212 5,260 47 2,488ProducingExploration 2012 Copa DDevelopment 19
  20. 20. Yaguazo Llanos Basin – Arrendajo Mirla Negra ARRENDAJO Highlights Azor Mirla Q4-2011 Mirla • Arrendajo is 7 km NE of the Cubiro block Blanca Oeste Arrendajo Norte Q1-2012 • 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 Arrendajo Sur • Six prospects in the Carbonera formation have been identified: Azor, Yaguazo, ArrendajoCUBIRO 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 Operator: Pacific Rubiales • PetroMagdalena acquiring 32.5% working WI: 67.5% interest from Pacific Rubiales, subject to ANH Contract: subject to ANH approval, for $10 million to be paid out of Product: Light Oil production and paying all costs for Pacific Area: 78,102 acres Rubiales go forward. Resources: 8,259 Mbbl (1) Stage: Exploration (1) Petrotech Engineering report April 2010, adjusted for the 32.5% interest being acquired from Pacific Rubiales. 20
  21. 21. Putumayo Basin About Putumayo • Putumayo Basin is located in southwest Colombia • High potential exploration targets Highlights • Partnered with experienced operators. • The possibility of finding a large field and on trend with Costayaco • PetroMagdalena Energy has a 50% working interest in the Topoyaco Block, subject to the ANH approval, with a 6% overriding royalty to Trayectoria. In addition, there is a 3.5% profit interest payable to Grant Geophysical for the seismic work. • PetroMagdalena has a beneficial 43% working interest in the Mecaya Block, subject to ANHTopoyaco & Mecaya approval, with no overrriding royalty and will pay 85%Contracts: ANH of the cost of the first 3D and well.Operator: Topoyaco - Pacific Rubiales (1) WI: 50%, subject to ANH approval Exploration Plan Mecaya – Gran Tierra WI: 42%, subject to ANH approval • One exploration well, Yaraqui -1X, (Prospect D)Product: L/M oil exploration potential commenced drilling on August 31Production: Nil (1) Contract assignment in process subject to approval by ANH 21
  22. 22. Putumayo Basin – Topoyaco Yaraqui-1X well spud August 31, 2011, in the central part of the block.Well: Yaraqui-1X The well reached totalProspect: D 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. 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 22
  23. 23. Maximize Value From Catatumbo AssetsActions TakenFarm Out Agreement for Santa Cruz:• Retain Operatorship• Retain 70% Working Interest• Pay 40% of first well in Q4 – 2011, 55% of second well, 70% thereafterFarm Out Agreement for Carbonera:• YPF becomes Operator, bring extensive gas experience• Retain 40% Working Interest• Carried through US$23 million work programFarm 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 23
  24. 24. Catatumbo Basin – Santa Cruz-1 Total of • Santa Cruz-1 is being drilled, and spud on Nov. 20th, 2011, in the A Block which has3480 acres C: 700 an area of 750 acres with a primary target acres (Mirador) thickness of over 300 ft of high porosity & permeability SS reservoir. • The well reached 3,905 ft in November,A: 750 the 13 3/8 inch casing point.acres F: 420 • The Santa Cruz Block prospective resources are acres based on the 3D seismic interpretations and surrounding analog fields. • The Santa Cruz Block has several faultedB: 800 E: 580 structures assigned prospective resources basedacres 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 51,100 215,600Operator: PetroMagdalena Source: Management EstimateWI: 70% Source: Management estimate of recoverable resources based on the 3D interpretation and are reported gross of royalties. 24
  25. 25. CapitalizationCash position (September 30, 2011): $12.3 millionDebt (September 30, 2011): Factoring Loan (maturing Oct 2012) $6.6 million Bank term loans (maturing May/ Aug 2013) $7.9 million 9% Senior Notes (maturing May 2014) CA$31.1 millionShare price (December 1, 2011): CA$1.60Shares outstanding: 142.3 millionOptions outstanding ($2.17 average) 13.5 millionWarrants outstanding ($3.50) 19 millionFully diluted: 174.8 millionMarket capitalization - undiluted (December 1, 2011): CA$227.7 million 25
  26. 26. Leadership teamManagement DirectorsLuciano Biondi Jaime Perez BrangerChief Executive Officer Executive ChairmanGregg K. Vernon, P.Eng Miguel de la CampaChief Operating Officer Serafino IaconoMichael Davies, C.A.Chief Financial Officer Ian MannFrancisco Bustillos, M.Sc. Robert MetcalfeColombian Finance &Administration Manager Luis Miguel MorelliJesus AboudExploration ManagerPeter Volk, LL.B.General Counsel & Secretary 26
  27. 27. Appendix 27
  28. 28. Assets in the most prolific basins (1) Area Operator Gross Acres WI Contract Stage Product StatusLlanos Basin Cubiro PMD 61,295 60-70-57% ANH E&P Light Oil Core Asset* Contract under La Punta Vetra 19,313 Up to 6% ECP E&P Light Oil review Arrendajo PRE 78,102 67.5% ANH Exploration Light Oil Near Cubiro Yamu WOGSA 18,194 10% ANH Prod & Exp Light Oil ProducingCatatumbo Basin Carbonera PMD 63,727 96% ANH E&P Oil & Gas Joint Venture Cerrito PRE 10,165 76-81% ECP E&P Gas or 15%/50% Farm-Out Catguas GTE 330,355 (2) ANH Exploration Oil & Gas S N Santa Cruz PMD 40,058 100% ANH Exploration Light Oil Farmed out 30% WI Carbonera – La E&P 3D seismic work plan PMD 12,558 58% ECP Light Oil Silla in placeMagdalena 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 OilPutumayo 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. 29. 2010 ANH Bid Round Six E&P Assets • Agreement for funding the exploration commitment, resulting in PetroMagdalenaVMM 35 holding a 10% Working Interest.VMM 11 LLA 41COR 33VSM 12VSM 13 MIDDLE MAGDALENA VALLEY BASIN CORDILLERA BASIN UPPER MAGDALENA VALLEY BASIN LLANOS BASIN 29
  30. 30. Colombian Pipeline Infrastructure 30