Investor Presentation - September 2011 (English)


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Investor Presentation - September 2011 (English)

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Investor Presentation - September 2011 (English)

  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. PetroMagdalena today1. Leadership team focused on strategy execution2. Enhancing netbacks, reducing costs, increasing efficiency3. Focus on core oil assets – exploration and development4. Maximize value from other assets in the portfolio - with strong partners IMPROVING HIGH EXPERIENCED POTENTIAL OPERATING DRIVING VALUE LEADERSHIP EXPLORATION CASH FLOW ASSETS Goal is to increase production and reserves 3
  4. 4. Focus on core oil assets Catatumbo Basin •Santa Cruz •CerritoMagdalena Basin •Carbonera-La •Las Quinchas Silla •Rio Magdalena •Carbonera •Catguas Llanos Basin •Cubiro •La Punta •Arrendajo •Yamu Putumayo Basin •Topoyaco •Mecaya 4
  5. 5. Achievement scorecard On Target OngoingReduced G&A by 29% Q2 2011 vs 2010 Qtrly average Increased Netback by 47% H1 2011from FY2010 average Increasing production and reserves ODrilling program at Cubiro Exploration at Cubiro Spudding of Topoyaco – D Received environmental permit for Santa Cruz Spudding of Santa Cruz * OFunded work plan in place Farm out Carbonera and Catguas to YPF** Sale of Las Quinchas & farm out of other non-core assets O PetroMagdalena is staying the course with achievable milestones* Civil and other works have begun to prepare the field** Subject to ANH approval 5
  6. 6. 2P Reserves* Crude Oil Natural Gas NGL Total (mmbbl) (mmcf) (mmbbl) (mmBOE)December 31, 2010: Total Proved (P1) 2.77 27.78 0.71 8.12 Total Proved + 9.33 99.78 4.37 30.33 Probable (2P)Change in 2P vs 2.72 (19.86) (0.73) (1.33)December 2009Focus on Core Oil Assets:• Game changer at Cubiro: added 1 MMbbls at Cubiro C (from acquisition) and exploration success at Petirojo +1.87 MMbbls and Copa B +1.28 MMbbls (mgmt estimate; not yet certified)• Company’s gross 2P oil reserves increased by 41% in 2010• Cubiro key driver fuelling recent 2P oil reserve growth • Increased 126% in 2010 to 5.8 MMbbls • Represents 62% of 2P oil reserves*December 2010 and 2009 Petrotech Reports (available at and;represents PetroMagdalena’s gross share before deduction of royalties. 6
  7. 7. Daily Average Production 2010-2011 4500 4000 3500 Copa B-1 (3-day test) 3000 Petirrojo-1 2500boed Yamu 2000 1500 32.13% Cubiro Block C acquired 1000 Arauco5/ Careto 13H 500 0 2010 base wells/ working interests Year 2010 Q1 2011 Q2 2011 Current * * September 1-11, 2011 daily average 7
  8. 8. Strengthened operating cash flow• Re-capitalized balance sheet in February 2011 through equity financing • Reduced debt by $31 million to $10 million, freeing up $1.0 million per month of operating cash flow to fund capital investments in core assets• Enhancing operating netback from Cubiro production • New oil marketing contract in conjunction with Pacific Rubiales • Implementing initiatives to reduce opex• Cost reductions generating positive trend in G&A per barrel produced $60 $35 G &A per barrel $50 $30 $25 $40Netback $20 $30 $15 $20 $10 $10 $5 $- $- Q2 - 2010 Q3 - 2010 Q4 - 2010 Q1 - 2011 Q2- 2011 Operating Netback G&A 8
  9. 9. Enhancing Cubiro’s netback• New 3-year conventional oil marketing agreement signed with Pacific Rubiales effective February 1, 2011• Three potential delivery points to Colombian pipeline infrastructure Illustrative summary of potential netbacks from crude oil sales from Cubiro production (1) (US$ per barrel) Rubiales/ Guaduas/ Araguaney/Delivery Point Vasconia Vasconia Vasconia (2)WTI (Nymex) $80 $80 $80Benchmark Quality Adjustment +8 +20 +20Net revenue 88 100 100Production costs (2011E; yearavg) 13 13 13Transportation & pipeline 16 23 10Netback $57 $64 $77(1) Management estimates, as of September 2011(2) Signing agreement in process – delivery volumes on availability 9
  10. 10. 2011E Cash flow (1)Operating cash flow from netbacks (2) $58 millionLess: G&A (including one-time costs in Q1) $15 millionLess: Debt service ongoing (principal & interest) $18 millionNet cash flow from operations $25 millionCash available from equity financing $35 millionTotal sources to fund 2011 capex plan and $60 millionworking capital2011E capex plan $40-$50 million(1) Management estimate(2) Represents estimated revenues less royalties, production and transportation costs based upon average daily production of 2,800 boe/d for the year. 10
  11. 11. 2011 Work program Estimated 2011 capital investment budget: $40 million - $50 million (1)Property Work Program 2011(1) Approximate timingExploration PlanCubiro • 3 wells (1 Block B, 2 Block C) • 2 drilled, 2 discoveries • Yopo well added to program • Yopo well, Q4-2011 (Block B)La Punta • 2 wells (LP-4 dry) • LP-4 drilled Q2, LP-5 Q4Topoyaco • 1 well (Yaraqui-1X) • Spud August 31stSanta Cruz • 1 well • Spud Early Q4-2011Development PlanCubiro • 3 wells + 3 WOs + facilities, • 2 wells completed in Q1- including storage 2011 • 1 well in Q3, WO’s in Q4-2011 • 1 well added to program • Petirrojo-2 well in Q4-2011 (Block B)(1) Management Estimate, subject to change 11
  12. 12. Llanos Basin – CubiroOperator: PetroMagdalena EnergyWI: A:60.5% B:70% C:57.13%Contract: ANHProduct: L/M OilArea: 61,295 acres2P Reserves: 5.8 MMbbl (1)Production: 2010 A (Year Avg): 1,905 boe/d 2011E (Year Avg): 2,100 boe/d – 2,300 boe/d(2) About Cubiro • Most prolific hydrocarbon basin in continental Colombia • Currently producing from 18 wells in the Careto, Arauco, Barranquerro and Copa fields • 126% increase in 2P reserves (Dec 2010 vs Dec 2009) • April 15, 2011 acquisition (Jaguar) represents incremental 1.0 MMbbls in 2P reserves as of Dec 31, 2010 • Improved marketing contract PRE and reduced opex has significantly improve the netback per Petrotech Dec 31, 2010 Report , PetroMagdalena share, (1) barrel vs 2010 gross before royalties • 2011 Exploration program two discoveries with Mgmt Management estimate , including impact of April 15,. 2011 (2) estimate of 3.1 MMbbls (3) of recoverable reserves. Jaguar acquisition (3) Company share, not yet certified 12
  13. 13. Llanos Basin - Cubiro Highlights Field • Operated by PetroMagdalena Energy Prospect • All production is subject to the sliding scale royalty rates of ANH and a 3% Palmarito C7 40 °API overriding royalty on total production Careto from the Block. Turpial Yopo, Q4-2011 • The Cubiro Block has been under an Exploration and Production (E&P) Arauco Sirenas Barranquero Petirrojo C5 37 °API Contract with ANH since October 8, Cernicalo Q1-2012 Petirrojo Sur 2004, followed by a 25 year production period. Sirenas • Currently, there are six producing oil Canario Sur Guanapalo Copa fields: Careto, Arauco, Barranquero, C7 30 °API Tijereto Sur Q1-2012 Copa, Copa B and Petirrojo. Copa AS • Currently producing from Carbonera C- Copa B 5, C-7 and Gacheta formations.Jordán Copa C, Q1-2012C729 °API Altair C7 Caño Gandul C5-C7 • Acquired an additional 32.13% of the 38 °API Cubiro C eastern area on April 15, 2011. • Two new fields discovered at Petirrojo and Copa B in Q3 2011 Polygon A : Polygon B : Polygon C : Development Area Exploration Area Exploration Area 60.5% W.I. 70% W.I. 57% W.I. 13
  14. 14. Petirrojo Field, Petirrojo South & Yopo Prospects• Petirrojo-1 encountered 32 ft of net pay. Carbonera C7 After an initial test rate of 1,545 bopd of TWT Seismic Map 40 API light oil the well averaged 1,849 bopd (Company share, 1,294 bopd) over the next 15 days and remains on production. Yopo Prospect• Petirrojo-2 development well will be drilled from the same location Q4-2011.• Yopo exploration well to be drilled when civil work is completed, Q4-2011.• Petirrojo South will be drilled when civil work has been completed, Q2-2012 Petirrojo Dev. Locations CURRENT MGMT. ESTIMATES (1) Recoverable Reserves (MM Bbls) Petirrojo Field Petirrojo 1,870 RESOURCES Petirrojo-1 (MM Bbls) Petirrojo South 1,100 Yopo 1,700 Petirrojo South Prospect 1 Km (1) Company share, not yet certified
  15. 15. Copa B Field, Copa AS & Copa AN Prospect Carbonera C7• Copa B-1 exploration well encountered 41 TWT Seismic Map ft of net pay. Initial 3-day test rate of 1,045 bopd (Company share, 597 bopd) of 39.3° Copa AN Prospect API light oil. The well will be put on test in 2 zones for approximately 6 weeks and then a full testing program on all zones will be completed.• Copa AS-1 exploration well will be drilled Copa AS Prospect from the same location in Q3-2011.• The Copa C structure to the south of Copa B will be drilled in Q1-2012 Copa AS-1 CURRENT MGMT. ESTIMATES (1) Recoverable Reserves (MM Bbls) Copa B Field Copa B-1 1,260 RESOURCES (MM Bbls) Copa B -1 Copa AS-1 1,002 1 Km (1) Company share, not yet certified 15
  16. 16. Cubiro ‘C’ Area – Copa Upside RESERVES COPA (MM Bbls) Petrotech Dec 2010 Gross 100% 25% 57.13% Copa Field Proved 1,592 398 910 Probable 1,599 400 914 2P 3,192 798 1,825 Copa A North RESERVES COPA B (MM Bbls) Management Estimate Gross Copa A South 100% 25% 57.13% Recoverable 2,210 553 1,260 Reserves Copa B RESOURCES Mgmt Volumetric Estimates: C7, C5, C3 (MM bbls) 100% 25% 57% COS Risked % 57% Copa C Copa A North 3,363 841 1,920 60 1,152 Copa A South 2,925 731 1,670 60 1,002Exploration 2011 Copa C 3,509 877 2,004 40 802Exploration 2012 Copa D 2,340 585 1,336 40 534 Copa D 12,137 3,034 6,930 200 3,490Development @ 25% WI @ 57% WI Change COPA 2P Reserves (MM bbl) 798 1,825 1,027 COPA B Recoverable (MM bbl) 553 1,260 708 COPA Exp. Risked Upside (MM bbl) 1,528 3,490 1,962 16
  17. 17. Putumayo Basin About Putumayo • Putumayo Basin is located in southwest Colombia • High potential exploration targets Highlights • Partnered with experienced operators. • The possibility of finding a large field and on trend with Costayaco • PetroMagdalena Energy has a 50% working interest in the Topoyaco Block, subject to the ANH approval, with a 6% overriding royalty to Trayectoria. In addition, there is a 3.5% profit interest payable to Grant Geophysical for the seismic work. • PetroMagdallena Energy has a 42% working interest in the Mecaya Block, subject to ANH approval, withTopoyaco & Mecaya no overrriding royalty and will pay 85% of the cost ofContracts: ANH the first 3D and well.Operator: Topoyaco - Pacific Rubiales (1) WI: 50%, subject to ANH approval Capital Investment Plan Mecaya – Gran Tierra WI: 42%, subject to ANH approval • One exploration well, at Prospect D on Topoyaco, willProduct: L/M oil exploration potential be drilled in Q3 of 2011Production: Nil (1) Contract assignment in process subject to approval by ANH 17
  18. 18. Putumayo Basin – Topoyaco Yaraqui-1X well spud August 31, 2011, in the central part of the block. The well plan isWell: Yaraqui-1X to reach a total depthProspect: D of 10,509 feet MD, or 9,402 feet TVD, targeting the Cretaceous Villeta and Caballos formations, in a sub-thrust structure called prospect “D”. Prospect ‘D; Resource Estimate -100% (mbbls) PROSPECT LOW BEST HIGH ‘D’ 15,808 46,907 147,119 Gross PetroMagdalena 7,904 23,453 73,560 Source: April 30, 2010 Petrotech Report (available at 18
  19. 19. 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 led exploration program• Retain working interests of 15% in North area and 4.5% in South area• Carried through 2012 work program 19
  20. 20. Catatumbo Basin – Santa Cruz-1Total of 3480 • Santa Cruz-1 will be drilled in Q4-2011, in the A Block, with an area of 750 acres and acres C: 700 an expected primary target (Mirador) acres thickness of over 300 ft of high porosity and permeability sandstone reservoir. • The environmental permit has been issued A: 750 and civil work has started on the location. F: 420 acres • The Santa Cruz Block prospective resources are acres based on the 3D seismic interpretations and surrounding analog fields. • The Santa Cruz Block has several 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. 20
  21. 21. CapitalizationCash position (June 30, 2011): $26.5 millionDebt (June 30, 2011): Bank term loans $9.5 million 18-month factoring Loan $8.6 million 3-year 9% Senior Notes CA$31.1 millionShare price (Sept 6, 2011): CA$0.95Shares outstanding: 142.3 millionOptions outstanding ($2.52 average) 9.5 millionWarrants outstanding ($3.50) 19 millionFully diluted: 170.8 millionMarket capitalization (Sept 6, 2011): CA$135.2 million 21
  22. 22. 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 22
  23. 23. Appendix 23
  24. 24. Assets in the most prolific basins (1) Gross Area Operator WI Contract Stage Product Status AcresLlanos 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 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 Farm out potential Carbonera – E&P 3D seismic Work PMD 12,558 58% ECP Light Oil La Silla plan 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 24
  25. 25. Llanos Basin – Arrendajo Highlights • Operated by Pacific Rubiales Energy • Several light oil prospects on trend with producing oil fields Sector A: 3% ORR • 120 km2 of 3D survey completed in April 2011, currently being evaluated • Five prospects in the Carbonera formation have been identified: Mirla Blanca, Yaguazo, Tigua, Buho and Babillas • Mirla Negra-1 well tests on the C-5 over the ARRENDAJO perforated interval of 5,506 - 5,510 feet MD Sector B: 3% ORR showed a daily rate of 130 barrels of oil at 34.5° Cubiro API with a 69% water cut. • Management estimates resources of ~ 5 Petirrojo 20 MMbbl with addition of the new 3D seismic surveyOperator: Pacific RubialesWI: 35% • PetroMagdalena acquired overriding royaltiesContract: ANH of 4% and 3% in the A and B sectors,Product: Light Oil respectively, on the block in April 2011.Area: 78,102 acres • Arrendajo is 7 km NE of the Cubiro blockResources: 3,059 Mbbl (1)Stage: Exploration(1) Petrotech Engineering report April 2010 25
  26. 26. 2010 ANH Bid Round Six New E&P Assets Agreement for funding the exploration commitment resulting in PetroMagdalena holding a 10% Working Interest.VMM 35VMM 11 LLA 41COR 33VSM 12VSM 13 MIDDLE MAGDALENA VALLEY BASIN CORDILLERA BASIN UPPER MAGDALENA VALLEY BASIN LLANOS BASIN 26
  27. 27. Colombian Pipeline Infrastructure 27
  28. 28. Valuation metrics As at September 6, 2011 $120,000 $60,000,000 $114,122x $49,559,154x Market Capitalization / Reserves (mmBOE)Market Capitalization / Production (boed) $100,000 $50,000,000 $80,000 $40,000,000 $64,338x $60,000 $30,000,000 $40,000 $20,000,000 $14,488,295x $20,000 $10,000,000 $- $- PetroMagdalena Energy Peer* PetroMagdalena Energy Peer* Corp Corp Source: Bloomberg & Company 2011 Q2 MD&A Reports *Peer: Gran Tierra, Canacol, Parex, Petrodorado & C&C Energia 28