1. Recursos y Reservas de Gas Natural de Venezuela Ing. Diego J. González Cruz [email_address] Caracas, 19 de octubre 2011

5. Licencias otorgadas en 12 años En tierra Socios Barbacoas Pluspetrol Barrancas Repsol, Ahora PDVSA San Carlos Petrobras Tinaco Petrobras Tiznado Pluspetrol Yucal Placer Norte Total (69,5%), Repsol (15%), Inepetrol (10,1%), Otepi (5,4%) Yucal Placer Sur Total (69,5%), Repsol (15%), Inepetrol (10,1%), Otepi (5,4%) Paraguana Cardón Bloque II Petropars (Iran) Cardón Bloque III Chevron Texaco Cardón bloque IV Repsol-ENI-PDVSA Moruy Bloque II Teikoku Petrobras (?) Urumaco Bloque I Gazprom Urumaco Bloque II Gazprom Urumaco Bloque III Gazprom Plataforma Deltana Petrosucre S.A. CVP (74%), ENI (24%) Petrolera Guiria CVP (64,25%, ENI (19,50%), INE Paria (16,25%) Petrolera Paria, S.A. CVP (60%,SINOPEC (32,0%), INE Paria (8%) Bloque 2 Chevron PDVSA Bloque 3 Chevron Bloque 4 Statoil Total Referencias: Informes de Gestión PDVSA varios años AVIH AVPG Mapas Petroguia

9. Recursos de Gas Natural Offshore Somero Fuente: PDVSA Prospectos de Gas Natural

10. Recursos de Gas Natural Offshore Profundo Fuente: PDVSA Prospectos de Gas Natural 73 + 74 = 147 tcf

11. Otras cifras! 98 tcf

12. Otras cifras! Referencia: PDVSA, publicación Avance Socialista, febrero 2010 108 tcf

13. 131 tcf en tierra Prospectos de Petróleo y Gas Natural en tierra

14. Un estimado conservador de las reservas de gas natural de Venezuela Reservas totales 195,1 tcf (oficiales 2010): Gas asociado 165,8 tcf (85%) Gas libre 29,2 tcf (15%) + 165,8 tcf (100%) de gas asociado - 29,8 tcf (18%) de gas que ha sido inyectado - 47,1 tcf (28,4%) asociadas a crudos pesados y extra pesados Se dispone de solo 88,9 tcf de reservas de gas asociado (Sumadas a los 29,2 tcf de gas libre) Resulta un importante volumen de 118,1 tcf.

15. El misterio de las reservas probadas no desarrolladas Ref.: PDVSA Informe de Gestión 2010 – 1 Bpe=5.800 pc 195,1 tcf totales 36,3 tcf desarrolladas Apenas el 18,6%

21. Requerimientos de gas metano por sectores a 2023 tcf Mpc/d Eléctrico, por expansión termoeléctrica en 8.400 MW 15 3.736,0 Por el aumento de la producción en 2,3 Mb/d 11 2.739,7 Petroquímico, por aumento en la producción en 25 Mtma 10 2.490,7 Siderúrgico y aluminio, por incremento producción en 2 Mtma 6 1.494,4 Refinerías, por incremento de capacidad en 500 mb/d 3 747,2 Requerimientos Faja del Orinoco 9 2.241,6 Total nuevos requerimientos principales como combustible 54 13.449,6 Total requerimientos tradicionales combustible, EyP y PQV 24 6.000,0 GRAN TOTAL DE REQUERIMIENTOS 78 19.449,6

22. Estimados de consumo Mundial de Gas Natural

23. Sobre las “reservas” de Shale Gas

24. Shale gas en Venezuela Based on regional mapping and analysis of available geologic data, the Maracaibo and Catatumbo onshore basins in Venezuela contain the most prospective shale gas plays in northern South America, holding an estimated 120 Tcf of risked shale gas in-place, Table III-1. Technically recoverable shale gas resources are estimated at approximately 30 Tcf. While a high proportion of these two basins contain shale source rocks, significant areas are immature for gas generation and/or are excessively deep for exploration and production (over 5,000 meters). Referencia: http://www.eia.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

25. Estimados de “reservas” de shale gas Referencia: http://www.eia.gov/analysis/studies/worldshalegas/ * En las formaciones La Luna y Capacho (Ver apéndice A-3) South America Venezuela 0.65 0.71 9% 178.9 11* Colombia 0.37 0.31 (21%) 4.0 19 Argentina 1,46 1.52 4% 13.4 774 Brazil 0.36 0.66 45% 12.9 226 Chile 0.05 0.10 52% 3.5 64 Uruguay - 0.00 100% 21 Paraguay - - 62 Bolivia 0.45 0.10 (346%) 26.5 48 2009 Natural Gas Market 1 (tillion cubic feet, dry basis) Proved Natural Gas Reserves 2 (trillion cubic feet) Technically Recoverable Shale Gas Resources (trillion cubic feet) Production Consumption Imports (Exports)

26. Ubicación de las shale gas en Venezuela

27. The estimates of technically recoverable shale gas resources represents a moderately conservative ‘risked’ resource for the basins reviewed . These estimates are uncertain given the relatively sparse data that currently exist and the approach the consultant has employed would likely result in a higher estimate once better information is available. At the current time, there are efforts underway to develop more detailed shale gas resource assessments by the countries themselves , with many of these assessments being assisted by a number of U.S. federal agencies under the auspices of the Global Shale Gas Initiative (GSGI) which was launched in April 2010 Una Aclaratoria Necesaria Referencia: http://www.eia.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

28. Risked Gas In-Place estimate is derived by first estimating the amount of ‘gas in-place’ resource for a prospective area within the basin, and then de-rating that gas in-place by factors that, in the consultant’s expert judgment, account for the current level of knowledge of the resource and the capability of the technology to eventually tap into the resource. The resulting estimate is referred to as t he risked gas in-place. Determining the risked gas in-place consists of the following specific steps: 1. Conduct a preliminary review of the basin and select the shale gas formations to be assessed. 2. Determine the areal extent of the shale gas formations within the basin and estimate its overall thickness , in addition to other parameters. 3. Determine the ‘prospective area’ deemed likely to be suitable for development based on a number of criteria and application of expert judgment. 4. Estimate the gas in-place as a combination of ‘free gas’ and ‘adsorbed gas’ 5. Establish and apply a composite ‘success factor’ made up of two parts. The first part is a ‘play success probability factor’ which takes into account the results from current shale gas activity as an indicator of how much is known or unknown about the shale formation. The second part is a ‘prospective area success factor’, which takes into account a set of factors (e.g., geologic complexity and lack of access) that could limit portions of the ‘prospective area’ from development. that is contained within the prospective area. Una Aclaratoria Necesaria (2)

29. The estimated technically recoverable resource base is one of the basic metrics for quantifying the total resource base that analysts would use to estimate future natural gas production. The technically recoverable resource estimate for shale gas in this report is established by multiplying the risked gas-in place by a shale gas recovery factor … The basic recovery generally ranged from 20 percent to 30 percent, with some outliers of 15 percent and 35 percent being applied in exceptional cases. The selected recovery factor based on prior experience in how production occurs, on average…. Production costs were not estimated for any of the basins. The costs of production could be greatly impacted by a number of factors including the availability of existing infrastructure, availability and cost of adequately trained labor, availability and cost of equipment such as rigs and pumping equipment, the geologic features of the fields within the play such as depth and thickness, and a number of other factors that affect the direct costs of production. Estimated production costs for each of the basins would also need to be considered in order to estimate the potential future production of shale gas given a future price. Una Aclaratoria Necesaria (y 3)

30. Conversión de gas metano en líquidos Es un proyecto de 19.000 millones de dólares en Qatar

31. Oportunidades de Negocios – Shell en Australia http://www.energydigital.com/oil_gas/shell-prelude-floating-liquefied-natural-gas-terminal Some 110,000 barrels of oil equivalent per day of expected production from Prelude should underpin at least 5.3 million tonnes per annum (mt/a) of liquids, comprising 3.6 mt/a of LNG, 1.3 mt/a of condensate and 0.4 mt/a of liquefied petroleum gas. The FLNG facility will stay permanently moored at the Prelude gas field for 25 years, and in later development phases should produce from other fields in the area where Shell has an interest.

32. El campo de producción y procesamiento en un barco! http://www.abc.net.au/pm/content/2011/s3222810.htm Un barco de 488 m de largo Produccion de 3.6 millones de toneladas de LNG anuales, ademas de 0,4 Mt/a de LPG y 1,3 Mt/a de condensados: 110.000 bep/d. Total final 3.0 tcf

33. Conversión de gas metano en líquidos “ La Perla” producirá 120.000 barriles por día (b/d) de condensado, GLP y etano además de 140.000 (b/d) de productos derivados del proceso GTL (diesel, kerosene, nafta, jet fuel y aceites lubricantes). En Pearl se fabricará suficiente diesel para abastecer a más de 160.000 vehículos al día y suficiente petróleo sintético al año para fabricar lubricantes para más de 225 millones de vehículos.

34. Proyectos LNG en Europa http://www.bloomberg.com/apps/news?pid=newsarchive&sid=a4fBz4gIVgHE Cada barco cuesta 5.000 millones de dólares

35. Industrialización del gas natural-Shell en Qatar El proyecto Pearl GTL procesa 260.000 bep/d (listo en 2011-2012) producirá diesel puro y kerosina, bases para lubricantes, nafta, y parafina normal para detergentes. Costo de operación: 6 US$/bep http://www.shell.com/home/content/aboutshell/our_strategy/major_projects_2/pearl/ships_first_products/

36. Industrialización del gas natural-Shell en Qatar El proyecto QATARGAS 4 de LNG (70% Qatar/30%Shell) Tiene una capacidad de 280.000 bep/d Producirá 1.400 Mpc/d; 7,8 Mta de LNG y 70.000 b/d de LGN Inversión: $:4.700 MUS$; costo de operación: US$/bep El proyecto incluye 9 barcos entre 210 y 266.000 m 3 c/u http://www.shell.com/home/content/aboutshell/our_strategy/major_projects_2/qatargas/

37. DJGC Muchas Gracias Diego J. González C Caracas, 19 de octubre 2011 [email_address]