SPE 151825

Risk Analysis and Economic Evaluation of Oil and Gas Prospects Offshore Uruguay S. Ferro, J. Tomasini, M. Soto, E. Morales, P. Rodríguez, B. Conti, H. de Santa Ana, ANCAP Exploración y Producción

Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference held in Mexico City, Mexico, 16–18 April 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Hydrocarbon exploration offshore Uruguay has been historically very limited. Only two wells were drilled in shallow waters in 1976. Additionally, there are about 30.000Km of 2D reflection seismic, including 6.400Km acquired in 2011. ANCAP, the National Oil Company, offered offshore areas for exploration and exploitation of hydrocarbons to interested international oil companies through Uruguay Round 2009. This bidding round successfully ended with the signature of contracts for two areas. This auspicious result, in addition to the interest shown by the upstream industry, have lead ANCAP to launch the Uruguay Round II. The most recent 2D seismic survey allowed the definition of several prospects. This article presents the risk analysis and economic evaluation of the potential development of three prospects offshore Uruguay, of different type and depth, considering for each one the possible occurrence of dry natural gas, natural gas with condensate or oil. The Estimated Ultimate Recovery, Net Present Value, Internal Rate of Return and Payout were determined for each prospect by Monte Carlo simulation. Different development concepts were considered for each case. A sensitivity analysis of the key variables (reservoir parameters, hydrocarbons price, capital and operational expenditures) was carried out showing the impact of each variable on the project. Finally, a decision tree analysis was used to compute the Expected Monetary Value of each case, incorporating the geological chance of success and minimum economic field size as inputs for the assessment. ANCAP signs the exploration and production contracts with offshore Contractors on behalf of the Uruguayan Government, and is in charge of designing the fiscal regime ruling in Uruguay. Thus, this analysis includes the latest and real terms applied in Uruguay Round II, including ANCAP’s participation and actual market considerations; consequently it provides a very good estimation of the oil company’s take. This work constitutes the first evaluation of this kind applied to prospects offshore Uruguay, therefore its results and conclusions are significant for those international oil companies that might be interested in carrying out exploration activities in offshore Uruguayan basins.

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Introduction There are 3 sedimentary basins offshore Uruguay: Punta del Este, Pelotas and Oriental del Plata basins. These basins comprise a great number of depocenters formed during Gondwana break up and the opening of Atlantic Ocean. Punta del Este basin has an area of 11.000Km2 and Pelotas basin an area of 15.000Km2, both under water depth ranging from 20 to 1000m. Oriental del Plata basin has an area of about 30.000Km2 and develops in the deep and ultra deep waters of Atlantic Ocean (Morales, In Review). Exploratory history of the Uruguayan continental shelf summarizes to a total of 30.000Km of 2D seismic and 2 exploratory wells drilled by Chevron in 1976, located in the shallow waters of Punta del Este basin. Even though both wells had natural gas shows they were declared dry without testing. Further studies on seismic sections acquired afterwards, showed lack of closure of the drilled structures. A later fluid inclusions analysis of the cuttings of both wells, showed the occurrence of 32ºAPI oil, methane and ethane proving the existence of an active petroleum system in the area (Tavella, 1996). Pelotas and Oriental del Plata basins have not been drilled yet. Therefore this situation allows us to describe Uruguayan offshore basins as truly under explored; frontier basins with a high exploratory risk. Many structural, stratigraphic or combined leads and prospects have been identified in Uruguayan offshore basins, at bathymetries ranging form 50 to 3000m. Those exploratory situations are analogous regarding sedimentary geometry, structural features, depositional systems and evolution phases to prospects successfully tested in other Atlantic margin basins (Soto, 2011). After 30 years of very limited exploration activity in Uruguay, ANCAP made an effort with a very challenging aim: reach a comprehensive knowledge of all offshore Uruguayan basins. For such purposes a regional survey of 7000Km of 2D seismic was carried out. It was afterwards supplemented by a 2D seismic infill carried out in 2008 in Punta del Este basin. This new 2D seismic information achieved its purpose of removing some of the geological and geophysical uncertainty that lied over Uruguayan offshore basins. Based on these promising results shown by the new 2D seismic data, the Uruguayan Government and ANCAP decided to launch Uruguay Round 2009, which was a call for bids for awarding Exploration and Exploitation of Hydrocarbons Contracts in areas on the Uruguayan continental shelf. Six companies submitted the required documents and were qualified to present offers: BHP Billiton, GALP, PDVSA, Petrobras, Pluspetrol and YPF. This bidding round successfully ended with the signature of 2 contracts for 2 areas with a consortium formed by GALP, PETROBRAS and YPF. But Uruguay Round 2009 was only the first step of the process of reactivation of the exploratory activity in the country. The auspicious result of Uruguay Round 2009 plus the interest shown by the upstream industry have lead ANCAP to launch the Uruguay Round II. For this new bidding round 15 offshore areas were offered, covering the 3 offshore basins, located from shallow to ultra deep waters. Uruguay Round II was officialy announced in Montevideo in September 2011 and bids were to be submitted on March 2012. With the aim to have new data for Uruguay Round II to offer to the upstream industry, and to better confirm some leads and prospects identified with the already existing data, ANCAP aquired in 2011 6400Km of 2D seismic. For this article, 3 prospects of different type and depth were selected, considering for each one the possible occurrence of dry natural gas, natural gas with condensate or oil. Monte Carlo simulation, decision tree analysis, sensitivity analysis and cash flow models including the latest and real terms applied in Uruguay Round II, were used as methodology for calculation of several parameters, such as EUR, NPV, IRR, Payout, EMV and Contractor’s take. This work constitutes the first evaluation of this kind applied to prospects offshore Uruguay, therefore its results and conclusions are significant for those international oil companies that might be interested in carrying out exploration activities in offshore Uruguayan basins.

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Geologic features of the selected prospects

The main geological characteristics of the prospects that were selected for the assessment presented in this article are:

Prospect 1

This prospect is a very large (P50 = 134Km2) stratigraphic trap of the synrift sequence located in shallow waters of the Punta del Este Basin aulacogen. It is interpreted as a lacustrine fan of Neocomian age which prograded into a large hemigraben of NW-SE trend from the hemigraben shoulder (Polonio High). It is interpreted as a sequence of interbedded sandstones and shales, and shows amplitude anomalies. In strike seismic sections it is shaped as a biconvex lens tilted towards the SW. Mean water depth is 100m and increasing towards the SE, and sediments depth is 4150m in average.

The main potential source rocks are Devonian and/or Permian marine shales of the prerift sequence and Jurassic-Neocomian lacustrine shales of the synrift sequence. Seal is provided by shales of the synrift sequence and the break-up unconformity.

Migration is achieved through faults and direct contact between the source and reservoir rocks.

Prospect 2

This prospect is a large (P50 = 92Km2) stratigraphic trap of the early drift sequence located in ultra-deep waters of the distal Punta del Este Basin. It is interpreted as a basin floor fan/turbidite of probable Late Cretaceous or Paleocene age related to a Falling-stage System tract (FSST), and covered by an onlapping marine sequence corresponding to a Transgressive System tract (TST). In dip seismic lines it is sigmoid shaped, with its major axis orientated to the NW-SE. The prospect is ponded against an anticline related to the uplift of the SDR sequence in the Late Cretaceous. It is interpreted as a mainly sandy sequence, and shows amplitude anomalies. Mean water depth is 1300m and increase towards the SE, while sediments average depth is 4350m.

Probable source rocks are: Jurassic-Neocomian lacustrine shales of the synrift sequence and Aptian marine shales of the transitional sequence.

Seal is provided by Paleocene-Eocene deep water marine shales.

Migration is achieved through faults that connect the underlying source rocks of the synrift and transitional sequences with the reservoir.

Prospect 3

This prospect is a large sized (P50 = 117Km2) structural trap of the synrift sequence located in ultra-deep waters of the distal Punta del Este Basin. It is interpreted as an anticline flanked by two hemigrabens, which probably was further structured as a consequence of Cretaceous reactivation. The anticline is locally faulted. The reservoir probably includes sandstones and conglomerates, and subordinately fractured crystalline rocks. The break-up unconformity shows an amplitude anomaly. Mean water depth is 1.230 m and increase towards the SE, and sediments depth is 5000m.

Probable source rocks are: Devonian and/or Permian marine shales of the prerift sequence, Jurassic-Neocomian lacustrine shales of the synrift sequence and Aptian marine shales of the transitional sequence.

Seal is provided by the break-up unconformity and Aptian distal marine shales.

Migration is achieved trough faults and direct contact between the underlying source rocks with the reservoir, and trough direct contact with the overlying source rocks of the transitional sequence.

The three prospects selected for this analysis are shown in 2D seismic sections in Figure 1.

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Fiscal Regime ANCAP, the National Oil Company of Uruguay, is the one to execute the hydrocarbons activities, business and operations by itself or by third parties. It acts on behalf of the Uruguayan Executive Branch by signing exploration and exploitation contracts with oil companies. By Hydrocarbons Law, fields and extracted substances are property of the Uruguayan State, therefore under this regime the contracts are of the Production Sharing Agreement type, for which Contractor assumes all risks, costs and responsibilities of the activity (ANCAP, 2011). The contract term is 30 years, which can be extended due to technical reasons up to a maximum of 40 years. The exploration term is up to 8 years, divided in 3 exploration subperiods of 3, 3 and 2 years. The Commited Exploratory Program for the first exploration subperiod is the one offered by the Oil Company at the bidding round. ANCAP does not require the mandatory drilling of an exploratory well for the first exploration subperiod. Hydrocarbons production would be splitted in 3 ways, Cost Oil, Profit Oil for the Contractor and Profit Oil for the Uruguayan Government. Cost recovery is limited to 60% in case of oil production and 80% in case of natural gas production.The Contractor is paid with the part of hydrocarbons produced corresponding to Cost Oil and its Profit Oil. Contractor is entitled to freely dispose such hydrocarbons, but ANCAP has the preferential right to totally or partially purchase the oil, for domestic consumption only. In that case, the price of oil and gas would be set at real value of the international market for hydrocarbons of similar characteristics. No bonuses, royalties or surface rentals are required. Profit Oil for the Uruguayan Government increases according to an R factor, which is defined as usually in the upstream industry, as the ratio of Gross Income over Cost Oil (Johnston, 2003). Regarding the tax regime, net worth, consumption and custom taxes are exempted by hydrocarbons law, which declares the activity of national interest. Income tax can also be totally exempted, due to the investment promotion regime in force in Uruguay. ANCAP has the right to associate with the Contractor after there is a discovery with a perecentaje offered by the oil company at the bid. ANCAP is only carried through exploration and would pay for its share of exploration costs at the moment of association and from that moment on ANCAP would pay its share of every cost and receive its share of the revenues, like any private partner in a joint venture. The cash flow analysis considered for this work, takes into consideration shooting of 3D seismic, which extension depends on the prospect area and the drilling of an exploratory well as risk capital. After discovery the drilling of 2 appraisal wells is considered. It also includes a percentaje of ANCAP’s association of 20%, 0% of taxes and a Profit Oil split given by Table 1, with X = 2 in case of Oil Production and XG = 4 in case of Natural Gas Production. In addition, sensitivity analysis of ANCAP’s association, X and XG were carried out. Methodology The most recent 2D seismic survey allowed the definition of several prospects. The risk analysis and economic evaluation of the potential development of three prospects offshore Uruguay was carried out. Nine different scenarios were considered in total, since 3 prospects were selected and for each one the possible occurrence of dry natural gas, natural gas with condensate or oil was considered. Due to the uncertainty inherent to all input variables, all the calculations were conducted stocastically by 10.000 iterations of Monte Carlo simulation (Bailey, 2001), with probability distributions as input for each variable. The Estimated Ultimate Recovery is given by the formula:

EUR = Area x Avg. Net Pay x Rec. Yield

Area of each prospect was defined by the interpretation of the available 2D seismic data, taking into account a maximum and a minimum value, and performing reality checks for the high ends. Similarly, reality checks were also carried out for the mean area of each prospect, comparing it with Gulf of Mexico, West Africa and Campos Basin prospects data. Average Net Pay was computed as the product of Gross Pay Thickness, Geometry Correction Factor and Net to Gross Ratio. These parameters were inferred from seismic and wells data and also submitted to reality checks.

SPE 151825 5

Recovery Yield was calculated by the product of Porosity, Hydrocarbons Saturation, Formation Volume Factor and Recovery Efficiency. These parameters were estimated from analogies with other prospects in similar basins and took into account the different type of fluid. As a result of the reality check iteration conducted, the mean value of the Recovery Yield was adjusted to the one of a good quality reservoir. In the scenario of oil, a 32º API oil was considered, taking into consideration the fluid inclusions analysis performed to the cuttings of the wells (Tavella, 1996). Reality checks for the resulting EUR was performed comparing mean values with data from other productive basins as well as checking the ratio of P90/P10 values (Alexander, 1998). Given the Estimated Ultimate Recovery Volume, the production profile was defined (30 years of production in case of oil with a plateau of 7 years and 40 years of production in case of natural gas with a plateau of 27 years), considering drainage area or productivity per well as production uncertainties. The best development concept was selected considering the number of production and injection wells, water depth and type of fluids to be produced. The number of wells to be drilled to accomplish the designed production profile, facilities and pipelines to be constructed and installed, abandon costs, in addition to the exploratory risk capital, allowed the calculation of the total CAPEX for each case. The operating costs per barrel of oil equivalent produced in each case and the sale price of hydrocarbons were input as lognormal distributions (Capen, 1992). All these factors were brought together in the cash flow model, with the addition of the fiscal regime described above, for the calculation of NPV, IRR and Payout. The cash flow analysis allowed us to calculate the cost oil and profit oil split, considering the profit for each party: the Contractor, the Uruguayan State and ANCAP. A Production Sharing Contract flow diagram was used in order to calculate the Contractor’s take (Johnston, 1994). The Expected Monetary Value (EMV) of each of the 9 assessed scenarios was calculated by means of a decision tree. The first Probability Node considers the Probability of Geological Success, the probability of finding sufficient quantities of oil/gas to produce a sustainable flow, and the dry hole probability. If there is a geological Success, the second Probability Node takes into account the probability of finding an accumulation size exceeding the Minimum Economic Field Size, which is finding enough hydrocarbons to obtain a positive NPV by developing the field. Finally, in addition to tornado plots showing the influence of each input variable on the EMV, a sensitivity analysis of the variables to be bid by oil companies at Uruguay Round II (% of ANCAP’s Association, X and XG) was carried out. Results

Considering the oil scenario, Prospect 1 and Prospect 2 could be clasified as giant fields while Prospect 3 could be classified as a sub giant field (according to their P50 EUR results). This result is mainly due to the large area of the selected prospect, which is the factor to which EUR is most sensitive.

Probability of Geological Success

The main risk associated with the prospects is the presence of source rocks, which have been interpreted in seismic sections, matching those expected by correlation with South Atlantic offshore basins (where Jurassic-Neocomian lacustrine source rocks and Aptian and Turonian marine source rocks are widespread) and with Uruguayan onshore basins (where very good Emsian, Artinskian and Aptian source rocks are present).

Other relatively high risks are:

- Prospect 1: presence of seal (the same as in other proximally located prospects of the rift and early drift sequences) and timing/migration are the most important risks after presence of source rock, which is the critical factor;

- Prospect 2: timing/migration is a risk, given that some faults that connect the underlying source rocks with the reservoir might have been developed (or at least reactivated) not later than in the Paleocene.

- Prospect 3: reservoir preservation is the critical factor

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The probability of geologic success (Pg) is obtained by multiplying the probabilities of the occurrence of each of the five factors of the prospect (Otis, 1997). To sum up, as can be seen in Figure 2, Pg for Prospects 1, 2 and 3 is 9.0%, 12.1% and 14.2%, respectively.

Development concepts The selection of development concepts was based in the particular features of each prospect (water depth, distance to the shore, recoverable hydrocarbons volumen, etc) as well as the 3 assessed scenarios regarding the potential fluid to be produced. A summary of the development concepts is presented in Table 2. Prospect 1 would be deloped for oil production by means of horizontal production wells, vertical water injection wells and vertical natural gas injection wells. Those wells would be connected to the main platform by sub sea well systems. The oil stabilization, natural gas and water separation would be carried out in the main platform facilities. The stabilized oil would be transported to a storage unit onshore by a 200Km pipeline. Produced natural gas and water would be reinjected to the reservoir. Part of the produced natural gas would be consumed for rig operations. In case of natural gas and condensate production, Prospect 1 would be developed by a similar concept described in the previous paragraph for oil production but with the difference of an additional 200Km natural gas pipeline transporting the gas to an onshore gas processing terminal and then distributed to for the regional market consumption. Finally, Prospect 1 would be devoleped in case of dry natural gas production with the same development concept described in the previous paragraph, but without the oil pipeline and the onshore oil storage. The produced natural gas would flow from the sub sea well systems to the main platform, then transported to the onshore gas terminal and distributed to the regional market through the existing pipeline network. Prospects 2 and 3 would be deloped for oil production by means of horizontal production wells, vertical water injection wells and vertical natural gas injection wells. Those wells would be connected to an FPSO by sub sea well systems. The oil stabilization, natural gas and water separation would be carried out in the FPSO facilities. The stabilized oil would be stored for the later tankers offloading. Produced natural gas and water would be reinjected to the reservoir. Part of the produced natural gas would be consumed for FPSO operations. In case of natural gas and condensate production, Prospect 2 and 3 would be developed by a similar concept described in the previous paragraph for oil production but with the difference of an additional 300Km natural gas pipeline transporting the gas to an onshore gas processing terminal and then distributed for regional market consumption. Finally, Prospect 2 and 3 would be devoleped in case of dry natural gas production with a floating platform in which the produced gas from the different sub sea well systems merge. The dry natural gas is then transported by a 300Km pipeline to an onshore gas terminal and distributed to the regional market through the existing pipeline network.

Cash flow Analysis The Capital Costs (including onshore and offshore facilities, pipelines, abandon costs and drilling and completion of exploratory, appraisal, production and injection wells) ranged from the lowest of P50 = 7.071MMUS$ in the case of Prospect 1, Oil scenario up to the highest of P50 = 18.451MMUS$ in the case of Prospect 3, gas and condensate scenario. As an average of all scenarios (at P50 values) CAPEX constitute a 20% of Gross Income, and Total Costs (CAPEX + OPEX) represent a 52% of Gross Income. As is shown in Figure 3, the cash flow has the shape of a typical upstream investment, with negative flows during the exploration, appraisal and development phases, and positive flows during the production phase, with a decline of the positive cash flows towards the end of project and field`s life. The Production Sharing Contract flow diagram is presented in Figure 4. For the purpose of comparison of fiscal terms, a Government’s take of about 45% places Uruguay among the top 3 countries with lowest Government Take in the world, regarding the International Petroleum Exploration and Development Contracts (Johnston, 2003). This calculation already takes into account the National Oil Company’s participation, which is carried

SPE 151825 7

through exploration, therefore highlighting the attractiveness of the Uruguayan fiscal regime. A summary of the results is presented in Table 3.

Expected Monetary Value Figure 5 illustrates a decision tree analysis showing the EMV probability density distribution. Considering each of the 9 cases under the light of the EMV decision rule (Newendorp, 2000) the P50 result is positive in all cases except for scenarios of dry natural gas for Prospects 2 and 3. If we consider the whole EMV distribution, it would be positive for P10, P50 and P90 only in the case of Prospect 1, oil scenario. On the other hand, the results of P10, P50 and P90 for Prospect 3 are all negative in the case of dry natural gas scenario. A tornado plot shows the relative influence of the variables on the EMV. As it is shown in Figure 6, taking as an example Prospect 1, gas and condensate scenario, the prospect area is the most important variable, followed by oil price and gross pay thickness. Gas-Oil Ratio also plays an important influence on EMV value but natural gas price play a minor role. Finally, Figure 7 shows the sensitivity of the EMV to the bid % of ANCAP’s association and the increase of the profit oil for the Uruguayan State. There is very little variation of EMV regarding a variation of XG, being the EMV always positive for the whole range of XG. The % of ANCAP’s association has a stronger impact on EMV value, but again EMV remains allways positive. Finally, the increase of profit oil for the Uruguayan State, X, has the strongest influence on EMV, making it negative but only for very high values of X.

Conclusions The methodology described in this article is very standard and widely used in the upstream business risk analysis and economic evaluations. Nevertheless, ANCAP’s Exploration and Production team contribution is based on the unique knowledge of the Uruguayan offshore basins geology and their hydrocarbon potential and of the actual fiscal regime designed for Uruguay Round II and presently ruling the offshore activities. The 3 selected prospects resulted to be very attractive, with large EMV P50 values. Out of the 9 considered cases, only the scenario of dry natural gas occurrence for the 2 ultra deep water prospects lead to a negative EMV P50 values, mainly to the impact of the high drilling costs. The calculated average Contractor’s take is about 55% giving a strong indication of the attractiveness of the Uruguayan fiscal regime. Therefore, if exploration and appraisal is successful, the contractors would have a very large profit, as a reward for the elevated exploratory risk that conducting exploration in the Uruguayan frontier basins currently represent. In conclusion, this article constitutes the first approach of economic evaluation and risk assessment applied to hydrocarbon prospects offshore Uruguay, therefore its results and conclusions are significant for those international oil companies that might be interested in carrying out exploration activities in offshore Uruguayan basins, in other words participating of the future Uruguay Round III.

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Acknowledgments Authors would like to thank to Nelson Ucha for his support and valuable insights to this work. Spectrum and ANCAP are acknowledged for the permission to publish seismic sections. Nomenclature ANCAP: Administración Nacional de Combustibles, Alcohol y Portland. CAPEX: Capital Expenditures EMV: Expected Monetary Value EUR: Estimated Ultimate Recovery FSST: Falling-stage System Tract GOR: Gas-Oil Ratio IRR: Internal Rate of Return NPV: Net Present Value OPEX: Operating Expenditures Pe: Probability of Economic Success Pg: Probability of Geological Success PSC: Production Sharing Contract TST: Transgressive System Tract X: The percentage in the increase of the Profit Oil for the Uruguayan State XG: The percentage in Uruguayan State’s Profit increase for Natural Gas References Alexander, J.A., and Lohr, J.R., 1998, Risk Analysis: Lessons Learned, SPE paper 49030, 10 pgs. ANCAP, 2011. Specifications for the process of selection of oil companies for hydrocarbon exploration and exploitation offshore República Oriental del Uruguay (Uruguay Round II) and model contract for allocation of areas for hydrocarbon exploration and exploitation offshore República Oriental del Uruguay; http://www.rondauruguay.gub.uy/rondauruguay2/en/LEGAL/BiddingROUNDterms.aspx Bailey, W., Couett, B., Lamb, F. E., Simpson, G.S., and Rose, P.R., 2001, Taking a Calculated Risk, Schlumberger Oilfield Review, October, pp 20-35. Capen, E.C., 1992, Dealing with Exploration Uncertainties, in Steinmetz, R., ed., The Business of Petroleum Exploration, AAPG Treatise of Petroleum Geology, Chapter 5, pp 29-61. Johnston, D. 1994. International Petroleum Fiscal Systems and Production Sharing Contracts, 94-115. Tulsa, Oklahoma: PennWell Publishing Company. Johnston, D. 2003. International Exploration Economics, Risk and Contract Analysis, 25-88. Tulsa, Oklahoma: PennWell Publishing Company. Morales, E.; Soto, M.; de Santa Ana, H.; Ferro, S.; Tomasini, J.; Conti, B.; Rodríguez, P.; Gristo, P.; Ucha, N.; Veroslavsky, G. In Review. The continental margin of Uruguay: tectono-stratigraphic evolution and exploratory potential. Petroleum Geoscience. Newendorp, P.; Schuyler J. 2000. Decision Analysis for Petroleum Exploration. Second Edition. Aurora, Colorado, Planning Press Otis, R.M., and Schneidermann, N., 1997, A Process for Evaluating Exploration Prospects, AAPG Bulletin, v.81, pp 1087-1109. Soto, M.; Morales, E.; Veroslavsky, G.; de Santa Ana, H.; Ucha, N. & Rodríguez, P. 2011. The continental margin of Uruguay: crustal architecture and segmentation. Marine and Petroleum Geology 28:1676-1689. Tavella, G.F.; Wright, C.G. 1996. Cuenca del Salado. Pp. 95-116 in Ramos, V.A. & Turic, M.A. (eds.), Geología y recursos naturales de la Plataforma Continental Argentina. Relatorio del XIII° Congreso Geológico Argentino y III° Congreso de Exploración de Hidrocarburos, Buenos Aires.

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Tables

Table 1. R factor for diferent Profit Oil Split for Oil and Natural Gas production

Prospect Fluid Scenarios

Oil Natural Gas and Condensate Dry Natural Gas

1

• Producing wells: 48 • Water injection wells: 3 • Natural gas injection wells:

3 • Sub sea well systems: 3 • Fixed Platform: oil

separation and stabilization • Capacity: 130.000bopd • Oil Pipeline 18”, 200Km • Onshore storage tanks

• Producing wells: 65 • Sub sea well systems: 3 • Fixed Platform: condensate

separation. • Capacity: 85.000bpd

(condensate), 25 MMscm/d (natural gas)

• Oil Pipeline 16”, 200Km • Gas Pipeline 32”, 200Km • Onshore condensate

storage tanks • Onshore gas terminal

• Producing wells: 65 • Sub sea well systems: 3 • Fixed Platform • Capacity: 25 MMscm/d

(natural gas) • Gas Pipeline 32”, 200Km • Onshore gas terminal

2

• Producing wells: 33 • Water injection wells: 3 • Natural gas injection wells:

3 • Sub sea well systems: 3 • FPSO: oil separation,

stabilization and storage. • Capacity: 130.000bopd

• Producing wells: 37 • Sub sea well systems: 3 • FPSO: oil separation,

stabilization and storage. • Capacity: 80.000bpd

(condensate), 25 MMscm/d (natural gas).

• Gas pipeline 32”, 300Km. • Onshore gas terminal.

• Producing wells: 37 • Sub sea well systems: 3 • Floating platform • Capacity: 25 MMscm/d

(natural gas). • Gas pipeline 32”, 300Km. • Onshore gas terminal.

3

• Producing wells: 44 • Water injection wells: 2 • Natural gas injection wells:

2 • Sub sea well systems: 3 • FPSO: oil separation,

stabilization and storage. Capacity: 60.000 bopd

• Producing wells: 62 • Sub sea well systems: 3 • FPSO: oil separation,

stabilization and storage. • Capacity: 50.000 bpd

(condensate), 15 MMscm/d (natural gas).

• Gas pipeline 26”, 300Km. Onshore gas terminal.

• Producing wells: 62 • Sub sea well systems: 3 • Floating platform • Capacity: 15 MMscm/d

(natural gas). • Gas pipeline 26”, 300Km. • Onshore gas terminal.

Table 2. Sumary of the different development concepts considered for each prospect and scenario.

R Factor Profit Oil for Uruguayan

Government (Oil Production)

Profit Oil for Uruguayan Government (Natural

Gas Production) ≥0,0 8 + X 8 + XG ≥1,0 15 + X 15 + XG ≥1,5 20 + X 20 + XG ≥2,0 30 + X 30 + XG

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Prospect Model Outputs

Fluid Scenarios

Oil Natural Gas and Condensate Dry Natural Gas

P10 P50 P90 P10 P50 P90 P10 P50 P90

1

EUR (MMBOE) 141 629 2.465 570 2.771 10.592 380 1.680 6.758 CAPEX (MMUS$) 1.904 7.071 24.416 2.789 10.221 43.897 2.680 10.604 35.437 OPEX (MMUS$) 2.315 13.695 71.857 6.318 52.073 296.971 3.681 24.626 124.093 Gross Income (MMUS$) 14.248 75.481 311.356 25.892 166.609 773.196 9.081 56.311 236.874 Total Profit (MMUS$) 1.857 47.178 224.774 -14.104 68.017 500.277 -18.460 11.636 110.732 NPV (MMUS$) -1.110 5.805 35.800 -5.960 4.763 39.651 -7.229 -239 6.154 IRR (%) 10 39 76 7,5 35,7 76,3 -3 12 31 Payout (years) 2,78 7,92 13,02 - 7,99 15,37 - 11,15 258,99 Contractor’s Take (%) 54,36 54,57 62,35 - 54,05 56,53 47,02 61,49 - Pg (%) 9,0 9,0 9,0 Pe (%) 84,3 73,8 44,2 EMV (MMUS$) 24,8 547,5 3.001,4 -3,65 505,1 3.227 -70,4 9,75 346,4

2

EUR (MMBOE) 148 659 2677 707 2.851 10.937 397 1.755 7.187 CAPEX (MMUS$) 3.313 10.357 36.490 3.057 15.166 56.127 3.387 14.517 51.549 OPEX (MMUS$) 2.316 13.518 72.247 5.915 53.157 327.722 3.668 28.741 140.530 Gross Income (MMUS$) 15.149 77.148 390.625 19.896 167.392 850.153 7.515 58.611 248.571 Total Profit (MMUS$) 819 46.378 296.647 -14.100 66.815 547.393 -30.189 5.420 94.717 NPV (MMUS$) -2.140 5.184 36.849 -8.185 4.298 42.777 -10.183 -1.059 4.833 IRR (%) 6 31 62 5 29 62 -5 8 25 Payout (years) 6,26 8,38 16,41 - 8,27 19,96 - 12,47 699 Contractor’s Take (%) 54,13 54,85 62,36 - 54,11 56,81 46,20 63,12 - Pg (%) 12,1 12,1 12,1 Pe (%) 79,5 69,3 32,9 EMV (MMUS$) -41,0 645,9 4.057,2 -98,5 547,4 3.776,4 -205,8 -83,7 299,5

3

EUR (MMBOE) 59 282 1245 318 1.497 6.256 204 1.035 4.138 CAPEX (MMUS$) 3.580 10.952 36.475 6.197 18.451 60.190 5.786 16.915 49.264 OPEX (MMUS$) 973 5.468 31.503 4.141 30.806 182.560 2.141 15.031 87.324 Gross Income (MMUS$) 666 34.319 160.400 12.701 92.631 426.368 5.713 33.496 150.864 Total Profit (MMUS$) -7.874 14.221 110.631 -24.047 25.887 230.749 -35.684 -1.601 50.754 NPV (MMUS$) -5.169 538,1 14.210 -9.698 156 15.760 -11.523 -2.482 873 IRR (%) -4 16 38 -3 15 40 -8 4 16 Payout (years) 7,20 10,12 38,96 - 10,27 350,14 - 19,50 2.069 Contractor’s Take (%) 38,27 57,52 - - 51,65 57,91 52,95 - - Pg (%) 14,2 14,2 14,2 Pe (%) 54,6 55,3 13,3 EMV (MMUS$) -102 173,1 1.657 -133 236,6 2.288,7 -232,3 -147,3 -22,5

Table 3. Sumary of the results showing for each prospect under diferent fluid scenarios: Untruncated EUR, Total CAPEX, Total OPEX, Gross Income, Total Profit, Contractor`s Net Present Value, Contractor`s IRR, Contractor`s Payout, Contractor`s Take, Probability of Geologic Success, Probability of Economic Success and Contractor`s Expected Monetary Value.

SPE 151825 11

Figures

Figure 1. Seismic sections of the three selected prospects

0%

20%

40%

60%

80%

100%Containment

Reservoir

HC SourceMigration

Closure

Prospect Chance Factors

 Prospect 1: Pg = 9,0%

Prospect 2: Pg = 12,1%

Prospect 3: Pg = 14,2%

Figure 2. Geologic chance factors and probabilities of geological success for the three selected prospects

Figure 3. Contractor`s undiscounted cash flow for Prospect 1 – Gas and Condensate scenario, showing the

investment and income during the phases of Exploration, Appraisal, Development and Production.

12 SPE 151825

Figure 4. PSC Flow Diagram for prospect 1 – gas and condensate scenario. Values in MMUS$.

SPE 151825 13

Figure 5. Decision Tree used for the calculation of the EMV for the case of Prospect 1 – Gas and condensate

scenario and probability density of the resulting EMV.

Figure 6. Tornado plot showing the relative influence of the main variables on the EMV for Prospect 1 – Gas and

Condensate scenario.

14 SPE 151825

-100

0

100

200

300

400

500

600

0% 10% 20% 30% 40% 50% 60% 70% 80%

EMV

(MM

US$

)EMV Sensitivity Analysis

X (%)ANCAP`s Participation (%)XG (%)

Figure 7. Sensitivity of the EMV for Prospect 1 – Gas and Condensate scenario, to the bid % of ANCAP’s

association and the increase of the profit oil for the Uruguayan State