Business plan 2013 2017 100 day plan August 30, 2012
Disclaimer Safe harbor statement under the US Private Securities Litigation Reform Act of 1995. This document contains statements that YPF believes constitute forward-looking statements within the meaning of the US Private Securities Litigation Reform Act of 1995. These forward-looking statements may include statements regarding the intent, belief, plans, current expectations or objectives of YPF and its management, including statements with respect to YPF s future financial condition, financial, operating, reserve replacement and other ratios, results of operations, business strategy, geographic concentration, business concentration, production and marketed volumes and reserves, as well as YPF s plans, expectations or objectives with respect to future capital expenditures, investments, expansion and other projects, exploration activities, ownership interests, divestments, cost savings and dividend payout policies. These forward-looking statements may also include assumptions regarding future economic and other conditions, such as future crude oil and other prices, refining and marketing margins and exchange rates. These statements are not guarantees of future performance, prices, margins, exchange rates or other events and are subject to material risks, uncertainties, changes and other factors which may be beyond YPF s control or may be difficult to predict. YPF s actual future financial condition, financial, operating, reserve replacement and other ratios, results of operations, business strategy, geographic concentration, business concentration, production and marketed volumes, reserves, capital expenditures, investments, expansion and other projects, exploration activities, ownership interests, divestments, cost savings and dividend payout policies, as well as actual future economic and other conditions, such as future crude oil and other prices, refining margins and exchange rates, could differ materially from those expressed or implied in any such forward-looking statements. Important factors that could cause such differences include, but are not limited to, oil, gas and other price fluctuations, supply and demand levels, currency fluctuations, exploration, drilling and production results, changes in reserves estimates, success in partnering with third parties, loss of market share, industry competition, environmental risks, physical risks, the risks of doing business in developing countries, legislative, tax, legal and regulatory developments, economic and financial market conditions in various countries and regions, political risks, wars and acts of terrorism, natural disasters, project delays or advancements and lack of approvals, as well as those factors described in the filings made by YPF and its affiliates with the Securities and Exchange Commission, in particular, those described in Item 3. Key Information Risk Factors and Item 5. Operating and Financial Review and Prospects in YPF s Annual Report on Form 20-F for the fiscal year ended December 31, 2011 filed with the US Securities and Exchange Commission. In light of the foregoing, the forward-looking statements included in this document may not occur. YPF does not undertake to publicly update or revise these forward-looking statements even if experience or future changes make it clear that the projected performance, conditions or events expressed or implied therein will not be realized. These materials do not constitute an offer for sale of YPF S.A. bonds, shares or ADRs in the United States or otherwise. 2
100 day plan 1 2 Context High impact plan 2012-2013 3 4 Business plan Financial considerations 2013-2017 3
Our new DNA Shareholder value Safety and environment Competitiveness Global Professionalism National sense Integration 4
Argentine energy demand has outstripped domestic supply GDP ; energy demand Index (100 = 1990) 230 220 210 200 190 180 170 160 150 140 130 120 110 100 90 80 70 Unprecedent growth Argentina oil & gas 99 00 01 02 03 04 05 06 07 08 09 10 11 GDP Energy demand YPF oil & gas Energy imports* (+USD 10 bn.) Production / Imports MBOE 600 500 400 300 200 100 50 0 CAGR (p.a.) last 10 years +7% -2% +4% -6% Source: IMF, World Bank, Secretaria de Energía de la Nación * Primary energy imported volume 5
High potential - strong infrastructure and dynamic market Pipelines and electric grid Tocopilla Taltal Norte Centro oeste Santiago Concepción 9 2 Loma La lata 30 5 3 Tucumán Santa cruz San jerónimo 19 23 33 16 La paz 29 20 Campo durán Paraná 16 20 1 Bahía Blanca 2,5 San Martin 12 3 Paisandú Cuiabá 30 Mercosur 22 Uruguaiana Montevideo Buenos Aires 14 NEUBA I y II 6 Belo horizonte Porto Alegre São paulo Yabog -gayrg GNEA São mateus Rio de janeiro 22 Production 2011 (by owner) Oil & gas Enap Sipetrol 1% Tecpectrol 2% Plus Petrol 3% Sinopec 3% Chevron San Jorge 3% Wintershall 6% Total Australl 6% Petrobras 7% Others 15% Total 496 MBOES YPF 36% Pan American 18% Full regional connectivity North 5 south, east west Open access Human capital +100,000 qualified jobs Highly educated management 100 years of world-class operations +50 operators and service providers (incl. top international players) 6
100 day plan Profitable growth strategy High impact Stop the decline New working platform Reverse the negative trend Growth Establish new operational DNA Mature fields Unconventional resources in factory mode Refining and marketing New paradigm Change the future of the energy sector Massive development of unconventional resources Argentina: Net energy exporter 7
100 day plan 1 2 Context High impact plan 2012-2013 3 4 Business plan Financial considerations 2013-2017 8
Seasoned management team 200+ Years of cumulative oil and gas experience 9
Seasoned management team Local and international experience 15 + years of industry experience each 10
Safety and environment first 45,000 Participants in safety and productivity program 11
Reprioritized safety and environment Creation of the QHSE Function at Corporate level, reporting directly to the CEO Environmental commitment Mapping of processes and capabilities to minimize impact Enhancement of our approach to Quality as the key to Operational Efficiency YPF Y LOS TRABAJADORES Technical training program focused on safety and productivity covering own and contractor s personnel across the country + 45,000 participants + 220 instructors 12
x 2.5 Relaunch exploration 50 exploratory wells in 2012 13
CZK 60.00 50 CZK 0.00 Exploration high impact plan Capex and wells High impact projects 350 300 250 Capex (MUSD) Wells 50 50 40 9 wells Relaunch conventional gas exploration (Neuquen basin, San Jorge Bay basin), increase exploration of tight gas (Lajas- Molles). 15 wells Exploration in mature fields aimed at rapidly putting additional resource into production. 200 30 Exploration wells Initial situation Current situation April 2012 August 2012 150 19 20 265 20 Monthly Accummulated 100 50 132 130 10 10 22 0 0 8 6 10 Average 2007/2011 Previous plan 2012 High impact plan 2012 4 2 0 January - december 2012 14
5 new shale discoveries 3 D-129 Golfo San Jorge 2 Vaca Muerta 15
New shale reserve play in San Jorge Gulf basin D129 formation Golfo de San Jorge Successful exploratory wells Wells with geochemical data LP.xp-2529 Total delineation area: 747 km 2 Blocks 100% owned by YPF: Cañadón Yatel: 237 km 2 Los Perales-las Mesetas: 1202 km 2 El Guadal - Lomas del Cuy: 531 km 2 ECh.xp-159 Las Heras LC.xp-818 Disclosed to SEN in April and June 2012 Productivity proven in additional source rock: extending shale oil and shale gas to Argentina s most mature basin 16
Shale gas discoveries in Vaca Muerta LDM.x-1 (Loma del Molle.x-1) YPF.Nq.LDMo.x-1 Location 67 km WSW from Rincón de los Sauces WI Exploration YPF 45% (operator), Exxon-Mobil 45% and G&P 10% LDMo.x-1 Rincón de los Sauces EOr.x-2 Añelo YPF.Nq.EOr.x-2 EOr.x-2 (El Orejano.x-2) Location 60 km NW from Añelo WI Exploration 100 % YPF Disclosed to SEN on 13/08/12 17
Continuing focused shale development in Vaca Muerta Vaca Muerta wells 2010-2011 Vaca Muerta 2012 Agrio 2012 Executed at 30/07/2012 Drilling or waiting completion Areas Blocks Operated by YPF With YPF Working Interest Complete delineation in progress Secure shale acreage Increase shale acreage value Delineación 930 km2 zona Norte LLL Oil window Wet gas window Dry gas window Delineate new development clusters 18
2012 Stop decline 2013 Growth again 19
Exploitation high impact plan - production Oil production (kbbls/day) Gas production (Mm 3 /day) 256 243 2008-2011 -5% p.a. 2012-2013 +7% 240 221 228 243 47 41 2008-2011 -10% p.a. 38 34 33 2012-2013 +3% 34 2008 2009 2010 2011 2012 2013 2008 2009 2010 2011 2012 2013 Initial situation Current situation Initial situation Current situation 235 230 225 37 35 33 31 220 29 215 210 High impact plan Previous plan Jan Feb Mar Apr May Jun Jul Ago Sep Oct Nov Dec 27 25 High impact plan Previous plan Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 20
Exploitation high impact plan - activity Oil Rigs 60 Drilling rigs 50 40 30 29 36 Initial situation Current situation April 2012 August 2012 55 Wells drilled 250 200 150 Initial situation Current situation April 2012 August 2012 accumulated 1,564 1600 1400 1200 1000 800 20 10 100 50 174 324 600 400 200 0 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2012 2013 2012 2013 0 Gas 16 14 12 10 8 6 4 2 0 Drilling and workover rigs 15 5 1 5 5 2 35 30 25 20 15 10 0 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2012 2013 2012 2013 accumulated 122 21 140 120 100 80 60 40 20
Increase refined products Reduce imports + 7% in 2012 vs. Previous plan - 47% in 1H-2012 vs. 1H-2011 22
Downstream high impact plan 2012 Increase crude oil processing through optimization of lubes production 2013 Start up of hydro-treatment plants Increase utilization factor of refining complex Key levers Increase production of distillates Higher fuel oil production to substitute imports Increase production of refined products via CCR Production de fueloil Imports of gasoline, diesel and jet fuel Utilization factor Production of refined products m 3 1 st half 2011 vs. 1 st half 2012 1 st half 2011 vs. 1 st half 2012 600,304 764,702 + 46% 410,291-47% 401,750 m 3 % 000 m 3 92% 88% 82% Diesel 10,076 6,380 + 7% 10,757 6,800 + 6% 11,290 7,180 Gasoline + 4% + 7% 3,696 3,957 4,110 1H-2011 1H-2012 1H-2011 1H-2012 1Q-2012 2012P 2013P 2012P (Previous) 2012P a (new) Actual. 2013P 2013P (new) 23
Financial stability roadmap 24
Financial stability roadmap Extended local lines of credit with great reception from banks Only lender that decided to accelerate financing was Repsol ($125 million payment done); all other creditors provided waiver or letter of non-acceleration or simply continued doing business-as-usual Met committment to repay 2028 bond holders Eminent launch of local issuance of notes with six prominent local banks as placing agents Received proposals from international banks for cross-border financing Called Shareholders Meeting to increase size of medium term notes program; first international tranche mandated to a leading international financial institution Will conduct international non-deal roadshow to communicate strategic plan to financial community 25
100 day plan 1 2 Context High impact plan 2012-2013 3 4 Business plan Financial considerations 2013-2017 26
Business plan development Cash flow and value generation Resources Supply Objective Generate value Capex Portfolio management Maximize company value External financing Capex plan and financial results Exploration Strategic planning Integrated project portfolio with IRR > cost of capital People and organization Technology and processes Exploitation Natural gas Security, safety and environment Communication and public relations Refining Impact on production / supply MBOE 160 2013 2017 Commercial Uses of cash Capex Dividends Debt service 27
Strong portfolio with upside 2,400 Mbbl Oil resources 400,000 Mm 3 Gas resources 28
Strong oil project portfolio significant upside Oil Total: 2.426 MBbl +500 Characterized projects Gas Total: 400.750 Mm +100 3 Characterized projects (14 TCF) Shale 51% Base production 20% Primary 11% Secondary 10% Shale 57% Base production 15% Primary 9% Tight gas 15% Heavy oil 2% Optimizations 3% Tertiary (EOR) 2% Infill 1% Compression 2% Infill 1% Optimizations 1% Only 20% of this resource portfolio in proven reserves (which largely supports 5 year production plan) 29
Renew 250 exploration focus Exploratory wells 2013-2017 30
Exploration plan Exploration portfolio Exploration capex and activity 45% 40% 35% Lower risk /higher potential UNCONVENTIONAL (Not to scale) > 12,000 MBOES Annual average Exploration wells 2007-2011 2012-2017 Capex (USD million) 132 288 19 50 30% 25% 20% 15% 10% 5% 0% AVERAGE SUCCESS CHANCE higher risk /Lower potential PRODUCTIVE BASINS 597 MBOE 71 PROSPECTS NEW BASINS 141 MBOE-14 PROSPECTS ARGENTINA SHALLOW OFFSHORE 7 MBOES-4 PROSPECTS INTERNATIONAL 168 MBOES 5 PROSPECTS 1 10 AVERAGE SIZE UNRISKED (MBOE) 100 The size of the bubbles represents the resource (unrisked) EEUU GOM 76 MBOE-2 PROSPECTS ARGENTINA DEEP OFFSHORE 688 MBOES 5 PROSPECTS 5 years total Exploration wells 2007-2011 90 Expected value of the process not included in production curves 2012-2017 Capex (USD million) 660 1,440 250 The exploration growth vector focuses on the extension of productive basins and the characterization of unconventional resources 31
2013-2017 exploration plan - vision Full coverage of basins and exploratory concepts aligned with strategic objectives Productive basins exploration Relaunch conventional gas exploration (Neuquén Basin, CGSJ) Brown fields exploration with first oil in short term Investigate heavy crude belt Unconventional Exploration Feasible unconventional plays (VM, Lajas-Molles, GSJ and Cuyana Agrio) Oil & gas growth vector Focused on large sized opportunities Requires significant investment efforts Offshore exploration Start exploration in Colorado Basin and northern margin of Argentina Continental Shelf Relaunch exploration in Austral and Malvinas basins New basins exploration Define the potential of currently unproductive basins based on Plan Argentina International exploration Exploration in countries in the region with strategic synergies 32
Exploration strategy - conventional vs. unconventional From play concept to execution CONFIDENCIAL 3-5 years +25 years Prospective resources Contingent Resources Unproven reserves (probable, possible) Proved reserves (Proved developed and undeveloped) Conventional Play Concept Surface geology gravimetry Leads Possible structures Exploratory prospect Quantifying prospective resources Development plan Execution Appraisal - development - infill Unconventional Play Concept Geochemistry maturity model Prospect Testing source rock Appraisal Source rock extension Resource play Development plan Execution Vaca Muerta Pilot factory model 33
Boost oil production +29% Production rate Average 2013-2017 vs. 2011-2012 34
Exploitation plan - oil Production Capex Wells Annual average 400 350 300 250 200 150 100 50 - Kbbl/d 4,500 MUSD # x2 1,200 4,000 + 19% +55% 3,500 1,000 + 29% 3,000 800 2,500 2,000 600 1,500 400 1,000 200 500 - - 2011-12 2013-17 2018-22 2011-12 2013-17 2018-22 2011-12 2013-17 2018-22 2013 2017 (incremental) 251 Mbbl USD 19.6 bn 5.380 wells 32% 46% 53% 49% 14% 24% 16% 27% 15% Shale Oil Heavy oils Optimization - secondary Optimization - primary Infill Drilling Tertiary (EOR) Development - secondary Development - primary Base production 35
Example 1 Primary Production Faja Plegada y Sector Occidental Flanco Norte Barranca Baya Development Development Strategy Barranca Baya Flanco Sur Amalgameted channel characterization Tighting well spacings Geologically optimized well locations Well completion optimization Discovery Date 1961 Concession up to November 2017 OOIP/OGIP 780 MBbl (164 Mm 3 ) Current Recovery Factor 11 % Fr Final 15 % Key parameters Oil (Kbbls) 49.938 Gas (Mm3) 330 Investment(MUSD) 1.517 Wells 886 Workovers 397 Unit Development Cost (USD/Boe) 29 36
Example 2 Waterflooding Project Los Perales Development Strategy Full Field Water Injection Production Optimization Development of underdeveloped areas EOR Challenge technical limits and new technologies Discovery Date 1975 Concession up to November 2017 OOIP/OGIP 1704 MBbl (271 Mm 3 ) Current Recovery Factor 12 % Fr Final 22% Current Development Development Plan Key parameters Oil (Kbbls) 106.443 Gas (Mm3) 455 Investment(MUSD) 3.834 Wells 1.548 Workovers 1.618 Unit Development Cost (USD/Boe) 35 37
Example 3- Terciary Recovery (EOR) Manantiales Behr Grimbeek Polymer Flood Grimbeek Development Strategy Optimal recovery via a more efficient flood Pilot to Demonstrate Incremental Recovery Technology to be extended to full field after a short waterflood Challenge of new technical limits Discovery Date 1930 Concession up to November 2015 OOIP/OGIP 730 MBbl (117 Mm 3 ) Current Recovery Factor 20 % Fr Final 30 % Key parameters Oil (Kbbls) 39.200 Gas (Mm3) 453 Investment(MUSD) 1.564 Wells 801 Workovers 684 Unit Development Cost (USD/Boe) 37 38
Increase refined products +37% Diesel and gasoline 2017 vs. 2013 39
Downstream plan Capex Refining complex expansion and upgrading Refined products increase 2013-2017 Total 2013-2017 USD 8.0 bn Contribution by project Utilization Capacity Upgrading Conversion Annual CAGR 9.5% 8.1% Gasoline 6% 3% 10% 5% 5.6% Diesel 8% 18% 18% Refining Logistics Petrochemicals Marketing + Light crude + Topping / vacuum capacity + Alkylation / reforming capacity + Hydrocracking / coking capacity 2013-2017 total increase Gasoline Diesel 24% 44% Total 37% 40
Leverage strong market position with commercial flexibility Market share (2011) Price gap (2012 YTD) Other Esso Petrobras Shell YPF 8% 13% 9% 15% 55% 28% 11% 12% 15% 34% To competition To import parity Diesel Gasoline Crude Processing Nr. of gas stations 15% 14% Other Esso Petrobras Shell YPF 5% 8% 13% 13% 8% 7% 19% 13% 54% 59% Gasoline Diesel 30% 24% Refined products increase of 8% per year will allow YPF to meet a growing demand while reducing price gap to competition and maintaining leading market share position 41
Relaunch natural gas development +23% Production rate Average 2013-2017 vs. 2011-2012 42
Natural gas plan Gas Bolivia 10 LA MORA TUCUMAN TGN BEAZLEY CAMPO DURAN PARANA SAN JERONIMO URUGUAYANA BUENOS AIRES Import prices USD/Mbtu Gasoil 23 Fuel oil 18 Gas Mm3/d 20,000 18,000 47 16,000 14,000 12,000 32 10,000 8,000 6,000 4,000 2,000-8% p.a. 2013 2014 2015 2016 2017 LOMA LA LATA TGS BAHIA BLANCA GNL 13-17 USD 6.5 billion capex program 2013-2017 to boost local gas production Susbtitute imports with local gas production USHUAIA Local prices USD/Mbtu Gas plus 4-7 Industry 4-6 43
Exploitation plan - gas Production Capex Wells Annual average 60 50 40 30 20 10 - Mm 3 /d 1,800 MUSD 400 # 1,600 + 20% x7 350 x9 1,400 300 + 23% 1,200 1,000 250 800 200 600 150 400 100 200 50 - - 2011-12 2013-17 2018-22 2011-12 2013-17 2018-22 2011-12 2013-17 2018-22 2013 2017 (incremental) 35.687 Mm 3 USD 6.5 bn 1.160 wells 21% 18% 32% 33% 41% 42% Shale Tight Development Optimizations Compression Infill Drilling 27% 35% 39% Base production 44
Example - natural gas project Lotena (Loma la Lata, Neuquén Basin) Integral Development of Lotena formation in block Loma La Lata-Sierra Barrosa. The project consists in obtaining reservoir information and a field gas development plan in the area. (model validation, reservoir architecture, structural appraisal to develop 22 M BOE Cumulative Gas Production, Wells/WO and Capex Gas Mm 3 New wells Repairs Capex M U$S 2012 Total 2012 Total 2012 Total 2012 Total 18 3587 1 18 2 6 11 227 Los Barreales C LLL-584 Production Curve Marimenuco LLL.a-411 1400 Proy. LLL Lotena - Gas km3/d LLL-465 1200 1000 800 600 400 200 0 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 45
Unlock shale potential +100 Kbbl/d Oil by 2017 +13 Mm 3 /d Gas by 2017 46
Encouraging results in Vaca Muerta development 1,000 100 Oil rate bopd 37 wells drilled 27 wells completed 10 Vaca Muerta Wells Current average performance YPF s Vertical Type Well (291 Kbbl) Achieved production rate of 6,800 Boe/d Ryder Scott s well (207 Kbbl) Months since first oil 1-2 4 6 8 10 12 14 16 18 20 22 10 wells waiting for completion Another 26 wells to be drilled in 2012 47
Better prospect than U.S. comparable basin Vaca Muerta Eagle Ford 1,800 Max Monthly Oil bbl/d 1,600 Eagle Ford wells are all horizontal with 15 hydraulic fractures on average 1,400 Vaca Muerta wells vertical with 2 to 4 hydraulic fractures only 1,200 TOC (%) 3-10 3-5 1,000 Thickness (mts) 30-450 Reservoir pressure (psi) 4,500-9,500 30-100 2,500 8,500 800 600 Last 6-month average 320 bpd 400 200 0 1/2008 7/2008 6-mos 1/20091 year 1.5 7/2009 years 1/2010 2 years 2.5 7/2010 years 31/2011 years Time since first oil 48
Shale oil development plan 5% of total Vaca Muerta oil window Oil projects scope Production Acreage developed 300 KBbl/d 1055 Km 2 Current production of NQN province 250 200 150 186 Km 2 114 Km 2 465 Km 2 290 Km 2 Upside 100 50 0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Pilot + first cluster Cluster #2 Cluster #3 Cluster #4 Loma Campana / LLL norte YPF net 49
Shale gas development plan Gas production evolution Current production of NQN province Production Acreage developed 60 Mm 3 /d 1888 Km 2 22 Km 2 50 20% of total gas window 47 Km 2 Upside 40 30 20 50 Km 2 105 Km 2 60 Km 2 1379 Km 2 185 Km 2 41 Km 2 10 0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 El orejano pilot Cluster #2 Cluster #3 Cluster #4 Cluster #5 Cluster #6 Cluster #7 Cluster #8 50
Huge unconventional potential in Argentina Among top 3 in the world (along China and U.S.A.), most advanced in shale oil Tarija Los Monos (shale gas) Cretaceous Yacoraite (shale/tight/oil & gas) Chaco Paraná Devonico Permico (shale oil) More than 45 total wells drilled to date by YPF Neuquina Vaca Muerta (shale oil/gas) Los Molles (shale gas) Agrio (shale oil) Lajas (tight gas) Mulichinco (tight oil/gas) Cuyana Cacheuta (shale oil) Potrerillos (tight oil) Golfo San Jorge Pozo D-129 (shale oil/tight oil) Neocomiano (shale oil/gas) Austral Inoceramus 51
Unlocking the potential Potencial YPF s leverage Partners Shale oil y gas - Vaca Muerta Gross Net YPF Area 30,000 km 2 Area 12,075 km 2 Know - how Facilities Qualified personnel Factory mode G&G Reservoir characterization Union relations Federal government relations Provincial government relations Strategic Unconventional experts Technology Services and applications Financial Local and international markets 52
100 day plan 1 2 Context High impact plan 2012-2013 3 4 Business plan Financial considerations 2013-2017 53
Business plan - total capex Annual capex plan* 2013 2017 breakdown 9,000 9.0 8,000 7,000 7.0 USD bn 22% Downstream 1% Corporate 4% Exploration 6,000 5,000 5.0 4,000 3,000 3.0 2,000 1,000 1.0 0 1 2 3 4 5 2013 2014 2015 2016 2017 Total 2013-2017 Gross USD 37.2 bn Net YPF USD 32.6 bn 73% Exploitation * Total base plan (gross) 54
Cash flow generation and external financing needs Capex Financing Free cash flow profile - YPF net Base plan (gross) that generates production growth of: Oil and gas Gasoline and diesel + 32% in 5 years + 37% in 5 years USD Bn Shale partner Financing Internal YPF cash flow generation 37.2 12% 18% 70% 71% 32.6 20% 80% 81% 27.9 100% USD Bn 4.0 3.0 2.0 1.0 2013-1.0 2014 2015 2016 2017 2018 2019 2020 2021 2022-2.0 Gross 17% YPF 17% Net net 2018 17% - 2022 2013 2017 business plan Financiability drivers Strong operating performance: growing EBITDA Prudent leverage: maximum debt/ebitda < 1.5x Shale partner with 50% working interest in first cluster (250 km 2 ) entering at an attractive IRR (carrying YPF in pilot development of 40km 2 ) Dividend policy: pay out ratio > 5% 55
Stress test reduced external financing Conservative scenario Reduced capex plan Production profile No shale partner Only USD 500 million additional debt financing p.a. (2013 2015) USD Bn 24.7 37.0 KBOE/day Total oil and gas CAGR: (%) 474 4% 550 4% 650 2013-2017 2018-2022 2013 2017 2022 Sources of capex financing Financing with local banks / capital markets or with government sponsored funds USD Bn Financing Internal cash flow generation 6% 94% 100% Sufficient supply to meet growing demand, while maintaining target market share 2013-2017 2018-2022 56
Upside scenario faster ramp-up of shale Upside scenario Accelerated capex plan Production profile More shale partners (50% working interest) USD Bn 40.4 Base Gross case (base (gross) case) Upside KBOE/d Base Upside 1 + shale oil cluster (290 km 2 ) 1 + shale gas cluster (80 km 2 ) 7.7 33.7 5.8 CAGR: (%) 9% 75 1% 81 32.7 27.9 492 641 659 2013-2017 2018-2022 2013 2017 2022 Reflects only part of the upside (still more than 65% of YPF s acreage in Vaca Muerta undeveloped by 2017) 57
2013-2017 32% Oil and gas production growth 37% Diesel and gasoline production growth +10,000 New jobs 58
Q&A Session
Business plan 2013 2017 100 day plan August 30, 2012