Oil & Gas/Climate Change Europe Oil & carbon revisited Value at risk from 'unburnable' reserves abc Global Research ? Lowering carbon emissions could put future oil and gas developments at risk ? Demand effects may mean lower oil and gas prices, a greater value risk ? Statoil's 'unburnable' reserves amount to 17% of market capitalisation; low costs mean BG has little value at risk Unburnable reserves: The IEA's World Energy Outlook (2012 edition) estimated that in order to have a 50% chance of limiting the rise in global temperatures to 2?C, only a third of current fossil fuel reserves can be burned before 2050. The balance could be regarded as 'unburnable'. Oil could deliver efficiency gains: Although coal reserves have significantly more embedded carbon than other fuels, we believe that oil demand could be reduced relatively quickly given the inefficiency of personal transport. Gas growth slows: In a low-carbon world, defined as limiting future CO2 emissions until 2050 to 1,440Gt, oil demand would fall post 2010. Gas demand would continue to grow but at a slower rate than currently. This means some potential oil and gas developments would no longer be needed. 25 January 2013 Paul Spedding* Analyst HSBC Bank plc +44 20 7991 6787 paul.spedding@hsbcib.com Kirtan Mehta* Analyst HSBC Bank plc +91 80 3001 3779 kirtanmehta@hsbcib.co.in Nick Robins* Analyst HSBC Bank plc +44 20 7991 6779 nick.robins@hsbc.com View HSBC Global Research at: http://www.research.hsbc.com *Employed by a non-US affiliate of HSBC Securities (USA) Inc, and is not registered/qualified pursuant to FINRA regulations Issuer of report: HSBC Bank plc Disclaimer & Disclosures This report must be read with the disclosures and the analyst certifications in the Disclosure appendix, and with the Disclaimer, which forms part of it Ceiling tests to assess value at risk: To assess the risk for the sector, we assume the world is already low carbon. We undertake a ceiling test on the future projects of the larger European majors we cover to assess the potential value at risk. We use USD50/b for oil and USD9/mmBtu for gas for our ceiling test. Oil and gas volumes at risk range from under 1% (BG Group) to 25% (BP). However, as a percentage, the value of reserves at risk is lower than this because they are largely undeveloped. The value impact ranges from under 1% (BG Group) to 17% (Statoil). Price risk a material threat: Although not directly related to 'unburnable' carbon, a greater risk to the sector would be if lower demand led to lower oil and gas prices. In that case, the potential value at risk could rise to 40-60% of market cap. Low costs are the key: Because of its long-term nature, we doubt the market is pricing in the risk of a loss of value from this issue. We think investors should focus on low-cost companies like BG; a gas bias is preferred, which would favour Shell. abc Oil & Gas/Climate Change Europe 25 January 2013 Summary ? We look at how a low-carbon world might affect European oils ? Loss of potential value from developments no longer needed would range from almost none (BG Group) to 17% of market capitalisation (Statoil) ? Focus on low-cost players with a gas bias in such a scenario Unburnable carbon Our first note on carbon and the oil sector ('Oil and carbon. Counting the cost', 23 September 2008) looked at the potential cost of carbon pricing for the industry. This note revisits this theme but looks at the risk to the oil sector were carbon policy to lead to lower demand for oil and slower growth in demand for gas. The IEA, based on research by Meinhausen et al (Nature, 40 April 2009), estimated that to have a 50% chance of limiting the rise in global temperature to 2?C , the world can only emit 1,440Gt over the first half of the current century. With around 400 Gt emitted from fossil fuels and other sources so far this century, only around 1,000 Gt or a third of current proven reserves can be 'burned'. This would mean that a material proportion of the world's coal, oil and gas reserves may be 'unburnable' over the next 40 years. In the IEA's '450 ppm' scenario ('450'), which limits global warming to 2C, the aim is to reduce carbon concentrations to 450 ppm, the level it believes is necessary to have a 50% chance of limiting the long-term temperature rise to 2?C. It assumes that between 2010 and 2035, coal consumption falls by 30% and oil by 12%. 2 IEA 450 scenario fossil fuel demand (CAGR, %) Gas 2.0% Oil Coal 1.0% 0.0% - 1.0% - 2.0% - 3.0% - 4.0% 2010-2020 2 020-30 Source: IEA WEO 2012 Looking at how the carbon in proven reserves is split between fossil fuels, it is clear that oil can only play a modest role in reducing emissions. Embedded 'carbon' in coal is three times the amount bound in oil and over four times that in gas (see "Coal and Carbon, Stranded assets; assessing the risk", 21 June 2012, for our analysis of the risks to coal). It is clear that reduced usage of coal is the key to stabilising and eventually reducing annual carbon emissions. However, we believe that reductions in oil demand, although smaller, can be delivered more quickly than coal through improvements in transport fuel efficiency. abc Oil & Gas/Climate Change Europe 25 January 2013 Potential embedded CO2 in reserves (Gt) 2000 1500 1000 500 0 Coal Oil Government Gas Private Source: IEA Natural gas would be less affected in a low-carbon world. Although demand is likely to grow more slowly than in a 'business as usual' (BAU) scenario, it should continue to gain market share. The gain in market share by natural gas is crucial to reducing emissions because of its lower carbon content relative to oil and especially coal. It is the only IEA scenario where the world has stable/modestly rising energy demand and falling carbon emissions. So new gas developments would go ahead but at a slower rate. European sector implications So quoted oil companies could face pressure on future developments, especially of oil. But the problem for quoted oil is that according to the IEA, 90% of the world's oil and gas is in the hands of governments or state oil companies. This means that the activities of even the majors are largely irrelevant in terms of carbon emissions. The behaviour of governments and state oil companies will be far more relevant. Around 70% of these 'government' reserves are in the hands of OPEC, where quoted oil has limited exposure in volume - and even less in terms of value. It seems to us the main threat to the majors will come from the behaviour of governments, especially that of OPEC states. We assume that in a low-carbon world, the projects that would be deferred or cancelled by the majors would be those with high costs. To assess those at risk, we have run these projects using Wood Mackenzie. For oil projects, we use a Brent price of USD50/b as a ceiling test. (This compares with our present Brent assumption for 2014e of USD90/b and the ICE futures strip of USD102/b.) For gas projects we use a price of USD9/mmBtu. This is around USD55/b in oil parity terms. (Our present assumption for European oil-linked gas prices is USD10.9.mmBtu.) Unburnable oil and gas reserves The volume of reserves at risk of being undeveloped in a low-carbon world varies markedly between the companies. At the high end, around 25% of BP's proven and probable (2P) reserves would fall into our 'unburnable' category, whereas virtually none of BG's would. Unburnable reserves (% of 2P reserves) 30% 25% 20% 15% 10% 5% 0% Shell BP Total Oil and associated gas Statoil Eni BG Gas and condensate Source: Company data, Wood Mackenzie, HSBC calculations However, BP's value at risk from unburnable reserves is equivalent to only 6% of its market value as most of the 'lost' reserves are low margin. We also look at the value of reserves at risk as a percentage of market capitalisation. 3 abc Oil & Gas/Climate Change Europe 25 January 2013 All companies would see a material loss of value under this scenario, but Total and RD Shell have slightly lower exposure; Statoil has the highest. Unburnable oil & gas reserves (% of market cap) 20% 15% Unburnable reserves and price effect (value/share) 10% Price (21/1/13) 5% 0% Shell BP Total Oil and associated gas Statoil Eni BG Gas and condensate Source: Company data, Wood Mackenzie, HSBC calculations Price effects 1,120 459 19.3 26.3 2,264 144 39.4 2.6 31 1.5 0.0 51 24 2.2 578 189 9 0 909 63 14 Source: Company data, Wood Mackenzie, HSBC calculations Statoil has the highest value of reserves at risk of becoming unburnable, equivalent to 17% of its market capitalisation. BG has virtually no value at risk. Loss of value on viable oil and gas portfolio We believe that such a large fall in demand would almost certainly lead to lower oil prices. All of the companies would lose material amounts of value were oil and gas prices to fall to the level we used for our ceiling test. (Some may feel that a USD50/b oil price is not realistic, but we would remind readers that a 3m b/d fall in demand in 2009 caused the Brent oil price to fall to USD40/b). Adding this to the value at risk from unburnable reserves would be equivalent to 40-60% of the market capitalisation of affected companies. Unburnable reserves and price effect (% of market cap) 70% 60% 50% We believe that investors have yet to price in such a risk, perhaps because it seems so long term. And we accept that our scenario probably exaggerates the risk as we assume a low-carbon world today rather than beyond 2020. However, we believe it does give an indication of the potential impact on the sector. Apart from BG, the level of unburnable carbon within the European oil sector is relatively high in terms of volumes of reserves (7-25%). As these are future developments, yet to incur development costs, the value impact is rather more modest (0-17%). The main risk for the oil sector, however, is whether a low-carbon future would lead to lower fossil fuel prices. Under the IEA '450' scenario, this becomes a growing risk beyond 2020. Our analysis probably overstates the value at risk as we assume an efficient world today. Nevertheless, our analysis shows that the impact of lower prices on value could be material. In our view, investors should focus primarily on companies with low-cost future projects. Capitalintensive, high-cost projects, such as heavy oil and oil sands, are most at risk under our scenario. 40% 30% 20% 10% 0% Shell BP Total Oil and associated gas Statoil Eni Gas and condensate Source: HSBC workings, Wood Mackenzie data 4 BG (p) BP (p) ENI (EUR) RD Shell A (EUR) RD Shell B (p) Statoil (NOK) Total (EUR) Unburnable effect BG abc Oil & Gas/Climate Change Europe 25 January 2013 Unburnable oil reserves by type (% of each class) 30% 25% 20% 15% 10% 5% 0% Traditional Deepwater Heavy oil Source: HSBC calculations, Wood Mackenzie data A focus on gas would be preferable but even the gas-focused companies within the sector have a relatively heavy oil focus. We would like to acknowledge the contribution from Priyankar Biswas, Associate, Bangalore, to this research report. Priyankar is employed by a non-US affiliate of HSBC Securities (USA) Inc., and is not registered/qualified pursuant to FINRA regulations. 5 abc Oil & Gas/Climate Change Europe 25 January 2013 Unburnable carbon ? In a low-carbon environment, a material proportion of the world's undeveloped reserves of fossil fuels could become 'unburnable' ? After coal, we believe that oil would be most exposed, particularly because of the potential to improve transport efficiency ? Gas demand would be less affected as it benefits from a lower carbon profile and a greater ability to capture emissions Curbing carbon Living within a carbon budget This report assesses how the European oil sector could be impacted if we were to move to a low-carbon world. Global greenhouse gas (GHG) emissions continue to rise, putting the world potentially on track for long-term warming approaching 4?C. This is far above the 2?C target that governments have set themselves. However, governments begin serious negotiations this year to deliver a global climate agreement in 2015. The aim is to intensify efforts to reduce emissions between now and 2020, and then take strategic action in the 2020s and beyond. Tomorrow's carbon emissions are embedded in today's reserves of coal, oil and gas. To have a 50% chance of limiting global warming to 2C, scientists estimate that around 1440Gt of CO2 can be emitted between 2000 and 2050 (Meinhausen et al, Nature, 40 April 2009). Based on this research, the IEA estimated in its World Energy Outlook 2012 (WEO) that remaining proven reserves of fossil fuel contained 2,860 Gt of potential carbon emissions. With around 400 Gt emitted so far this century, only around 1,000 Gt or a third of current proven reserves can be commercialised without significant deployment of carbon capture and storage (CCS). A tougher carbon budget giving an 80% chance of keeping warming below 2?C would cut this allowance still further. In our report, 'Energy in 2050' (22 March 2011), we explored how to deliver a threefold expansion of the global economy whilst achieving climate security. In our low-carbon Solution scenario, we estimated that global demand for energy in 2050 would need to be 37% below our business-asusual scenario (BAU). The supply mix would also need to shift from an 81% reliance on fossil fuels today to just 43% by 2050. Fossil fuel use would be 34% lower than at present and 66% lower than the BAU scenario. In this scenario, the share of oil would fall from 32% today to 13% by 2050, and gas would also decline from 21% to 16%. 6 Shifting the energy mix Most conventional assessments project rising energy consumption and fossil fuel use. The IEA's central New Policies scenario, for example, estimates that global energy demand will grow by over 17% from 2010 levels by 2020 and by 29% by 2030. Fossil fuel's share would decline from 81% to 76%, but overall in absolute terms its consumption should still grow. abc Oil & Gas/Climate Change Europe 25 January 2013 Fossil fuel demand in the IEA's 450 PPM scenario (CAGR, %) Gas 2.0% Oil Coal 1.0% 0.0% - 1.0% - 2.0% - 3.0% - 4.0% 2010-2020 2 020-30 Source: IEA WEO 2012 In its low-carbon 450 PPM ('450') scenario, the IEA estimates that demand for fossil fuels would still grow up to 2020. Oil demand, for example, is forecast to grow at 0.4 % annually. However, from 2020 onwards, the IEA projects that oil demand would decline, though not as much as coal (see Chart above). Demand for gas is projected to continue to grow in the 2020s, but not as much as in the 'New Policies' scenario. Overall, the '450' scenario estimates that between 2010 and 2035, coal consumption would fall by 30% and oil by 12%. Oil in a low-carbon world We believe that reductions in oil demand could be delivered more quickly than coal (and probably more quickly than gas as well) through better transport efficiency. Historically, personal transport has accounted for around 60% of oil demand, equivalent to 21-23m b/d. The rate of annual fuel efficiency is already improving by 1.7% on average per year - and cost-effective technologies could deliver much more. By 2035, the IEA projects that road transport demand for oil could be 9m b/d or 18% lower than under its 'New Policies' scenario, split evenly between freight and passenger vehicles. We believe that this is achievable with existing technology. India has the best average fuel efficiency at 6 litres per 100km compared with 9L/100km in the United States. Many passenger vehicles appear to have been designed to be deliberately inefficient. This is because in some cases, power and speed sells more cars than efficiency. For example, the Bugatti Veron, so beloved of some motoring shows, emits over 600 g/km of carbon, six times that of the average car in the mini class. (There is hope though. For example, the Ferrari Enzo emits 545g but the new hybrid version lowers this by 40%.) There has been a material improvement in the efficiency of the internal combustion engine over the past few decades. But much of this has been offset by increased weight and engine size. According to Christopher R. Knittel's 2009 report "Automobiles on Steroids", if US auto weight and horsepower had been held at 1980s levels, fuel efficiency would have increased by nearly 50%. Steps are being taken to improve the fuel efficiency of new vehicles. In the US, the EPA and transport department have announced new economy standards for light-duty vehicles (LDVs) set at 54.4 mpg (4.3L/100 km) for 2025. The Chinese government is considering a new fuel economy target for 2020, targeting 5.0L/100km. In the EU, regulators are targeting carbon directly, aiming for 95g CO2/km (4.1L/100km) by 2020. India's standards were already at 6L/100km in 2008, and proposed standards would take this 5.14L/100 km in 2020. On a demand-weighted basis, we think that a 40% improvement in mileage per gallon is achievable by 2020, equivalent to a near 30% or 6-7m b/d reduction in demand. 7 abc Oil & Gas/Climate Change Europe 25 January 2013 Gas in a low-carbon world Gas continues to have growth potential in a lowcarbon world on the back of its much lower share of embedded carbon in fossil fuel reserves. Gas is already displacing coal in US power generation based on the cost advantages of shale. The emissions from gas-fired power can also be reduced further through CCS, although currently, no large-scale integrated projects are in place. But in a low-carbon world, the growth rate for gas is forecast by the IEA to be less than half that of the current decade. In the IEA's low-carbon '450' scenario, global gas demand would be 20% below its central scenario in 2035. This is equivalent to a fall of 16m b/d in oil-equivalent terms (the equivalent decline in oil is 27m b/d). Even so, we believe that the world would still need new gas developments to offset declines in existing production. New developments would go ahead but there would be fewer of them. Global implications Some observers have suggested that oil companies should cut back investments in order to reduce carbon emissions and avoid stranded assets. The problem for quoted oil is that, according to the IEA, 90% of the world's oil and gas is in the hands of governments. This means that the activities of even the majors are marginal in terms of global carbon emissions; the behaviour of governments and state oil companies will be far more relevant. The bulk of the remaining carbon emissions in the world's proven oil reserves is tied up in four regions (in order of importance): ? The Middle East ? Latin America (predominantly Venezuelan heavy oil) ? Canada (predominantly tar sands) ? Africa (predominantly Nigeria and Angola) Around 70% of these reserves are in the hands of OPEC, where quoted oil has limited exposure in volume - and even less in terms of value. It seems to us the main threat to the majors will come from the behaviour of governments, especially that of OPEC states. As discussed later, lower demand tends to lead to lower prices. For small movements in demand, OPEC can normally act as a buffer zone. However, a fall in demand for oil of up to 10m b/d would likely overwhelm OPEC, leading to significantly lower oil prices. The threat to the majors therefore is twofold: ? First, future projects being deferred or cancelled owing to lack of demand ('unburnable' projects); and ? Second, loss of value from their portfolios because of lower oil prices. Distribution of global oil and gas reserves (%) Potential embedded CO2 in reserves (Gt) 2000 Gas 1500 1000 Oil 500 0 Coal Oil Government Source: IEA, WEO 2012 8 Gas 0% 20% 40% Government Private Source: IEA WEO 2012 60% Private 80% 100% abc Oil & Gas/Climate Change Europe 25 January 2013 European stocks ? European oils face two potential threats, future developments becoming unnecessary and lower demand leading to lower prices ? The threat from 'unburnable' future reserves is relatively small: Statoil has the most potential value at risk, 17% of market cap ? However, the threat from lower prices would have an impact on all stocks, equivalent to 37-52% of market cap Unburnable carbon For this analysis, we assume we are already in an efficient world with lower demand for oil and slower future growth for oil and gas. With lower demand, fewer future projects will be needed. We analyse the companies' oil and gas developments to see which are high cost and therefore at risk of cancellation. For oil projects, we use a Brent price of USD50/b as a ceiling test. (This compares with our Brent assumption for 2014 of USD90/b and the ICE futures strip of USD102/b.) At USD50/b, many high-cost oil projects in non-OPEC, including oil sands, some deep-water plays and some US shale oil projects, would not be economical. likely to continue to rise but at a slower rate than under 'New Policies'. The world will continue to need new gas projects and USD9/mmBtu is a price that we estimate would support greenfield LNG plants (our assumption for 2014 is USD10.9/mmBtu for European contract prices). Reserve exposure We use proven and probable (2P) to assess the exposure to unburnable carbon for the European majors. We believe this is more realistic than using the proven reserves reported by the oil majors (normally half the 2P level). This is because US SEC definitions of proven reserves are overly conservative and understate the majors' fossil fuel exposure relative to some state oil companies. For gas projects we use a price of USD9/mmBtu. This is around USD55/b in oil parity terms. Oillinked gas prices normally trade at a discount to oil and this gas price would be consistent with a Brent price of around USD75-85/b for European and Asian oil-linked gas contracts. This means we assume that in oil-equivalent terms, natural gas in many parts of the world would see a narrowing of the price discount with oil to reflect its better 'green' credentials. Unlike oil, gas demand is 9 abc Oil & Gas/Climate Change Europe 25 January 2013 low-carbon world. In volume terms, there is a wide range of exposures to 'unburnable' carbon between the companies. Reserve exposure (bn barrels) 35 30 25 20 15 10 5 0 Potentially unburnable oil (% of total reserves) 15% 10% Shell BP Total Statoil Eni BG 5% Entitlement 2P Working interest technical 0% Source: Company data, Wood McKenzie Shell Oil versus gas BP Onstream Clearly, given the differing outlook the IEA has for the demand growth of oil relative to gas, exposure to the latter should tend to lower the threat of unburnable carbon. On the basis of entitlement 2P reserves, oil makes up 36% of RD Shell's total reserves, the lowest of the six companies. Ironically, BG Group (BG), which is perceived to be a gas company, has the highest exposure to oil. This is because BG's exposure to oil has increased significantly over the past four years as it has established a massive resource base in Brazil. Exposure to oil reserves (% of entitlement 2P reserves) Total Statoil Expansion Eni BG Future Source: Company data, Wood Mackenzie, HSBC calculations Most reserves in the at-risk category are future developments. Existing projects enjoy the benefit of sunk costs and so tend to have low cash operating costs. New projects need to incur capex in addition to operating costs giving them a higher cash cost per barrel (capex plus operating cost). In terms of type of future development, we think heavy oil projects (including oil sands) are most at risk. Unburnable reserves by type (% of each class) 30% 100% 25% 80% 20% 60% 15% 40% 10% 20% 5% 0% 0% Shell BP Total Statoil Eni BG Oil and associated gas Gas and condensate Traditional Deepwater Heavy oil Source: HSBC calculations, Wood Mackenzie data Source: HSBC workings, Wood Mackenzie data Which oil can't be burned? Using Wood Mackenzie, we grade each company's projects using our ceiling price to see which are high cost and so could be at risk in a 10 In aggregate, close to 30% of heavy oil reserves, around 20% deepwater reserves and around 10% of traditional reserves, would be at risk of not being developed at USD50/b and so fall into the high-cost category. abc Oil & Gas/Climate Change Europe 25 January 2013 Value at risk To calculate the value of the reserves potentially at risk, we aggregate the value of these 'unburnable' projects using our USD90/b assumption for 2014. The loss of value for the companies from these 'unburnable' projects is relatively low. This is because most are in the yet-to-be-developed category and so there are no sunk costs to be 'lost'. The companies we analyse in this report have quite different levels of value at risk with developments that may well not proceed because they are high cost (defined as non-economical at USD50/b Brent prices). Unburnable oil project value (% of market cap) 15% 10% 5% 0% BP Total Statoil Eni Statoil's exposure to deepwater oil reserves amounts to around 10% of its 2P reserve base and is dominated by Angola and the US Gulf of Mexico. More than a third of these reserves would not be commercial. Eni, BP and Total In terms of value, ENI, BP and Total have similar levels of oil reserves at risk of becoming unburnable. Eni's oil reserves at risk make up around 11% of its total reserves, equivalent to 8% of its market value. The oil reserves at risk mainly lie in the deepwater and heavy oil categories, which account for a third of its oil reserve base. We believe around 60% of these may be unburnable. Its heavy oil assets at Junin 5 in Venezuela and Mariner in the UK would not be commercial at USD50/b and so are in the high-cost category. 20% Shell Statoil's exposure to heavy oil is spread across the UK, Canada, Brazil, Norway and Venezuela, and amounts to around 9% of its 2P reserve base. Nearly 30% of these reserves would not be viable, including Mariner and Bressay in the UK. BG Source: Company data, Wood Mackenzie, HSBC calculations This probably overstates the value at risk as we believe most companies trade at a discount to the discounted cash flow value of their assets. If this is true, we would expect the share price reaction to such a loss of value to be less than the percentages above. For example, BG and BP trade at around a 40% discount to our published SOTP valuations. Statoil Statoil has the highest exposure to potentially unburnable oil reserves. These make up 15% in volume terms and 17% of market value. We attribute this relatively high value at risk to its exposure to high-cost traditional projects in Norway. Of the reserves at risk, 55% are traditional projects, 25% are deepwater projects in Angola and the US Gulf of Mexico, and 20% are heavy oil projects. BP's potentially unburnable oil reserves make up around 12% of its total reserves. This is equivalent to 6% of its market capitalisation. Around half of the group's unburnable oil reserves are in the deepwater category with the balance in heavy oil. Within the deepwater oil category, the projects at risk are predominantly in Angola and the US Gulf of Mexico. Within heavy oil, BP's Sunrise project would be sub-commercial at USD50/b. For Total, we estimate that oil at risk makes up 10% of its volumes, equivalent to 5% of its market value. Most of these reserves are in the heavy oil category with its Canadian oil sands projects (Fort Hills, Joslyn, Surmont) and a project in Gabon (Ayol) sub commercial below USD50/b. 11 abc Oil & Gas/Climate Change Europe 25 January 2013 BG and RD Shell Loss of value from oil price effects (% of market cap) BG and RD Shell have relatively low exposure to oil assets that could be sub-commercial at our ceiling test assumption. 50% BG's oil reserves are dominated by the future developments that tend to make up the bulk of the unburnable projects. But BG sees few projects turn uneconomical under a USD50/b scenario. This is because the economics of its Brazil assets are so resilient that they are commercial even below a USD40/b oil price. 20% We estimate RD Shell's oil reserves at risk make up around 5% of total reserves, equivalent to around 2% of market value. RD Shell has significant exposure to Canadian oil sands, but more than 60% of these are already considered non-commercial by Wood Mackenzie. This means they do not influence our analysis. Its exposure to commercial heavy oil reserves makes up around 25% of its oil reserve base, of which 20% would be at risk. (Oil makes up around 36% of Shell's total reserve base, the lowest of the companies in this study.) RD Shell also has lower exposure to high-cost deepwater oil reserves than its peers. Within the deepwater oils category, which is around 20% of its oil reserve base, only 14% is at risk. Oil price impact Although not directly linked to the need to restrict carbon emissions, companies could also see a loss of value from a price effect. Even though some existing assets may be still commercial, their value would fall if weaker demand led to lower oil and gas prices. This effect is significantly more important than the loss of value from future projects that are sub commercial. On our estimates, under an oil price of USD50/b, the companies could see a loss of value from their oil reserves equivalent to 29-44% of their market value. 12 40% 30% 10% 0% Shell BP Onstream Total Statoil Expansion Eni BG Future Source: HSBC workings, Wood Mackenzie data The value of 'Future' reserves tends to have higher sensitivity to price movements than existing projects because capital expenditure is yet to be incurred. High impact - BG, Eni and BP Although BG saw only a small loss of value from unburnable projects, it has the highest loss of value from oil price effects. This is because of its high exposure to projects yet to be developed, especially in Brazil. Eni and BP also have above-average sensitivity, with oil price effects amounting to around 38% and 36% of market value, respectively. Low impact - Total, Statoil and RD Shell We estimate that Total has the smallest loss of value from lower oil prices, equivalent to 29% of its market capitalisation. This reflects the lower sensitivity of Total's portfolio to oil price changes and is mainly attributable to its assets in Africa, Asia Pacific, Middle East and Latin America. RD Shell and Statoil also exhibit relatively low sensitivity with oil price effects, equivalent to around 32% of market capitalisation. RD Shell has above-sector-average exposure to low-cost onshore oil, which helps lower its price sensitivity. Although Statoil has relatively high exposure to undeveloped oil projects, the high tax nature of some of its assets helps lower oil price sensitivity. abc Oil & Gas/Climate Change Europe 25 January 2013 Combined oil impact Unburnable gas (% of 2P total reserves) Together, the oil price and the unburnable carbon effects are equivalent to between 34% and 52% of market capitalisation. It is clear from this that the main risk to the oil sector is oil price effects rather than the loss of reserves should they become unburnable. 15% Price and unburnable carbon value (% of market cap) 10% 5% 0% Shell 60% BP Onstream 50% Total Statoil Expansion Eni BG Future Source: Company data, Wood Mackenzie, HSBC calculations 40% 30% The gas in BP's portfolio that would become sub economic at USD9/mmBtu makes up around 15% of its total oil and gas reserves. 20% 10% 0% Shell BP Total Unburnable reserves Statoil Eni BG Lower prices Source: HSBC workings, Wood Mackenzie data Statoil and Eni have the highest potential loss of value of the companies we have analysed. RD Shell and Total have the lowest potential loss of value. The share price impact of such a scenario would probably be less than this as most majors trade at a material discount to the value of their assets, in our view. Gas exposure We take a similar approach for each company's gas reserves. As our threshold price of gas is higher than for oil and similar to our existing assumption, there is less potential loss of value for the companies. The main assets that could become unburnable include the tight gas field in Oman (KhazzanMakarem PSC) and some of its deepwater and LNG projects, including North Alexandria in Egypt and Point Thomson in Alaska. Apart from BP, no company sees a large value effect under our scenario. Even with BP, the loss of value is limited to 1% of its market value owing to the low-margin nature of its gas assets. Gas price effect As with our analysis of the oil price effect, the lower gas price also reduces the value of the companies' portfolios. The fall is less than we saw with oil as the price movement is smaller. The potential value at risk is equivalent to around 0-1% of market capitalisation. The combination of both effects works out at between 6% and 9% of market capitalisation. 13 abc Oil & Gas/Climate Change Europe 25 January 2013 Gas: Unburnable reserves and price effect (% of mkt cap) Unburnable reserves of oil & gas (% of 2P reserves) 10% 30% 25% 8% 20% 6% 15% 4% 10% 2% 5% 0% 0% Shell BP Total Statoil Unburnable reserves Eni Shell BG BP Total Oil and associated gas Lower prices Statoil Eni BG Gas and condensate Source: Company data, Wood Mackenzie, HSBC calculations Source: HSBC workings, Wood Mackenzie data Virtually all the potential loss of value is from the price effect rather than from projects becoming unburnable owing to lower gas prices. However, BP's value at risk from unburnable reserves is equivalent to only 7% of its market value. Unburnable reserves (% of market capitalisation) Combined impact 20% Unburnable oil and gas reserves 15% Unburnable reserves and price effect (value per share) 10% Price (21/1/13) BG (p) BP (p) ENI (EUR) RD Shell A (EUR) RD Shell B (p) Statoil (NOK) Total (EUR) Unburnable effect Price effects 5% 1,120 459 19.3 26.3 2,264 144 39.4 2.6 31 1.5 0.0 51 24 2.2 578 189 9 0 909 63 14 0% Source: Company data, Wood Mackenzie, HSBC calculations The volume of reserves at risk of being undeveloped in a low-carbon world varies markedly between the companies. At the high end, 26% of BP's 2P reserves would fall into our 'unburnable' category, whereas virtually none of BG's would. 14 Shell BP Total Oil and associated gas Statoil Eni BG Gas and condensate Source: Company data, Wood Mackenzie, HSBC calculations Statoil has the highest value of reserves at risk of becoming unburnable, equivalent to 17% of its market capitalisation. BG has virtually no value at risk. Loss of value on viable oil and gas portfolio All of the companies would lose material amounts of value were oil and gas prices to fall to the level we used for our ceiling test. Adding this to the value at risk from unburnable reserves would be equivalent to 40-60% of their market capitalisation for the companies. abc Oil & Gas/Climate Change Europe 25 January 2013 Unburnable reserves and price effect (% of market cap) 70% 60% 50% 40% 30% 20% 10% 0% Shell BP Total Oil and associated gas Statoil Eni BG Gas and condensate Source: HSBC workings, Wood Mackenzie data All companies would see a material loss of value under this scenario, but Total and Royal Dutch have slightly lower exposure. Statoil has the highest. 15 abc Oil & Gas/Climate Change Europe 25 January 2013 Carbon and pricing ? In a low-carbon world, lower demand for oil and falling demand post 2020 would likely put pressure on oil prices ? We assume in the longer term that OPEC would defend market share rather than price ? Oil prices may need to fall to as low as USD50/b to achieve this Break-evens for selected high-cost oil projects Technology Country Project name Breakeven USD/b Oil sands Heavy oil Deepwater Deepwater Deepwater Deepwater Traditional gas and condensate Traditional gas and condensate Liquids-rich shale gas Liquids-rich shale gas Canada Venezuela Angola Angola US US Norway Norway US US Joslyn SAGD_MINE Junin 5 Kizomba Satellites Phase2 Block 1506 Eastern Hub Tiber (KC 102) Gunflint (MC 948) Valemon Dagny BP ALT Cotton Valley Hz TGS TX Fee BP AKM Woodford Hz SHG OK Fee 2P reserves Million b 75.5 54.7 51.6 49.3 64.0 49.4 60.7 57.0 71.5 65.9 874 1,526 471 350 566 250 211 216 35 456 Source: Wood Mackenzie data Under our low-carbon scenario, demand for crude oil would be significantly lower than it is today. This could put downward pressure on crude prices. Even the IEA '450' scenario, which shows demand falling in the longer term, would also lead to downward pressure, in our view. To maintain market share in a weak market, OPEC would need to let prices fall to a level that makes some non-OPEC's projects sub-commercial. Non-OPEC's highest-cost production currently is probably oil sands given the high cost of energy (gas) needed to separate the oil and the need for capital-intensive upgrading equipment. The IEA gives quite a wide range of estimates for the breakeven price for different technologies. At the low end, oil sands projects have a breakeven price of USD65-55/b. We believe this applies to expansions rather than green-field projects, which would more likely be at the top end of the range (USD85-105/b). Breakeven estimate (USD/b) for different technologies Wood Mackenzie 2012 US tight oil Oil sands thermal Oil sands mining Ultra-deepwater Deepwater Source: Wood Mackenzie, IEA 16 IEA 2008 45-105 55-85 65-105 35-105 30-85 50-100 40-80 (combined) 40-65 (combined) abc Oil & Gas/Climate Change Europe 25 January 2013 We see US shale oil (tight oil) production as relatively high-cost production, although probably lower cost than oil sands. From OPEC's perspective, US shale oil would probably be an important target because of its short-term nature - fast drill times and fast declines. A low oil price would have a more rapid impact on drilling and development of shale oil reservoirs than on most conventional projects. Wood Mackenzie estimates that US shale oil production is viable at an oil price range of USD45-105/b with an average of USD70/b. Statoil's chart of average breakeven level for its sanctioned projects, shared at its site visit to Brazil in September 2012, also supports our USD50/b oil hypothesis. Nearly half of its potential projects would be marginal or non-commercial at a price of USD50/b. Statoil's sanctioned projects average breakeven USD45/b 100 90 80 70 60 50 40 30 20 10 0 Average break-even per boe INT NCS Source: Statoil {HSBC chart} Based on this, we believe USD50/b is an acceptable oil price for a ceiling test to assess the potential of value at risk in a low-carbon world. X-Axis: Oil reserves (bn b), Y-Axis: Oil price breakeven (USD/b) 150 140 130 120 All deep water 110 100 90 80 O t C h o e 2 r E E O O R R 70 60 50 40 Other conv. oil 30 Already Produced 20 10 0 0 1000 MENA Conv. Oil Heavy Oil Bitumen Oil Shales G TL CTL B T L Ethanol Bio Diesel Arctic 2000 3000 4000 5000 6000 7000 8000 9000 Source: IEA 17 abc Oil & Gas/Climate Change Europe 25 January 2013 Gas prices Unlike oil, gas is sold using a wide range of pricing mechanisms, the three main types being free-market, oil linked and regulated. Wide range of gas pricing mechanisms (2010) Wholesale gas price formation, 2010 Oil escalation Gas-on-gas competition Bilateral mechanisms Netback Regulation: Cost of service Regulation: Social and political Regulation: Below cost No price 23% 38% 4% 1% 12% 10% 11% 1% Source: IGU, 2012 At present, most European and Asian LNG gas prices are linked to oil prices in some way. Unlike oil, the IEA assumes that gas demand will continue to rise in a low-carbon world. This is partly because of a necessary shift in the fossil fuel mix from oil/coal to gas. It is also because gas is more of an 'economic' fuel than oil. Most oil is used for road transport with around 60% being used for personal transport. Only 15% of oil is used in direct industrial processes (including power). For gas, the figure is nearly 60%. 18 Lower growth in gas demand could put pressure on gas pricing. However, with many major consumers of gas in Asia relying heavily on LNG for imports, we believe prices would be supported at the level needed to justify a new-build LNG scheme. We estimate that most LNG projects need a gas price of around USD8-11/mmBtu. At its 2012 management day (15 November 2012), Shell indicated that US-based LNG projects would need a landed price of USD12/mmBtu in Asia and USD10/mmBtu in Europe to be commercial. We have used a gas price of USD9/mmBtu. This is around USD55/b in oil parity terms. Oil-linked gas prices normally trade at a discount to oil and this gas price would be consistent with a Brent price of around USD75-85/b for European and Asian oil-linked gas contracts. abc Oil & Gas/Climate Change Europe 25 January 2013 Valuations ? Overweight ratings are Total, BG and BP ? Underweight rating is Statoil ? ENI and Royal Dutch Shell A & B have Neutral ratings Valuation and risks We use our 2013 estimates, which assume a Brent price of USD90/b. Multiples-based approach For all the companies except BG, our valuation methodology uses a weighted average of two different approaches based on the EV/DACF (25%) and EV/NOPAT (75%) target multiples. We adjust our valuation components to account for our estimate of the likely future cost of carbon, arrived at by using a cost of carbon of USD20/tonne. This includes cost of the companies' operations in the upstream (production) and downstream (refining and chemicals.) Target price derivation TP EV/NOPAT value BG.L BP.L ENI.MI RDSa.AS RDSb.L STL.OL TOTF.PA 1,820 530 19 30 2,400 150 45 EV/DACF value NA 460 22 27 2,191 186 48 NA 552 18 31 2,469 137 44 Cost of carbon/ share 25 17 0.6 0.9 75 1.4 1.5 Source. HSBC estimates For our multiples-based valuation of the oil majors, we use a target EV/DACF ratio of 5.0x and a target EV/NOPAT ratio of 9.0x, which are based on the average ratios for the European sector over the past 12 months. We adjust these targets for our estimate of WACC (used as a measure of risk) for each company. Please note that the cost of carbon share is not related to the cost of unburnable carbon discussed in this note. We have included this in our valuation methodology for the European oil sector since 2009. (See 'Oil and carbon. Counting the cost', 23 September 2008, for a more detailed methodology). Our target prices are set on a 12-month timeframe by uplifting by our estimate of companies' cost of equity and rounded. Valuation summary as on 21 January 2013 Company Price RIC TP Potential Rating PE IBES PE EV/NOPAT Return (2013e) (2013e) (2013e) BG (p) BP(p) ENI (EUR) RD Shell A (EUR) RD Shell B (p) Statoil (NOK) Total (EUR) 1,120 BG.L 1,820 459 BP.L 530 19.3 ENI.MI 19 26.3 RDSa.AS 30 2,264 RDSb.L 2,400 144 STL.OL 150 39.4 TOTF.PA 45 63% 15% -2% 14% 6% 4% 14% OW OW N N N UW OW 13.7 8.1 9.6 8.3 8.5 9.4 7.6 12.6 7.7 9.1 7.8 8.3 8.7 7.4 17.1 9.6 11.0 8.4 8.6 11.0 9.4 EV/DACF Div yield FCF yield* PB (2012e) (2013e) (2012e) (2013e) 9.2 6.4 5.0 5.2 5.3 4.6 5.0 1.4 4.5 5.6 4.9 4.8 4.7 5.9 -7.3 1.7 6.0 5.4 5.3 -2.6 2.4 1.9 1.1 1.2 1.2 1.2 1.4 1.2 *Free cash flow yields exclude exceptional items and working capital movements that result from commodity price movements Potential return equals the percentage difference between the current share price and the target price, including the forecast dividend yield when indicated Source. Thomson Reuters Datastream, HSBC estimates, consensus from IBES 19 abc Oil & Gas/Climate Change Europe 25 January 2013 It is our estimate of the cost each company would have to bear if carbon pricing were introduced globally to cover all of their operations, upstream and downstream. HSBC CoE and RFR HSBC uses a risk-free rate of 3% for all companies under its coverage. The equity risk premium is 4.5% for the UK, 6.0% for the eurozone and 8.0% for Norway, which gives costs of equity of 7.5%, 9.0% and 11.0%, respectively. Company cost of capital For valuing companies, we use a US cost of capital because oil companies are largely dollardenominated businesses. For US companies, HSBC uses a risk-free rate of 3% and an equity risk premium of 4%. We arrive at companyspecific cost of capital by using company-specific beta, leverage and debt cost. Cost of capital RFR BG BP ENI RD A & B Statoil Total ERP Beta Debt 4.0% 4.0% 4.0% 4.0% 4.0% 4.0% 1.1 0.9 1.0 0.9 1.1 0.9 3.5% 3.2% 3.5% 3.2% 3.2% 3.2% 7.0% 6.3% 6.6% 6.2% 6.3% 6.1% Source. HSBC estimates 20 Under our research model, for stocks without a volatility indicator, the Neutral band is 5ppts above or below the hurdle rates of 7.5% for UK stocks, 9.0% for eurozone stocks and 11.0% for Norwegian stocks. HSBC Neutral band derivation Risk-free Equity risk rate premium UK Eurozone Norway 3.0% 3.0% 3.0% 4.5% 6.0% 8.0% Cost of equity Neutral band 7.5% 9.0% 11.0% 2.5% to 12.5% 4.0% to 14.0% 6.0% to 16.0% Source. HSBC estimates Potential return equals the percentage difference between the current share price and the target price, including forecast dividend yield when indicated. Please note this means that companies with quotes in different countries, such as RD Shell, may have different neutral bands and so may have different ratings. WACC 3.0% 3.0% 3.0% 3.0% 3.0% 3.0% Rating BG Group (OW, TP 1,820p) Valuation. For BG, we use a sum-of-the-parts (SOTP) approach to derive our target price as a large part of its upstream asset base does not contribute to earnings yet. Our valuation for the upstream assets is based on the company's FAS69 disclosures of the value of its proven and probable reserves, adjusted to our oil and gas price assumptions. For BG's Brazil and Australian assets, we use DCF from HSBC's field models. We value sustainable LNG earnings on a PE of 11x of our 2013 forecast. We adjust our target price for our forecast of potential cost of carbon, which we estimate at 25p/share. abc Oil & Gas/Climate Change Europe 25 January 2013 Catalysts. BP remains a risky investment, in our BG SOTP valuation (p/share) USD90/b Brent USD100/b Brent Core assets Proven reserves Probable reserves Resources 372 164 76 406 225 104 Growth assets Brazil resources Australian CSG Tanzania resources US Shale 717 152 73 43 854 170 73 43 Total growth assets LNG & T+D Net debt Carbon 986 285 -177 -25 1,140 285 -177 -25 1,608 1,820 1,885 2,120 Total Implied TP (12m uplift) Source: HSBC estimates, BG data Catalysts. Delivering on its key projects in Brazil and Australia is essential to restore confidence in BG's growth potential. If the group can convince investors that its longer-term growth is intact, it should start to restore its premium rating. Evidence that production at its two problematic Brazil FPSOs is building during 2013 could help this process. Risks. The generic risks to our Overweight stance include failure to deliver projects on time, disappointing exploration and appraisal wells, and materially weaker oil and gas prices or dollar exchange rates than those assumed for our long-term forecasts. The value of its Brazilian and Australian finds is highly sensitive to oil prices and the US dollar. BG's above-average exposure to Brazil and Kazakhstan also exposes it to country-specific risks. BP (OW, TP 530p) view, given the uncertainties surrounding the costs associated with the oil spill. The key catalyst is an acceptable conclusion to the Macondo lawsuit, which goes to trial at end-February 2013. A decision that BP was not 'grossly negligent' and a reasonable settlement with the DoJ are possible positive catalysts. After the completion of its announced divestment plan, BP's next operational focus is likely to be on delivering its guidance of "50% plus" growth in cash flow by 2014 under an oil price assumption of USD100/b. BP is also accelerating its exploration efforts from 2013. The delivery of its project pipeline and exploration success could restore investors' confidence that BP can deliver longer-term growth. Risks. Downside risks to our Overweight rating are that oil and gas prices, refining margins and the US dollar are materially weaker than our long-term assumptions. Apart from the spill liabilities, which are difficult to quantify, BP-specific risks include an above-sector-average exposure to US gas prices and above-average exposure to Azerbaijan, which expose it to country-specific risk. ENI (N, TP EUR19) Valuation. Our EUR19 target price is set on the basis of target multiples for 2013e, which are based on USD90/b Brent. Our target price assumes the sale of the entire 52.53% stake in Snam and the sale of its residual stake in Galp Energia at current market value. Valuation. Our 530p target price is set on the basis Catalysts. We believe that a possible catalyst for of target multiples for 2013e, which are based on USD90/b Brent. As we have excluded the contribution of TNK-BP Holding from our forecasts but not yet included the benefit from the Rosneft stake, our component valuations include the transaction value (USD12.3bn cash and the current market value of its 19.75% stake in Rosneft (ROSN LI, price USD8.69, UW, TP USD6.50). the stock is the sanctioning of future projects needed to sustain growth in its upstream production. Specifically, approving a development plan for its Mozambique gas discoveries should be a positive for sentiment. ENI is set to increase its exploration for 2012-15. Further resource upgrades in the Skrugard/Havis area in the Barents Sea or success in its West African drilling programme are possible positive 21 abc Oil & Gas/Climate Change Europe 25 January 2013 catalysts. ENI's gas business has been affected by the weak Italian economy. A recovery in the macroeconomic environment in Italy could also help investor sentiment. Statoil (UW, TP NOK150) Risks. Generic upside and downside risks to our Catalysts. Exploration failures in East Africa or Neutral view are oil and gas prices, refining margins or the US dollar are materially different from our long-term assumptions. the US Gulf are key drivers to the downside. Company-specific risks include an above-sectoraverage exposure to North Africa, Nigeria and Kazakhstan. A perceived deterioration or improvement in political risks in these regions could be the downside or upside risks. ENI also has below-sector-average exposure to refining. RD Shell B (N, TP 2,400p) Valuation. Our 2,400p target price is set on the basis of target multiples for 2013e, which are based on USD90/b Brent. Catalysts. The growth in cash flow from RD Shell's Pearl GTL and AOSP developments is likely to continue through 2013 and should comfortably pave the way for further increases in dividends. Improving global economic growth could lead to a tightening global gas market, a potential positive catalyst given the group's growing gas bias. The refining industry faces a challenging longer-term outlook given rising costs and soft demand. If the refining margins were to fall back to below mid-cycle levels, this could be seen as a negative by investors given RD Shell's downstream bias. Risks. Generic upside and downside risks to our Neutral ratings are long-term oil and gas prices, refining margins or the dollar are materially different to our assumptions. RD Shell-specific risks include an above-sector-average exposure to refining. It also has above-average exposure to Nigeria and Qatar. 22 Valuation. Our NOK150 target price is set on the basis of target multiples for 2013e, which are based on USD90/b Brent. Risks. The generic upside risks to our Underweight rating are that long-term oil and gas prices or the USD/NOK rate are materially stronger than our assumptions. Further exploration success in its East African exploration portfolio, new successes in the Gulf of Mexico and a continued improvement in the European gas market could also be risks to our rating. Company-specific risks include an above-sectoraverage exposure to Norway. Total (OW, TP EUR45) Valuation. Our EUR45 target price is set on the basis of target multiples for 2013e, which are based on USD90/b Brent. Catalysts. In the short term, a successful ramp-up in Elgin could be a positive catalyst. The delivery of the project pipeline could increase investors' confidence in the company's growth target. Material discoveries in its frontier exploration areas could also help sentiment. In 2013, the company will be drilling key wells in Angola (pre-salt), Gabon (pre-salt), Kenya, the Ivory Coast, Libya, French Guyana, Mauritania and Indonesia. Risks. The generic risks to our Overweight rating are long-term oil and gas prices, refining margins or the US dollar are materially weaker than our long-term assumptions. Total has above-average exposure to Angola, Nigeria, and Kazakhstan, bringing in country-specific risk. Oil Gas/Climate Change Europe 25 January 2013 Notes 23 Oil & Gas/Climate Change Europe 25 January 2013 abc Disclosure appendix Analyst Certification The following analyst(s), economist(s), and/or strategist(s) who is(are) primarily responsible for this report, certifies(y) that the opinion(s) on the subject security(ies) or issuer(s) and/or any other views or forecasts expressed herein accurately reflect their personal view(s) and that no part of their compensation was, is or will be directly or indirectly related to the specific recommendation(s) or views contained in this research report: Paul Spedding, Kirtan Mehta and Nick Robins Important disclosures Stock ratings and basis for financial analysis HSBC believes that investors utilise various disciplines and investment horizons when making investment decisions, which depend largely on individual circumstances such as the investor's existing holdings, risk tolerance and other considerations. Given these differences, HSBC has two principal aims in its equity research: 1) to identify long-term investment opportunities based on particular themes or ideas that may affect the future earnings or cash flows of companies on a 12 month time horizon; and 2) from time to time to identify short-term investment opportunities that are derived from fundamental, quantitative, technical or event-driven techniques on a 0-3 month time horizon and which may differ from our long-term investment rating. HSBC has assigned ratings for its long-term investment opportunities as described below. This report addresses only the long-term investment opportunities of the companies referred to in the report. As and when HSBC publishes a short-term trading idea the stocks to which these relate are identified on the website at www.hsbcnet.com/research. Details of these short-term investment opportunities can be found under the Reports section of this website. HSBC believes an investor's decision to buy or sell a stock should depend on individual circumstances such as the investor's existing holdings and other considerations. Different securities firms use a variety of ratings terms as well as different rating systems to describe their recommendations. Investors should carefully read the definitions of the ratings used in each research report. In addition, because research reports contain more complete information concerning the analysts' views, investors should carefully read the entire research report and should not infer its contents from the rating. In any case, ratings should not be used or relied on in isolation as investment advice. Rating definitions for long-term investment opportunities Stock ratings HSBC assigns ratings to its stocks in this sector on the following basis: For each stock we set a required rate of return calculated from the cost of equity for that stock's domestic or, as appropriate, regional market established by our strategy team. The price target for a stock represents the value the analyst expects the stock to reach over our performance horizon. The performance horizon is 12 months. For a stock to be classified as Overweight, the potential return, which equals the percentage difference between the current share price and the target price, including the forecast dividend yield when indicated, must exceed the required return by at least 5 percentage points over the next 12 months (or 10 percentage points for a stock classified as Volatile*). For a stock to be classified as Underweight, the stock must be expected to underperform its required return by at least 5 percentage points over the next 12 months (or 10 percentage points for a stock classified as Volatile*). Stocks between these bands are classified as Neutral. Our ratings are re-calibrated against these bands at the time of any 'material change' (initiation of coverage, change of volatility status or change in price target). Notwithstanding this, and although ratings are subject to ongoing management review, expected returns will be permitted to move outside the bands as a result of normal share price fluctuations without necessarily triggering a rating change. 24 abc Oil & Gas/Climate Change Europe 25 January 2013 *A stock will be classified as volatile if its historical volatility has exceeded 40%, if the stock has been listed for less than 12 months (unless it is in an industry or sector where volatility is low) or if the analyst expects significant volatility. However, stocks which we do not consider volatile may in fact also behave in such a way. Historical volatility is defined as the past month's average of the daily 365-day moving average volatilities. In order to avoid misleadingly frequent changes in rating, however, volatility has to move 2.5 percentage points past the 40% benchmark in either direction for a stock's status to change. Rating distribution for long-term investment opportunities As of 24 January 2013, the distribution of all ratings published is as follows: Overweight (Buy) 45% (28% of these provided with Investment Banking Services) Neutral (Hold) 37% (27% of these provided with Investment Banking Services) Underweight (Sell) 18% (22% of these provided with Investment Banking Services) Information regarding company share price performance and history of HSBC ratings and price targets in respect of its longterm investment opportunities for the companies the subject of this report,is available from www.hsbcnet.com/research. 25 abc Oil & Gas/Climate Change Europe 25 January 2013 HSBC & Analyst disclosures Disclosure checklist Company BG BP PLC ENI REPSOL ROYAL DUTCH SHELL A SHS ROYAL DUTCH SHELL B SHS STATOIL ASA TOTAL Ticker Recent price Price Date Disclosure BG.L BP.L ENI.MI REP.MC RDSa.AS RDSb.L STL.OL TOTF.PA 11.49 4.63 19.37 17.08 26.36 22.71 145.30 39.42 23-Jan-2013 23-Jan-2013 23-Jan-2013 23-Jan-2013 23-Jan-2013 23-Jan-2013 23-Jan-2013 23-Jan-2013 2, 4, 6, 7, 11 1, 2, 4, 5, 6, 7, 11 1, 2, 5, 6, 7, 11 1, 2, 4, 5, 7, 11 2, 4, 5, 6, 7, 11 2, 4, 5, 6, 7, 11 11 1, 2, 4, 5, 6, 7, 11 Source: HSBC 1 2 3 4 5 6 7 8 9 10 11 HSBC* has managed or co-managed a public offering of securities for this company within the past 12 months. HSBC expects to receive or intends to seek compensation for investment banking services from this company in the next 3 months. At the time of publication of this report, HSBC Securities (USA) Inc. is a Market Maker in securities issued by this company. As of 31 December 2012 HSBC beneficially owned 1% or more of a class of common equity securities of this company. As of 30 November 2012, this company was a client of HSBC or had during the preceding 12 month period been a client of and/or paid compensation to HSBC in respect of investment banking services. As of 30 November 2012, this company was a client of HSBC or had during the preceding 12 month period been a client of and/or paid compensation to HSBC in respect of non-investment banking securities-related services. As of 30 November 2012, this company was a client of HSBC or had during the preceding 12 month period been a client of and/or paid compensation to HSBC in respect of non-securities services. A covering analyst/s has received compensation from this company in the past 12 months. A covering analyst/s or a member of his/her household has a financial interest in the securities of this company, as detailed below. A covering analyst/s or a member of his/her household is an officer, director or supervisory board member of this company, as detailed below. At the time of publication of this report, HSBC is a non-US Market Maker in securities issued by this company and/or in securities in respect of this company Analysts, economists, and strategists are paid in part by reference to the profitability of HSBC which includes investment banking revenues. For disclosures in respect of any company mentioned in this report, please see the most recently published report on that company available at www.hsbcnet.com/research. * HSBC Legal Entities are listed in the Disclaimer below. Additional disclosures 1 2 3 4 5 26 This report is dated as at 25 January 2013. All market data included in this report are dated as at close 22 January 2013, unless otherwise indicated in the report. HSBC has procedures in place to identify and manage any potential conflicts of interest that arise in connection with its Research business. HSBC's analysts and its other staff who are involved in the preparation and dissemination of Research operate and have a management reporting line independent of HSBC's Investment Banking business. Information Barrier procedures are in place between the Investment Banking and Research businesses to ensure that any confidential and/or price sensitive information is handled in an appropriate manner. As of 31 December 2012, HSBC and/or its affiliates (including the funds, portfolios and investment clubs in securities managed by such entities) either, directly or indirectly, own or are involved in the acquisition, sale or intermediation of, 1% or more of the total capital of the subject companies securities in the market for the following Company(ies): BG, BP PLC, REPSOL, ROYAL DUTCH SHELL A SHS, ROYAL DUTCH SHELL B SHS, TOTAL As of 11 January 2013, HSBC owned a significant interest in the debt securities of the following company(ies): ENI, ROYAL DUTCH SHELL A SHS, ROYAL DUTCH SHELL B SHS, TOTAL Oil & Gas/Climate Change Europe 25 January 2013 abc Disclaimer * Legal entities as at 8 August 2012 Issuer of report 'UAE' HSBC Bank Middle East Limited, Dubai; 'HK' The Hongkong and Shanghai Banking Corporation Limited, HSBC Bank plc Hong Kong; 'TW' HSBC Securities (Taiwan) Corporation Limited; 'CA' HSBC Bank Canada, Toronto; HSBC 8 Canada Square Bank, Paris Branch; HSBC France; 'DE' HSBC Trinkaus & Burkhardt AG, D?sseldorf; 000 HSBC Bank (RR), London, E14 5HQ, United Kingdom Moscow; 'IN' HSBC Securities and Capital Markets (India) Private Limited, Mumbai; 'JP' HSBC Securities (Japan) Limited, Tokyo; 'EG' HSBC Securities Egypt SAE, Cairo; 'CN' HSBC Investment Bank Asia Limited, Telephone: +44 20 7991 8888 Beijing Representative Office; The Hongkong and Shanghai Banking Corporation Limited, Singapore Branch; The Fax: +44 20 7992 4880 Hongkong and Shanghai Banking Corporation Limited, Seoul Securities Branch; The Hongkong and Shanghai Website: www.research.hsbc.com Banking Corporation Limited, Seoul Branch; HSBC Securities (South Africa) (Pty) Ltd, Johannesburg; HSBC Bank plc, London, Madrid, Milan, Stockholm, Tel Aviv; 'US' HSBC Securities (USA) Inc, New York; HSBC Yatirim Menkul Degerler AS, Istanbul; HSBC M?xico, SA, Instituci?n de Banca M?ltiple, Grupo Financiero HSBC; HSBC Bank Brasil SA - Banco M?ltiplo; HSBC Bank Australia Limited; HSBC Bank Argentina SA; HSBC Saudi Arabia Limited; The Hongkong and Shanghai Banking Corporation Limited, New Zealand Branch incorporated in Hong Kong SAR In the UK this document has been issued and approved by HSBC Bank plc ("HSBC") for the information of its Clients (as defined in the Rules of FSA) and those of its affiliates only. 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MICA (P) 038/04/2012, MICA (P) 063/04/2012 and MICA (P) 110/01/2013 [357720] 27 Global Natural Resources & Energy Research Team Metals and Mining Chemicals EMEA Andrew Keen Global Sector Head, Metals and Mining +44 20 7991 6764 andrew.keen@hsbcib.com Europe Dr Geoff Haire +44 20 7991 6892 abc Thorsten Zimmermann, CFA +44 20 7991 6835 thorsten.zimmermann@hsbcib.com Vladimir Zhukov +7 495 783 8316 vladimir.zhukov@hsbc.com CEEMEA Cor Booysen +27 11 6764224 cor.booysen@za.hsbc.com North America & Latin America Jonathan Brandt +1 212 525 4499 jonathan.l.brandt@us.hsbc.com James Steel +1 212 525 3117 james.steel@us.hsbc.com Patrick Chidley, CFA +1 212 525 4915 patrick.t.chidley@us.hsbc.com Howard Wen +1 212 525 3726 howard.x.wen@us.hsbc.com Asia Simon Francis Regional Head of Metals and Mining, Asia Pacific +852 2996 6620 simonfrancis@hsbc.com.hk Thomas Zhu +852 2822 4325 thomasjzhu@hsbc.com.hk Chris Chen +852 2822 4277 chrislchen@hsbc.com.hk Jeff Yuan +852 3941 7010 jeffsyuan@hsbc.com.hk Jigar Mistry, CFA +91 22 2268 1079 jigarmistry@hsbc.co.in Energy Europe Paul Spedding Global Sector Co-head, Oil and Gas +44 20 7991 6787 paul.spedding@hsbcib.com David Phillips Global Sector Co-head, Oil and Gas +44 20 7991 2344 david1.phillips@hsbcib.com geoff.haire@hsbcib.com Sebastian Satz, CFA +44 20 7991 6894 sebastian.satz@hsbcib.com Jesko Mayer-Wegelin, CFA +49 211 910 3719 jesko.mayer-wegelin@hsbc.de CEEMEA Yonah Weisz +972 3 710 1198 yonahweisz@hsbc.com Sriharsha Pappu, CFA +971 4 423 6924 sriharsha.pappu@hsbc.com Asia Dennis Yoo, CFA +852 2996 6917 dennishcyoo@hsbc.com.hk Utilities Europe Adam Dickens +44 20 7991 6798 adam.dickens@hsbcib.com Verity Mitchell +44 20 7991 6840 verity.mitchell@hsbcib.com Asia Jenny Cosgrove Regional Head of Utilities and Alternative Energy, Asia Pacific +852 2996 6619 jennycosgrove@hsbc.com.hk Arun Kumar Singh Analyst +91 22 2268 1778 arun4kumar@hsbc.co.in Gloria Ho +852 2996 6941 gloriapyho@hsbc.com.hk Summer Y Y Huang +852 2996 6976 summeryyhuang@hsbc.com.hk Latin America Eduardo J Gomide +55 11 3371 9502 eduardo.j.gomide@hsbc.com.br CEEMEA Levent Bayar Analyst +90 212 376 46 17 leventbayar@hsbc.com.tr dmytro.konovalov@hsbc.com Peter Hitchens +44 20 7991 6822 peter.hitchens@hsbcib.com Phillip Lindsay +44 207 991 2577 Dmytro Konovalov +7 495 258 3152 phillip.lindsay@hsbcib.com Alternative Energy Kirtan Mehta, CFA +91 80 3001 3779 kirtanmehta@hsbc.co.in CEEMEA, Latam Anisa Redman +1 212 525 4917 anisa.redman@us.hsbc.com B?lent Yurdag?l +90 212 376 46 12 Charanjit Singh +91 80 3001 3776 charanjit2singh@hsbc.co.in bulentyurdagul@hsbc.com.tr Ildar Khaziev, CFA +7 495 645 4549 Gloria Ho +852 2996 6941 gloriapyho@hsbc.com.hk ildar.khaziev@hsbc.com Specialist Sales Middle East John Tottie, CFA +966 1 299 2101 john.tottie@hsbc.com Asia Thomas Hilboldt Regional Head of Oil, Gas and Petrochemical Research, Asia Pacific +852 2822 2922 thomaschilboldt@hsbc.com.hk Kevin Lian +852 2822 4337 kevinzqlian@hsbc.com.hk Dennis Yoo, CFA +852 2996 6917 dennishcyoo@hsbc.com.hk Kumar Manish +91 22 2268 1238 kmanish@hsbc.co.in Puneet Gulati +91 22 681235 puneetgulati@hsbc.co.in SI Tingting +852 2996 6590 tingtingsi@hsbc.com.hk Jenny Cosgrove Regional Head of Utilities and Alternative Energy, Asia Pacific +852 2996 6619 jennycosgrove@hsbc.com.hk Mark van Lonkhuyzen +44 20 7991 1329 mark.van.lonkhuyzen@hsbcib.com Annabelle O'Connor +44 20 7991 5040 annabelle.oconnor@hsbcib.com James Lesser +44 207 991 1382 james.lesser@hsbcib.com