UK power generators SECTOR REVIEW. Close to the bottom of the cycle. Figure 1: UK reserve margins look set to narrow 2008A 2009A

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1 Europe/United Kingdom Equity Research Utilities Research Analysts Mark Freshney Vincent Gilles UK power generators SECTOR REVIEW Close to the bottom of the cycle Figure 1: UK reserve margins look set to narrow Michel Debs Mark Whitfeld % 30% 25% 20% 15% CCGT (gas-fired) plant closures Coal and oil-fired plant closures 10% 5% 0% -5% -10% 2008A 2009A 2010A 2011E 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E -15% Reserve margin Reserve margin ex. opted-out coal Headline level of comfort Source: Company data, Credit Suisse research and estimates Higher power prices: After a temporary pull-back, we think UK power prices are set to increase, driven by regulation, industry self-help and taxes. We estimate this will take UK power prices to c 83/MWh by 2020 (from c 54/MWh at present). We think it is time to highlight SSE, the generator most exposed to UK power prices/the CO2 floor. A favourable mix of factors driving the UK: (1) CO2 floor driving up power prices: The UK s CO2 floor price (a tax) works to raise costs for coalfired plant, and should alone drive the power price upwards (we do not assume real growth in energy commodities), which should benefit clean plant. As the CO2 floor raises c 7bn p.a. for government by 2020 at current levels, it is unlikely to be reduced. (2) Low spark spreads encourage retirements: Older, less efficient gas-fired power plants are experiencing very low clean spark spreads. We have already seen c1gw of closures, and forecast another c6.5gw. (3) Coal plant to close: There is c12gw of oil and coal-fired plant which must close by 2016 (c13% of total UK generation fleet), and we estimate another c10gw (c11%) of coal plant will have restricted running hours post We expect reserve margins to fall to low or negative levels in 2015E 16E (Figure 1) and flexibility of the fleet to decline. We expect this to be priced into forward curves from 2013E. We see SSE (TP 1,450p, Outperform) and EDF (TP 24, Outperform) as the best ways to play the theme: SSE has flexible and fixed cost generation (particularly hydro and wind) and is diversified across fuel types. It is therefore the stock most exposed to the CO2 floor, as a fraction of EV. EDF owns 80% of British Energy, which benefits under a variety of commodity/co2 scenarios, albeit the UK is diluted in the EV. DISCLOSURE APPENDIX CONTAINS ANALYST CERTIFICATIONS AND THE STATUS OF NON-US ANALYSTS. U.S. Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

2 Table of contents Focus point: Key charts 3 1. Executive summary CO2 prices (and potentially energy commodities) move upwards, helping UK power prices Plant closures set to become a theme over the coming three years (Figure 2) UK reserve margins likely to fall to low levels UK power prices steadily increase to c 83/MWh in 2020E, spark spreads likely to rise We focus on the clean and fixed-cost generators as the way to play the theme 5 2 Upside to CO2, gas and coal Context: Energy commodities and some power price contracts have temporarily moved downwards CO2 floor helps underwrite UK power prices CO2 floor here to stay (and perhaps increase) Gas-oil links elsewhere still relevant for the UK Thermal coal indicates upside risks, driven by China 11 3 Oversupply of generation set to end Weak spreads part of the solution High gas and coal prices, cheap CO2, and low spark spreads a perfect storm to close older CCGTs More permanent gas-fired plant closures LCPD will work to close coal-fired plants The Industrial Emissions Directive will significantly curtail much of the UK coal-fired fleet Capacity payments only a distant possibility Nuclear the key unknown, but on balance a downside risk No reason to invest in new thermal generation UK power consumption is structurally falling, but more slowly than supply cuts will be made 19 4 Conclusions Our assumptions Reserve margins set to tighten within three years Looking beyond headline reserve margins Our forecasts show spark spreads and power prices bottoming in 2012, reserve margins declining Conclusions Who will benefit? 4.7 Key exposed names, stock by stock Where we could be wrong Our thesis is reliant upon gas plant closures 28 Appendix 1: gas prices 29 Winter-ahead UK gas prices 29 Month-ahead UK gas prices 29 Appendix 2: our commodity and power price forecasts 30 Appendix 3: our demand assumptions 31 UK power generators 2

3 Focus point: Key charts Figure 2: Our forecasts for UK generation capacity In Gigawatts Dec-11 Mothballed plant closing Additional CCGT closures Opening of efficient gas plants Opted-out coal Opted-out oil Magnox Others Opening of wind farms Jan-16 Restricted coal plant Jan-16 - Exrestricted coal Source: National Grid, Credit Suisse research, Credit Suisse estimates Figure 3: Our reserve margin estimates Figure 4: Price of EU ETS and CO2 price support /t 35% 30% 25% CCGT (gas-fired) plant closures % 15% Coal and oil-fired plant closures % 25 5% 20 0% 15-5% -10% -15% 2008A 2009A 2010A 2011E 2012E Base case headline Level of comfort required 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E Reserve margin ex. opted-out coal E 2010E 2012E 2014E 2016E 2018E 2020E CO2 price support rate CS estimate of average EU ETS Phase III CO2 price ( /tn) Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse estimates Figure 5: UK power price /MWh A 2010A 2011A 2012A 2013A 2014A 2015E 2016E 2017E 2018E 2019E Market price ( /MWh) Credit Suisse estimate of System Marginal Price ( /MWh) 2020E Source: HM Treasury, APX, Credit Suisse estimates Figure 6: Clean dark and spark spread estimates /MWh (5) 2009A 2010A 2011A 2012A 2013A 2014A 2015E 2016E 2017E 2018E 2019E 2020E Baseload Clean Dark 36% efficiency Baseload Clean Spark 49% efficiency Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse research Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse research UK power generators 3

4 1. Executive summary The UK power market has weakened of late owing to cheaper CO2, cheaper gas and lower spark spreads. The near-term power price has therefore fallen to c 54/MWh (from c 63/MWh in April 2011). The reality that the UK is facing structural y-o-y demand destruction has compounded investor concerns. In this report, we show why we think c 54/MWh could be seen as exceptionally cheap in future, and why we think a new era in power prices is likely, driven by the CO2 floor price. We look across the UK market and analyse which businesses have most upside potential into this theme. 1.1 CO2 prices (and potentially energy commodities) move upwards, helping UK power prices The CO2 floor price will effectively drive up power prices and clean spreads (Figure 4): The CO2 floor has been written into legislation in the UK, and will work to drive power prices progressively higher. This is good for low-cost and fixed-cost generation. We think the UK Government needs the c 7bn p.a. revenue it is set to bring (by 2020); hence we see the risk of the CO2 floor being dropped as low rather, we view increases in the CO2 floor s trajectory as more likely. Commodity assumptions conservative: We take the forward curves for gas and coal prices through to 2015E. We follow our team assumptions (c66p/therm gas and US$120/t API-2 thermal coal) from 2015E, which is close to the forward curves, and only assume c1.5% p.a. inflation. Our bullish view is therefore not predicated on an energy commodity price pick-up. 1.2 Plant closures set to become a theme over the coming three years (Figure 2) Gas-fired plant closures inevitable: Clean spark spreads for less efficient plant have fallen to low levels, and free CO2 allocations soon end. We see c1gw of gas-fired power plant that has already closed in response, and another c3.2gw mothballed. Two more years of low spark spreads is likely to stimulate mothballed plant to close permanently, in our view, and we see scope for the closure of an additional c3.3gw of less efficient plant. Environmental rules working to close coal-fired plant: Under LCPD 1 rules, there are just three years of life left for c8gw of the UK s c28gw of coal-fired power plants (even on a low c25% load factor 2 ). Even if the plant stays open to burn biomass, low maintenance spend and c44-year average ages are likely to limit flexibility and reliability. Even tighter emissions requirements to further restrict plant: From 2016, the c20gw of coal-fired plant that remains will be required to fit further emissions reduction equipment, or else become restricted (hence not reliable). The coal-fired industry requires c 2bn of capex on our estimates, which we think would be prohibitively expensive for many players, especially with the CO2 floor reducing profitability. 1 Large Combustion Plant Directive 2 The plant has four years, but current run-rates suggest it will close in three years UK power generators 4

5 1.3 UK reserve margins likely to fall to low levels Reserve margins could tighten to levels that are good for generators (Figure 3): On our estimates, headline reserve margins fall to c5% before 2016 (-10% if we exclude the c10gw of coal-fired power plant we expect to be restricted). This scenario includes life-extensions for nuclear and c1% structural y-o-y demand destruction. We would expect the forward curves to price this in from late 2013E. We do not include a scarcity premium in our numbers. Quality of the UK fleet likely to deteriorate: Looking beyond the headline reserve margins, we estimate that flexible generation will fall to c47gw in 2016 (from c67gw currently) and baseload generation will fall to 47GW (from 64GW). This is below peak demand (c58gw) and average winter daily peak demand of c47gw. The UK market would therefore be more reliant upon peak load generation (e.g. reservoir hydro, which has market power). This would lead to higher and more volatile power prices, in our view. 1.4 UK power prices steadily increase to c 83/MWh in 2020E, spark spreads likely to rise Power prices should move upwards (Figure 5): Our forecasts suggest that power prices will steadily increase to c 64/MWh by 2015 and c 83/MWh by 2020, driven by the CO2 floor (at present, calendar 2013 is c 54/MWh and day-ahead c 46/MWh). New entrant spreads for gas and wind (Figure 6): We believe the CO2 floor will ensure coal takes over from gas as the marginal price-setting fuel in the UK. We forecast c10/mwh baseload clean spark spreads by 2016 and c16/mwh by This would be enough to stimulate new-entry 3 for gas-fired power plants by Likewise, wind will be economic without subsidies in the UK by 2020, on our estimates. 1.5 We focus on the clean and fixed-cost generators as the way to play the theme Our two most preferred stocks on the theme SSE (TP 1,450p, Outperform): Likely beneficiary under any plausible scenario: SSE will have c9twh p.a. of fixed-cost generation by 2014E, and has the most flexible generation fleet with a bias towards peak load generation (the premia over baseload can increase with higher power prices). After EDF, SSE is the biggest beneficiary of the CO2 floor price, and the most focused way of playing the theme in our view. Earnings impact assuming 2020 power price assumptions on 2012E Upside Diff. SSE.L 100p 43p 43% EDF.PA % CNA.L 28p 6p 22% IPR.L % DRX.L 54p (38p) -70% Source: Credit Suisse estimates EDF (TP 24, Outperform): The biggest primary energy player in UK power: EDF will see a benefit through its 80% effective shareholding in British Energy (Not rated). We estimate that each 10/MWh increase in the power price (be it driven by spreads, natural gas or, as we think, by the CO2 floor) would drive EBITDA up by 660m and recurring 2013 EPS by c 0.21/share, or c10%. As we forecast power prices to increase to c 83/MWh by 2020, EBITDA could increase by c 2bn, and EPS by c 0.63 by 2020, in addition to other moving components. Our two least preferred stocks on the theme Drax (TP 440p, Underperform): CO2 floor a negative: Drax is currently a beneficiary of attractive spreads (realised clean dark spreads are above c 20/MWh). We believe the CO2 floor cost will increase by more than power prices. Gas and coal 3 Note that new plants are c53% thermal efficiency (Higher Heating Value) while the closed plant is c44-48%, on our numbers. Older plant (if kept open) would still be loss-making in 2017E. UK power generators 5

6 plant closures should increase Drax s ability to benefit from peak pricing, but in any event, our model indicates dark spreads drifting downwards. We acknowledge, however, that Drax is exposed to any scarcity premium, and its UK coal-fired plant could be the last to close. IPR (TP 320p, Underperform): Exposure limited to two plants: IPR has the lowest sensitivity to the UK, as just c10% of its 2012E EV is in the UK. Further, we think the Deeside, Teesside and Derwent plants may need to close (they are old gas-fired power plants), and that only Saltend and the First Hydro Pumped Storage asset will benefit from power price volatility. Our numbers already include First Hydro returning to peak profitability by 2016E (c 180m p.a. UK GAAP EBITDA). UK power generators 6

7 2 Upside to CO2, gas and coal The CO2 floor will effectively work to drive power prices in the UK progressively higher. We think the UK Government needs the fiscal revenues, making the risk of downward adjustment to the CO2 floor trajectory unlikely. We expect the budget on 21 March 2012 to set the CO2 floor at c 10/t for April 2014 March The CO2 floor will drive clean spark spreads and power prices higher, and likely reduce volatility of power prices, as the CO2 floor will introduce a large fixed component. It will drive clean dark spreads lower as coal-fired generation goes to the margin. We also see upside risks to UK natural gas and thermal coal prices (which could also drive power higher), albeit we show later that this is not our base case. 2.1 Context: Energy commodities and some power price contracts have temporarily moved downwards The Generation sub-sector has been under pressure in recent months, partly from lower commodity prices. Natural gas (currently the price-setting fuel for the UK) fell c10% across the forward curve during the past nine months, as has thermal coal. CO2 emission permit prices also fell on fears of oversupply, as emissions fell but permits continued to come to market. Lower commodities reduced power prices and negatively affected mark-to-market valuations, and hence investor sentiment towards the sector. UK power prices have temporarily moved downwards, driven primarily by lower CO2 prices, in our view Figure 7: Breakdown of UK power prices Winter 2012/13 ( /MWh) /MWh 0.9/MWh 3.4/MWh 4.1/MWh 54.0/MWh Apr-11 Lower Gas Price Lower CO2 price Lower CSS Feb-12 Gas 49% ( /MWh) CO2 cost ( /MWh) Clean Spark Spreads ( /MWh) Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse research, Credit Suisse estimates The headline result of lower energy commodities, falling demand and rising supply of generation is that power prices have moved downwards. In Figure 7 we show how the wholesale power price is broken down, and three items in order of magnitude which have contributed to the decrease: We think this pull-back is only temporary, and from here onwards we see potential upside The key item is CO2 emission permits, which have continued to decrease in recent months; Clean spark spreads have fallen c60%, from c 6.8/MWh to c 2.7/MWh in the last ten months; and UK power generators 7

8 Gas the biggest component of wholesale prices has fallen the least on a relative basis In this section, we show why we think power prices have reached the bottom, why we think CO2 will drive UK power prices upwards, and why there is also upside risk to gas and coal prices. 2.2 CO2 floor helps underwrite UK power prices Figure 8: Price of EU ETS and CO2 price support mechanism /tonne nominal Figure 9: Illustration chart of 2015 electricity price using hypothetical 50p/therm gas price (cus$56boe) /MWh E 2010E 2012E 2014E 2016E 2018E 2020E CO2 price support rate CS estimate of average EU ETS Phase III CO2 price ( /tn) 30 Gas component CO2 Clean Spark Spread CO2 floor component Electricity price (We take an arbitrary c 7.7/t, not far from current prices) to demonstrate the mix, and the fact the floor is what matters Source: HM Treasury, Credit Suisse estimates Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse estimates The CO2 floor is designed to underpin the total cost of CO2 emissions in the UK, via a top-up tax. In the medium term, it will drive the power price progressively higher. The CO2 floor will raise costs for dirty generators (mainly coal), but these power plants will price it through. The clean generators (e.g. hydro, nuclear, wind and gas) will benefit through a higher power price without an increase in costs. The floor is structured via an additional c 4.94/t CO2 tax applicable for the year starting April 2013 (shown in Figure 8). Based on the formula, we expect the top-up tax to rise to c 10/t for the year starting April The price of CO2 permits have fallen, which has been one of the key items influencing the power price. But we do not expect this to last for long, as the CO2 floor price will take CO2 up to highs by 2014 To illustrate, we estimate, in Figure 9, that even if spark spreads are only c 4/MWh and gas c50p/therm, the CO2 floor will take power prices to c 47/MWh, not far from where they are at present 5. More stable power prices We also think that in future, power prices could be more stable. A large component of the power price will be set by a floor, rather than volatile and uncertain markets (as is the case with the EU ETS). Therefore, power prices could be more stable, reducing risk for fixed-cost generators. 4 To be set in the forthcoming UK government budget, due 21 March We expect other European governments to follow the UK government's lead and adopt non-market mechanisms. We model a European CO2 floor at c75% of the UK's level. See our 11 January 2012 report entitled All depends on hot air for more details. UK power generators 8

9 2.3 CO2 floor here to stay (and perhaps increase) The CO2 floor is unlikely to be cut by the UK Government, in our opinion. We note that there have been calls for Government to focus much more on working to get the EU ETS working effectively than to tax dirty power (e.g. from Tim Yeo, a Member of Parliament and head of the Climate Change Committee). However, our view is that important fiscal reasons are driving the CO2 floor: (1) Important part of the fiscal take: By 2020, we calculate that the CO2 floor and EU ETS will together raise c 7bn p.a. for the UK government, which will be c1% of fiscal revenues. (2) Offsetting the negative impact of lost CO2 value: The c170m tonnes of CO2 permits p.a. due to be used by the UK power sector from 2013 have fallen in value by c 1.2bn p.a. in the last nine months as the CO2 price has approximately halved; and (3) Scope and a need to raise bills: Government take on the electricity value chain is low, especially compared with other Northern European countries, partly because sales tax on electricity and gas to homes is just c5% (compared with a c20% standard rate in the UK). This is lower than in France. We think it will be hard for Government to ignore the low taxes on electricity, and the CO2 floor taxes electricity by subtle means (i.e. via the wholesale price not retail prices). We believe that if anything, the CO2 floor could be raised above the levels already set by Government in order to raise yet more money in the drive for fiscal austerity. Most utilities have clean low-carbon plant that would make them net beneficiaries. 2.4 Gas-oil links elsewhere still relevant for the UK It is our opinion that the UK government cannot afford to lose the fiscal revenues from the CO2 floor price, and that it may even be increased Figure 10: Day-ahead gas price p/therm Pence/therm Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 NBP Gazprom Henry Hub Jul-12 Figure 11: LNG demand Million tonnes per annum LNG (existing) LNG under construction LNG supply (bear) LNG supply (base) Speculative LNG demand (base) LNG demand (China bull) Source: Thomson Reuters, Gazprom, Credit Suisse research Source: BP, Credit Suisse research, Credit Suisse estimates The biggest absolute component of the UK power price is the UK gas price, which we think has bottomed. Over recent months, it has pulled back from c65p/therm in April 2011 to c50p/therm currently. A combination of: (1) potential recession in Europe hence potential oversupply of gas and (2) inflexible Gazprom contracts 6, where the selling price is linked to oil, both means there is less demand for UK gas, and has caused it to drift down from the Gazprom oil-link (Figure 10). LNG is becoming important for the UK market, and oillinked prices (as seen in Asia) could put upward pressure on UK gas prices 6 On our estimates, two-thirds of European gas is sold on the oil-link, predominantly by Gazprom, where the selling price is currently c86p/therm (US$13.5/mmBTU) UK power generators 9

10 From here onwards, we see a lack of downside, and there may even be potential upside. Our Economics team has upgraded its 2012 European GDP growth forecast to 0% (from - 0.5%), and the oil price to which gas is linked has not moved downwards. Indeed, in sterling terms, gas could become even more expensive if sterling weakens. Tight LNG in the medium term putting upward pressure on UK gas Figure 12: Sources of UK Gas; moving to LNG and Norway over the past decade Figure 13: Sources of UK Gas; increasing role of LNG in the future Indigenous Production LNG import Other import Exports 100% 90% 13% 80% 70% 60% 50% 40% 30% 20% 10% 0% 2010A UK Continental Shelf LNG Continental (mainly Russia) 40% 2020E Norway Unconventional (Shale / Biogas) Source: DECC Source: National Grid estimates UK gas could move closer to oil-linked gas (priced at c86p/therm), which is more expensive than spot gas. LNG is becoming an increasingly important source of gas for the UK (Figure 12 and Figure 13), and is currently sold mostly to countries on oil-links (South Korea, Japan and LatAm). The UK gas price could therefore more closely tie in with the oil link into any potential economic recovery. Qatar pricing strategy may put upward pressure on UK prices Qatar s LNG export strategy is a case in point. It is the only producer with large amounts of flexible LNG which can be sent either to Europe or to Asia. We believe Qatar s restricting LNG supplies to Asia creates a perception of market tightness, thus locking Asian customers into long-term oil-related contracts. Around half of Qatar s LNG exports to Europe are contracted and the other half is spot i.e. flexible. If Qatar successfully signs long-term contracts into Asia in 2012, then up to 15mtpa of LNG (~1/4 of the UK s gas consumption) could theoretically get redirected away from Europe, thus tightening the market and putting upward pressure on UK spot prices. According to our Integrated oil and gas analyst, Kim Fustier, the LNG market is likely to be tight until 2016, until which point demand for LNG is likely to outstrip supply. This is bullish for gas prices in the UK According to our Integrated oil and gas analyst Kim Fustier, the LNG market is likely to be tight until 2016, until which point demand for LNG is likely to outstrip supply. This is bullish for gas prices in the UK. See Appendix 1 for an illustration. UK power generators 10

11 2.5 Thermal coal indicates upside risks, driven by China Figure 14: Chinese domestic coal supply and demand Million metric tonnes p.a. Figure 15: China s thermal coal trade % 2, , ,700 2,600 2,500 2,400 2,300 2,200 2, , Jul-05 Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 China: Consumption China: Production China: Imports China: Exports Source: Credit Suisse Commodities team, IEA Source: Credit Suisse Commodities team, China customs data The final commodity we look at is thermal coal. While natural gas is currently the most expensive fuel (hence it is the marginal power price-setting technology meaning that UK power couples with gas), expensive CO2 would penalise coal and could push it to the margin. Coal would therefore take over from gas as the marginal price-setting solid fuel for the UK market in future, on our thesis. A potential coal-link is important, since higher thermal coal prices could drive the power price higher in the long term. Our Commodities Research teams see two reasons for coal prices increasing, both related to China: (1) China a coal importer: China now accounts for almost 50% of world coal consumption and, since 2009, has moved from a position of total self-sufficiency (historically, it was a moderate net exporter) to being a significant importer of thermal coal. Consequently, movements in China s domestic market have increasingly come to influence the seaborne market and hence international prices. (2) China should remain dependent on coal: Furthermore, despite abundant resources, we believe China s coal mining industry will struggle to keep pace with demand growth, without steeply rising economic and social costs, leading to steadily rising imports. Energy security dictates that coal (and electricity) will continue to dominate China s energy mix and mitigate the risks of too heavy a reliance on oil. While Coal s proportional contribution will likely fall in the longer term (e.g. as China starts to import natural gas), in absolute terms, consumption should grow strongly, thus driving European coal prices higher. We assume cus$120/t coal in 2015E, growing by 1.5% p.a., but we believe this could be conservative. We also think that coal which could well become the marginal fuel for the UK could see upside pressure on the back of increased Chinese demand UK power generators 11

12 3 Oversupply of generation set to end Low spark spreads (and low volatility) are a signal to generators to close capacity. Only c1gw of gas plant has closed to date, but we expect c3.2gw (c3.4% of the generation fleet) of mothballed plant to close permanently, and another c3.3gw of plant (3.7%) to go straight to closure. The regulation coal-fired power plant face will cause retirements. Further, our base case is that there is only c10gw of unrestricted coal post-2015, when the IED comes into force. About 4GW of oil-fired peaking plant will close at the end of We expect demand destruction to continue (perhaps because energy efficiency in the home spreads to the public and commercial sectors). We estimate c % p.a. declines in demand. However, we expect supply of generation to decrease more quickly. 3.1 Weak spreads part of the solution Figure 16: Winter 12E/13E Clean Dark Spread (36% net thermal efficiency) /MWh Figure 17: Winter 12/13 Clean Spark Spread (49% net thermal efficiency) /MWh Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Jan-12 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Jan-12 36% 2012 Winter 2012/13 CO2 Coal Winter 12/13 CDS 49% Winter 2012/13 Winter 2012/13 CO2 Gas Winter 12/13 CSS Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse research Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse research The cyclical part of the UK market is generation spreads. Around 75 80% of the UK s power comes via coal and gas-fired plants, which have high operational gearing (i.e. a high fixed O&M cost base and low gross margins). This makes free cash flow and valuation highly sensitive to small changes in spreads. There is currently oversupply of this type of generation in the UK 7. The recession caused demand to drop, meaning that opted-out (i.e. life-limited) coal plant did not work through their c20,000 running hours as expected and remained operational. At the same time, c8gw of new-build CCGT ordered to replace opted-out coal-fired plants came online. Clean spark spreads (relevant for gas-fired power plants) and clean dark spreads for less efficient players (relevant for coalfired plants) have been under pressure of late 7 For much of the period, the UK generation fleet was c80gw, but this increased to c95gw in , while peak load demand did not change UK power generators 12

13 Oversupply of thermal generation Therefore, the UK generation fleet is currently c95gw (historically, it was c80gw), on our numbers 8. This means headline spreads (gross margin for coal- and gas-fired plants) have come under pressure, particularly spark spreads (Figure 17). All UK merchant plants currently have exposure to spark spreads through the marginal pricing mechanism; so lower spark spreads impact all generators. In this section, we look at some of the themes facing the UK generation sector (LCPD 9, IED 10, capacity payments) and show why the regulation can work to the sector s advantage. We undertake a plant-by-plant review of the UK generation fleet, looking at which plants might close. 3.2 High gas and coal prices, cheap CO2, and low spark spreads a perfect storm to close older CCGTs Figure 18: UK Clean Dark and Spark Spreads (baseload) range of efficiencies /MWh, average across past three months Figure 19: Volatility in month-ahead Clean Dark and Spark Spreads Standard deviation of clean spark and clean dark spreads Low volatility Summer 2012 Winter 12/13 Summer 2013 Winter 13/ Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Range of LHV efficiencies for coal: % (Grey-Left) Range of HHV efficiencies for gas: % (Dark-Right) Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse research, Credit Suisse calculations Volatility: Month ahead CDS Volatility: Month ahead CSS Source: The BLOOMBERG PROFESSIONAL service, Credit Suisse research, Credit Suisse calculations It is natural for a downcycle with oversupply for cash flows for the least efficient players to move downwards and cause older plants to close. This is how a market mechanism works. It happened in , and we think we are seeing this now. There are three points that we think will put pressure on some older gas-fired plants to permanently close: (1) In a high commodity price environment, thermal efficiency matters: In Figure 18 we show how the most efficient gas and coal plants are making healthy spreads, but the least efficient gas plants are making negative spreads. This is because the relative efficiency difference is worth more at high commodity prices. We believe this simultaneous feast and famine will become more acute as commodities rise and put pressure on older plants to close; (2) Market volatility has fallen: Just as important as spreads is the money that can be made through trading around a physical asset and monetising optionality. Volatility Older power plants have been penalised by high commodity costs and low volatility 8 Peak demand in the UK has fluctuated around c60gw 9 The Large Combustion Plant Directive, which will require c12gw of plant closures by end The Industrial Emissions Directive, which could require coal-fired power plants, and some gas-fired plants to fit expensive equipment UK power generators 13

14 as measured by the standard deviation has fallen and been low for the last three years (Figure 19), and older plants will find it difficult to trade this volatility; and (3) Loss of free CO2 emissions permits: We believe that free CO2 emission permits act as a quasi-capacity payment, helping plants to pay fixed costs 11. All plants are now eligible for free CO2 emission permits for 2012 and there will be no more free permits. Our estimates suggest most gas-fired plants below c50% thermal efficiency (i.e. roughly those built before 2000) are loss-making on a mark-to-market basis. We show later (on page 24) that we foresee another one-two years of lower spark spreads to stimulate closure. Figure 20: List of plants that have been taken off the Grid Date Owner Age Asset Action MW % of UK capacity Retired Feb-10 SSE 32 yrs Peterhead (Gas) Closure 344 Feb-12 SSE 12 yrs Fife (Gas) Closure 123 Oct-12 CNA 14,16 yrs Barry, King Lynn (Gas) Closure 555 De-Ratings (reduction in capacity) Apr-11 RWE 44 yrs Tilbury 'B' (Coal) Biomass conversion 300 Oct-11 CNA 19,19,21 yrs P'boro, Brigg, R cote (Gas) Remove steam turbines 270 Dec-11 E.ON 13,18 yrs Cottam, Killingholme Remove steam turbines 390 Jan-12 E.ON 42 yrs Ironbridge (Coal) Biomass conversion 250 Mothballed Mar-11 IPR 20 yrs Teesside (Gas) Mothballed for one year 1,800 Jan-12 SSE 18,17 yrs Keadby, Medway (Gas) Considering options* 1,437 Short Term Operating Reserve (contracted to NG) Oct-12 CNA 19,19,21 yrs P'Boro, Brigg, R cote (Gas) One-cycle mode 570 Jan-12 E.ON 13,18 yrs Cottam, Killingholme (Gas) One-cycle mode 910 1, % 1,210 2% 3, % 1, % Grand total 6, % * SSE has stated it is looking at options to make the plants more flexible Source: Company data, DECC Dukes, Credit Suisse analysis In Figure 20 we show the action taken to date on gas-fired plants. Only c1gw of plant has permanently closed down, but another c5.9gw is half-way between full closure and staying open (de-rated, mothballed or in short-term reserve). The short-term operating reserve is a capacity market run by National Grid to help balance the market. Centrica has de-rated capacity, and has made public announcements about mothballing plants again (e.g. in Bloomberg News) if it were not to win balancing contracts, which is a further step to closure. We think the European operators (EON, RWE, EDF and SPW) will follow suit. We have seen c1gw of older gas-fired power plant close, and we see action taken on another c6gw Most interesting is that the total 6.9GW on which action has been taken is almost as big as the c8gw of new gas-fired CCGTs to have come online across , and is c12% of peak demand. Unlike in Germany (where there is also over-supply and low thermal spreads), utilities in the UK are taking voluntary action, which we expect to continue given the factors outlined on page To illustrate this point, we flag that excluding the free CO2 emission permits, Centrica's oldest c2.9gw of gas-fired power plant has been loss-making (after depreciation) across the past seven years UK power generators 14

15 3.3 More permanent gas-fired plant closures We look towards more permanent closure of mothballed plants A key bullish sign will be permanent closure of Teesside, Keadby and Medway, totalling 3.2GW (currently mothballed). Keeping these plants off is costing the owners >c 50m p.a. in grid fees, insurance, council rates and maintenance contracts, on our numbers. Our base case is that these are closed permanently within two years in response to low spreads and age. Closure of these plants will help to remove a ceiling from spreads, as power market participants will know these plants are not available. More closures likely We think there are more closures to come. We see similarly old power plants that have potentially lower thermal efficiency and potentially in zones with higher transmission charges (e.g. EDF s Sutton Bridge, IPR s Deeside, CNA s Killinghome, E.ON s Connah s Quay, ATCO s Barking, Scottish Power s Rye House, and ESBi s Corby). These plants total c5.5gw, and would come in addition to those outlined in Figure 20. We assume c3.3gw of additional closures, on top of the 3.2GW of mothballed plant closing permanently. 3.4 LCPD will work to close coal-fired plants We expect to see c6.5gw of closures (c3.2gw of mothballed plant permanently closed) and another 3.3GW of less efficient plant Figure 21: Average hours run for coal-fired LCPD plants Figure 22: Running hours left of opted-out coal plant MW Dec-10 Dec-11 Years left* Still running on coal Didcot A 1,940 11,030 8, yrs Ferrybridge 1& ,500 8, yrs Cockenzie 1& ,885 2, yrs Cockenzie 3& ,520 3, yrs Kingsnorth 1,940 7,738 4, yrs 6,012 40,673 27, yrs Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Coal Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Converted to biomass Ironbridge** ,295 11, yrs Tilbury 7& ,614 7, yrs Tilbury 9& ,160 7, yrs 1,990 30,069 26, yrs * Assuming a c25% load factor ** Only some of the plant is burning biomass Source: Elexon, Company data Source: Elexon, Company data From a coal-fired power plant perspective, there is 28GW of plant on the system, of which c8gw does not have fitted flue gas desulphurisation, and which therefore is limited to c20,000 running hours across the inclusive period. In any event, the plant must close before December 2015, under UK laws. Around 2GW of these plants have taken the option to convert some or all of the capacity to biomass co-firing 12, and the units running on coal have just c3 years of running at current load factors (Figure 22). Unless the plants close for a year and fit emission reduction equipment at a cost of approaching 1bn, they must still close. Even if the law is changed, the plants may simply not be able to run for two reasons: The Large Combustion Plant Directive ( LCPD ) will work to close coal-fired power plants. In any event, these plants are old, and could be incapable of running reliably, even if special derogations are made 12 We believe these plant owners can divert biomass from European countries and so become eligible for UK 'ROC' subsidies and monetise attractive 'bark spreads' in the UK to maximise NPV. UK power generators 15

16 (1) Serviceability down: The plants will be an average c44 years old in 2015, and assetlife issues are already coming to the fore. These issues will be compounded because we think it unlikely the plants will have been maintained for high availability, given that owners originally expected them to close by Usually, low maintenance shows through in lower availability around five years after cutting capex. (2) Expense: Further to that, owing to higher (and increasing) fixed O&M costs, the output will likely be lower, and hence the fixed costs will be absorbed across a lower volume. 3.5 The Industrial Emissions Directive will significantly curtail much of the UK coal-fired fleet Figure 23: Requirements on coal plant for the industrial emissions directive Legislation LCPD 1 Industrial Emissions Directive Date Jan 2008 Dec 2015 Jan 2016 Dec 2023 Coverage SOx, NOx, Particulates SOx, NOx, Particulates Options for coal 1 Opt-in through complying: Opt-in through complying: plant owners <400mg/m3 for SO2 <200mg/m3 for SO2 <500mg/m3 for NOx <50mg/m3 for particulates <200mg/m3 for NOx <20mg/m3 for particulates Derogations were available Decision by < cumulative plant-by-plant limits for NOx and SO2 ( NERP ) 3 Opt out: 20,000hr operation (=> c29% load factor), close before Opt out: 17,500hr operation (=> c25% load factor); close before Derogations available: restricting Transitional Arrangements: Opt in by running to 2,000hours when fitting FGD July 2020, but subject to constraints on overall emissions. Similar to NERP Just as important as the Large Plant Combustion Directive ( ) is the Industrial Emissions Directive ( ) which will tighten regulation further still Source: DEFRA, Credit Suisse research 20GW of coal-fired generation out of 28GW opted-in and 8GW opted-out Our base case is that 10GW of coal plant opts-in and 10GW opts out Once the LCPD mentioned above ends, a new set of standards will take over the Industrial Emissions Directive. These rules are much tighter and require further capital investment. This will set new emissions regulations reducing greenhouse gas emissions (NOx and SO2) their implementation is imminent for UK power generation (Figure 23). It will impact all 20GW of coal plant that is allowed to remain open post 2015 and some gasfired plant Note that other European countries wither[?] already have the equipment fitted (Germany) or else have less affected coal (Spain, France and Scandinavia) hence this is very much a UK-centric issue UK power generators 16

17 Figure 24: Plants required to undertake capex to run unrestricted (i.e. not subject to volume constraints) in LCPD 2 Plant Owner Total units SCR units required Installed capacity (MW) Age (yrs) Notes Likely to run unrestricted (i.e. SCR to be installed) Drax 1-3 Drax 3 0 1, Shares stack with Units 4-6, hence not needed Drax 4-6 Drax 3 3** 1, To be fitted, depending upon biomass options Ratcliffe EON 4 3* 2, Currently being fitted as part of a 900m upgrade Total ,920 Questionable whether SCR will be installed Rugeley IPR 2 2* Not clear from speaking to management Longannet SPW 4 3* 2, Being studied as part of a portfolio of options Eggborough Various 4 3* 1, Only 2 units fitted with FGD, hence may require more Aberthaw RWE 3 2* 1, Considering fitting SCR. Final Investment Decision Total ,715 will only be taken if it meets investment criteria SCR not to be installed at present Fiddlers Ferry SSE FEED studies undertaken, not going ahead at present Ferrybridge SSE 4 n/a Studies not undertaken, no plans to fit at present Uskmouth SSE 3 2* Studies not undertaken, no plans to fit at present Cottam EDF 4 3* 2, Looking into all options, but few scenarios profitable West Burton EDF 4 3* 1, Looking into all options, but few scenarios profitable Total ,340 Total ,975 FGD = Flue Gas Desulphurisation; SCR = Selective Catalytic Reduction; * CS calculation, based upon a minimum of 2/3rds capacity being fitted ** Depends upon biomass plans; ***FEED=Front End Engineering Design Source: Company data, Credit Suisse research The plant will need to either: (i) fit further emissions reduction equipment (e.g. Selective Catalytic Reduction); (ii) limit itself to c17,500 running hours inclusive (implying a c25% load factor, versus c35 60% realised at present); or (iii) be subject to evertightening standards for 4.5 years under the Transitional National Plan, with an option to fit SCR later 14. Asset owners must make elections to the UK government by end Cost of fitting SCR is prohibitively expensive for many SCR is expensive. Each unit will cost at least c 70m, based upon company guidance and ranges given by Government. While plant-by-plant data on emissions, hence units required, are not available, our basic calculation is that c27 SCR units may be needed for all opted-in coal plants, and that the total cost for the UK power industry would be c 2bn. There will also be extra running costs from parasitic demand, potentially lower flexibility and higher O&M charges, which could further marginalise coal power plants. Only 6GW of coal plant owners have indicated they would will be compliant, in our view, but we assume 10GW. 3.6 Capacity payments only a distant possibility As part of the Electricity Market Reform, the government in December 2011 released its 'Technical Paper' on capacity payments. The paper supports a market-wide capacity market, but was short on detail. The exact mechanism (let alone the quantum of the payments) is yet to be finalised, but the salient points are: To become compliant with the Industrial Emissions Directive, the UK coal fleet will need c 2bn of capex. We doubt this will take place, and our base case is for just half the remaining fleet to be fitted with it (only c6gw out of 20GW has committed; Drax and EON) 14 DEFRA, the Environments Agency and the Welsh Assembly are due to issue a consultation on Draft Regulations early on in Some items - inlcuding emission limit values - are due to be reviewed by the EU by December 2013 UK power generators 17

18 Form: The capacity payments will be market-wide (albeit it is not clear whether plants already eligible for support will get it). Demand-side response may also be eligible. Government will set required capacity, and reverse auctions would be held. National Grid would administer the scheme, with monitoring from OFGEM and Government. Indicative costs: An impact assessment by the government has a best estimate of c 2.9bn of cost and 0.3bn of benefits (in 2009 money) across 20 years through to This would imply a drop in producer surplus of 5.5bn, and an increase in consumer surplus of 3.1bn; i.e. overall the economics would be less attractive to generators. Capacity payments are some way away, in our view Timing: Detailed design will take place from , with indications that the first auction would be in 2015, with secondary trading for four years, before the capacity would be deliverable by The potential is mixed. Capacity payments would increase supply of generation and reduce spreads, and there is no guarantee as to whether the utilities would be better off. That said, capacity payments would provide a fixed but at present uncertain cash flow, and some older plants with sunk costs could benefit. At this stage, we do not know enough to conclude whether capacity payments will be positive or negative for the sector (the costs above are built on a number of assumptions). We believe capacity payments appear more of a distant incentive for unprofitable plants to consider staying open to prevent a reserve margin squeeze mid-decade. Our view is that it will be three years before we have visibility on the quantum of capacity payments, and at least seven years before generators can begin to receive cash. Given the length of time and age of generation, this is too much, too far away. 3.7 Nuclear the key unknown, but on balance a downside risk In many countries (e.g. Germany, France and Japan) the big variable in reserve margins is nuclear generation: Magnox: Wylfa and Oldbury, where the last two Magnox reactors are situated, run out of fuel in the next two years, and will need to close. The AGR fleet: Performance has varied between c40twh and 68TWh p.a. in the last 13 years. EDF targets c55twh. An additional 13TWh (back to peak) would help to reduce reserve margins and EDF is making positive progress with the reactors (e.g. resolving Hot Box issues). However, the assets are older, and two plants are due to close in 2016 (we assume life extensions to 45 years). We do not see much material upside. New-build nuclear: EDF and Centrica are seeking a final investment decision by the end of 2012, but these reactors are unlikely to be on the system before 2019, and delays at Flamanville in France and Finland suggest it could take significantly longer. As a result of us already assuming a conservative scenario, we do not see the nuclear fleet as a key driver of UK reserve margins. 3.8 No reason to invest in new thermal generation Even if potential builders of new capacity are prepared to put aside the uncertainty on capacity payments, investment in new-build thermal power plants is unlikely in our opinion: Returns are better elsewhere: The key problem for diversified players, in our view, is that returns are so good elsewhere. For example, project-level returns for UK onshore wind are c9 12% real, and we estimate Scottish Transmission owners will be able to We see little reason to invest in new thermal generation UK power generators 18

19 realise a c6% real return for regulated networks under RIIO. These are the benchmark, in our view. CCGT equipment prices are stubbornly high: We understand from the companies that a two-unit (c900mw) CCGT would cost c 750/KW, declining to c 650/KW for a three-unit (c1,400mw) facility. This requires an all-in spark spread of >c 16/MWh. While we do forecast these spreads from 2016, it will be difficult for utilities to justify to an investment committee at a time when they are closing plants. Financial capacity limited: There are not many players that: (i) have progressed far enough in the planning process; (ii) have supply customers to balance risks; (iii) with different fuel hedges; and (iv) have shareholders able to look through weak spreads and uncertain capacity payments to sanction a c 700m merchant investment. Coal unlikely to get consent in the UK again: Given: (1) the Emissions Performance Standard effectively rules out new coal-fired generation without carbon capture storage ( CCS ); (2) CCS itself being a long way from commercial operations; and (3) public opposition to coal-fired generation (e.g. E.On s plans for Kings north that were ultimately scrapped), we think it unlikely that there will be any new coal facilities in the UK. It takes three years to construct a new CCGT, on top of the >5 years to obtain all necessary consents and fix the costs. If no plants are sanctioned in 2013, the earliest any new plant will arrive is We do not rule out the possibility of an opportunistic player sanctioning a new plant, but we doubt the big-six UK utilities will launch into a round of new-builds any time soon. 3.9 UK power consumption is structurally falling, but more slowly than supply cuts will be made Figure 25: Our power demand forecasts Figure 26: Changes in prices vs. changes in consumption Total demand (TWh) A 2002A 2004A 2006A 2008A 2010A 2012E 2014E 2016E 2018E Commercial and public sector (LHS) Industrial (ex. energy industry) LHS Household (LHS) Peak demand (GW) - RHS 2020E Peak demand (GW) 25% 20% 15% 10% 5% - (5%) (10%) (15%) 1972A 1975A 1978A 1981A 1984A 1987A 1990A 1993A 1996A 1999A 2002A 2005A Real price change (LHS) Y-O-Y change in consumption (RHS) 2008A 2011E (20%) (16%) (12%) (8%) (4%) - 4% 8% 12% Source: DECC, Credit Suisse research Source: DECC, Credit Suisse research UK power generators 19