6058532 European Utilities

UBS Investment Research

European Utilities

Renewables to wipe out 50% of profits

German renewables have crashed spot prices and spreads in just two yearsThe German renewables boom has quickly reshaped the central European (CE)1

power market. Solar is eliminating mid-day peaks, even when it is rainy. Wind iscrashing night-time spot prices. Coal and gas utilisation are down, and renewablesare now cutting into lignite volumes. And the situation is set to deteriorate.

Half to 2/3rds of central European generation EBITDA may be wiped out By 2020, we forecast CE wind capacity to grow by 2.4x and solar by 3.3x, with 60%of the additions in Germany. Renewables continue to displace coal and gas – though not to the extent that we forecast closures or a need for generic capacity payments.CO2 emissions should fall by a third, adding to the carbon market oversupply. Atinflation-adjusted commodity prices, we would see conventional generation EBITDAfalling by two-thirds, mainly due to lower margins on lignite and nuclear. However,an assumed carbon market pick-up should limit the fall to c50%.

Power prices will have to rise, but that could take a decade Higher power prices look inevitable, considering costs for new capacity are 50% above current prices. However, given the weak demand outlook, this would requireless renewables, widespread closures and a 3-4x higher CO2 price. As we do not see this happening near term, power prices may remain depressed for a decade.

Avoid generators with large nuclear and lignite exposure Our analysis is negative in particular for utilities with large nuclear and ligniteexposure. We downgrade RWE, CEZ and EDF to Sells, and reiterate our Sell ratingon Verbund. While we lower our E.ON and GDF estimates, we retain Buy ratings. Please see our series of individual stock notes, also published today.

Global Equity Research

Europe Including UK

Utilities

Sector Economics

19 July 2012

www.ubs.com/investmentresearch

Per Lekander

[email protected]

+33-14-888 32 96

Patrick Hummel, CFAAnalyst

[email protected]+41-44-239 79 23

Alberto GandolfiAnalyst

[email protected]+44-20-7568 3975

Stephen HuntAnalyst


Ignacio Perez CossioAssociate Analyst


1 By Central Europe we mean Germany, France, Belgium, Netherlands, Austria, Switzerland and Czech

Republic.

This report has been prepared by UBS Limited ANALYST CERTIFICATION AND REQUIRED DISCLOSURES BEGIN ON PAGE 38. UBS 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.

Chart 1: German renewables vs. demand in 2011 – average day Chart 2: German renewables vs. demand in 2020E - average day

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ab

mailto:[email protected]





European Utilities 19 July 2012

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Contents page

Investment summary 3 Current situation 4 Solar eliminates mid-day peaks 6

— Renewables are crashing prices .............................................................................8 Wind impact significant at night 9

— …but there are large daily variations ....................................................................9 — Renewables contribute little to reserve margins, but eases hydro.......................11 — Price and volume effects on other generation.....................................................11

By 2020 50-67% of profits gone 13 — Hourly simulation of the CE power market..........................................................13

Annual generation profiles Central Europe 2011, 2015, 2020 15 — Price collapses should become increasingly frequent.........................................17 — Profitability to fall by two-thirds assuming stable real fuel prices.........................20

No need for broad capacity payments 22 New capacity costs >€70/MWh 24 LT solar boom may get worse 26

— And cost trend is likely to continue .....................................................................26 — Rooftop solar can be cheaper than buying from utilities......................................27 — Southern Italy already at grid parity ....................................................................27 — Other regions could catch up within Germany ....................................................28

RWE 29 E.ON 30 Key Call: GDF Suez 31 CEZ Group 32 Verbund AG 33 EDF 34 Fortum 35 Appendix: Methodology 36

Per Lekander

[email protected]

+33-14-888 32 96

Patrick Hummel, CFAAnalyst

[email protected]+41-44-239 79 23

Alberto GandolfiAnalyst


Stephen HuntAnalyst


Ignacio Perez CossioAssociate Analyst



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Investment summary Germany has seen a remarkable renewable energy boom over the last decade: the country now has more than 60GW of wind and solar capacity, one-third of its total capacity. Some 32GW have been installed since 2008. In this note, we analyze how subsidized renewables will affect generation markets out to 2020.

German renewables boom reshaping central European power market

The market impact of renewables has accelerated over the last two years, and can now be seen across central Europe. Utilities have historically made most profits during the day, as volumes and prices are higher. However, solar is already shaving away most of this upside. Wind is creating frequent price crashes, in particular during winter nights and weekends. So far, renewables have mainly replaced gas and coal generation, but we are now also starting to see an impact on higher-margin baseload plants, in particular lignite.

Conventional profits could be down by a half to two-thirds by 2020

We forecast around 10GW of annual renewables additions to 2020, in line with the recent trend. Germany’s share gradually declines, but remains in excess of 50%. Coal and gas load factors continue to decline, but most plants remain cashflow positive, so we foresee limited closures. We expect power prices/generation spreads to gradually decline by €5/MWh, as price crashes become more frequent. Including the effect of lower volumes, the total EBTIDA pool for CE generation could fall by 50%. The drop would be two-thirds if we did not assume (as we do) a doubling of the CO2 price during 2015-20.

Recovery will come, but higher power prices could take a decade

We estimate that the full cost of new generation capacity is €60-110/MWh, depending on the technology, so a power price below €50/MWh is not sustainable long term. However, considering the weak demand outlook, power prices are unlikely to increase until we see less subsidised renewables, widespread capacity closures and a 3-4x higher CO2 price. We do not expect any of the above over the next five years; it could thus take up to a decade before prices recover.

Avoid European power generation, in particular those with nuclear and lignite exposure

Our analysis is negative for all central European power generators, but particularly so for lignite and nuclear baseload producers. Table 1 below summarises our rating, price target and estimate changes.

Table 1: Central European utilities – Changes to ratings, price targets and estimates

Company Share price* New Rating Old Rating New PT Old PT 2012 P/E 2012 DY 2015 EPS % change vs old 2012-2015 EPS CAGR

E.ON €18.0 Buy Buy €19.0 €17.0 7.9x 6.1% 2.0 0.0% 8%

RWE €34.2 Sell Neutral €28.0 €30.0 8.2x 5.9% 4.0 -6.5% -2%

CEZ Group CZK 728 Sell Neutral CZK 660 CZK 740 9.4x 6.2% 70.9 -22.5% -3%

GDF Suez €18.1 Buy Buy €21.0 €22.0 11.2x 8.3% 2.1 -6.5% 8%

EDF €17.5 Sell Neutral €16.0 €17.0 8.8x 6.6% 2.1 -14.7% 2%

Verbund AG €17.6 Sell Sell €16.0 €18.0 15.1x 3.1% 1.3 -24.2% 3%

Source: UBS estimates, *Current prices as of 18 July 2012

Renewables are removing peaks and creating crashes

Central European power generation EBITDA could fall 50%

Little prospect of recovery until less subsidised renewables, capacity closures and a 3-4x higher CO2 price

Downgrading RWE, CEZ and EDF to Sell from Neutral


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Table 2: Exposure to falling power prices and valuation

Company Rating

CE generation

% of total EBITDA

Share of baseload

generation

EPS sensitivity to 10% decline in power price

Net debt/EBITD

A 2013E PE 2013E

Adj. EPS CAGR

2012-15E Key earnings drivers 2012-16E

E.ON Buy 20% 60% 11% 2.8x 10.9x 8% Cost cutting (+), growth capex (+), CO2 (-), Power price (-)

RWE Sell 33% 65% 21% 3.4x 8.1x -2% Cost cutting (+), gas turnaround (+), CO2 (-), Power price (-)

GDF Suez Buy 13% 42% 4.5% 2.4x 10.2x 8% IPR (+), Gas Renegotiations (+), LNG (+), Power Price (-)

EDF Sell 41% 90% 28% 2.6x 8.8x 2% Increase in regulated tariffs (+), Nuclear cost & availability (-)

Fortum Sell 65% 95% 15% 2.9x 10.7x -10% Russia (+), Power price (-)

CEZ Sell 62% 93% 17% 2.1x 9.4x -3% Renewables (+), CO2 (-), Power price (-)

Verbund Sell 91% 95% 26% 4.3x 14.3x 3% International associates (+), Power price (-)

Source: UBS estimates


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Current situation Germany has experienced a remarkable boom in renewable capacity over recent years. Wind energy additions have been growing fairly steadily – by around 2GW per year – whereas solar has gone through a massive boom, starting in 2008, with 5-8GW of annual additions. Today there is c30GW of installed capacity of each technology in Germany. Solar and wind combined makes up one-third of Germany’s total 180GW installed capacity, and its 74TWh of output is 13% of the country’s total generation output. For other central European countries, there has not yet been a similar boom. But the interconnections between countries mean that the German renewables boom is affecting the market throughout the entire CE power region.

Wind and solar today make up 7.2% of total installed capacity in central Europe and less than 3% of total output. Table 3 shows the wind and solar capacity in central Europe since 2006, breaking out Germany and the other countries.1

Table 3: Renewables growth in central Europe has been driven by Germany

2006 2007 2008 2009 2010 2011 2012

Wind capacity (MW) 24,819 27,593 30,950 34,352 37,195 40,452 44,558

- growth (yoy %) 16% 11% 12% 11% 8% 9% 10%

Wind production (TWh) 38 50 53 54 55 68 74

- of which Germany 81% 80% 76% 71% 68% 68% 67%

Solar capacity (MW) 2,965 3,983 5,666 11,106 21,277 31,279 37,769

- growth (yoy %) 83% 34% 42% 96% 92% 47% 21%

Solar production (TWh) 2 3 5 7 14 25 34

- of which Germany 96% 96% 96% 92% 86% 78% 72%

Source: Eurostat, Euromonitor, UBS estimates

In the following sections, we present our analysis of how renewables are affecting the German and central European markets. Our key conclusions are:

Solar is more reliable than perceived, consistently shaving the mid-day peaks from March to October. It is less sensitive to bad weather than expected, and is delivering between 8GW and 22GW in the daytime during the spring and summer months.

Wind is much more intermittent, generating less than 2.5GW of output for around a third of the hours. The output also seems to have a larger negative effect on pricing, which we think can be explained by its intermittency, which makes planning harder and leads to oversupply.

From a reserve margin perspective, renewables are poor contributors, as the absolute peaks tend to happen after sunset on days with low wind speeds. Wind does, however, have higher average output during the winter and is hence contributing well to overall demand. Similarly, solar seems to be fairly good at daytime peaks, as cold periods normally coincide with clear skies.

1 We define Central Europe as Germany, Benelux, France, Austria, Switzerland and the Czech Republic.

The interconnections mean that the German renewables boom is affecting the market throughout the entire CE power region


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Solar eliminates mid-day peaks Our analysis of hourly solar output shows that solar is surprisingly stable, with mid-day output in excess of 8GW even on rainy spring/summer days. So far solar has just reduced mid-day peak premiums, but we see an increasing risk of price collapses going forward.

Solar is generating 10-16GW on average from March to October

Our analysis of European generation data shows that the mid-day output from solar in Germany is now above 10GW on average from March to October, and is hence already contributing more to peak daytime demand than the remaining nuclear fleet. Chart 3 shows the average output profile for the first six months of 2012.

Chart 3: From March to October solar output is 10-16GW mid-day, and growing

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Given the current run-rate of 7GW new solar capacity per year, the average peak output will continue to climb by around 2.5-4.0GW per annum, for the 10 months where solar has the most stable contribution. Based on these findings, it is clear to us that contracting peak-to-base spreads due to solar PV is not only a summer phenomena.

Even on rainy summer days solar produces 8GW+

Another misconception related to solar, in our view, is the perception that solar needs clear skies to make a meaningful contribution to overall power demand. While solar production of course varies with the weather, our analysis of German generation data shows that solar is remarkably stable, with minimum daytime production in excess of 8GW even on the rainiest spring/summer days, as shown in Chart 4.

Contracting peak-to-base spreads due to solar PV is not only a summer phenomena


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Chart 4: Solar production at 1pm in Germany, May-June 2012

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Peak prices could contract further

The German solar boom has so far reduced the peak-to-base spreads at mid-day, while premiums in the morning and afternoon remain unaffected. The chart below shows that spot prices are typically higher in the morning and in the afternoon.

Chart 5: Average spot price curve – Germany, 2011

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We expect mid-day prices to deteriorate further in future, as Germany moves towards its 52GW solar target. If one assumes that the mid-day spreads will be eliminated completely, that would have a negative impact of around €3.5/MWh on the average price over the day, as shown in our calculation in Table 4.

If mid-day spreads are eliminated completely, that would have a negative impact of c€3.5/MWh on average price


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Table 4: Impact on achieved prices if peak flattens

Impact of flat price curve €/MWh

Peak-base spread 12

Hours 10

Months (March-November) 9

Price impact 3.7

Source: Bloomberg, UBS estimates

Renewables are crashing prices In Table 5 we analyze the relationship between renewables and pricing. We see how much of the hourly demand is covered by solar and show the average spot price for these hours. For the periods when solar production is marginal, there is not a big price difference; however, when solar covers more than 25% of total demand, we see a rapid decline in the price. This is mainly occurring during weekends with lower demand.

Table 5: Solar output as percentage of demand, 10am to 3pm

Solar as % of total demand Probability Price (€/MWh)

<10% 43% 53.9

10-15% 26% 55.5

15-20% 17% 52.5

20-30% 12% 42.7

30-40% 2% 36.4

>40% 0% 17.0

Source: Bloomberg, TenneT, 50Hertz, Amprion, Transnet BW, UBS estimates

When solar covers more than 25% of total demand, we see a rapid decline in the price


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Wind impact significant at night Wind output is twice as high in the winter months…

Chart 6 shows the average wind generation output through the day for January-June 2012. Wind generation is much higher during the winter months and lowest during the summer. Thus there is a positive correlation between demand and wind generation.

Chart 6: Wind generation is highest in winter, but “waste” production at night

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…but there are large daily variations Unlike solar, where the difference between good and bad days is around 2x, it is quite frequent that wind contributes close to nothing to the total generation output. This is particularly common during the spring and summer months. The distribution of German wind production at 1pm in the first six months of 2012 is shown in the chart below. For 59 days, wind contributed less than 2.5GW, while it was below 5GW for another 38 days. Hence, for more than half of the days wind output was less than 17% of the installed capacity of the fleet.

Chart 7: Wind production at 1pm in Germany, January-June 2012

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Positive correlation between demand and wind generation

For more than half of the days wind output was less than 17% of the installed capacity of the fleet


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Table 6 shows the relationship between wind production and German spot prices during the day. Table 7 shows the same during the night. High wind output seems to have an even larger negative price effect than solar output. We believe that this is due to the volatility: there is a lot of ramping up and down when wind fluctuates, making planning very difficult and leading to overcapacity.

Table 6: Wind output/demand, 10am to 3pm Table 7: Wind output/demand, 1am to 5am

Wind as % of total demand Probability Price (€/MWh)

<5% 45% 39.2

5-10% 21% 34.7

10-15% 13% 34.0

15-20% 10% 30.6

20-30% 8% 25.3

>30% 3% 12.3

Wind as % of total demand Probability Price (€/MWh)

<5% 26% 39.9

5-10% 28% 36.2

10-15% 18% 35.2

15-20% 12% 32.6

20-30% 10% 28.2

>30% 7% 24.6

Source: Bloomberg, TenneT, 50Hertz, Amprion, Transnet BW, UBS estimates Source: Bloomberg, TenneT, 50Hertz, Amprion, Transnet BW, UBS estimates

High wind output seems to have an even larger negative price effect than solar output, owing to the volatility


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Renewables contribute little to reserve margins, but eases hydro For extreme winter peaks, renewables contribute only a few percentage points of total demand, as wind speeds tend to be low when it is really cold. In most cases, the peak tends to occur in late afternoon, when solar does not contribute either. We still think there may be a positive indirect effect from solar. Cold days tend to be correlated with clear skies, so solar saves hydro generation during the day, potentially allowing higher hydro production during the evening peak. However, overall the peak contribution is clearly low. Chart 8 shows the generation output during the highest-demand day during the 2011/12 winter. As shown, solar contributed close to 10GW mid-day and hence resulted in a more concentrated peak for conventional generators.

Chart 8: Production mix at peak demand in Germany, 7 February 2012 (MW)

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Price and volume effects on other generation Chart 9 shows the average generation mix per hour for the four-month period from March to June 2012 in Germany. Renewables, and in particular solar, flattened the peak output for conventional generation, replacing generation volume which was previously covered by coal and gas. Overall, we see a c11% negative impact on coal and gas load factors from this ‘peak-shaving’, and also a negative pricing effect.

We see a c11% negative impact on coal and gas load factors from ‘peak-shaving’, and a negative pricing effect


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Chart 9: Solar has flattened mid-day peak – average German generation March-June 2012

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By 2020 50-67% of profits gone While the recent cut in subsidies for German solar systems might temporarily slow the pace of growth seen in recent years, we estimate that solar output in central Europe will more than triple by 2020. Also, wind development is poised for strong growth, with large offshore projects being pushed through the pipeline due to highly lucrative feed-in schemes.

While the German domination should ease, we still expect Germany to contribute around 60% of the total renewables output in central Europe in 2020. The second-largest market will be France, where we expect more than 20GW of new solar and wind capacity to be added.

Table 8: Output from wind and solar set to more than double by 2020

2011 2012 2013 2014 2015 2020

Wind capacity (MW) 40,452 44,558 48,924 53,246 57,504 83,731

Wind production (TWh) 68 74 84 92 103 165

- of which Germany 68% 67% 67% 66% 66% 58%

Solar capacity (MW) 31,279 37,769 43,338 48,938 54,538 82,338

Solar production (TWh) 25 34 42 47 53 82

- of which Germany 78% 72% 73% 72% 70% 67%


Hourly simulation of the CE power market Based on a detailed simulation of hourly demand, generation and prices until 2020, we conclude that the renewables boom in central Europe is creating further downside risk to power generation profitability. Our simulation is created by combining actual hourly load data for each country with detailed data on solar and wind output in Germany (which we have scaled up to match the capacity of the entire region). Based on this data and some assumptions on the cash cost and flexibility of different technologies, we have simulated hourly prices and output from different generation sources in central Europe out to 2020. A more detailed description of our simulation methodology is given in Appendix 1.

Results show downside to baseload price and lower production from lignite and nuclear

While coal and gas have so far taken the largest hit, nuclear and lignite profitability and load factors look set to be worst affected by 2020. In a scenario where commodity prices increase in line with inflation, we expect lignite volumes to decrease by 21% and nuclear by 9%. We forecast the average baseload spot price to stay at around €42-44/MWh until the end of the decade.

We see solar output in central Europe more than tripling by 2020, and wind development is poised for strong growth

The renewables boom in central Europe is creating further downside risk to power generation profitability


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Table 9: Simulated generation output for central Europe

Output (TWh) 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Consumption 1534 1535 1520 1520 1522 1526 1528 1531 1534 1537

Wind 68 74 84 92 103 113 128 139 154 165

Hydro/other renewables/CHP

302 341 338 342 345 350 349 354 354 357

Nuclear 630 617 613 609 610 604 602 591 587 575

Lignite 194 192 189 179 175 171 165 161 155 152

Solar 25 34 42 48 53 59 65 71 77 83

Coal 214 202 199 198 184 175 167 162 156 155

CCGT 71 56 41 39 38 40 39 39 37 38

Gas 25 17 12 12 12 12 12 12 12 12

Oil 6 2 1 1 2 2 2 2 2 2

Price (€/MWh) 52.2 42.6 41.2 41.8 42.1 42.7 42.9 43.5 43.5 44.2

Source: ENTSOE, UBS estimates

The changes in output shown in the table above include around 8GW of net thermal retirements over the period (40GW retirements). However, if one looks at the forecast load factors, it is clear that output also will fall on a relative basis.

Chart 10: Load factors for thermal generation should fall despite capacity retirements

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Annual generation profiles Central Europe 2011, 2015, 2020 The charts below illustrate how the average load curve in central Europe will be impacted by the increasing output from solar and wind. While the renewables boom has already resulted in deteriorating market conditions, it is clear that the situation is likely to get much worse over the coming years

Chart 11: Generation profile, 2011

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Chart 12: Generation profile, 2015E

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Our modelling shows that by 2020, lignite on average will need to cycle during the night and also during midday as the massive increase in solar output will invert the midday peaks.

Renewables boom likely to make a deteriorating situation worse


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Chart 13: Generation profile, 2020E

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Lignite and nuclear should increasingly become price-setters

The main driver of weak power prices and spreads can be illustrated through the changes to the merit order illustrated in the chart below. In 2020 the average daytime demand should only have a marginal need for coal, which creates significant downside risks to prices due to the volatile output from renewables.

Chart 14: Merit order implies larger downside risks by 2020, while upside will be lower

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In current market conditions prices are set by gas, coal and oil more than 85% of the time. With the growing contribution from renewables, this situation should change dramatically towards 2020 when these technologies should be the price-setters around 65% of the time.


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Chart 15: 2011 Marginal technologies (% of total hours) Chart 16: 2020 Marginal technologies (% of total hours)

COAL34%

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Source: UBS estimates Source: UBS estimates

Looking at the pie charts above, it is also worth noting that low-cost nuclear and lignite will mainly steal production hours from high-cost oil and gas. The effect on the spot price distribution is shown in the table below.

Table 10: Price risk shifts to the downside

Price distribution (€/MWh) 2011 2020 2020 vs 2011

0 - 40 15% 38% 23%

40 - 60 65% 48% -16%

60 - 80 14% 10% -3%

80 - + 7% 3% -4%

Total 100% 100% 0%


Price collapses should become increasingly frequent Based on our forecasts for renewable capacity additions, the number of hours where wind and solar cover more than 20% of demand is going to increase rapidly over the next 3-8 years. This is, in our view, going to have a negative impact on achieved power prices, as renewables appear to push down spot prices when it covers more than 20-30% of total demand. The tables below show the distribution of daytime hours (10am to 4pm) where wind and solar output reach different levels of total demand.

Wind and solar set for further medium-term growth


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Table 11: Probability of price collapse caused by wind output likely to increase

Wind as % of total demand Price (€/MWh) 2011/12 2015 2020

<5% 39.2 45% 36% 27%

5-10% 34.7 21% 23% 22%

10-15% 34.0 13% 12% 12%

15-20% 30.6 10% 9% 9%

20-30% 25.3 8% 15% 15%

>30% 12.3 3% 7% 15%

Source: TenneT, 50Hertz, Amprion, Transnet BW, Bloomberg, UBS estimates

Compared to wind, solar seems to have a less negative impact on prices when output is relatively modest. However, when solar goes beyond 20% of output, it starts to have significant negative impact. So far, these hours have been limited to around 14% of the year, but in 2015 they should increase to around 44%. In 2020 solar output is likely to be in excess of 20% of German demand on more than 50% of days. While it is not clear if the relationship between renewables output and prices can be applied directly to forecast the future impact on prices (or if generators will somehow learn to adapt to the growing renewables output), the increase in days when solar and wind contribute significantly to total demand represents a large downside risk to power prices, in our view.

Table 12: Solar will gradually remove premium prices during daytime

Solar as % of total demand Price (€/MWh) 2011/12 2015 2020

<10% 53.9 43% 26% 17%

10-15% 55.5 26% 13% 10%

15-20% 52.5 17% 17% 10%

20-30% 42.7 12% 34% 27%

30-40% 36.4 2% 10% 26%

>40% 17.0 0% 0% 8%

Source: TenneT, 50Hertz, Amprion, Transnet BW, Bloomberg, UBS estimates

Reserve margin on a regional level still decent

On a regional basis the reserve margin is still going to be around 10%, even if we expect around 40GW of closures by 2020. While in normal market conditions this is within a range where decent profitability is achievable, the concept of a reserve margin becomes increasingly misleading, as it excludes the average availability of wind and solar, and hence is only representative as a worst-case indicator of system stability.

Increase in days when solar and wind contribute significantly to total demand represents a key risk to power prices, in our view


UBS 19

Chart 17: Reserve margins in central Europe

11% 11%

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Source: UBS estimates, ENTSOE

Carbon emissions likely to fall faster than ETS target

One of the side-effects of lower load factors for lignite and coal is that we expect carbon emissions to fall an average of 3.8% per annum throughout the rest of the decade. This will, in our view, limit any recovery in the carbon price (as the annual reduction is falling faster than the 1.74% emission reduction rate in ETS). Based on this result it is also clear that a simple set-aside of allowances is unlikely to result in permanently higher carbon prices, and that a structural change is required to restore the balance of the ETS mechanism.

Chart 18: Carbon emissions from power sector should decline by c3.8% per annum

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We expect carbon emissions to fall an average of 3.8% pa until 2020 – faster than the 1.7% emission reduction rate


UBS 20

Profitability to fall by two-thirds assuming stable real fuel prices Looking at the combined profitability of the power generation sector, we expect combined EBITDA to fall from around €14bn in 2011 to less than €5bn in 2020 (excluding the French nuclear). €4.3bn of this can be attributed to the loss of free carbon allowances, while the remaining €10bn is due to deteriorating margins caused by growing solar and wind output and near-flat demand.

Table 13: Generation profitability, central Europe

2011A 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Weighted average price (€/MWh) 58 48 47 48 48 50 50 52 52 53

Forward premium 2.0 5.0 5.0 4.0 3.0 2.5 2.5 2.5 2.5 2.5

Hedging -1 0 2 1 0 0 0 0 0 0

Average overnight cash cost (€/MWh)

-36 -29 -30 -30 -31 -32 -32 -33 -33 -34

Fixed operating expenses (€/MWh)

-10 -11 -11 -11 -11 -12 -12 -12 -12 -12

Generation margin (€/MWh) 14 13 13 11 9 9 9 9 9 9

Thermal volume (TWh) 692 649 622 608 590 563 546 529 513 498

EBITDA (€bn) 13.7 11.3 8.0 6.7 5.5 5.1 5.0 5.0 4.6 4.6

% growth -18% -30% -16% -18% -6% -3% 0% -7% 0%


In terms of individual technologies, our simulation clearly pinpoints nuclear and lignite as the two big losers, as we see EBITDA/GW halving over the next 2-4 years.

Chart 19: Profitability of nuclear/lignite to halve Chart 20: Close to zero EBITDA for coal and gas generation

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UBS 21

Simulation assumes fuel prices increasing with inflation, but flat costs

The assumptions in our simulation are based on unchanged real commodity prices. In terms of fixed costs, we assume these remain flat as we believe ongoing cost-cutting programmes could offset the inflationary effect. Our fuel price assumptions are outlined in the table below.

Table 14: Fuel price assumptions

Fuel price assumptions 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Carbon (€/t) 11 7 8 8 8 8 9 9 9 9

Coal (€/t) 92 72 73 75 76 78 79 81 83 84

Gas (€/MWht) 23 24 24 25 25 26 26 27 28 28

Oil (€/barrel) 81 80 82 83 85 87 88 90 92 94


Carbon recovery looks unlikely but could soften the fall

While we do not currently see any carbon price upside, we realise that over the longer term a structural solution could lead to higher carbon prices. In order to take a balanced risk approach, we assume that carbon will remain at around €7/tonne throughout 2014, and then gradually increase to €15/tonne by 2020. In this scenario the downside would be more limited for nuclear, while lignite and coal profitability would be hit even harder.

Chart 21: Nuclear downside more limited if carbon recovers Chart 22: Carbon prices will shift some profit to CCGTs

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UBS 22

No need for broad capacity payments A common argument brought forward is that the renewables boom is creating an unsustainable situation for thermal plants, and thus will lead to significant plant closures or capacity payments. Our analysis does not support this argument. We believe there is confusion between baseload spreads and the spreads that plants actually achieve. Table 15 below calculates what spread plants will need in order to cover their fixed operating costs. We estimate that both coal and gas plants will need around €15/MWh at the average load factors we forecast for 2020.

Table 15: Required spreads for coal and gas generation

Coal Gas

Staff cost (k€/y) 90 90

Maintenance cost ( €/kW/y) 40 15

Staff (people/GW) 80 40

Staff cost (€/kW/y) 7 4

Load factor 35% 15%

Operating cost (€/MWh) 15.4 14.2


This is not significantly different from what we expect the assets to achieve given that they operate during the best operating hours. The plants will not make much money, but they will not be so loss-making that closure will be a simple decision, and any such decision would, in any case, be subject to a great deal of scrutiny from regulators and competition authorities, in our view. We could still see capacity payments being introduced, but these would more likely be for plants that are considered ‘must-run’ for grid purposes, for instance in areas with significant nuclear closures.

Economics of “zombie plants”

Looking at the detail of our simulation output, we find that a CCGT will manage to offset the large decrease in load factors through higher achieved prices, and with a simulated clean spark spread of c€20/MWh we think most of the central European CCGT fleet will be able to cover their cash costs. Considering that most of these plants still have significant balance sheet and option values, we think it is unlikely that owners will engage in large-scale closures.

Plants unlikely to be sufficiently loss-making to warrant closure


UBS 23

Table 16: CCGT profitability

CCGT 2011 2020

Hours 2473 1293

Utilization 28% 15%

Achieved price 74 79

Fuel cost 49.4 58.7

Achieved spread 25 20

Gross profit (€/MW) 61370 25772


Based on a similar analysis for dark coal stations, we reach the same conclusion, and expect coal stations to be able to generate similar gross profits as they did in 2011 (when high coal prices weighed on dark spreads).

Table 17: Coal profitability

COAL 2011 2020

Hours 4751 3368

Utilization 54% 38%

Achieved price 62 63

Fuel cost 47.7 43.2

Achieved spread 14 20

Gross profit (€/MW) 68832 66987



UBS 24

New capacity costs >€70/MWh Chart 23 shows our forecast for full cost of new capacity, indicating that current unsubsidised costs are 50% higher than the current power price, and our forecast for around €45/MWh by 2020 is around half the new-build costs (detailed calculations are shown in appendix C). Building new generation capacity without subsidies would therefore be highly value-erosive.

Chart 23: Estimates of full new entrant cost, split by technology (€/MWh)

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It also looks likely that eventually power prices would need to increase to reflect these high costs. However, we doubt that new entrant costs are the best forecast for long-term power prices, for several reasons:

As long as renewables get subsidised and keep growing, irrespective of the supply/demand balance in the system, there is structural oversupply.

Should the German government decide to introduce capacity payments or another form of operating subsidy, this would keep supply in the system and power prices low.

Another topic under discussion is how to incentivise new clean conventional capacity (CCGTs) through direct investment subsidies. This would lower the minimum power price required, ie, new power plants would also be economical below (unsubsidised) new entrant cost.

Summing up, we think it is very unlikely that free market forces in the near term can drive power prices up to new entrant cost, due to government/regulatory intervention. Even if such an unlikely scenario materialises, we think it could trigger government action in the form of new/higher taxes on windfall profits made with the fully depreciated baseload cash cows (nuclear, lignite, hydro stations).

It should also be noted that renewables will not become competitive without subsidies on a utility-scale basis. We do not see any meaningful further learning curve in wind power. Despite the expected steep decline in solar generation costs, plants will not be profitable as the economic value of solar power will approach zero. This is because of the increasing oversupply during

Building new generation capacity without subsidies would be highly value-erosive

Government/regulatory intervention means free market forces very unlikely to drive power prices up to new entrant cost in the near term


UBS 25

noon/afternoon hours, when solar reaches its maximum production. The situation is different on the retail level, as it makes sense for ratepayers to replace electricity from the grid with their own solar generation.


UBS 26

LT solar boom may get worse Before the financial crisis, solar PV module prices enjoyed a period of relative stability as silicon supply failed to keep up with increasing demand. In recent years this has reversed as a massive increase in production capacity has led to oversupply in the industry. This, combined with real efficiency improvements, has resulted in a sharply falling cost curve for PV systems: fully installed rooftop PV systems in Germany today cost around c60% of what they did four years ago.

Chart 24: Average price of fully installed rooftop PV systems

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And cost trend is likely to continue Looking at the pipeline of new technologies and announced cost targets of the main producers, it is likely that module costs will continue to fall by at least 5-10% per annum over the next few years.

Chart 25: First Solar cost targets as of Q1 12

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We estimate that utility-scale solar in Germany will fall to around €1000/kWp by 2015, with prices below €800/kWp by 2020. This should massively reduce

Rooftop PV systems in Germany today cost c60% less than four years ago


UBS 27

the need for feed-in tariffs and likely make solar PV competitive as a source of peak supply in sunny parts of the world.

Rooftop solar can be cheaper than buying from utilities Solar development in Germany has so far been fuelled by attractive subsidies for utilities, and by home-owners and the commercial sector being willing to install solar panels on their rooftops. In recent years, the cost of solar has, however, been falling much quicker than feed-in tariffs, resulting in additions massively overshooting official targets. The German government (like its Italian, Spanish and UK counterparts) has therefore announced several rounds of subsidy cuts.

At current cost levels, it can make a lot of sense for homeowners and businesses to install rooftop PV systems, even if subsides are cut, as long as the solar power produced can be used to reduce energy bills. In southern Europe the payback period is currently less than eight years, versus 8-10 years in Germany. As we expect solar economics to continue to improve, we also see a significant risk that the ongoing solar boom may be increasingly hard to stop.

Table 18: Payback time of rooftop solar if used to cut energy bills (no feed in profits)

Country Investment

(€/kWh/year) Residential tariff

(€cent/kWh) Payback

period (yr) Commercial tariff

(€cent/kWh) Payback

period (yr)

Spain 1.30 0.20 6.4 0.14 7.7

Italy 1.47 0.20 7.2 0.25 4.8

France 1.68 0.14 11.9 0.11 13.1

Germany 2.24 0.25 8.8 0.20 9.5

UK 2.29 0.15 15.2 0.12 16.2

Denmark 2.41 0.29 8.2 0.21 9.8

Source: Eurostat, BSW-Solar, UBS estimates

In the US there are already emerging signs of such a development, with solar installers offering homeowners the option to lease a PV system at rates lower than the retail tariffs charged by regional utilities. Also, if governments would introduce net metering of residential PV systems, solar PV would be likely to continue to grow at a strong pace for the rest of the decade as the reduction in energy bills would work as an economic incentive to install rooftop systems.

Southern Italy already at grid parity The cost of utility-scale solar is also declining slowly towards grid parity in regions with both excellent solar conditions and high wholesale power prices. In Europe we estimate that this is already the case for Sicily, where daytime power prices averaged €106/MWh in 2011 and solar can achieve load factors in the range of 16-18%.

Solar costs still attractive for domestic and commercial markets, even if subsidies are cut

We estimate solar already at grid parity in Sicily


UBS 28

Table 19: Solar PV utility scale – Sicily

Value Unit Comment

Cost 1400 €/kWp First solar estimates €1215/kWp in 2012

Load factor 17.7% Net of 20% system losses

OPEX 10 €/MWh

Power price 100 €/MWh Average 9am-4pm prices in 2011 was €106/MWh

Pre tax IRR 8.6% Unlevered, 25 year, 1 year construction


Other regions could catch up within Germany For the rest of the European continent, solar PV still relies on subsidies to be economical for developers. Depending on what happens to gas prices and peak-to-base spreads, solar might reach grid-parity in the most favourable locations in Spain within 3-5 years, though we don’t expect solar to reach grid parity in northern Europe before the end of the decade. Another factor that is likely to limit unsubsidised solar development in central Europe is the fact that the German solar boom has already depressed daytime spreads, which impairs the economics of utility-scale solar projects.

Table 20: Levelised cost of solar for power generation by country2

County Load factor 2012 2014 2016 2020

Spain 19.4% 86.5 74.4 65.3 56.2

Italy 17.1% 97.0 83.3 73.0 62.6

France 14.8% 110.8 94.9 83.0 71.1

Germany 10.8% 148.8 127.1 110.8 94.5

UK 10.6% 152.6 130.3 113.6 96.9

Denmark 10.3% 156.7 133.7 116.5 99.3

Cost (€/kWp) 1300 1100 950 800

Annual cost decline -8.0% -7.1% -4.2%

Source: UBS estimates, PVGIS

We would like to thank Eirik Hogner for his assistance in creating this research report.

2 Assumed €5/MWh OPEX, 10% cost of equity, 5% cost of debt, 28% tax rate

…with parts of Spain to follow in medium term


UBS 29

ab


RWE

No earnings growth until 2020 – Sell

We see zero earnings growth until 2020 due to negative generation outlookFollowing our findings in today’s sector note Renewables to wipe out 50% of CEprofits, we expect RWE to lose €1.0bn of its German power generation EBITDA by 2020, due to lower baseload prices and decreasing lignite and nucleargeneration on the back of renewables growth. This trend offsets the cost-cutting benefits and organic growth in other divisions, leaving 2020E EPS exactly on the2013E level (€3.8 adjusted for disposals). We cut 2014-16E EPS by 3-15%.

Gearing could prove too high in low power price environment In such a scenario, we think cash generation gearing remains a concern. Netdebt/EBITDA, even after not-yet-executed disposals, remains around 3.0x. This could increase dividend risk and/or limit future growth, and it might prove too highfor a credit rating in the A range given RWE’s high commodities exposure.

Not excessively valued, but 15-20% downside to cons. and writedown risk The valuation discount to peers turns into a premium over time as RWE trades on10x PE 2015E (new estimates). And long-term earnings growth is worse. We seec15-20% downside to 2014/15E consensus. As RWE invests €6.8bn in new coal/CCGT plants in CE, we see risk of significant write-downs. In terms of upcoming newsflow, we take a cautious stance for the coming months (no largedisposals expected, credit rating risk).

Valuation – PT cut to €28, downgrade to Sell Our reduced €28 PT (from €30) reflects the more bearish power generationoutlook. It is based on an absolute SOTP model. We prefer E.ON over RWE.

Highlights (€m) 12/10 12/11 12/12E 12/13E 12/14ERevenues 53,320 51,686 55,422 57,088 58,910EBIT (UBS) 7,681 5,814 5,820 6,051 5,959Net Income (UBS) 3,752 2,479 2,572 2,579 2,551EPS (UBS, €) 7.03 4.60 4.19 4.20 4.16Net DPS (UBS, €) 3.50 2.00 2.00 2.00 2.00 Profitability & Valuation 5-yr hist av. 12/11 12/12E 12/13E 12/14EEBIT margin % 14.0 11.2 10.5 10.6 10.1ROIC (EBIT) % 28.5 19.2 18.1 17.4 16.4EV/EBITDA (core) x 6.8 6.4 6.5 6.3 6.3PE (UBS) x 10.6 8.2 8.2 8.1 8.2Net dividend yield % 5.4 5.3 5.9 5.9 5.9 Source: Company accounts, Thomson Reuters, UBS estimates. (UBS) valuations are stated before goodwill, exceptionals and other special items. Valuations: based on an average share price that year, (E): based on a share price of €34.15 on 18 Jul 2012 21:40 BST Patrick Hummel, CFA Analyst [email protected] +41-44-239 79 23

Per Lekander Analyst [email protected] +33-14-888 32 96

Global Equity Research Germany

Electric Utilities

12-month rating Sell Prior: Neutral 12m price target €28.00/US$34.35 Prior: €30.00/US$36.80

Price €34.15/US$41.77 (ADR) RIC: RWEG.DE BBG: RWE GR

Trading data (local/US$) 52-wk range €37.85-21.77/US$54.84-29.60Market cap. €21.0bn/US$25.6bnShares o/s 614m (ORD)/614m (ADR)ADR ratio 1 ADR:1 ORDFree float 75%Avg. daily volume ('000) 3,226/10Avg. daily value (m) €101.5/US$0.4 Balance sheet data 12/12E Shareholders' equity €17.3bnP/BV (UBS) 1.2xNet Cash (debt) (€16.3bn) Forecast returns Forecast price appreciation -18.0%/-17.8%Forecast dividend yield 5.9%Forecast stock return -12.1%/-11.9%Market return assumption 4.9%Forecast excess return -17.0% EPS (UBS, €) 12/12E 12/11 From To Cons. ActualQ1E - - 2.13 -Q2E - - 0.71 -Q3E - - 0.52 -Q4E - - 0.91 -12/12E 4.19 4.19 4.0412/13E 4.22 4.20 4.03 Performance (€)

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Source: UBS www.ubs.com/investmentresearch


UBS 30

ab


E.ON

Solid despite solar, still a good value play We stay positive on E.ON, despite declining earnings in power generation

Based on our findings in today’s sector note, Renewables to wipe out 50% ofgeneration profits, we estimate E.ON should lose €0.9bn EBITDA in power generation earnings between 2013 and 2020, partially offset by cost-cutting. However, the cuts to our medium-term EPS remain small (below 3%) as we feelmore confident on the cost-cutting targets after having met the CE.

B/S and gas contracts fixed – focus shifting to medium-term earnings After the strong progress in asset disposals and successful renegotiations withGazprom (we see the deal as an intermediate step towards a structural solution), themarket should re-focus on medium-term earnings growth. Despite headwinds in generation, we forecast €2.0 EPS in 2015E, thanks to growth in E&P andrenewables and the €1.5bn cost cuts, which we now fully include in our numbers.

Still a c25% TSR opportunity, but shares might take a breather near-termDespite the strong bounce in E.ON shares, we see another c25% TSR opportunityon a two-year view as the stock should trade on 10x PE by then. We consider the6.1% DY solid (backed by a not-too-high payout ratio) and attractive vs. bondyields. However, we highlight that our 2013E EPS is 3% below the lower end of guidance, and expect the range to be cut with 1H results on the generation outlook.

Valuation – €19 price target (from €17), Buy rating confirmed Our €19 PT is based on the average of an absolute SOTP (€21.5) and the peeraverage PE 2014E after disposals (€17). We prefer E.ON over RWE due to moreresilient earnings growth, a more solid balance sheet and more visible dividends.

Highlights (€m) 12/10 12/11 12/12E 12/13E 12/14ERevenues 92,863.00 112,954.00 112,284.73 122,106.08 125,412.67EBIT (UBS) 9,454.00 5,438.00 6,779.19 6,711.80 6,949.81Net Income (UBS) 4,882.00 2,501.00 4,337.85 3,139.88 3,394.68EPS (UBS, €) 2.56 1.31 2.28 1.65 1.78Net DPS (UBS, €) 1.50 1.00 1.10 1.10 1.10 Profitability & Valuation 5-yr hist av. 12/11 12/12E 12/13E 12/14EEBIT margin % 10.3 4.8 6.0 5.5 5.5ROIC (EBIT) % 15.4 10.0 14.1 14.3 14.4EV/EBITDA (core) x 8.1 8.1 6.5 6.0 5.9PE (UBS) x 12.1 14.8 7.9 10.9 10.1Net dividend yield % 4.9 5.2 6.1 6.1 6.1 Source: Company accounts, Thomson Reuters, UBS estimates. (UBS) valuations are stated before goodwill, exceptionals and other special items. Valuations: based on an average share price that year, (E): based on a share price of €17.95 on 18 Jul 2012 21:40 BST Patrick Hummel, CFA Analyst [email protected] +41-44-239 79 23

Per Lekander Analyst [email protected] +33-14-888 32 96

Global Equity Research Germany

Electric Utilities

12-month rating Buy Unchanged 12m price target €19.00/US$23.31 Prior: €17.00/US$20.85

Price €17.95/US$22.01 (ADR) RIC: EONGn.DE BBG: EOAN GR

Trading data (local/US$) 52-wk range €19.50-12.88/US$28.19-17.45Market cap. €34.2bn/US$41.9bnShares o/s 1,905m (ORD)/1,905m (ADR)ADR ratio 1 ADR:1 ORDFree float 100%Avg. daily volume ('000) 9,826/51Avg. daily value (m) €156.7/US$1.0 Balance sheet data 12/12E Shareholders' equity €37.3bnP/BV (UBS) 0.9xNet Cash (debt) (€14.6bn) Forecast returns Forecast price appreciation +5.8%/+5.9%Forecast dividend yield 6.1%Forecast stock return +11.9%/+12.0%Market return assumption 4.9%Forecast excess return +7.0% EPS (UBS, €) 12/12E 12/11 From To Cons. ActualQ1E - - 0.87 -Q2E - - 0.35 -Q3E - - 0.34 -Q4E - - 0.38 -12/12E 1.33 2.28 1.7812/13E 1.65 1.65 1.85 Performance (€)

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UBS 31

ab


Key Call: GDF Suez

Renewables boom doesn’t change Buy case

Renewables should wipe out 50% of conventional generation profits We forecast that solar and wind capacity will gradually reduce conventionalgeneration EBITDA by 50%. We have already seen renewables cutting into gasand coal profitability, but going forward the largest impact should be on nuclearand lignite as they see lower prices, as well as some lower volumes for lignite.

Impact only on a small part of GDF Suez means only a 5% cut to EPS We forecast almost a 50% (€1.5bn) 2011-16 decline in GDF-Suez central/south European power EBITDA. However, the affected businesses represent less than 15%of GDF, and almost half the downside is included in the 2012 guidance (nuclear tax,lower spreads). We are thus lowering EBITDA by only €500-700m (3-4%), partially offset by €200m lower cost of debt – leading to EPS cuts of 3-5%.

Over 8% dividend yield and 17% annual stock return to 2015 Despite the negative outlook for European power, we continue to view GDF Suezas a quality company with good positioning in growth markets (IPR, LNG) and asolid balance sheet. The 8% dividend yield appears safe considering a prospective10% EPS CAGR. We see potential for an annual total return of more than 17%over the next three years.

Valuation: Key Call, Buy rating and €21 price target (from €22 ps) Our €21 PT (was €22) is set as the average of three multiple valuations (PE,EV/EBITDA, DY) indicating €17-21 ps, and three absolute (SOTP, DCF, DDM)valuations indicating €25-26 ps.

Highlights (€m) 12/09 12/10 12/11E 12/12E 12/13ERevenues 79,908.00 84,478.00 90,673.00 96,073.04 99,092.27EBIT (UBS) 8,347.00 8,795.00 8,978.00 9,588.53 10,101.27Net Income (UBS) 4,227.00 4,124.60 3,337.00 3,695.20 4,214.72EPS (UBS, €) 1.89 1.84 1.50 1.62 1.78Net DPS (UBS, €) 1.47 1.50 1.50 1.50 1.55 Profitability & Valuation 5-yr hist av. 12/10 12/11E 12/12E 12/13EEBIT margin % - 10.4 9.9 10.0 10.2ROIC (EBIT) % - 9.6 8.5 8.1 8.3EV/EBITDA (core) x - 7.6 6.2 6.3 6.0PE (UBS) x - 14.5 12.1 11.2 10.2Net dividend yield % - 5.6 8.3 8.3 8.5 Source: Company accounts, Thomson Reuters, UBS estimates. (UBS) valuations are stated before goodwill, exceptionals and other special items. Valuations: based on an average share price that year, (E): based on a share price of €18.12 on 18 Jul 2012 21:40 BST Per Lekander Analyst [email protected] +33-14-888 32 96

Global Equity Research France

Gas Utilities

12-month rating Buy Unchanged 12m price target €21.00/US$25.76 Prior: €22.00/US$26.99

Price €18.12/US$22.34 (ADR) RIC: GSZ.PA BBG: GSZ FP

Trading data (local/US$) 52-wk range €23.94-15.95/US$34.53-19.76Market cap. €40.6bn/US$50.0bnShares o/s 2,240m (ORD)/2,240m (ADR)ADR ratio 1 ADR:1 ORDFree float 64%Avg. daily volume ('000) 5,496/60Avg. daily value (m) €95.0/US$1.3 Balance sheet data 12/11E Shareholders' equity €67.5bnP/BV (UBS) 0.6xNet Cash (debt) (€37.6bn) Forecast returns Forecast price appreciation +15.9%/+15.3%Forecast dividend yield 8.3%/8.2%Forecast stock return +24.2%/+23.5%Market return assumption 5.2%/8.3%Forecast excess return +19.0%/+15.2% EPS (UBS, €) 12/11E 12/10 From To Cons. ActualH1E - - - -H2E - - - -12/11E 1.50 1.50 1.5912/12E 1.67 1.62 1.61 Performance (€)

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CEZ Group

Downgrade to Sell on CE power outlook

CEZ’s lignite and nuclear fleet to suffer from German renewables growth We expect German renewables to have a growing negative impact on baseload power stations, in terms of load hours and achievable prices. As >60% of CEZ’EBITDA stems from Czech nuclear and lignite plants, the company is verynegatively affected. We expect CEZ’s EPS to decline 11% over the period 2012-16E, compared to the current consensus estimate of c15% positive growth.

Significant cut to estimates: by c20% for 2015E; EPS decline is structural Our lower medium-term power price forecasts and plant load factors lead to largeEPS cuts starting in 2014E, with a c20% negative impact for 2015E and beyond. Inthe absence of growth opportunities, we believe CEZ turns into a long-term EPS decline story – we estimate CZK62 EPS for 2020E, implying 12x PE 2020E.

Additional risks: Nuclear plans, Czech coal and situation in Albania In this environment, we see the planned nuclear expansion by up to 3GW aspotentially value-erosive – not only because of too low power prices, but also dueto lower load factors. Short-term, uncertainties about negotiations with Czech Coal(7% EPS risk UBSe) and losses in Albania (5% EPS risk) weigh on shares.

Valuation – Downgrade to Sell, CZK660 price target Our PT is based on an absolute SOTP. CEZ trades on a small premium to 2013E peermultiples, but we believe it should trade at a discount given the negative earnings outlook. In CEE, we see better value in PGE, which offers a more attractivevaluation, a healthier Polish power market and a large share buyback/dividendopportunity.

Highlights (Kcm) 12/10 12/11 12/12E 12/13E 12/14ERevenues 198,848.00 209,761.00 210,621.44 217,326.05 221,270.94EBIT (UBS) 65,057.00 61,542.00 60,846.85 59,193.52 55,322.39Net Income (UBS) 47,232.00 40,756.00 41,260.93 41,323.47 38,342.20EPS (UBS, Kc) 88.48 76.32 77.26 77.38 71.80Net DPS (UBS, Kc) 50.00 45.00 45.00 45.00 45.00 Profitability & Valuation 5-yr hist av. 12/11 12/12E 12/13E 12/14EEBIT margin % 32.7 29.3 28.9 27.2 25.0ROIC (EBIT) % 23.6 19.3 17.2 15.6 14.0EV/EBITDA (core) x 7.3 6.8 6.5 6.6 6.8PE (UBS) x 11.4 10.7 9.4 9.4 10.1Net dividend yield % 5.1 5.5 6.2 6.2 6.2 Source: Company accounts, Thomson Reuters, UBS estimates. (UBS) valuations are stated before goodwill, exceptionals and other special items. Valuations: based on an average share price that year, (E): based on a share price of Kc728.00 on 18 Jul 2012 21:40 BST Patrick Hummel, CFA Analyst [email protected] +41-44-239 79 23

Global Equity Research Czech Republic

Electric Utilities

12-month rating Sell Prior: Neutral 12m price target Kc660.00/US$32.03 Prior: Kc740.00/US$35.91

Price Kc728.00/US$35.33 RIC: CEZP.PR BBG: CEZ CP

Trading data (local/US$) 52-wk range Kc878.00-679.00/US$51.69-33.60Market cap. Kc392bn/US$19.0bnShares o/s 538m (ORD)Free float 30%Avg. daily volume ('000) 96Avg. daily value (m) Kc70.0 Balance sheet data 12/12E Shareholders' equity Kc244bnP/BV (UBS) 1.6xNet Cash (debt) (Kc186bn) Forecast returns Forecast price appreciation -9.3%Forecast dividend yield 6.2%Forecast stock return -3.1%Market return assumption 6.1%Forecast excess return -9.2% EPS (UBS, Kc) 12/12E 12/11 From To Cons. ActualQ1E - - 27.80 -Q2E - - - -Q3E - - - -Q4E - - - -12/12E 77.95 77.26 80.2312/13E 76.20 77.38 80.86 Performance (Kc)

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Verbund AG

Quality assets in the wrong region – Sell

Cutting estimates again - €1.2 EPS is the new normal due to low power px We see further downside to achievable prices and spreads in hydro powergeneration. Baseload prices around €50/MWh imply €1.2 EPS for Verbund, c10-25% below consensus for the coming years. Also, due to ongoing oversupply, weexpect the CCGTs in Austria, Italy and France to remain a burden to groupearnings for longer.

Further portfolio restructuring should be needed, gearing seems stretchedOn our estimates, Verbund remains FCF negative after dividends at least until2015, and gearing remains >4x net debt/EBITDA, exceeding Verbund’s envisaged4x maximum. In our view, Verbund should accelerate the refocusing of itsportfolio in order to cut debt, increase dividend visibility and reveal value inparticipations. However, execution has been slow so far, and the environment is challenging for disposals (risk of writedowns, EPS dilution).

Catalyst: FY12 guidance to be provided with 1H results; we are cautious We expect cautious FY12 guidance on 1H results day (25 July) given the pooroutlook for CCGTs and the uncertainty around gas contract renegotiations.Verbund should guide for €900m EBIT and €400m net income, 17% belowconsensus on net income level.

Valuation – PT lowered to €16, Sell rating confirmed Our PT is based on a blend of an absolute SOTP with a DCF for Austrian hydro plants and the peer PE. While the longevity of the hydro fleet deserves a premiumvs. peers, we think the current 60% premium to the sector PE 2013E is excessive.

Highlights (€m) 12/10 12/11 12/12E 12/13E 12/14ERevenues 3,307.89 3,865.37 3,529.03 3,295.76 3,209.52EBIT (UBS) 828.46 1,001.60 897.68 845.75 788.29Net Income (UBS) 400.83 352.62 404.29 427.91 406.32EPS (UBS, €) 1.28 1.01 1.16 1.23 1.17Net DPS (UBS, €) 0.55 0.55 0.55 0.55 0.55 Profitability & Valuation 5-yr hist av. 12/11 12/12E 12/13E 12/14EEBIT margin % 28.3 25.9 25.4 25.7 24.6ROIC (EBIT) % 20.3 15.0 12.7 11.4 10.2EV/EBITDA (core) x 7.3 11.2 7.4 7.7 8.1PE (UBS) x 20.8 25.9 15.1 14.3 15.1Net dividend yield % 2.5 2.1 3.1 3.1 3.1 Source: Company accounts, Thomson Reuters, UBS estimates. (UBS) valuations are stated before goodwill, exceptionals and other special items. Valuations: based on an average share price that year, (E): based on a share price of €17.62 on 18 Jul 2012 21:40 BST Patrick Hummel, CFA Analyst [email protected] +41-44-239 79 23

Global Equity Research Austria

Electric Utilities

12-month rating Sell Unchanged 12m price target €16.00/US$19.63 Prior: €18.00/US$22.08

Price €17.62/US$21.61 RIC: VERB.VI BBG: VER AV

Trading data (local/US$) 52-wk range €29.42-17.31/US$42.41-21.11Market cap. €6.12bn/US$7.51bnShares o/s 347m (ORD)Free float 19%Avg. daily volume ('000) 132Avg. daily value (m) €2.5 Balance sheet data 12/12E Shareholders' equity €4.54bnP/BV (UBS) 1.3xNet Cash (debt) (€4.24bn) Forecast returns Forecast price appreciation -9.2%Forecast dividend yield 3.1%Forecast stock return -6.1%Market return assumption 5.2%Forecast excess return -11.3% EPS (UBS, €) 12/12E 12/11 From To Cons. ActualQ1E - - 0.34 -Q2E - - - -Q3E - - - -Q4E - - - -12/12E 1.35 1.16 1.4112/13E 1.29 1.23 1.38 Performance (€)

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EDF

Renewables remove upside, not downside

Only 2.5% annual tariff increases needed to converge with market by 2016We forecast renewables to lower baseload power prices to €45/MWh by 2016. This means that only 2.5% of annual tariff increases are needed to align EDF’s tariffs withthe market by 2016 vs. a consensus estimate of 4.5%. This is positive for Frenchpoliticians, but negative for EDF as we forecast almost flat earnings to 2016.

Excessive capex – UK nuclear to be cut and the cash dividend is not safe EDF generates an impressive €11-12bn of cashflows, but invests even more andborrows to pay the €2bn dividend. We expect UK nuclear projects to be stopped, butthis is not sufficient to stabilise the situation. Cutting French capex will be politicallydifficult, and doing it while continuing the dividend almost impossible. We believethat an ongoing a scrip dividend (not yet in our estimates) is the likely outcome.

And the almost endless list of potential risks remains intact EDF faces many difficult issues near term. Nuclear liabilities are likely to increase.At least the Fessenheim reactors will close. Life extensions are at risk. The CSPE-tariff deficit is escalating. The government wants a new tariff system. The €340k compensation cap is a problem in terms of attracting new top management talent.

Valuation: Downgrading to Sell with €16 PT based on a DDM valuation Given the 85% state controlling stake, we see the dividend as the most importantfactor for an EDF shareholder and thus value it on DDM. We assume the dividendto stay flat until 2015 and then to increase with inflation. We reduce EPS by 5-15% 2013-15E.

Highlights (€m) 12/10 12/11 12/12E 12/13E 12/14ERevenues 65,165.00 65,307.00 71,317.60 76,005.33 78,235.58EBIT (UBS) 6,240.00 8,286.00 8,912.23 9,274.30 9,502.63Net Income (UBS) 3,961.00 3,010.00 3,682.09 3,694.23 3,753.94EPS (UBS, €) 2.14 1.63 1.99 2.00 2.03Net DPS (UBS, €) 1.15 1.15 1.15 1.15 1.15 Profitability & Valuation 5-yr hist av. 12/11 12/12E 12/13E 12/14EEBIT margin % 13.7 12.7 12.5 12.2 12.1ROIC (EBIT) % 12.5 9.6 9.8 9.7 9.4EV/EBITDA (core) x - 6.9 5.9 5.9 5.9PE (UBS) x 20.5 15.6 8.8 8.8 8.6Net dividend yield % 3.0 4.5 6.6 6.6 6.6 Source: Company accounts, Thomson Reuters, UBS estimates. (UBS) valuations are stated before goodwill, exceptionals and other special items. Valuations: based on an average share price that year, (E): based on a share price of €17.54 on 18 Jul 2012 21:40 BST Per Lekander Analyst [email protected] +33-14-888 32 96

Global Equity Research France

Electric Utilities

12-month rating Sell Prior: Neutral 12m price target €16.00/US$19.63 Prior: €17.00/US$20.85

Price €17.54/US$21.52 RIC: EDF.PA BBG: EDF FP

Trading data (local/US$) 52-wk range €27.43-14.98/US$39.81-18.62Market cap. €32.4bn/US$39.8bnShares o/s 1,849m (ORD)Free float 15%Avg. daily volume ('000) 2,413Avg. daily value (m) €38.8 Balance sheet data 12/12E Shareholders' equity €30.8bnP/BV (UBS) 1.1xNet Cash (debt) (€39.8bn) Forecast returns Forecast price appreciation -8.8%Forecast dividend yield 6.6%Forecast stock return -2.2%Market return assumption 5.2%Forecast excess return -7.4% EPS (UBS, €) 12/12E 12/11 From To Cons. ActualQ1E - - - -Q2E - - - -Q3E - - - -Q4E - - - -12/12E 2.01 1.99 2.0412/13E 2.04 2.00 2.08 Performance (€)

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Fortum

German renewables boom reduces exports

German solar has reduced Nordic exports by 32% on sunny weekends We expect Germany’s renewables boom to negatively impact European generators.With c60GW of capacity, wind and solar also negatively impact neighbouringcountries, as Germany needs to export power on windy nights and sunny days.During sunny weekends in 2012, Nordic exports have been 32% lower than onnon-sunny days.

By 2020 Germany should push excess power to Nordics one day in every five We forecast that German solar output will grow by 2.9x and wind by 2.0x by 2020.For the Nordics this means that it will be increasingly hard to export power. Wehave previously estimated 30-40TWh of export potential by 2020, but due to the impact from growing renewables we think this could be around 20-30% lower. In 2020 we estimate that solar and wind will cover more than half of Germany’sdemand on one out of every five days. When this happened in May, the Nordicsturned net importers even as the spot price was pushed below €20/MWh.

Weak Q2 results support our thesis – and this will be a recurring theme Fortum delivered weak results for Q2, with €0.21 EPS 22% below consensus. Its30% unhedged generation position was hit by lower spot prices, a recurring themegoing forward, in our view. Ongoing nuclear and wind additions, limited exportspotential and weak demand growth should push power prices towards €20/MWh. This should gradually reduce Fortum’s earnings and dividends by 40-50%.

Valuation: Reiterating Sell and price target of €11.0 Our €11.0 price target is set in line with our SOTP and DDM valuations.

Highlights (€m) 12/10 12/11 12/12E 12/13E 12/14ERevenues 6,296.00 6,161.00 6,178.29 6,286.13 6,327.65EBIT (UBS) 1,833.00 1,802.00 1,857.30 1,752.73 1,518.42Net Income (UBS) 1,425.00 1,289.00 1,295.02 1,208.58 1,024.69EPS (UBS, €) 1.60 1.45 1.46 1.36 1.15Net DPS (UBS, €) 1.00 1.00 0.90 0.80 0.70 Profitability & Valuation 5-yr hist av. 12/11 12/12E 12/13E 12/14EEBIT margin % 33.4 29.2 30.1 27.9 24.0ROIC (EBIT) % 13.1 11.2 10.6 9.6 8.2EV/EBITDA (core) x 10.3 10.3 8.0 8.2 9.0PE (UBS) x 13.0 13.8 10.0 10.7 12.7Net dividend yield % 5.2 5.0 6.2 5.5 4.8 Source: Company accounts, Thomson Reuters, UBS estimates. (UBS) valuations are stated before goodwill, exceptionals and other special items. Valuations: based on an average share price that year, (E): based on a share price of €14.61 on 18 Jul 2012 21:40 BST Per Lekander Analyst [email protected] +33-14-888 32 96

Global Equity Research Finland

Electric Utilities

12-month rating Sell Unchanged 12m price target €11.00/US$13.49 Unchanged

Price €14.61/US$17.92 RIC: FUM1V.HE BBG: FUM1V FH

Trading data (local/US$) 52-wk range €19.30-13.95/US$27.50-17.50Market cap. €13.0bn/US$15.9bnShares o/s 888m (ORD)Free float 45%Avg. daily volume ('000) 1,818Avg. daily value (m) €27.6 Balance sheet data 12/12E Shareholders' equity €11.5bnP/BV (UBS) 1.1xNet Cash (debt) (€6.78bn) Forecast returns Forecast price appreciation -24.7%Forecast dividend yield 0.0%Forecast stock return -24.7%Market return assumption 6.3%Forecast excess return -31.0% EPS (UBS, €) 12/12E 12/11 UBS Cons. ActualQ1E 0.00 0.46 0.00Q2E 0.00 0.28 0.00Q3E 0.00 0.23 0.00Q4E 0.00 0.46 0.0012/12E 1.46 1.4912/13E 1.36 1.50 Performance (€)

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Appendix: Methodology In order to get a quantitative view of the impact that renewables have on load factors and pricing, we have a constructed an hour supply/demand model out to 2020. The key assumptions in our model are:

Demand is simulated using the hourly demand for 2011/2012 as reported by ENTSOE for Germany, France, the Czech Republic, Netherlands, Belgium, Austria and Switzerland. We have assumed that the load curve will remain unchanged going forward, but we have slightly adjusted the height of the curve based on our total demand growth expectations for the region (-1% in 2012, 0% for 2013/14 and then 0.2% annual growth until 2020).

For wind and solar we have used the actual hourly output from Germany and scaled this up to match the total capacity of the region. Likewise, for demand we have assumed that the hourly load factor stays unchanged going forward, but that total output will increase with capacity growth.

Table 21: Renewables additions in Central Europe

2012 2013 2014 2015 2016 2017 2018 2019 2020

Wind 3953 4366 4322 4258 5345 5335 5224 5216 5107

Solar 7387 5569 5600 5600 5600 5600 5600 5600 5400

Hydro Other renewables 1,344 370 749 2,646 1,060 1,357 1,280 1,506 541


Output from thermal generation is simulated based on the residual demand (demand after hydro, CHP, wind, solar and other renewables). The output of each technology is based on available capacity and the bidding assumptions shown in table below. This way we have derived a system price and production per technology for every hour until 2020.

Table 22: Merit order bidding assumptions

Short-term price assumptions (€/MWh) 2011 2012 2013

Nuclear 21.0 21.4 21.8

Lignite 25.4 19.8 21.2

Coal 47.7 36.6 38.0

CCGT 49.4 49.8 51.1

Gas 61.4 61.3 63.1

Oil/other thermal 123.0 118.3 121.4


To include seasonal effects on available capacity (e.g. higher availability in winter and more maintenance in the summer), we adjusted the availability of thermal capacity based on the monthly output for each technology as reported by ENTSOE. In our modelling we have also included retirements of older lignite, hard coal and gas turbines over the period.


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Table 23: Net conventional capacity additions

Net capacity additions 2012 2013 2014 2015 2016 2017 2018 2019 2020

Nuclear 0 -460 -460 440 -633 100 -1,244 100 -1,350

Lignite 600 300 -1,375 -125 -375 -375 -375 -375 -375

Coal 1,440 3,424 328 -2,500 -2,000 -1,000 -1,000 0 0

CCGT/gas 3,249 -2,005 -1,000 -60 1,220 440 440 440 440

Oil/other thermal -500 -2,000 -1,000 -1,000 -200 0 0 0 0

Total 4,789 -741 -3,507 -3,245 -1,988 -835 -2,179 165 -1,285


One of the strengths of our hourly modelling is that it exposes lignite and hard coal stations to short-term volatility in demand. As lignite and hard coal stations are unable to perfectly cycle their output to match changing demand conditions, there is a risk of generating at hours when their fuel cost is higher than the spot price. The cost/loss of future revenues as a result of fully shutting down also means they will continue to have some output in periods where their demand is not needed, if they expect to be able to produce at profit some hours later. This in turn means that lignite and nuclear actually see falling output quicker than one would expect from the average increase in output from solar and wind.


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Statement of Risk

Utilities are driven by commodities, power prices, M&A, regulatory intervention and interest rates.

Analyst Certification

Each research analyst primarily responsible for the content of this research report, in whole or in part, certifies that with respect to each security or issuer that the analyst covered in this report: (1) all of the views expressed accurately reflect his or her personal views about those securities or issuers and were prepared in an independent manner, including with respect to UBS, and (2) no part of his or her compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressed by that research analyst in the research report.


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Required Disclosures This report has been prepared by UBS Limited, an affiliate of UBS AG. UBS AG, its subsidiaries, branches and affiliates are referred to herein as UBS.

For information on the ways in which UBS manages conflicts and maintains independence of its research product; historical performance information; and certain additional disclosures concerning UBS research recommendations, please visit www.ubs.com/disclosures. The figures contained in performance charts refer to the past; past performance is not a reliable indicator of future results. Additional information will be made available upon request. UBS Securities Co. Limited is licensed to conduct securities investment consultancy businesses by the China Securities Regulatory Commission.

UBS Investment Research: Global Equity Rating Allocations

UBS 12-Month Rating Rating Category Coverage1 IB Services2

Buy Buy 55% 33%Neutral Hold/Neutral 37% 31%Sell Sell 8% 16%UBS Short-Term Rating Rating Category Coverage3 IB Services4

Buy Buy less than 1% 0%Sell Sell less than 1% 0%

1:Percentage of companies under coverage globally within the 12-month rating category. 2:Percentage of companies within the 12-month rating category for which investment banking (IB) services were provided within the past 12 months. 3:Percentage of companies under coverage globally within the Short-Term rating category. 4:Percentage of companies within the Short-Term rating category for which investment banking (IB) services were provided within the past 12 months. Source: UBS. Rating allocations are as of 30 June 2012. UBS Investment Research: Global Equity Rating Definitions

UBS 12-Month Rating Definition Buy FSR is > 6% above the MRA. Neutral FSR is between -6% and 6% of the MRA. Sell FSR is > 6% below the MRA. UBS Short-Term Rating Definition

Buy Buy: Stock price expected to rise within three months from the time the rating was assigned because of a specific catalyst or event.

Sell Sell: Stock price expected to fall within three months from the time the rating was assigned because of a specific catalyst or event.


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KEY DEFINITIONS Forecast Stock Return (FSR) is defined as expected percentage price appreciation plus gross dividend yield over the next 12 months. Market Return Assumption (MRA) is defined as the one-year local market interest rate plus 5% (a proxy for, and not a forecast of, the equity risk premium). Under Review (UR) Stocks may be flagged as UR by the analyst, indicating that the stock's price target and/or rating are subject to possible change in the near term, usually in response to an event that may affect the investment case or valuation. Short-Term Ratings reflect the expected near-term (up to three months) performance of the stock and do not reflect any change in the fundamental view or investment case. Equity Price Targets have an investment horizon of 12 months. EXCEPTIONS AND SPECIAL CASES UK and European Investment Fund ratings and definitions are: Buy: Positive on factors such as structure, management, performance record, discount; Neutral: Neutral on factors such as structure, management, performance record, discount; Sell: Negative on factors such as structure, management, performance record, discount. Core Banding Exceptions (CBE): Exceptions to the standard +/-6% bands may be granted by the Investment Review Committee (IRC). Factors considered by the IRC include the stock's volatility and the credit spread of the respective company's debt. As a result, stocks deemed to be very high or low risk may be subject to higher or lower bands as they relate to the rating. When such exceptions apply, they will be identified in the Company Disclosures table in the relevant research piece. Research analysts contributing to this report who are employed by any non-US affiliate of UBS Securities LLC are not registered/qualified as research analysts with the NASD and NYSE and therefore are not subject to the restrictions contained in the NASD and NYSE rules on communications with a subject company, public appearances, and trading securities held by a research analyst account. The name of each affiliate and analyst employed by that affiliate contributing to this report, if any, follows. UBS Securities France SA: Per Lekander. UBS AG: Patrick Hummel, CFA. UBS Limited: Alberto Gandolfi; Stephen Hunt; Ignacio Perez Cossio. Company Disclosures

Company Name Reuters 12-mo rating Short-term rating Price Price date CEZ Group CEZP.PR Neutral N/A Kc728.00 18 Jul 2012 E.ON5, 16, 22 EONGn.DE Buy N/A €17.96 18 Jul 2012 EDF4, 16, 22 EDF.PA Neutral N/A €17.54 18 Jul 2012 Fortum16 FUM1V.HE Sell N/A €14.61 18 Jul 2012 GDF Suez5, 16 GSZ.PA Buy N/A €18.12 18 Jul 2012 PGE PGEP.WA Buy N/A PLN19.49 18 Jul 2012 RWE2, 4, 5, 16 RWEG.DE Neutral N/A €34.15 18 Jul 2012 Verbund AG4, 16 VERB.VI Sell N/A €17.62 18 Jul 2012

Source: UBS. All prices as of local market close. Ratings in this table are the most current published ratings prior to this report. They may be more recent than the stock pricing date 2. UBS AG, its affiliates or subsidiaries has acted as manager/co-manager in the underwriting or placement of securities of

this company/entity or one of its affiliates within the past 12 months. 4. Within the past 12 months, UBS AG, its affiliates or subsidiaries has received compensation for investment banking

services from this company/entity. 5. UBS AG, its affiliates or subsidiaries expect to receive or intend to seek compensation for investment banking services

from this company/entity within the next three months. 16. UBS Securities LLC makes a market in the securities and/or ADRs of this company. 22. UBS AG, its affiliates or subsidiaries held other significant financial interests in this company/entity as of last month`s end

(or the prior month`s end if this report is dated less than 10 working days after the most recent month`s end).


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