Solar plays Russian roulette

Sector report: 2011 outlook
Renewable Energy
Solar plays Russian roulette
Renewable Energy
02.09.2010
Renewable Energy vs Nasdaq
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Renewable Energy
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Analysts:
Einar Kilde Evensen
+47 22948232
einar.kilde.evensen@dnbnor.no
Trygve Lauvdal
+47 22948932
trygve.lauvdal@dnbnor.no
Dan Erik Glover
dan.erik.glover@dnbnor.no
Please see the last page for
important information.
The solar market has tangled itself into a risky "game", shovelling
modules into Germany at an unsustainable pace. Our estimates
indicate installations there may nearly triple from 2009 to 9.2GW in
2010, and will soar even higher next year if no decisive action is
taken by the Bundestag. Sooner rather than later, we say, since the
pain will be worse the longer the delay.
Mcap Price Target Poten- Price / earnings ratio
Ticker Curr. REC (EURm) (curr.) (curr.) tial 2010e 2011e 2012e
FSLR US USD HOLD 8,159 127.9 140.0 10 % 14.4x 12.5x 16.6x
QCE GR EUR SELL 619 5.1 5.0 -2 % n.m. 9.7x 25.3x
REC NO NOK BUY 3,589 16.3 24.0 48 % 74.5x 11.9x n.m.
SWV GR EUR SELL 1,713 9.0 8.0 -11 % 14.6x 15.3x n.m.
SPWRA US USD HOLD 1,468 10.8 11.5 7 % 7.9x 6.0x 20.7x
STP US USD SELL 1,924 7.7 7.0 -10 % 15.3x 9.7x n.m.
VWS DC DKK BUY 8,678 219.2 350.0 60 % 24.4x 8.6x 7.3x
Germany is seriously overheating. Our calculations indicate that the
German market is heading for 9.2GW of installations this year. If no action
is taken, the current legislation is likely to spur further rapid growth in 2011
– in stark contrast to Germany's long-term target of ~3GW per year. We see
a capping of this market as inevitable, but for practical reasons not before
mid-2011. Until then, demand will be strong and ASPs (relatively) resilient.
Module ASPs to fall 27% in 2012 from USD 1.55/Wp in 2011. During
the last year, module ASPs has fallen almost around 15%, and now trades
at USD 1.70 per Wp. Based on our analysis of German IRRs, production cost
and available capacities we expect module ASPs next year to average USD
~1.55/Wp. We believe there is enough production capacity with combined
cash costs below USD 1.55/W to supply 21 GW of polysilicon, wafers, cells
and modules (including thin-film) in 2011.
World ex-Germany must grow by 18GW in 2012 to avoid oversupply.
While we model 2011 to be another strong year with demand reasonably in
balance with supply, our expected 4GW cap in Germany from 2012 coupled
with 29GW worth of available modules means demand outside Germany
needs to grow from 7GW in 2010 to 25GW in 2012.
Should we worry about 2012 when the party is extending into 2011?
Of course, but there will come warning signs from Germany before the
Bundestag revises the FiT legislation. In the mean time there are several
(for some companies - very) good quarters ahead of us. Investors can ride
this wave a little longer, but do stay alert. One could also hope (or pray?)
the 2012 situation will somehow be resolved by the time we get there.

Sector report > Renewable Energy
DnB NOR Markets – 2
02.09.2010
Table of contents
1. EXECUTIVE SUMMARY 6
1. 2011 ANOTHER RECORD, BUT UNSUSTAINABLE – 2012 TO FACE SEVERE
OVERSUPPLY 6
2. MODULE ASPS SLIPPING TO EUR 1.20-1.25/W IN 2011, BUT BRACE
FOR 2012 6
3. GERMANY NEEDS TO INTRODUCE CAP – SOON! 6
4. WIND – GROWTH SLOWING IN 2010, CAGR OF 10% EXPECTED NEXT
FIVE YEARS 8
5. INVESTMENT STRATEGY 8
2. ELECTRICITY MARKET OUTLOOK 9
MACRO BACKDROP: MODEST RECOVERY 9
ELECTRICITY DEMAND GROWTH HAS HISTORICALLY BEEN RESILIENT VS MACRO 10
DEMAND GROWTH IS VULNERABLE, BUT AGING PLANTS MUST STILL BE
RETIRED 12
ENERGY SUPPLY: CURRENT NEW-BUILD PACE IS INSUFFICIENT 13
NUCLEAR: PHASING OUT OR NEW DAWN? 15
ENERGY SECURITY REMAINS A SIGNIFICANT DRIVER OF RENEWABLE ENERGY 17
ELECTRICITY PRICES LIKELY TO RISE 19
ELECTRICITY MARKETS ARE VERY HETEROGENOUS 21
3. ESTIMATING COST OF NEW ELECTRICITY PRODUCTION (LCOE) 22
WHAT IS LCOE AND WHY DO WE NEED IT? 22
KEY FINDINGS: WIND CAN COMPETE WITHOUT SUBSIDIES 22
LCOE: SENSITIVE TO THE DIFFERENT COST PARAMETERS 22
PROS AND CONS OF THE DIFFERENT TECHNOLOGIES 22
WIND – ONSHORE 24
WIND - OFFSHORE 25
SOLAR - PV 26
NUCLEAR 27
HYDRO 28
NATURAL GAS 29
COAL 30
DISCOUNT RATE SENSITIVITIES 31
4. POLITICAL FRAMEWORK 32
HOW EXPENSIVE ARE RENEWABLE ENERGY SUBSIDIES REALLY? 32
OVERVIEW OF WORLD SUBSIDIES FOR SOLAR AND WIND 33
OBJECTIVE OF POLICIES 1: REDUCING THE DEPENDENCE ON FOSSIL FUELS 33
OBJECTIVE OF POLICIES 2: REDUCING GREENHOUSE-GAS EMISSIONS 35
US POLICIES: AMBITIOUS TARGETS, LOW FIT RATES 36
GERMANY: LUCRATIVE TARIFFS SPURRING RAPID BUT UNSUSTAINABLE
GROWTH 37
GERMANY: WHY A CAP IS INEVITABLE 38
DEMAND - EUROPE: EMERGING SOLAR MARKETS 40
ASIA: A POLICY CHANGE CAN RESULT IN A SOLAR BOOM 40
WIND POWER: OFFSHORE BECOMING CLOSE TO COST COMPETITIVE 41
5. SOLAR COST AND PRICES 43
SUMMARY: MARGIN COMPRESSION CONTINUES 43
POLYSILICON: DIFFICULT, IF NOT IMPOSSIBLE, TO SEE PRICES NOT FALLING 44
WAFERS: NO LONG-TERM BOTTLENECK 46
CELL AND MODULE – NO BOTTLENECKS IN SIGHT 46
PROJECT COSTS: NO LONG-TERM BOTTLENECK 47
COST OUTLOOK THROUGH THE VALUE CHAIN IN 2011 48
DEMAND VS SUPPLY: OVERSUPPLY LOOMING FOR 2011 49

02.09.2010
6. WIND INDUSTRY 51
SUMMARY: SIGNIFICANT GROWTH POTENTIAL NEXT DECADE 51
INDUSTRY STRUCTURE: INCREASINGLY DIVERSIFIED 53
GEOGRAPHICAL PRESENCE 54
FURTHER CONSOLIDATION LIKELY 54
WIND OFFERS COMPETITIVE COST OF (UN-SUBSIDISED) ELECTRICITY 55
KEY MARKETS: EUROPE, THE AMERICAS AND ASIA/PACIFIC 56
7. ELECTRICAL CARS – A (SMALL) PIECE OF THE PUZZLE 65
EVS ARE SOON BECOMING COST COMPETITIVE 65
BATTERY COST IS THE KEY ISSUE FOR (PH)EVS 66
IMPACT ON ELECTRICITY DEMAND 67
8. VALUATION SUMMARY 69
SHARE PRICE DEVELOPMENT 69
HISTORICAL 1-YEAR FORWARD MULTIPLES 70
PEER GROUP MULTIPLES 74
EPS REVISION TABLES 76
9. APPENDIX 77
A1: TOP 10 PRODUCERS: POLY, WAFERS, CELLS AND MODULES 77
A2: SOLAR TECHNOLOGY BASICS: TWO ROUTES TO HARNESS ENERGY FROM
THE SUN 77
A3: SOLAR AND PV VALUE CHAIN 78
A4: WHAT IS A "SMART GRID"? 78
A5: US STATE AND LOCAL SUBSIDIES FOR RENEWABLE ENERGY 80
A6: GLOSSARY, RENEWABLE ENERGY TERMS AND EXPRESSIONS 81
10. COMPANY COVERAGE 83
FIRST SOLAR 84
Q-CELLS 88
RENEWABLE ENERGY CORP. 91
SOLARWORLD 100
SUNPOWER 103
SUNTECH POWER 106
VESTAS WIND SYSTEMS 109

02.09.2010
Table of exhibits
EXHIBIT 1-1: ASP PROJECTIONS 2010-2012E............................................... 6
EXHIBIT 1-2: GERMAN SOLAR INSTALLATIONS (TWO SCENARIOS) ........................... 7
EXHIBIT 1-3: ELECTRICITY FROM PV VS GERMAN ELECTRICITY DEMAND .................... 7
EXHIBIT 2-1: KEY MACRO ASSUMPTIONS: GDP GROWTH ..................................... 9
EXHIBIT 2-2: GERMAN ELECTRICITY DEMAND VS GDP 1952-2010E ......................10
EXHIBIT 2-3: ELECTRICITY DEMAND BY REGION...............................................11
EXHIBIT 2-4: MWH/CAPITA AND POPULATION GROWTH .....................................11
EXHIBIT 2-5: ANNUAL ELECTRICITY USE PER CAPITA..........................................12
EXHIBIT 2-6: OECD ELECTRICITY USAGE INDICATORS.......................................13
EXHIBIT 2-7: EUROPE HAS AN AGE PROBLEM ..................................................14
EXHIBIT 2-8: EUROPEAN THERMAL POWER CAPACITY TRENDS 1960-2010................14
EXHIBIT 2-9: THE 439 OPERATING NUCLEAR POWER PLANTS WORLDWIDE .................15
EXHIBIT 2-10: 31 CAPACITY OF NUCLEAR PLANTS UNDER CONSTRUCTION .................16
EXHIBIT 2-11: HOW SAFE AND RELIABLE IS REALLY NUCLEAR?..............................17
EXHIBIT 2-12: ENERGY SECURITY AND OIL SUPPLY “DEFICITS”..............................18
EXHIBIT 2-13: THE MARGINAL PLANT PRINCIPLE IN GERMANY...............................19
EXHIBIT 2-14: COST OF NEW ELECTRICITY PRODUCTION BY SOURCE .......................20
EXHIBIT 2-15: ELECTRICITY SUPPLY 2008 BY MARKET AND SOURCE .......................20
EXHIBIT 2-16: COST BREAK DOWN FOR A GERMAN KWH (23.69 EURC/KWH) ..........21
EXHIBIT 3-1: COST OF NEW ELECTRICITY PRODUCTION FROM ONSHORE WIND .............24
EXHIBIT 3-2: COST OF NEW ELECTRICITY PRODUCTION FROM OFFSHORE WIND ............25
EXHIBIT 3-3: COST OF NEW ELECTRICITY PRODUCTION FROM PV ...........................26
EXHIBIT 3-4: COST OF NEW ELECTRICITY PRODUCTION FROM NUCLEAR.....................27
EXHIBIT 3-5: COST OF NEW ELECTRICITY PRODUCTION FROM HYDRO .......................28
EXHIBIT 3-6: COST OF NEW ELECTRICITY PRODUCTION FROM NATURAL GAS ...............29
EXHIBIT 3-7: COST OF NEW ELECTRICITY PRODUCTION FROM COAL .........................30
EXHIBIT 3-8: DISCOUNT RATE IMPACT ON TOTAL GENERATION COST .......................31
EXHIBIT 4-1: NON-OECD ENERGY SUBSIDIES ...............................................32
EXHIBIT 4-2: CURRENT SOLAR FEED-IN TARIFFS IN KEY COUNTRIES 2010 ..............33
EXHIBIT 4-3: OPEC NET OIL EXPORT REVENUES..............................................34
EXHIBIT 4-4: THE STRAIT OF HORMUZ ........................................................34
EXHIBIT 4-5: REQUIRED FALL IN GHG EMISSIONS ...........................................35
EXHIBIT 4-6: US RENEWABLE PORTFOLIO STANDARDS (RPS) .............................36
EXHIBIT 4-7: GERMAN TARIFFS AND PV INSTALLATIONS.....................................37
EXHIBIT 4-8: SURCHARGES TO GERMAN RATEPAYERS RISING FAST .........................38
EXHIBIT 4-9: GERMAN SOLAR INSTALLATIONS (TWO SCENARIOS) ..........................39
EXHIBIT 4-10: ELECTRICITY FROM PV VS GERMAN ELECTRICITY DEMAND..................39
EXHIBIT 4-11: CURRENT WIND FEED-IN TARIFFS IN KEY COUNTRIES .....................42
EXHIBIT 5-1: MAIN ASSUMPTIONS SOLAR .....................................................43
EXHIBIT 5-2: ASP ESTIMATES FOR 2011 AND 2012........................................43
EXHIBIT 5-3: FORWARD ASP SUMMARY .......................................................44
EXHIBIT 5-4: SILICON SUPPLY 2006 – 2012E...............................................45
EXHIBIT 5-5: SILICON SPOT PRICE .............................................................46
EXHIBIT 5-6: PRODUCTION ESTIMATES THROUGH THE PV VALUE CHAIN....................47
EXHIBIT 5-7: PROJECT COSTS 2007 – 2010 ................................................47
EXHIBIT 5-8: UNIT (FULLY LOADED) COST OVERVIEW AND COST TARGETS .................48
EXHIBIT 5-9: VERTICAL INTEGRATION AND MARGIN IMPLICATIONS..........................48
EXHIBIT 5-10: WORLD SOLAR MODEL (SIMPLIFIED)..........................................49
EXHIBIT 5-11: WORLD PV DEMAND 2004 – 2012E ........................................50
EXHIBIT 6-1: MAIN ASSUMPTIONS WIND ......................................................51
EXHIBIT 6-2: YEARLY WIND INSTALLATIONS...................................................51
EXHIBIT 6-3: WIND AS PERCENTAGE OF ELECTRICITY CONSUMPTION .......................52
EXHIBIT 6-4: WIND TURBINE MANUFACTURER MARKET SHARE ...............................53
EXHIBIT 6-5: MARKET SHARE DEVELOPMENT ..................................................53
EXHIBIT 6-6: TOP 3 PLAYERS IN TOP 10 MARKETS (2009) .................................54
EXHIBIT 6-7: ESTIMATED WIND FARM PROJECT COST.........................................55
EXHIBIT 6-8: COST OF NEW ELECTRICITY PRODUCTION FROM ONSHORE WIND .............56

02.09.2010
EXHIBIT 6-9: ANNUAL AND ACCUMULATED INSTALLATIONS IN EUROPE .....................57
EXHIBIT 6-10: NET INCREASE/DECREASE IN POWER CAPACITY EU 2000-2008..........57
EXHIBIT 6-11: NATIONAL RENEWABLE ENERGY PLANS (SUBMITTED)........................58
EXHIBIT 6-12: ANNUAL AND ACCUMULATED INSTALLATIONS IN THE AMERICAS ............58
EXHIBIT 6-13: WIND INSTALLATIONS IN THE UNITED STATES ..............................59
EXHIBIT 6-14: US SUPPLY CURVE FOR WIND ENERGY (EXCL. CONNECTION) ...............60
EXHIBIT 6-15: US SUPPLY CURVE FOR WIND ENERGY (INCL. CONNECTION) ...............60
EXHIBIT 6-16: ANNUAL AND ACCUMULATED INSTALLATIONS IN ASIA/PASIFIC.............61
EXHIBIT 6-17: ANNUAL AND ACCUMULATED INSTALLATIONS IN ROW ......................62
EXHIBIT 6-18: ANNUAL AND ACCUMULATED INSTALLATIONS OFFSHORE ....................62
EXHIBIT 6-19: INSTALLED AND PLANNED OFFSHORE WIND CAPACITY IN UK ...............63
EXHIBIT 6-20: PLANNED OFFSHORE CAPACITY BY MARKETS..................................64
EXHIBIT 6-21: HYWIND, WORLD'S FIRST FLOATING WIND TURBINE.........................64
EXHIBIT 7-1: EVS THEN AND NOW .............................................................65
EXHIBIT 7-2: US CAR COSTS, 2011E .........................................................66
EXHIBIT 7-3: US DRIVING PATTERNS ..........................................................67
EXHIBIT 7-4: ELECTRICITY DEMAND IMPACT FROM MORE (PH)EVS.........................67
EXHIBIT 7-5: NEW EV AND PHEV MODELS ...................................................68
EXHIBIT 8-1: SOLAR SHARE PRICE DEVELOPMENT SINCE 2009 .............................69
EXHIBIT 8-2: WIND SHARE PRICE DEVELOPMENT SINCE 2009 ..............................69
EXHIBIT 8-3: FIRST SOLAR – HISTORICAL 1-YEAR FWD MULTIPLES ........................70
EXHIBIT 8-4: Q-CELLS – HISTORICAL 1-YEAR FWD MULTIPLES .............................70
EXHIBIT 8-5: REC – HISTORICAL 1-YEAR FWD MULTIPLES..................................71
EXHIBIT 8-6: SOLARWORLD – HISTORICAL 1-YEAR FWD MULTIPLES .......................71
EXHIBIT 8-7: SUNPOWER – HISTORICAL 1-YEAR FWD MULTIPLES ..........................72
EXHIBIT 8-8: SUNTECH POWER – HISTORICAL 1-YEAR FWD MULTIPLES....................72
EXHIBIT 8-9: VESTAS – HISTORICAL 1-YEAR FWD MULTIPLES ..............................73
EXHIBIT 8-10: WIND PEER GROUP MULTIPLES ................................................74
EXHIBIT 8-11: SOLAR PEER GROUP MULTIPLES ...............................................75
EXHIBIT 8-12: WIND EPS REVISIONS.........................................................76
EXHIBIT 8-13: SOLAR EPS REVISIONS........................................................76
EXHIBIT 9-1: TOP 10 PRODUCERS: POLY, WAFERS, CELLS AND MODULES .................77
EXHIBIT 9-2: THE WAYS TO CAPTURE ENERGY AND MAKE ELECTRICITY FROM THE SUN ....78
EXHIBIT 9-3: THE PV VALUE CHAIN............................................................78
EXHIBIT 9-4: SMART GRID LAYOUT.............................................................79
EXHIBIT 9-5: THE MYRIAD OF US INCENTIVES FOR RENEWABLE ENERGY ...................80
EXHIBIT 10-1: FSLR: MANUFACTURING COST TARGET BELOW 0.6 USD/W..............85
EXHIBIT 10-2: FSLR: MANUFACTURING COST TARGET BELOW 0.6 USD/W..............85
EXHIBIT 10-3: FSLR: BOS COST TARGET BELOW 1 USD/W...............................85
EXHIBIT 10-4: FSLR: ESTIMATE CHANGES ...................................................86
EXHIBIT 10-5: FSLR: QUARTERLY ESTIMATES ...............................................86
EXHIBIT 10-6: NEW ESTIMATES: YEARLY......................................................89
EXHIBIT 10-7: QUARTERLY ESTIMATES ........................................................89
EXHIBIT 10-8: NEW ESTIMATES: YEARLY......................................................92
EXHIBIT 10-9: QUARTERLY ESTIMATES ........................................................93
EXHIBIT 10-10: SOTP - VALUATION SUMMARY...............................................94
EXHIBIT 10-11: SOTP - ASSUMPTIONS.......................................................95
EXHIBIT 10-12: SOTP - BEAR CASE ..........................................................96
EXHIBIT 10-13: SOTP - BASE CASE ..........................................................97
EXHIBIT 10-14: SOTP - BULL CASE...........................................................98
EXHIBIT 10-15: NEW ESTIMATES: YEARLY ..................................................101
EXHIBIT 10-16: QUARTERLY ESTIMATES ....................................................101
EXHIBIT 10-21: VWS: CHANGES TO ESTIMATES ..........................................110
EXHIBIT 10-22: VWS: QUARTERLY ESTIMATES ............................................110
EXHIBIT 10-23: VWS: BACKLOG ...........................................................110

02.09.2010
1. Executive summary
1. 2011 another record, but unsustainable – 2012 to face severe
oversupply
In last year's report (published 29 Sept 2009), we predicted that 2010
would be a year of oversupply in the module market. What we
overestimated was Germany's willingness to cut FiTs decisively (we
expected up to 25% reduction), thereby underestimating the resulting
demand following a smaller FiT reduction. In 2011, we see Germany
becoming a 10-12GW market, if nothing is done to the existing legislation.
However, for reasons we explain inside this report, Germany needs to
reduce annual installations to (or preferably below) 5GW as soon as
possible. Based on our estimate of Germany growing to 11.2GW in 2011, a
4GW cap imposed from 1 Jan 2012 translates into a demand reduction for
the PV industry of 7.2GW YoY. Coupled with around 7 GW of new supply in
2012, that means 14 GW without a "home", spelling "buyers' market" in
capital letters with correspondingly falling ASPs to marginal production
costs. The later the cap comes, the lower it must be, for reasons we
explain from page 38 in Chapter 4 and in point 3 below.
2. Module ASPs slipping to EUR 1.20-1.25/W in 2011, but brace for
2012
The strong demand from Germany is going to prevent prices from falling in
spite of the significant supply growth in 2011. As shown in Exhibit 1-1
below, we see module ASPs down 12% and silicon down 11% in 2011, to
levels where top tier cost producers enjoy super profits. However, the tide
will turn in 2012 at the latest, when Germany either imposes a cap or
reduces their FiT by the scheduled, max rate of 21% (see Exhibit 4-7).
Unless new markets "magically" appear, with similar or higher paying
propensities as German PV system buyers, prices must fall. A lot. It will be
painful, with the marginal producers just breaking even at the EBITDA
level. But even at these low levels, Chinese cost leaders will generate
decent profits.
Exhibit 1-1: ASP projections 2010-2012e
(Estimated yearly ASPs) (YoY change)
Product Unit 2010 2011e 2012e 2011e 2012e
Silicon USD/kg 55.9 49.6 38.1 -11 % -23 %
Wafer USD/Wp 0.90 0.78 0.58 -14 % -26 %
Cell USD/Wp 1.32 1.13 0.84 -15 % -26 %
Module USD/Wp 1.75 1.55 1.13 -12 % -27 %
Silicon EUR/kg 43.3 39.7 30.5 -8 % -23 %
Wafer EUR/Wp 0.70 0.62 0.46 -11 % -26 %
Cell EUR/Wp 1.02 0.90 0.67 -12 % -26 %
Module EUR/Wp 1.36 1.24 0.90 -9 % -27 %
* EURUSD 1.290 1.250 1.250
Source: DnB NOR Markets Equity Research
3. Germany needs to introduce cap – SOON!
In 2009, a record amount of 3.8 GW new capacity was installed, beating
even the most bullish forecasts. Almost 83,000 individual solar systems
with a total capacity of 2.3 GW were registered in the fourth quarter alone.
This year, installations are set to grow at an even higher rate nearly tripling
to 9.2 GW.
This enormous growth is rapidly becoming a headache for both German
ratepayers (who are funding the subsidies) and utilities (who are required

02.09.2010
to absorb all the electricity coming from the PV systems). Exhibit 1-2
below shows two scenarios of growth in the German market. One with 5%
annual growth after our 10-12 GW in 2011, and the other with a 4GW cap
from 1 Jan 2012. Couple this with Exhibit 4-10, and you clearly see the
challenges to the German grid even with an (for the PV industry)
aggressive 4GW cap from as early as 2012.
Exhibit 1-2: German solar installations (two scenarios)
The German market by
month in 2009
Monthly German installations 2009
0
400
800
1,200
1,600
Jan Mar May Jul Sep Nov
Inst. (MW)
German PV market projections
159,697
41,785
66,025
34,025
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Estimates
Newinstallations(MWp)
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
Aggregatedinstallations(MWp)
Aggregated EoY (5% growth after 2011) Aggregated EoY (w/ 4GW/yr cap in 2012)
New installations (5% growth after 2011) New installations (w/ 4GW/yr cap in 2012)
Our 5% growth scenario means that on a beautiful sunny day across the
whole of Germany in July, solar would completely inundate the German grid
with electricity. And even in 2012, solar could supply 40-50% of demand
at peak production. This is a big concern.
Exhibit 1-3: Electricity from PV vs German electricity demand
In 2012, with 4GW cap
Germany: July weekday electricity demand and 34 GWp solar
0
10
20
30
40
50
60
70
80
90
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
12:00
13:00
14:00
15:00
16:00
17:00
18:00
19:00
20:00
21:00
22:00
23:00
0:00
GWp
0 %
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
90 %
PVshareoftotalproduction/demand
Supply, other plants Supply, PV (34 GW)
Total demand PV share (right scale)
In 2012, without cap
0
10
20
30
40
50
60
70
80
90
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
12:00
13:00
14:00
15:00
16:00
17:00
18:00
19:00
20:00
21:00
22:00
23:00
0:00
GWp
0 %
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
90 %
In 2020, with 4GW cap
0
10
20
30
40
50
60
70
80
90
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
12:00
13:00
14:00
15:00
16:00
17:00
18:00
19:00
20:00
21:00
22:00
23:00
0:00
GWp
0 %
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
90 %
In 2020, without cap
0
10
20
30
40
50
60
70
80
90
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
12:00
13:00
14:00
15:00
16:00
17:00
18:00
19:00
20:00
21:00
22:00
23:00
0:00
GWp
0 %
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
90 %

02.09.2010
Note: Calculations assume 10% derate factor, i.e. 1GW installed capacity on module level can deliver up to 900MW of electricity
to the grid.
True, it is possible to export electricity from Germany, but it would be a
very uneconomic proposition given the EUR 0.17-0.23/kWh paid by the
German utilities (and their ratepayers) versus the much lower price they
are likely to obtain in return.
4. Wind – Growth slowing in 2010, CAGR of 10% expected next five
years
In 2009, growth in order intake slowed significantly due to reduced
availability of capital, and this will slow installation growth in 2010.
However, the attractive value proposition wind can offer today remains
unchanged: a production cost in line with conventional sources like coal and
natural gas (without subsidies), but with a highly predictable future cost.
Driven by regional requirements for renewable energy share (e.g. in EU, 29
US states and Australia) and the need for new electricity generation
capacity, wind is expected to grow 10% annually the next five years.
5. Investment strategy
Should investors worry about 2012 when the party is extending into 2011?
Of course, we say, but there will come warning signs from Germany before
the Bundestag revises the FiT legislation. In the mean time there are
several (for some companies - very) good quarters ahead of us. Investors
can ride this wave a little longer, but do stay alert. One could also hope (or
pray?) the 2012 situation will somehow be resolved by the time we get
there.

02.09.2010
2. Electricity market outlook
Macro backdrop: Modest recovery
The effects of the public stimulus efforts are fading and several countries
will soon begin to tighten their fiscal policies. Meanwhile, unemployment is
high and private demand still modest. After 3% growth since the trough a
year ago, our macro team expects GDP growth in advanced countries to be
significantly lower going forward. Overall OECD GDP is expected to grow by
1¾ per cent next year, with a growth rate of 2½ per cent thereafter. Global
growth in 2011 is projected to be around 3½ per cent, and just above 4 per
cent in years thereafter. Although potential output will grow more slowly
than the historical norm, it will still take time to return to normal capacity
utilization. Inflation will consequently remain low with a risk of deflation in
some countries. They therefore expect the current zero interest rate policy
to continue in the major economies until the first half of 2012. Unchanged
short-term interest rates will lead to continued low long-term yields.
Ever since the Lehman bankruptcy our macro team predicted a modest
recovery lasting several years. Unfortunately, even their relatively
downbeat expectations have turned out to be too optimistic. Forecasts from
November 2008 indicated that OECD GDP would only rise by 2.5% from
2008 to 2011. Almost a year later – in August 2009 – the prediction was
2%, and now, in August 2010, the best guess is 0.8%.
Exhibit 2-1: Key macro assumptions: GDP growth
Source: DnB NOR Markets 2010:III
This conservative prognosis is based on three fundamental assumptions.
First, history shows that economic setbacks in the wake of banking crises
are generally both deeper and longer lasting than other setbacks, although
the variation between countries is large. One reason for this is that the
period prior to a banking crisis is generally characterized by excessive
borrowing and risk taking. When the crisis materialises, businesses,
households and/or financial institutions all have to simultaneously reduce
their debt/income ratios. Put simple, this can be done in two ways: a)
by
Our macro team still
anticipates a weak, U-
shaped recovery…
…because of past
experience with banking
crises…

02.09.2010
reducing debt (the numerator) or b)
increasing income (the denominator).
The latter is largely dependent on overall macro-economic conditions, while
the former is controlled at the household level. When enough households
choose to save more, savings will eventually rise on the macroeconomic
level too, thus reducing growth in both activity and income. Lower income
growth could in turn force households to save even more. This inevitable
adjustment takes time. Until debt is brought down to a sustainable level
output growth is expected to be low.
Second, the current downturn in economic activity was extraordinarily
severe. Capacity utilization was thus also exceptionally low, as capacity
does not adjust as quickly as activity. OECD estimates that actual GDP in
advanced countries was 5.5% below potential GDP in the spring of last
year, the largest negative output gap since the Second World War. This is
coupled with the highest unemployment rates – in both absolute and
relative terms – in the post-war period. In some industries, capacity
utilization was even lower and in Japan, where capital goods production
accounts for a large share of total production, capacity utilization fell at one
point below 40% of the past four decades' average. The consequences of
significant excess capacity are obvious. Companies operating in markets
with too low demand will start to compete on prices (cut margins), stop
expanding capacity and cut costs as much as possible. This keeps total
demand weak. Similarly, households that have either experienced or fear
for job losses or wage cuts will hold back on spending. Price, margin and
wage cuts all amplify deflationary forces.
Finally, it was pointed out that the stimulus were largely temporary, albeit
not without nuances. When interest rates are cut to zero, it is not possible
to cut them any further. The substitution effect1
will still be there, but the
income effect2
is exhausted now that interest rates have reached bottom.
Electricity demand growth has historically been resilient vs macro
Historically, electricity demand growth has been resilient, even in times of
slow or even negative GDP growth. Until last year, there were only three
instances with negative electricity demand growth rates in Germany3
, and
they were caused by specific external shocks like the oil crisis and the
collapse of the Eastern European industries.
Exhibit 2-2: German electricity demand vs GDP 1952-2010e
OECD electricity
demand fell 4% in FY
2009, with 1Q 2010 up
1.9% again
-8
-6
-4
-2
0
2
4
6
8
10
12
14
1952
1954
1956
1958
1960
1962
1964
1966
1968
1970
1972
1974
1976
1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010e
YoYchange(%)
Electricity demand / production
GDP growth
Industrial collapse in
parts of Eastern
Europe; Reunification
Oil price
shock
Oil price
shock
Recent
financial
crisis
Source: IEA, IMF, Eurostat, Destatis, Photon International, Kohlenstatistik.de
1
Substitution effect = low interest rates stimulate borrowing and consumption rather
than savings
2
Income effect = lower borrowing costs increase disposable income
3
Germany used as example because this is where we found the longest data sets
…and weak demand
caused by ample capacity

02.09.2010
As economies grow the electricity intensity in an economy tends to grow.
This is reflected in our electricity demand estimates where we expect
electricity to increase its share of total energy demand from 13.3% in 2006
to 20.2% in 2030. As a reference, IEA’s figures1
estimate that world
electricity demand growing 2.7% p.a. from 2007 to 2015.
Exhibit 2-3: Electricity demand by region
Demand conclusion:
Developing countries
will be the primary
drivers for electricity
demand, particularly
India and China,
somewhat countered
by higher energy
efficiency.
Electricity Demand by Region
18,302
21,554
24,494
28,023
32,240
37,298
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
2005 2010 2015 2020 2025 2030
TWh
RoW: 4.1%
China: 4.7%
Japan: -0.1%
Europe: 1.8%
America: 1.2%
2005-2030
CAGR 2.8%
Source: IEA, DnB NOR Markets Equity Research
The table below shows some of the data we used for Exhibit 2-5. Today the
developing countries (including China, India and Brazil) combined represent
approximately 45% of total world electricity demand with an average
MWh/capita of 2.5. With higher economic growth than developed countries
this is expected to increase to 67% by 2030 (the population of these
countries comprise more than 80% of the world's total). However, this still
implies significantly lower electricity consumption per capita for developing
countries.
Exhibit 2-4: MWh/Capita and population growth
Our electricity demand
estimates are based
on assumptions made
for MWh/capita across
regions.
TWh Population (mn) MWh/Capita
Country 2005 2010 2020 2030 2005 2010 2020 2030 2005 2010 2020 2030
Europe
Germany: 2.4% 620 650 755 876 82 82 80 78 7.5 7.9 9.4 11.2
Spain: 0.5% 294 321 372 432 43 45 49 50 6.8 7.1 7.7 8.7
France: 2.0% 575 593 706 819 61 63 65 66 9.4 9.5 10.9 12.3
Italy: 1.2% 304 326 388 450 59 60 60 60 5.2 5.4 6.4 7.6
UK: 1.6% 398 401 477 553 60 62 65 68 6.6 6.5 7.3 8.1
Russia: 5.4% 953 1,054 1,206 1,358 143 140 135 129 6.7 7.5 8.9 10.5
Other Europe: 1.9% 1,767 1,989 2,485 3,120 281 280 278 273 6.3 7.1 8.9 11.4
Total Europe 4,911 5,335 6,388 7,608 729 733 733 723 6.7 7.3 8.7 10.5
America
Canada: 1.9% 597 651 678 734 32 34 37 40 18.5 19.2 18.3 18.3
USA: 2.0% 4,257 4,370 4,664 5,152 303 318 346 370 14.1 13.8 13.5 13.9
Latin America: 2.2% 1,171 1,386 1,818 2,327 557 589 646 690 2.1 2.4 2.8 3.4
Total America 6,025 6,407 7,160 8,213 892 940 1,029 1,100 6.8 6.8 7.0 7.5
RoW
Japan: 1.9% 1,134 1,087 1,098 1,109 127 127 124 117 8.9 8.6 8.9 9.4
China: 7.7% 2,500 3,733 5,659 8,789 1,312 1,354 1,431 1,462 1.9 2.8 4.0 6.0
South Korea: 4.4% 397 444 517 695 48 49 49 49 8.3 9.2 10.5 14.1
India: 6.4% 709 886 1,514 2,465 1,131 1,214 1,367 1,485 0.6 0.7 1.1 1.7
Other RoW: 3.0% 2,626 3,662 5,687 8,418 2,273 2,492 2,914 3,372 1.2 1.5 2.0 2.5
WORLD 18,302 21,554 28,023 37,298 6,512 6,909 7,648 8,309 2.8 3.1 3.7 4.5
Source: UN, IEA, DnB NOR Markets Equity Research
Our electricity demand estimates are based on 1) energy intensity, 2) GDP
3) electricity intensity and 4) population growth. All these vary across
1
WEO 2010

02.09.2010
regions and ultimately provide an MWh/capita result. The population
estimates are according to UN's moderate population prospects scenario.
Exhibit 2-5 below shows a selection of countries for which we have
modelled energy consumption development and compared them to
consensus GDP growth estimates and UN population projections. We
expect developing countries like China and India to demand and need much
more energy per person: currently they use only tiny fractions of what the
developed world does. Russia’s leap on MWh/Capita is explained by the
expected 10% drop in their population from 2005 to 2030, and with our
estimate of 1.3% annual energy consumption growth, together implies a
gradually less efficient energy market and higher use per person.
Exhibit 2-5: Annual electricity use per capita
We expect electricity
consumption per capita
among different
countries to converge
Percentage after
country represents
annual GDP per capita
growth
2008 largest
electricity users:
Country TWh %
USA 4,355 21 %
China 3,451 17 %
Japan 1,085 5 %
Russia 1,023 5 %
India 781 4 %
Germany 633 3 %
Canada 633 3 %
France 575 3 %
Other 7,939 39 %
Total 20,475 100 %
Electricity use and GDP per capita
2005, 2010e, 2020e and 2030e (big dot is 2030)
Germany: 2.4%
France: 2.0%
Italy: 1.2% Canada: 1.9%
USA: 2.0%
China: 7.7%
India: 6.4%
OtherRoW:3.0%
Russia: 5.4%
Japan: 1.9%
1
10
100
- 2 4 6 8 10 12 14 16 18 20
MWh/Capita
GDPpercapita(USD'000)
1
10
100
GDPpercapita(USD'000)
Country/region with % showing
estimated nominal yearly
GDP/capita growth
Source: IEA Source: DnB NOR Markets Equity Research, EIA, World Bank, Bloomberg, UN
Demand growth is vulnerable, but aging plants must still be retired
The world is facing a slowly, but steadily growing energy problem the
coming years. This comes from the combination of
• A steadily growing demand for electricity, particularly (in percentage
terms) from developing regions of the world. In its projections
published 10 August 2010, the EIA1
projects that total US electricity
consumption will grow by 4% during 2010 and another 0.4% in 2011 –
a slower rate assuming more normalised temperatures during the next
summer. The same agency projects residential electricity prices to
grow by 0.6% in 2010 and 2.9% in 2011.
• Increasing pressure to reduce carbon emissions; of which the energy
sector is the main culprit
• An aging base of conventional energy generation assets (coal, oil and
nuclear in particular)
• In the case of nuclear, uniquely long lead-times (10-20 years) for the
construction of new, efficient, low-carbon and safe(r) plants
• The possibility of having seen peak oil; at least, there is a broad
consensus that new discoveries are unlikely to be made in easily
1
www.eia.gov

02.09.2010
accessible locations. This means the average cost per barrel of oil will
be accreted with production from new fields.
Adding to this, the geopolitical situation is such that the need for distributed
electricity generation that reduces dependence on foreign imports of oil,
gas, nuclear feedstock and to a lesser extent coal. Renewable energy is
part of the solution to this.
A mitigating factor of energy demand growth will be the strong drive
towards energy efficiency solutions. A large portion of such projects, also
referred to as the generation of “negative demand”, not only reduces
energy demand and thereby reduces carbon emissions, but also offers
positive investment IRRs.
Exhibit 2-6 below supports our assumption that we have described above:
• Electricity demand outpaces population growth. Shown by the
“long-dashed” line (Elec./Population)
• Electricity demand and GDP are correlated ~1:1. Shown by the
“short-dotted” line (Elec./GDP) shows.
Exhibit 2-6: OECD electricity usage indicators
Electricity demand will
grow faster than total
energy growth
because of economies
advancing and a
waning off coal and oil
Source: IEA
Notes:
* Elec./TFC: Relative contribution of electricity to Total Final energy Consumption;
* Elec./GDP: Electricity intensity of economic activity; Prod./Cons.: Electricity
supply self-sufficiency = Net Production / (Net Production + Imports – Exports);
* Elec./Population: Per capita electricity consumption
Energy Supply: Current new-build pace is insufficient
In addition to building new capacity to supply our projected growth in
demand for energy in general and electricity in particular, a significant
portion of existing production capacity must be replaced over the next
years. This is predominantly the case in the western world, and much less
a concern in the developing region.
If we take Europe as an example, a 1.8% annual growth of demand
translates into a supply shortage of 2,300 TWh in 2020 and nearly 4,200
TWh in 2030. Using an average load factor of 60%, this is 440 GW and 800
GW of capacity by those years respectively. In other words, by 2030
Europe needs to add and replace the equivalent of more than 80% of the
existing asset base by 2030 in order to meet this demand.
The world needs to build
and replace the equivalent
to 80 per cent of all
current capacity by 2030

02.09.2010
Exhibit 2-7: Europe has an age problem
Projected European demand vs supply from existing capacity
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029
TWh
Supply shortage: Demand @ 1.8% annual growth
Generation capacity, existing plants
Demand
Source: DnB NOR Markets Equity Research, RWE, VGB PowerTech, Electricity
Generation 2007
To put these figures into perspective, there are 196 existing nuclear power
plants in Europe that together provide a capacity of 170 GW. Considering a
nuclear power plant like the state-of-the-art 1.6 GW Olkiluoto-3 which is
being built in Finland (last update regarding commissioning is 2013, nearly
four years after the original schedule), Europe would need almost 500
similar plants over the next two decades if nuclear alone should satisfy the
expected growth in demand. According to The International Energy Atomic
Agency however, only 19 plants (see Exhibit 2-10 on page 16) with a
combined capacity of 17 GW are under construction.
Exhibit 2-8 below supports our opinion of a growing sense of urgency
concerning Europe’s electricity supply situation. The figure shows five main
types of electricity generation assets, and their respective age profiles as of
2007. For example, it shows that during the next 15 years, approximately
69 GW, or half, of the 134 GW hard coal capacities online today will have
reached the end of their planned lives. Decisions will have to be made on
whether to make expensive life extension investments, or close them
permanently.
Exhibit 2-8: European thermal power capacity trends 1960-2010
Hard coal: 74GW built
in the 1960s and '70s
Annual commissioning of power generation capacities in the EU-27 in GW *
Source: RWE (2010), Platts Database, Worldwatch Institute
Note * Adjusted net generation capacity. Lignite = Brunt kull (Norwegian)
If nuclear was to
satisfy all
replacements and new
demand, Europe
would need to build
and complete 500
new state-of-the-art
nuclear plants the
next twenty years

02.09.2010
Nuclear: Phasing out or new dawn?
In 2002, the then-ruling coalition of Social Democrats and Greens passed a
law that said all of Germany's nuclear power plants were due to go off line
by 2022 at the latest. However, it now looks like this will be delayed by 10
to 15 years, "on technical grounds", based on recent comments by
Chancellor Angela Merkel. An independent consultants' report published in
mid-August 2010 this week, indicated that such a time frame would ensure
Germany's energy needs, in terms of energy prices and greenhouse gas
emissions, are met as the country transitions to renewable energy sources.
By 2050, however, Germany still aims to have half of all energy needs
supplied by renewable energy, with nuclear and coal power continuing until
supplies can be met entirely by clean energy. A poll published on Friday 27
August found that 56% of Germans are against keeping nuclear power
plants beyond 2021.
There are three main arguments backing a phase-out of nuclear energy:
• "Chernobyl-like" incidents
• Increasingly problematic to dispose of radioactive waste; particularly
long-term, but also short-term repositories are in thin supply
• Non-proliferation of nuclear weapons, and the difficulty of separating
civilian nuclear electricity plants with military (or indeed civilian, in the
case of Iran, where this border is particularly fuzzy) nuclear arms
With fossil fuel costs at historical highs, many countries are discussing a
new look at nuclear energy as a proven technology to deliver large
quantities of base-load electricity. Nuclear's benefits are obvious: near-zero
CO2 emissions; the ability of to a certain extent to balance intermittent
wind energy production; no sensitivity to oil and coal prices; security of
supply (if your country has uranium and plutonium resources), and all this
with a proven technology.
Exhibit 2-9: The 439 operating nuclear power plants worldwide
Existing in Europe
Total 195 plants
Total 169 GW
Source: International Atomic Energy Agency (IAEA)
Hearing these arguments, many find it hard to understand why the world’s
major utilities, with strong credit ratings and cash flows, are not scrambling
to submit plans for new reactors. There are currently 61 nuclear plants
under construction where the lion's share is in China (23), Russia (11),
Korea (6) and India (4). Compared to the just mentioned 69GW of hard
coal capacity which is to close down in Europe within the next 15 years,
only 19 new plants are under construction in Europe with a total capacity of
World operational nuclear reactors by country (total 439# @ 372 GW)
0
20
40
60
80
100
120
Argentina
Armenia
Belgium
Brazil
Bulgaria
Canada
China
CzechRep.
Finland
France
Germany
Hungary
India
Iran
Japan
Korea
Lithuania
Mexico
Netherlands
Pakistan
Romania
Russia
Slovakia
Slovenia
SouthAfrica
Spain
Sweden
Switzerland
Taiwan
Ukraine
UK
USA
Numberofunits
0
20,000
40,000
60,000
80,000
100,000
120,000
TotalMWcapacity
Total MW (right scale)
No. of Units (left scale)
Benefits of nuclear:
• CO2 free electricity
• Low exposure to fuel
cost
Issues for nuclear:
• Long lead time
• Usually ends up costing
much more than
originally planned
• Lack of long-term
waste repositories
• NIMBY factor

02.09.2010
17GW. For the time being, not enough nuclear plants are being planned for
nuclear to be a substitute to the high carbon alternatives and be the
solution to the energy crises.
Exhibit 2-10: 31 Capacity of nuclear plants under construction
Under construction
in Europe
Total 19 plants
Total 17.0 GW
The Finnish nuclear project Olkiluoto-3, with its 1.6GW net capacity, was
designed to be a shiny showcase for the nuclear industry. It was originally
meant for start up in summer 2009, but various problems have delayed the
construction and the current completion date is set to be in 2013. It is
estimated to be at least 50 per cent over budget. In June 2010 the AREVA-
Siemens Consortium announced that the majority of the work is expected
to be completed in 2012 and electricity production at Olkiluoto 3 is
scheduled to start in 2013.
In July 2010 the Finnish parliament granted a license to build a fourth
reactor on the Olkiluoto site (Olkiluoto-4). As previously mentioned, Europe
would need to build around 500 plants similar to Olkiluoto-3 over the next
two decades if nuclear alone was to substitute both replacement needs and
the expected growth in demand.
Exhibit 2-11 below shows unplanned power losses from all nuclear plants in
the world. Although a range of factors can trigger these unplanned
shutdowns, it is obvious that several countries have serious challenges
linked to the predictability of supply from their nuclear sector.
World nuclear reactors under construction (total 61# @ 59GW)
0
5
10
15
20
25
Argentina
Brazil
Bulgaria
China
Finland
France
India
Iran
Japan
Korea
Pakistan
Russia
Slovakia
Taiwan
Ukraine
USA
Numberofunits
0
5,000
10,000
15,000
20,000
25,000
TotalMWcapacity
Total MW (right scale)
No. of Units (left scale)

02.09.2010
Exhibit 2-11: How safe and reliable is really nuclear?
Several countries have
serious problems with
unplanned losses of
production from their
nuclear plants.
These losses can come
from:
• Grid instability or
failure
• Environmental
factors (low cooling
pond level, deluges,
earthquakes)
• Labour strikes
• Fuel coast downs
• Lack of demand
Unplanned Capacity Loss factors
0 %
5 %
10 %
15 %
20 %
25 %
30 %
35 %
Argentina
Armenia
Belgium
Brazil
Bulgaria
Canada
China
Czech
Finland
France
Germany
Hungary
India
Japan
Korea
Lithuania
Mexico
Netherland
Pakistan
Romania
Russia
Slovakia
Slovenia
S.Africa
Spain
Sweden
Switzerland
Taiwan
Ukraine
UK
USA
World
UCL
2006
2007
2008
2009
Average 2006-09
Note 1: Number after country indicates number of reactors
Note: Unplanned capacity loss (UCL) factor is defined as the ratio of the unplanned
energy losses during a given period of time, to the reference energy generation. UCL
is energy that was not produced during the period because of unplanned shutdowns,
outage extensions, or unplanned load reductions due to causes under plant
management control. Causes of energy losses are considered to be unplanned if
they are not scheduled at least four weeks in advance. Reference energy generation
is the energy that could be produced if the unit were operated continuously at full
power under representative annual mean conditions for the unit.
Our conclusion on nuclear is that while it on paper provides an attractive
solution by i)
cost/kWh and ii)
energy stability measures, the length and
degrees of uncertainty regarding a)
plant lead-times and costs, b)
operational predictability in geologically unstable regions and c)
permanent
waste repositories, we factor nuclear in only to be a help, not a solution to
the world’s growing need for energy. Nuclear can be used as a bridging
technology until renewable energy can reliably replace it.
Energy security remains a significant driver of renewable energy
Energy security will remain one of the most important drivers behind
renewable energy in the coming years. The underlying concern is the same
everywhere: Countries need secure and inexpensive access to energy to
see continued economic growth. The main reason for the growing concern
is the high fossil fuel prices and uneven distribution of oil production and
consumption in the world, see Exhibit 2-12.

02.09.2010
Exhibit 2-12: Energy security and oil supply “deficits”
Supply
(million barrels per day) 2006 2007 2008 2009 2010
OECD 21.6 21.5 20.9 20.8 20.4
USA 8.3 8.5 8.5 8.9 9.0
Canada 3.3 3.4 3.4 3.4 3.4
Mexico 3.7 3.5 3.2 2.9 2.7
North Sea 4.8 4.5 4.3 4.0 3.7
Other OECD 1.5 1.5 1.6 1.6 1.6
Non-OECD 63.0 63.0 64.5 63.1 64.3
OPEC 34.7 34.4 35.7 33.9 34.5
Former Soviet Union 12.2 12.6 12.5 12.8 13.0
China 3.9 3.9 4.0 4.0 4.0
Other Non-OECD 12.2 12.1 12.3 12.5 12.8
Total World 84.5 84.4 85.4 83.9 84.7
Non-OPEC Production 49.8 50.0 49.7 50.0 50.2
Consumption
(million barrels per day) 2006 2007 2008 2009 2010
OECD 49.5 49.2 47.6 45.5 45.4
USA 21.0 21.0 19.8 19.0 19.2
Canada 2.3 2.3 2.3 2.2 2.3
Europe 15.7 15.3 15.3 14.7 14.6
Japan 5.2 5.0 4.8 4.3 4.1
Other OECD 5.3 5.5 5.4 5.3 5.3
Non-OECD 35.4 36.8 37.9 38.2 39.2
Former Soviet Union 4.2 4.2 4.3 4.2 4.1
Europe 0.8 0.8 0.8 0.8 0.8
China 7.2 7.6 7.9 8.1 8.4
Other Asia 8.8 9.1 9.2 9.2 9.3
Other Non-OECD 14.4 15.1 15.7 16.0 16.6
Total World 84.9 85.9 85.5 83.7 84.6
Source: EIA
Also refer to Exhibit 4-3 on page 34 for details on how USD 11 trillion was
spent on oil by oil importers to OPEC from 1975-2009, with Saudi Arabia,
Iran and the United Arab Emirates the biggest benefactors. In addition,
IEA estimates that OPEC will pocket another USD 28 trillion for oil and gas
exports in the period 2008-2030.
As discussed through the preceding pages, the need for new production
capacity is expected to increase significantly the next years, and even
without growth in demand, the problem of aging energy plants will require
capacity to be replaced. The governments around the world are then faced
Oil "deflicts" (negative) or "surpluses" (positive)
-20
-10
0
10
20
30
40
USA Canada Other OECD Former Soviet
Union
China Other Non-
OECD
mbpd
2006
2007
2008
2009
2010e*
Estimated OPEC
revenues from oil and
gas exports 2008-
2030: $28 trillion.

02.09.2010
the following problem: If new generation capacity is based on fossil fuel,
dependence of potentially unstable regimes will increase in the future.
Examples of energy security concerns are China’s future availability of coal
and Europe’s dependence of natural gas from Russia (again, there is
speculation that supplies of Russian gas to Ukraine will be shut down, as
issues of payment for deliveries persist). China’s massive investments in
renewable energy and EU's aggressive targets for renewable energy in
2020, are, at least partly, openly motivated by energy security.
Electricity prices likely to rise
The electricity price is the single most important long-term driver for
renewable energy, and for renewable sources like solar and wind to capture
significant market shares in the future, they must be competitive without
subsidies.
Short-term, the electricity price (before transmission costs and taxes) is
determined by the marginal – the last kWh of – electricity, see Exhibit
2-13. In most markets, this is gas and/or coal, due to the relative short
start-up time and their high fuel costs. Hence, the current base load prices
in deregulated markets like Germany equal their respective costs of
producing electricity.
Exhibit 2-13: The marginal plant principle in Germany
"Must run" is hydro,
wind and CHP.
CO2 costs have a
significant impact on
generation costs for
fossil fuels and thus
electricity prices
Source: RWE 2010
Notes: 1)
OCGT: Open-Cycle Gas Turbine. 2)
CCGT: Combined-Cycle Gas Turbine. 3)
Must run: run-of-river, wind, CHP.
Long-term, the electricity prices are determined by the cost of new
capacity. And to build new capacity, decent returns on invested capital are
needed. This, rather than the marginal costs that we observe today, is the
benchmark for renewable sources. The main reason is that renewable
electricity generation is not expected to replace existing capacity, but
rather to reduce the share of fossil fuels in new capacity needed the
upcoming decades. Hence, the theory behind electricity prices is relatively
straightforward in a deregulated market with no limitations in transmission
capacity:
Short-term, it is the marginal cost of electricity production ("the marginal
plant") that sets the electricity prices.
Long-term, utilities need a certain return on invested capital in order to
ensure a dynamic efficient market with new production capacity coming
online.
Coal and gas provides
the marginal kWh and
therefore defines the
electricity price
Long-term,
renewables must be
bench-marked against
other new-build costs,
not today’s electricity
prices

02.09.2010
In Exhibit 2-14 we show our high-low estimated costs of electricity
production, including capital expenses. Our calculations show that wind
already today is competitive with conventional sources used for electricity
production. This is especially the case when including possible costs related
to CO2 emissions. For solar, the financial crisis has driven the sector to
close the gap on the other power generating resources.
Exhibit 2-14: Cost of new electricity production by source
From last year's
report, the solar mid-
point is down $1¢ and
the low point down
$3¢, while the cost of
conventional energy
sources is revised
upwards $1-3¢.
MPR – Market price
referent
California's estimated
cost of electricity
generation from a
new, combined-cycle
natural gas power
plant
Levelised Cost of Energy (LCOE)
Discounted lifetime costs over lifetime production
5 4 4 5
9
13
3 4 3
5
7
14
7
9 8
11 12
24
6 6 7 8
11
25
10
14 13
21
16
47
11 10
13 14
18
45
0
10
20
30
40
50
60
Nuclear
Coal
Nat.Gas
(CC)
Nat.Gas
(CT/ST)
Coal(CCS)
Oil
Hydro
Geothermal
Biomass
Wind
Onshore
Wind
Offshore
Solar
Conventional Renewable
UScent/kWh
CO2 cost
Low-high range
Cal. MPR 2011 (20-yr)
Base case
In most markets today, fossil fuels are the marginal cost of electricity
production. Exhibit 2-15 below illustrates the world’s ten largest energy
consumers’ respective shares of electricity sources. The mix varies greatly
from market to market!
Exhibit 2-15: Electricity supply 2008 by market and source
Examples:
• USA: 70% from coal
and gas
• France: 77% from
nuclear
• China: 67% from
coal
• Italy: 54% from gas
• India: 81% from
coal
Electricity generation by source
(shares of total)
0 % 10 % 20 % 30 % 40 % 50 % 60 % 70 % 80 % 90 % 100 %
OECD: 10,702 TWh
USA: 4,355 TWh
China: 3,451 TWh
Japan: 1,085 TWh
Russia: 1,023 TWh
India: 781 TWh
Germany: 633 TWh
Canada: 633 TWh
France: 575 TWh
Italy: 318 TWh
Spain: 309 TWh
Coal Oil Gas Nuclear Hydro Other renew. Other
Source: DnB NOR Markets Equity Research, IEA
One important fact to keep in mind when comparing cost of electricity is
predictability of future cost. The last two years have shown us that future

02.09.2010
price of fossil fuels are very difficult to predict and the future generating
cost is not determined by spot prices. Adding the probability of a future
CO2-tax, return on investment in a new coal or natural gas plant is very
unpredictable. This is a significant advantage for renewable energy, since
production cost (mostly capital cost) is known for the next 20-25 years.
Electricity markets are very heterogenous
The world electricity market is impossible to analyze as one single entity
due to widely different government price regulations and limitations in the
transmission capacities, generation portfolios, marginal production costs
and source etc. Often, prices are regulated with the government setting the
electricity price and subsidizing the power producer if they produce power
with losses. Either the customers or the tax payers pay the true cost of
electricity – the only difference is that in the latter case it is not visible on
the monthly bill from the utility.
Furthermore, in deregulated markets there may be different prices in
different regions due to constraints in the transmission capacity. An
example is Norway; 2008 gave very low prices in the southern parts due to
high water reservoir levels, while the Northern parts saw significantly
higher prices, for the opposite reason. It is important to differentiate
between wholesale price and retail price to analyze the competitiveness of
the different energy sources used for electricity production. In Exhibit 2-16
we show a breakdown of the retail price for a kWh in Germany (January
2009).
Exhibit 2-16: Cost break down for a German kWh (23.69
EURc/kWh)
The German consumer’s
electricity bill as of April
2010
• Price: EUR 23.7ct/kWh
• REA surcharge: 2.05ct
January 2009
• Price: EUR 22.7ct/kWh
• REA surcharge: 1.13ct
Assumptions: 3,500 kWh per year consumption, 19% VAT, wholesale prices for
prorated purchases
Source: RWE, Bundesverband der Energie- und Wasserwirtschaft e.V. (German
Energy and Water Association), April 2010.
The wholesale price for electricity is only a small portion (34%) of the
consumer’s electricity bill. The difference between wholesale electricity price
and consumer prices is important in discussions on grid parity.
When solar companies discus grid parity of PV installation, it is usually seen
from the consumer's perspective. On that basis, grid parity will be reached
when a PV-system can be installed on a roof and produce power at a lower
cost than the price of buying it in the market (EUR 22.7ct /kWh in the
example above). Hence, since electricity is produced locally (no grid needs)
the PV system’s owner can include grid fees and taxes in addition to the
wholesale price of electricity for the purpose of comparison.
For utilities or IPPs, on the other hand, the picture is completely different.
Their investment conclusion is based on the wholesale price. Since the
truly big volumes of demand for renewable energy will have to come from
utilities, it is in our view correct to mark the cost of renewables against this
benchmark. Hence, the solar industry is still some way from reaching grid
parity.

02.09.2010
3. Estimating cost of new electricity
production (LCOE)
What is LCOE and why do we need it?
Levelized cost of energy (LCOE) is the net present value of all the costs
connected to the energy technology investment divided by the net present
value of the energy generated during the expected lifetime of the
technology. LCOE gives an estimate of the cost per kWh which makes
different energy technologies comparable. When compared to local
electricity prices (or subsidies) it determines if a specific energy technology
project is economical profitable. It also takes the different investment
patterns and returns on investment into account.
Key findings: Wind can compete without subsidies
Our calculations show that in favourable locations, onshore wind can cost as
little as USD 0.05-0.06 per kWh, but a more typical cost is USD 0.07-0.10
per kWh. This is competitive, excluding subsidies, with conventional energy
sources like coal, gas and hydro.
At a typical cost of USD 0.20-0.30 per kWh, solar PV still has quite a
distance to go before reaching grid parity on a broad level.
However, as we discuss in the following paragraph, the variations from
country to country and in between regions are so significant that a global
conclusion is impossible to reach. An LCOE evaluation will only yield
"proper" results when made for a specific project, taking into account local
and regional grid capacities, load curves and demand curves, availability
and predictability of feedstock (coal, gas etc) and many more factors.
LCOE: Sensitive to the different cost parameters
The levelized cost of energy (LCOE) for the different electricity sources is
very sensitive to the different cost parameter assumptions. Fuel and carbon
prices, construction costs, load factors, lifetimes, lead times and discount
rates will deeply affect the cost results. Uncertainty drives up the costs
through higher discount rates for all technologies. This is specially the case
for low carbon technologies due to their higher investment costs. The
competitiveness of solar, wind and hydro is also very dependent on the
local characteristics of each particular market.
Pros and cons of the different technologies
It is impossible to say that any one technology has an overall advantage
over the others on a global scale – not even regionally. That comes from
the wide dispersion of actual and estimated cost data gathered by the IEA1
.
Global LCOE comparisons can therefore only be done for illustrative
purposes – however each technology nevertheless has an inherent set of
traits that sets it apart:
1
International Energy Agency (IEA): “Projected Costs of Generating Electricity”
(2010)

02.09.2010
Technology Pros Cons
Nuclear • Low-carbon
• Low fuel cost, opex
• Predictable costs
• Significant size
• Long lead time
• High capital at risk
• Long-term waste disposal
• Security
• Nuclear proliferation
• NIMBY
• High decommissioning cost
Coal • Cheap (excl CO2 and other
emissions), if close to mine
• Significant size
• Can be sited near demand
center
• Large fuel reserves
• Dirty, both on CO2 and
other pollutants
• High CCS cost
Gas • Lower carbon than coal and
oil
• Can be cited near demand
center
• Suitable for marginal
production capacity
• Still emits carbon
compounds
• Leakage of methane gas is
21 times worse than CO2
Hydro • Low-carbon
• No fuel costs
• Minimal stop/start costs
• Low maintenance
• Ease of energy storage
• Limited potential for new
sites
• Transmission costs
significant
Wind • Low-carbon
• No fuel costs
• Land area can still be used
to i.e. agriculture
• NIMBY
• Unpredictable output
• Significant transmission
costs. (especially offshore)
Solar (PV) • Low-carbon
• No fuel costs
• Cost are less scale
dependent
• Low maintenance
• Expensive CapEx.
• Unpredictable output
• Expensive energy storage
(battery technology)
The main changes since our 2009 report are;
1) Higher carbon price. We increased our future base carbon price to
$30/ton which we still believe is a conservative assumption due to more
political pressure to increase low carbon energy technologies.
2) Lower Solar PV capital expenditure due to the impressive cost
reductions throughout the value chain.
3) Different discount rates to illustrate the impact discount rates have
on total costs.

02.09.2010
Wind – onshore
Exhibit 3-1: Cost of new electricity production from onshore wind
ONSHORE WIND
Assumptions unit Low Base High
Investment Costs
Discount Rate 7.5% 7.5% 7.5%
Economic lifetime years 25 20 20
CapEx USD/kW 1,500 1,750 2,200
Capacity Factor 35% 30% 22%
Fuel Costs
- - - -
- - - -
O&M Costs
Fixed USDc/kWh 1.0 1.5 3.1
Variable USDc/kWh - - -
Externality costs
CO2 quota price USD/ton 30 50
Investment USDc/kWh 4.4 6.5 11.2
Fuel USDc/kWh - - -
O&M USDc/kWh 1.0 1.5 3.1
Externalities USDc/kWh - 0.0 0.0
Total cost USDc/kWh 5.4 8.1 14.3
Source: DnB NOR Markets
Evaluation of the cost factors
Capital cost Fuel cost O&M cost Externalities
Onshore wind is capital intensive and
the investment depends on factors like
location, existing infrastructure, and grid
connection. Construction time on the
other hand is very low, around one year.
Typical investment costs in main
markets like Europe and USA is 1.5-2.5
USD/Wp for a wind park, all included. In
China, wind parks are constructed at
close to half of this. A wind turbine
normally will stay in operation for 20
years, and depending on the wind
resources the capacity factor is 25-40%.
None The reported specific O&M costs for
wind power plants vary widely from
country to country, even in the same
region there can be significant
differences. The US Department of
Energy (2007) reported O&M costs
below USDc 1 /kWh. According to IEA
(2010 numbers) the costs vary from
0,5 to 4,2 USDc/kWh depending on the
location, size and age of the wind park.
If we assume that most parks in the
future will be more operating and
maintenance efficient, an average of
USDc 1.5 /kWh is reasonable.
Only related to
production of wind
turbine
LCOE Cost Onshore wind
81 %
0 %
19 %
0 %
Investment
Fuel
O&M
Externalities

02.09.2010
Wind - Offshore
Exhibit 3-2: Cost of new electricity production from offshore wind
OFFSHORE WIND
Investment Costs
CapEx USD/kW 3,000 3,500 4,500
Fuel Costs
- - - -
- - - -
O&M Costs
Externality costs
Fuel USDc/kWh - - -
O&M USDc/kWh 1.9 2.5 3.6
Offshore wind is more capital intensive
than onshore and the investment depends
on factors like location, existing
infrastructure, and grid connection. The
variety in CapEx depends significantly on
the different technologies used, i.e.
floating vs. bottom mounted technologies.
Offshore wind as an alternative to onshore
has just recently started to be attractive.
Therefore investment costs are likely to
decrease steadily from today's values.
Typical investment costs in Europe today is
3-5 USD/Wp, all included. A wind turbine
will normally stay in operation for at least
20 years (some expect up to 25 years due
to less turbulence), but no turbine has
been tested off-shore for that time period.
There is typically better wind resources
off-shore, giving a capacity factor of 35-
55%.
None There are few offshore wind farms in
operation and O&M costs are thus
more uncertain than for onshore. IEA
(2010) collected data from eight
different offshore wind farms where
O&M costs varied from USDc 1.0 to
USDc 5.0 per kWh. IEA expect O&M
costs to drop to USDc 1.5 – 2.0 on
average over the next decade, but
stated that the assumptions were
subject to high uncertainty.
Only related to the
production of the
wind turbines and
base structures.
LCOE Cost Offshore wind
0 %
23 %
0 %
77 %
Investment
Fuel
O&M
Externalities

02.09.2010
Solar - PV
Exhibit 3-3: Cost of new electricity production from PV
SOLAR
Investment Costs
CapEx USD/kW 2,000 3,000 4,000
Fuel Costs
- - - -
- - - -
O&M Costs
Externality costs
Fuel USDc/kWh - - -
O&M USDc/kWh 1.61 2.45 4.36
Source: DnB NOR Markets
PV is highly capital intensive. However,
the cost is less scale dependent than other
renewable energies, meaning it can be
installed in small, decentralized units,
without making each kWh hopelessly
expensive. Investment costs generally
reflect the level of support mechanisms in
each market, and therefore vary
significantly. The fallout of the Spanish
market in 2008 was countered by the
record breaking growth in Germany
resulting in a positive growth in 2009. This
resulted in a 16% mid-year FIT cut in July
2010 in Germany. Other markets have
also experienced significantly growth
which is a necessity for the growth in solar
to continue. Technological progress will
probably decrease capital costs per kW in
2011 by 10 to 20 per cent from 2010
levels, possibly even more.
None Very low. Since solar plants are a
fairly recent phenomena, real-life
and long-term data on specific O&M
costs is limited. The only moving
parts are the tracking systems, and
most are designed to last more than
20 years, many without lubrication.
In addition, the inverter will have to
be changed every 6-7 years or so.
And in regions without rain, the
panels need to be cleaned routinely.
In total, O&M costs average around
USDc 1.5-3.5 per kWh, maybe less,
and for residential systems it will be
next to nothing.
Only related to
production of the
solar module and its
components.
LCOE Cost Solar
89 %
0 %
10 % 1 %
Investment
Fuel
O&M
Externalities

02.09.2010
Nuclear
Nuclear power generated electricity has a vast potential. The existing plants
produce electricity at a very low price, and emit no CO2. However, there is
a very high NIMBY factor and waste disposal is still an environmental
concern. In addition the lead times are long, often more than 7-8 years.
Exhibit 3-4: Cost of new electricity production from nuclear
Investment Costs
CapEx USD/kW 3,000 4,000 5,000
Fuel Costs
Uranium Price USD/lbm 20 30 50
Waste disposal USDc/kWh 0.10 0.20 0.25
Efficiency 34% 34% 34%
O&M Costs
Variable USDc/kWh 0.16 0.20 0.24
Externality costs
Fuel USDc/kWh 0.83 1.24 2.07
O&M USDc/kWh 0.92 1.23 1.61
Externalities USDc/kWh - - -
The capital costs constitute a
significant part of the total LCOE, thus
the construction and red tape involved
in the investment process are the
most important factors determining
the final LCOE. According to IEA the
capital costs of 20 nuclear plants from
OECD countries lay between 2 USD/W
and 5 USD/W.
Platt’s estimated that the construction
cost for an EPR power plant is around
3 USD/Wp. However, the Finnish
Olkiluoto3 1.6 GWp nuclear power
plant under construction will realise
significantly higher costs. The plant,
scheduled for completion by 2011 at
the earliest, has run into problems
and the final cost will most likely
exceed 5 USD/Wp. Plants have low
incremental fuel cost, and achieve a
typically capacity factor of 75-90%.
The fuel cost is
approximately 15-20%
of the current
generation cost. This,
however, is based on
long-term contracts
with significantly lower
prices than spot. There
are worries regarding
future supply
constraints and fuel
costs may increase.
Waste disposal is also
included in this LCOE
estimate and is
accounted to be USDc
0.2 per kWh.
Nuclear plants have been in
operations for decades and there
exists exact information regarding
O&M cost. Nuclear Energy Institute
(NEI) has reported O&M costs of
USDc 1.29 - 1.4 per kWh in the US
every year since 2003. More
concerning is that nuclear generation
requires nuclear physicists and
engineers and hence requires highly
skilled and attractive labor. The
supply of personnel may be a
bottleneck for nuclear expansion
going forward.
Only related to
construction, the
CO2 emissions
from nuclear
generated
electricity are
minimal.
Decommissioning costs usually is accounted to be 15% of construction
costs on average and runs at the end of the plants lifetime. Due to a
nuclear power plants long lifetime, the levelised decommissioning costs are
negligible with any reasonable discount rate and therefore excluded from
this report.
LCOECost Nuclear
18 %
18 %
0 %
64 %
Investment
Fuel
O&M
Externalities

02.09.2010
Hydro
Hydro is the most competitive energy source according to our calculations,
but the supply constraint is obvious. A hydro plant is dependent on
environmental factors as waterfalls and streams, and most of the ones
viable for energy production already have a power plant installed. Therefore
the price of hydro varies and may be a lot higher than our estimates.
According to IEA, some power plants, i.e. Japan and Czech Republic, are 10
times more expensive than some power plants in China.
Exhibit 3-5: Cost of new electricity production from hydro
HYDRO
Investment Costs
CapEx USD/kW 1,800 2,800 4,000
Fuel Costs
- - - -
- - - -
O&M Costs
Externality costs
Fuel USDc/kWh - - -
O&M USDc/kWh 0.37 0.67 1.12
Hydro is a capital intensive energy
source, but measured by capital
cost per Wp it is much less
expensive than e.g. nuclear. The
capital costs vary considerably
dependant on suitable locations.
None O&M of a hydro plant is very low
compared to other power
producers. It varies between plants
and regions, but it is typically well
below 1 USDc/kWh.
Only in construction of
the plant. Hydro plants
may at some extent
threaten local
biodiversity.
LCOE Cost Hydro
12 % 0 %
0 %
88 %
Investment
Fuel
O&M
Externalities

02.09.2010
Natural Gas
Natural gas is the most versatile and economically attractive interesting
fossil fuel electricity source in the current environment. Capital
investments are comparatively low, and the externalities are significantly
lower than coal and oil. Since most new gas power plants in North America
and Europe are combined cycle power plant1
, we use these to calculate
power price from new natural gas electricity generation.
Exhibit 3-6: Cost of new electricity production from natural gas
NATURAL GAS
Investment Costs
CapEx USD/kW 1,000 1,200 1,500
Fuel Costs
Gas Price USD/Mbtu 4 6 10
O&M Costs
Externality costs
Fuel USDc/kWh 2.28 3.26 5.70
O&M USDc/kWh 0.43 0.59 0.81
Data from IEA estimated that the
construction cost for a Combined
Cycle power plant is 1-1.5 USD/Wp,
approximately 28% of the LCOE
cost of electricity. Given the short
lead-time and technological
maturity, the investment cost is
fairly transparent. Natural gas often
represents the marginal cost of
electricity and the capacity factor is
therefore usually low, often down to
10-30%. Hence, even though
capital cost is low per Wp, the cost
per kWh is high.
Gas plants are highly fuel-
intensive and the business
case is thus mainly dependent
on the projections one makes
about the gas prices vs the
electricity prices. The gas
prices vary from country to
country and the spot prices
NBP (UK) and Henry Hub (US)
where at levels half of oil-
linked spot prices (Japanese
LNG) in summer 2009. Since
then, spot prices have
increased, and we estimate a
gas price of around USD 6 per
MBtu.
O&M Costs equals less
than 10% of the levelised
cost of electricity
generated from gas
plants.
While the CO2 emissions
are in a different league
than nuclear, hydro and
other carbon neutral
energy sources it is also
in a different league than
its fellow fossil fuel
sources. Coal emits 50%
more CO2 than gas
generated electricity. But
even so, given today's
CO2 quota price the
externality cost/kWh is
approximately 25% of
cost cost/kWh.
1
In a combined cycle power plant (CCPP), or combined cycle gas turbine (CCGT)
plant, a gas turbine generator generates electricity and the waste heat is used to
make steam. This steam is then used to generate additional electricity via a steam
turbine. The last step increases the efficiency of electricity generation to around 60%
for state-of-the-art power plants.
LCOE Cost Natura Gas
28 %
42 %
8 %
22 %
Investment
Fuel
O&M
Externalities

02.09.2010
Coal
Coal is by far the most important electricity source in the world contributing
more than 40% of all electricity produced. While generation costs
historically have been extremely low, explaining its vast impact, the current
coal prices and environmental concerns are turning coal into a high cost
electricity source.
Exhibit 3-7: Cost of new electricity production from coal
COAL
Investment Costs
CapEx USD/kW 1,000 2,500 3,500
Fuel Costs
Coal Price USD/s.ton 60 75 100
O&M Costs
Externality costs
Fuel USDc/kWh 1.99 2.37 3.32
O&M USDc/kWh 0.66 0.86 1.07
Capital cost per MW is high
for coal, but high capacity
factor reduce the capital cost
per kWh. Platts estimates
and IEA market data indicate
a construction cost for a
supercritical, pulverized coal
plant is around 2 -3 USD/Wp.
This implies that capital costs
comprise ~32% of the LCOE.
Up till 2006 the fuel costs were
negligible, but when coal drove
though USD 100/short ton the fuel
costs became a major cost driver.
Some countries (i.e. Australia and
the US) are not subject to the
fluctuations of the international
market. They operate with
domestic coal prices below the
current spot price.
A coal plant is labor
intensive and the O&M
costs will vary depending
on the local salary level.
Coal plants emit
0.95kg/kWh thereby being
the worst polluter in the
electricity sector. With a
CO2 quota price of ~30
USD/ton this equals 2.73
USDc/kWh. If CO2 quota
prices were to increase to
USD 75/ton the cost of
CO2 would exceed the
entire low-cost scenario.
LCOE Cost Coal
32 %
10 %
31 %
27 %
Investment
Fuel
O&M
Externalities

02.09.2010
Discount rate sensitivities
High discount rates increase the costs of investments. Some technologies,
especially low carbon technologies, have high overnight costs and therefore
are highly impacted by the discount rate. It has been a norm to set
discount rates at 10%, but with the current scenario of low economic
growth and corresponding low interest rates, discount rates should be
expected to be lower. Exhibit 4-9 illustrates the impact on LCoE from 5.0%,
7.5% and 10.0% discount rate assumptions.
Exhibit 3-8: Discount rate impact on total generation cost
Discount rate sensitivities on Low Case estimates
13.7
3.5
4.0
4.1
2.6
8.0
5.6
13.2
14.5
3.8
4.5
5.0
3.5
9.3
6.6
16.2
15.4
4.2
5.0
5.9
4.5
10.8
7.7
19.6
0
5
10
15
20
25
30
35
40
45
Oil Coal Natural
Gas
Nuclear Hydro Wind
Offshore
Wind
Onshore
Solar
USDc/kWh
5.0 %
7.5 %
10.0 %
Discount rate sensitivities on Base Case estimates
22.2
8.1
7.1
5.6
4.2
9.7
6.9
19.9
23.9
8.9
7.7
6.8
5.6
11.3
8.1
24.5
25.7
9.8
8.3
8.0
7.1
13.0
9.4
29.5
0
5
10
15
20
25
30
35
40
45
Oil Coal Natural
Gas
Nuclear Hydro Wind
Offshore
Wind
Onshore
Solar
USDc/kWh
5.0 %
7.5 %
10.0 %
Discount rate sensitivities on High Case estimates
35.8
12.2
11.5
7.5
6.1
12.8
9.9
27.8
38.4
13.3
12.2
9.0
8.2
14.8
11.4
33.9
41.1
14.6
13.0
10.7
10.3
17.0
13.0
40.5
0
5
10
15
20
25
30
35
40
45
Oil Coal Natural
Gas
Nuclear Hydro Wind
Offshore
Wind
Onshore
Solar
USDc/kWh
5.0 %
7.5 %
10.0 %

02.09.2010
4. Political framework
The political framework is important to the renewable energy industry since
demand still depends upon subsidies in various shapes and sizes in order
for prices to be competitive with conventional forms of electricity.
Drawing out a comprehensive overview is both a daunting and hopeless
task, given the complex structure of policies, their lack of comparability
across borders and simply the sheer number of different legislations that
support the absorption of renewable energy.
In the paragraphs below, we draw some headlines of the most important
policies. But first, it is important to put things into perspective:
How expensive are renewable energy subsidies really?
In 2008, the 20 largest non-OECD countries subsidised oil, gas and coal
products by $233 billion, in order to keep the retail or wholesale price
below the true market level. It should be noted that many of these
countries acknowledge the cost to their societies from these support
mechanisms, and therefore have plans to fade them out over time. One
conclusion from the G20 summit in June 2010 was to phase out subsidies
for “inefficient” fossil fuels in the medium term, but no concrete solutions or
strategies were proposed.
Exhibit 4-1: Non-OECD energy subsidies
USD 233 billion spent
in 2008 alone to
subsidise oil, gas and
coal prices by largely
developing countries
Non-OECD Energy subsidies (2008)
56.4
51.1
38.7
25.2
23.6
17.9 17.3
15.7 15.2
9.5
43.5
313.9
0
10
20
30
40
50
60
Iran
Russia
China
SaudiArabia
India
Venezuela
Indonesia
Egypt
Ukraine
Argentina
Next9
(aggregated)
Total(right
axis)
USDbillion
0
60
120
180
240
300
360
USDbillion
Electricity
Coal
Gas
Oil
Source: IEA December 2008, DnB NOR Markets Equity Research
A common objection to renewable energy is the "high cost to society"
because of the subsidies involved. However, it has been estimated by New
Energy Finance that the world's governments in 2009 spent USD 43-46bn
in direct subsidies and support for renewable energy projects and
technologies. The largest single program was Germany's, where the FiT
cost ratepayers an estimated USD 9.6bn. The US was the country with the
highest total subsidies totalling USD 18.2bn, through a large number of
different federal and state programs.
World subsidies for
renewable energy:
USD 43-46bn in 2009

02.09.2010
Overview of world subsidies for solar and wind
Exhibit 4-2 and Exhibit 4-11 shows a brief overview of current wind- and
solar feed-in tariffs in key countries. The tariffs typically guarantees grid
access and long term contracts with purchase prices based on the cost of
renewable energy generation. The tariffs depreciate over time as renewable
energy generation costs decrease due to technological progress and cost
efficiency improvements. Some counties set a cap to prevent renewable
investment booms which can result in an overheated market. This was the
case in Spain in 2008.
The rightmost column in Exhibit 4-2 below shows the present value of
ground-mounted PV system tariffs in some of the countries. The values are
calculated with a 7% pretax cost of capital. Compared with the module and
inverter prices, installation costs and other costs, a best in class ground
mount PV system in 2010 is estimated by New Energy Finance to be
$3.6/W. Many markets, and especially Israel, are therefore very lucrative
markets to invest in solar energy at the moment.
Exhibit 4-2: Current Solar Feed-in Tariffs in Key Countries 2010
"Present value of
tariffs" indicates
discounted future
revenue from
electricity sales or FiTs
per W on an installed
PV system.
PVoT compares to a
best-in-class system
cost of USD 3.60/W
Country Roof-Top
(EUR/kWh)
Free-field
(EUR/kWh)
Term
(Years)
Present
value of tariffs
($/W)
USA*
California 0.07-0.11 0.07-0.11 10-25
Florida 0.25 0.22-0.25 20
Illinois 0.52 0.52
New Jersey 0.28 0.28
Canada (Ontario) 0.43 0.33 20 5.61
China 0.36 0.21
Japan 0.39 0.39 15
Korea 0.24-0.34 0.24-0.34 20
Czech Rep. 0.49-0.50 0.49-0.50 20 5.99
Spain 0.29-0.31 0.29 5.21
France 0.29 0.31-0.38 20 4.96
Germany 0.26-0.33 0.24 20 3.02
2011 (Max deprec.) 0.23-0.29 0.21 20 2.63
Italy 0.38-0.42 0.35-0.39 20 6.14
UK 0.29-0.41 0.29 25 3.61
Israel 0.44 0.40 10.05
Source: DnB NOR Markets Equity Research, PV-tech.org, Bloomberg NEF
* With July exchange rates
Objective of policies 1: Reducing the dependence on fossil fuels
The International Energy Agency (IEA) expects the market share of OPEC
to increase from 2008 to 2030 as non-OPEC production remains largely flat
over this time period leaving the supply gap to be filled by OPEC. This is
going to heighten concerns about OPEC pricing and production policies.
Exhibit 4-3 below shows the inflow of money into OPEC as estimated by the
US Energy Information Administration (EIA). It shows that from 1975 to
2009, a total of USD 11.1 trillion was paid from oil importers to OPEC, with
Saudi Arabia, Iran and the United Arab Emirates being the largest
benefactors, receiving USD 2,536bn, USD 794bn and USD 732bn
respectively. Amounts are in real terms (2000-dollar).
Payment for oil
from 1975-2009:
* Saudi: $ 2.5 trillion
* Iran: $ 0.8 trillion
* UAE: $ 0.7 trillion

02.09.2010
Exhibit 4-3: OPEC net oil export revenues
Yearly revenues
OPEC Net Oil Export Revenues real (2000$B)
406
421
433
380
543
650
522
329
258
242
202
115
145
124
159
200
160
167
145
154
169
201
192
127
171
280
220
212
255
348
511
593
634
859
510
662
711
0
100
200
300
400
500
600
700
800
900
1,000
1975
1977
1979
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
2011
USDbillion(2000)
Venezuela
UAE
Saudi Arabia
Qatar
Nigeria
Libya
Kuwait
Iraq
Iran
Ecuador
Angola
Algeria
Aggregated revenues
OPEC Net Oil Export Revenues real (2000$B)
11,036
12,409
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
1975
1977
1979
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
2011
USDbillion(2000)
Venezuela
UAE
Saudi Arabia
Qatar
Nigeria
Libya
Kuwait
Iraq
Iran
Ecuador
Angola
Algeria
OPEC
Source: DnB NOR Markets Equity Research, EIA
Governments around the world are increasingly seeking to reduce their
vulnerability from disruptions to supplies of fossil fuels.
One case in point is the Strait of Hormuz. On average, 16.5-17.0mbpd
passes through this 34 km narrow strait, equivalent to roughly 40 per cent
of the world's seaborne traded oil and nearly 20 per cent of total oil
demand. The consequences of a major international political crisis involving
Iran could potentially disrupt this flow of oil. Choking off supply, this would
lead to a significant short-term spike in the price of oil, with worldwide oil
spare capacity limited to 1mbpd, possibly 2mbpd. However, a blockage of
Hormuz over a longer time period is highly unlikely, given the stakes
involved. Finally, with world stocks of oil currently at 60 days (measured at
88mbpd full consumption), the world inventories would take about ten
months to dry out with these 17mbpd cut off.
Exhibit 4-4: The strait of Hormuz
An average of 16.5-
17.0 mbpd passes
through the Strait of
Hormuz. This is
equivalent to nearly
20% of the world's
consumption (~88
mbpd)
Source: Google Maps

02.09.2010
Our main concern is that while Hormuz is probably the most significant,
single risk point, there are others, albeit smaller, that seem to be
developing, and that aggregated is enough to cause concern for energy
security. We can mention:
• Russian gas supplies
• Eurasian gas pipelines
• (North) Korean situation
• Increasing occurrences of extreme weather events affecting deliveries
• …and more
Objective of policies 2: Reducing greenhouse-gas emissions
In 2005, the world emitted about 43 billion tonnes of CO2-equivalents1
.
Although the developing countries' share of this is growing rapidly, they
only accounted for a bit less than half of the total (at far lower emission
rates per capita2
). China and India alone accounted for about 25%.
The consensus in the scientific community is that worldwide green house
gas emissions need to be curbed by 50% by 2050 from their 1990 levels.
For the developed world, this translates into a preliminary target of 30% by
2020.
Exhibit 4-5: Required fall in GHG emissions
Source: UNDP, Meinshausen
Since pre-industrial times, the amount of CO2 in the atmosphere has risen
from near 280 parts per million (ppm) to around 455ppm today. This is far
higher than the natural range of 180-300ppm during the last 650,000
years, as recorded from ice-core and tree samples. This will cause the
global average temperature to rise to a level never experienced in historical
times. While some sceptics argue that the world has experienced much
higher temperatures in the more distant past, the broad consensus in the
scientific camp is that these temperature rises will significantly (and
adversely) affect the human civilization.
1
Source: IEA WEO 2008
2
In 2006, USA emitted 18.6 tonnes per capita; Russia 11 tonnes; Japan 9.5 tonnes;
EU 8 tonnes; China 4.3 tonnes; India 1.1 tonnes and Africa 0.9 tonnes. Source: IEA.
Current CO2 content in
atmosphere is much too
high and must be reduced
in order to minimize effect
on climate

02.09.2010
US Electricity supply 2009
Nuclear
20 %
Gas
24 %
Coal
44 %
Other renew.
4 %
Hydro
7 %
Oil
1 %
Source: EIA
US Policies: Ambitious targets, low FIT rates
In USA, subsidies exist on both federal, state and local levels. US states
have considerable autonomy in setting up renewable energy targets and to
decide how to reach those targets, i.e. which incentives to employ.
Federal support mechanisms
In February 2009 the American Recovery Act was signed extending two of
the most important US federal subsidies and introducing a third:
• Production Tax Credit (PTC) provides a USD 0.021 per kWh benefit
for the first ten years of a renewable energy facility's operation.
• Investment Tax Credit (ITC) is a reduction in the overall tax liability
for individuals or businesses that make investments in a variety of
pre-determined areas. Until 1 Jan 2009, the credit for solar-electric
and solar water heating residential property expenditures was 30%
of the cost with a maximum cap of USD 2,000 for residential
installation. After 1 Jan 2009, the USD 2,000 cap was lifted.
• The national Cash Grant Program gives 30% of the cost of small
solar, wind or fuel cell investment reimbursed in the form of a grant.
This grant is set to expire within the end 2010.
Exhibit 4-6: US Renewable Portfolio Standards (RPS)
Source: DSIRE
State support mechanisms
California’s target that 20% of total electricity supply should come from
renewable energy sources by 2010 has not yet been met, in spite of
California representing 50% of all solar installations in the US in 2009, with
1.1 GW cumulative capacity installed at the end of 2009 was 1.1GWp. This
is 67% of the total solar capacity in the US.
In line with the general US level, California’s subsidies are among the
lowest in the world. Still California has set a new target of 33% renewable
electricity production within 2020. Similarly New Jersey’s Renewable
Portfolio Standard (RPS) has set a target of 22.5% within 2021. Exhibit 4-2
shows that New Jersey has higher subsidy rates than California. In New
Jersey the cumulative capacity increased by 80% compared to California’s
increase of only 24% from 2008 to 2009.
Florida adopted a European-style FIT rate in Gainseville in 2009. Florida
installed 36MWp of solar electric power during 2009, which is an increase of
1200% from 2008. Some states, i.e. Illinois and Florida, have implemented
tariffs for solar similar to those in Germany. It is not unlikely that other
states will follow. European tariffs have had great success in shortening the
time remaining before the price of solar energy reaches grid parity.

02.09.2010
Some 20bn Euro has been
spent in cumulative
subsidies by German
ratepayers since the
introduction of the EEG
program in 2004.
The province of Ontario in Canada implemented in October 2009 a FIT
program similar to those found in Germany, Italy and France. These FIT
rates will be open to various types of energy technologies (bio, wind, solar,
water) and allow all types of generators. Four months after the FIT program
was implemented there were almost 1000 applications totalling 8GW of
potential renewable energy. Transmission capacity expansion is therefore a
focus area for Ontario. In April 2010 the Ontario Power Authority's (OPA)
announced the approval of 76 ground-mounted PV projects along with the
previously announced 94MW of rooftop and ground-mounted solar projects.
Germany: Lucrative tariffs spurring rapid but unsustainable growth
Germany installed 3,800 MW of new solar capacity in 2009 alone, which is
an increase from 1,500MW in 2008. In 2010 over 3GW was installed the
first 6 months, and we estimate a total of 9.2GW will be installed in 2010,
24% more than the world total in 2009.
The installation numbers from 2009 made the German government pursue
extraordinary mid-year cut in incentives of 16% in 2010. The FiT
degression intervals which depend upon installed volumes are set forth in
Exhibit 4-7 below.
Since Germany currently represents more than 50 per cent of the global PV
market, many companies are heavily exposed to the German market, and
will need to search hard for other markets for expansion to continue their
growth trend. This is especially the case for those whose business is tied to
ground mounted systems.
Exhibit 4-7: German tariffs and PV installations
Germany total 2009: 591 TWh
Oil
2 %
Hydro
3 %
Other
renew.
14 %
Coal
45 %
Gas
13 %
Nuclear
23 %
EURc/kWh, valid 1 Jan - 31 Dec 1H 2H
Category 2007 2008 2009 2010e 2010e 2011e 2012e
Free-field (not farmland) 37.96 35.49 31.94 28.43 24.26 21.11 16.67
Free-field (farmland) 37.96 35.49 31.94 28.43 0.00 0.00 0.00
Rooftop systems
< 30 kWp 49.21 46.75 43.01 39.14 33.03 28.74 22.70
30 – 100 kWp 46.82 44.48 40.91 37.23 31.27 27.21 21.49
100 – 1,000 kWp 46.30 43.99 39.59 35.32 29.60 25.75 20.34
> 1MWp 46.30 43.99 33.00 29.37 26.14 22.74 17.97
"Market corridor" (MWp installed)
Minimum 1,000 1,100 2,500 2,500 2,500
Maximum 1,500 1,700 3,500 3,500 3,500
DnB NOR estimates (MWp installed)
Installations in Germany 1,328 1,855 3,807 3,500 5,700 11,200 4,000
YoY degression 1H 2H
Category 2007 2008 2009 2010e 2010e 2011e 2012e
Free-field (not farmland) 6.5% 6.5% 10.0% 11.0% 15.0% 13.0% 21.0%
Free-field (farmland) 6.5% 6.5% 10.0% 11.0% 100.0% - -
Rooftop systems
< 30 kWp 5.0% 5.0% 8.0% 9.0% 16.0% 13.0% 21.0%
30 – 100 kWp 5.0% 5.0% 8.0% 9.0% 16.0% 13.0% 21.0%
100 – 1,000 kWp 5.0% 5.0% 10.0% 9.0% 16.2% 13.0% 21.0%
> 1MWp 5.0% 5.0% 25.0% 11.0% 11.0% 13.0% 21.0%
* Note: Degression from 2010 potentially 2.5%-point higher if preceding years' installations exceed ''market corridor'
(#) Roof-mounted: 1 April. Ground-mounted: 1 July
Intervals (MW) FiT reduction
Degression intervals Min Max Int'v. # 2011e 2012e
Under 1,500 MW 0 1,499 1 6.00 % 1.50 %
1,500-1,999 MW 1,500 1,999 2 7.00 % 4.00 %
2,000-2,499 MW 2,000 2,499 3 8.00 % 6.50 %
2,500-3,500 MW 2,500 3,500 4 9.00 % 9.00 %
3,501-4,500 MW 3,501 4,500 5 10.00 % 12.00 %
4,501-5,500 MW 4,501 5,500 6 11.00 % 15.00 %
5,500-6,500 MW 5,501 6,500 7 12.00 % 18.00 %
Over 6,501 MW 6,501 8 13.00 % 21.00 %

02.09.2010
Some 20bn Euro has been
spent in cumulative
subsidies by German
ratepayers since the
introduction of the EEG
program in 2004.
Exhibit 4-7: German tariffs and PV installations
German FiT "Market corridor" vs estimates
750 850
1,328
1,855
3,807 3,500
11,200
4,000
5,700
13% 56% 40% 105% 142% 220% -30%
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2005 2006 2007 2008 2009 2010e 2010e 2011e 2012e
1H 2H
MWp
"Market corridor" (full-year)
Installations (est.)
YoY growth
Germany: Why a cap is inevitable
In 2009, a record amount of 3.8 GW new capacity was installed, beating
even the most bullish forecasts. Almost 83,000 individual solar systems
with a total capacity of 2.3 GW were registered in the fourth quarter alone.
This year, installations are set to grow at an even higher rate nearly tripling
to 9.2 GW.
According to estimates made by the German utility company RWE (Europe's
fourth largest in terms of TWh delivered in 2009), surcharges to German
ratepayers for electricity from wind, solar and biofuels will increase rapidly
going forward. In 2008, the surcharges were EUR 9.7bn, but in only three
years this is estimated to grow by 70% to EUR 16.4bn.
Exhibit 4-8: Surcharges to German ratepayers rising fast
German renewable energy: Output vs Surcharges
20
40
60
80
100
120
140
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Estimates
REgenerated(TWh)
0
2
4
6
8
10
12
14
16
18
REAsurcharges(EURbn)
TWh actual (left)
TWh forecasted (left)
Surcharges actual (right)
Surcharges forecasted (right)
Source: DnB NOR Markets Equity Research, RWE, Bundesverband der Energie- und
Wasserwirtschaft e.V. (German Energy and Water Association), German transmission
system operators
This enormous growth is rapidly becoming a headache not only for German
ratepayers (as discussed above), but also for utilities (who are required to
absorb all the electricity coming from the PV systems). Exhibit 4-9 below
shows two scenarios of growth in the German market. One with 5% annual
growth after our 10GW in 2011, and the other with a 4GW cap from 1 Jan
2012. Couple this with Exhibit 4-10, and you clearly see the challenges to

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