European Utilities Basics Electricity Gas Industry Overview[1]

E U R O P E A N U T I L I T I E S B A S I C S - E L E C T R I C I T Y & G A S I N D U S T R Y O V E R V I E W

6 F E B R U A R Y 2 0 0 8

European Utilities Research TeamChris RogersAC +44 20-7325 9069 [email protected] LaitungAC +44 20-7325 6826 [email protected] Garrido +34 91- 516 1557 [email protected] Savvantidou +44 20-7325 0650 [email protected] Casali +44 20-7325 9023 [email protected]

For specialist sales advice, please contact:Ian Mitchell +44 20-7325 8623 [email protected]

For full JPMorgan Global Utilities Team details, please see inside cover

See page 117 for analyst certification and important disclosures, including investment banking relationships.JPMorgan 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. The analysts listed above are employees of either J.P. Morgan Securities Ltd. or another non-US affiliate of JPMSI, and are not registered/qualified as research analysts under NYSE/NASD rules, unless otherwise noted.

J.P. Morgan Securities Ltd.

Global utilities team

Chris Rogers - Germany, Nordic, UK Energy & [email protected] Savvantidou, CFA - France, Greece, UK [email protected] Garrido - Spain, [email protected] [email protected] [email protected] Keenan, CFA - [email protected] Specialist Sales advice, please contact Ian [email protected]

Andrew [email protected] [email protected] [email protected]

Grace [email protected] [email protected]

Edmond Lee, [email protected] Mirchandani – Hong Kong, Philippines [email protected] Kan – [email protected] Krishnan – [email protected] Jamal – [email protected] Chong – [email protected] Chawalitakul – [email protected] Tantri – [email protected]

Sergey [email protected]

Lilyanna Yang, [email protected] Frey, [email protected] Souza [email protected]

USAUSA

Latin AmericaLatin America

RussiaRussia

Asia PacificAsia Pacific

AustraliaAustralia

EuropeEurope

1EU

RO

PE

AN

UT

IL

IT

IE

SB

AS

IC

S

Agenda

Page

Appendix

Valuation and drivers

Renewables

Climate change

The energy value chain

2

Electricity generationNatural gas upstream sourcingTradingTransmission and distributionSupply

2

84

94

99

108

EU

RO

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AN

UT

IL

IT

IE

SB

AS

IC

S


TradingSourcing, despatch, management, proprietary

ELECTRICITYValue chain

NATURAL GASValue chain

Regulated networksTransmission &

Distribution


Distribution

Dua

l-fu

el c

ontr

acts

Fuel

sou

rcin

g

Upstream sourcing / E&P

Supply

Supply

Source: JPMorgan

Generation

3TH

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Distribution


Distribution

Dua

l-fu

el c

ontr

acts

Fuel

sou

rcin

g

Generation


Supply

Supply

Source: JPMorgan

4TH

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5TH

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Economics - the load curve

Time (Day / Year)

Dem

and

/ Su

pply

/ P

rice

/ C

ost

BaseloadDemand present most of the time (c.80%)Baseload power plants operate continuously, even when it might not be economical to do soGeneration: nuclear, lignite, r-o-r hydro, CCGTs Gas: long term contracts with long distance suppliers

Mid-meritDemand present 30 – 80% of the time, predictable variabilityGeneration: coal, CCGTs. Gas: contracts with near distance suppliers, seasonal storage and spot

Peak loadComes on and off very quicklyDemand present <30% of the time, timing of peaks predictable, levels less soGeneration: oil, OCGTs, storage hydro. Gas: spot market and daily storage

RenewablesTend to be outside the load curve on a must-take basis – run when they canImpact on environment offset partly by need for balancing power

Source: JPMorgan

Shows the order in which different plants are called upon to run based

on their variable operating cost

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Economics - the merit order

The short run marginal cost (SRMC) of the last unit required to meet demand sets the marginal price of power at any given point in time

Drives day-to-day price, based only on cost of fuel & CO2 permits

Electricity demand has to be met instantaneously by supply - electricity cannot be stored

Price tends to be set by mid-merit plant for most hours of the day

Baseload plants (hydro, coal, nuclear) have large margins since the marginal unit is typically gas-fired, which tend to have higher costs

A unit with operating cost below the current price keeps the margin

However, the long term power price is driven by the long run marginal cost (LRMC)

The cost of generating a unit of electricity when all factors of production (i.e. including capital) can be varied

If new capacity is required, a profit margin (spread) sufficient to cover all capital costs is needed

We therefore need to look at future reserve margins (system adequacy) to determine where spreads need to be

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Economics - SRMC

price

time (hours)

merit order / load curve

demand

Source: JPMorgan 8760

Which type of power plant will set the power price?

Currently ≈indifferent between building a coal or gas plant in Central Europe as SRMC are the same at prevailing market fuel prices

Other considerations, e.g. Germany reliant on Russian gas, whereas Spain uses gas from a variety of sources (pipeline and LNG) so more inclined to build gas fired power plants

Indifference between building a new clean (i.e. using CCS technology) or dirty coal plant is a function of the CO2 emission permit price

8TH

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* Worked example: attractiveness of coal vs. gas

Source: RWE Factbook 20071 including renewables and CHP2 oil, OCGT, hydro, etc.

GermanyGermany UKUK

Large proportion of low SRMC plant Large proportion of high SRMC plant

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Interconnectorand must run1

Nuclear

New hard coal

Hard coal CCGT

New CCGT

Peaking2

Min MaxHourly demandPower price

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Must run1 Nuclear

New lignite

Lignite Hard coal

New hard coal

Min MaxHourly demandPower price

Peaking2

New CCGT

9TH

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OCGT&

CCGT

Economics - wholesale pricesPrice at which electricity generators/ gas producers sell to the market

Market arrangements are based on bilateral trading between generators, suppliers, traders and customers

such as BETTA in the UK

Power exchanges have been launched in recent years to provide screen-based anonymous 24 hour trading

EEX in Germany

Powernext in France

OMEL in Spain and Portugal

GME in Italy

APX in The Netherlands

UKPX (a subsidiary of APX) in the UK

Nordpool in Scandanavia

Generators have contracts with the transmission grid for

Connection

Use of the system

Balancing services including reactive power10T

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IN

Economics - spreads

“Spark” corresponds to gas

“Dark” corresponds to coal

“Quark” corresponds to nuclear

“Dirty” = “brown”

“Clean” = “green”

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Dirty CleanSpark = power price = power price

- cost of gas - cost of gas - carbon price

Dark = power price = power price - cost of coal - cost of coal

- carbon price

* Worked example – Central European spreads

New hard coal, no CO2 capture, 2008ENew hard coal, no CO2 capture, 2008E

t/MWh€/$1t) shippingof costcoalof 1tof (price ×+

intensity CO COof price 22 ×

( )per year hours 8760factor load

return requiredcost capitallife plantcost capitalM&Op

×

×+��

��+

65

0.72t/MWh)-(25€/t ×

( )

4.1-

100087600.8

)10%1144501144(42

=

××

×++−

- Fuel cost:

- Carbon cost:

- Fixed cost:

0.3257)/1.45-(106.9 ×+

Power price

= Clean dark spread (€/MWh) =21.5

Long term new entrant breakeven price is forecast at €65/MWh

This assumes coal at $67/t and carbon at €30/t

On current (spot) commodity prices this calculation shows a new entrant would not breakeven at €65/MWh

Therefore

If commodity costs stay high, power prices will have to rise to encourage new build

If not, coal prices will need to fall to $67/t for a new entrant to breakeven at €65/MWh

12TH

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* Worked example – Central European spreads

New CCGT, no CO2 capture, 2008ENew CCGT, no CO2 capture, 2008E

1000€/$rate) heatgasof 1mmbtuof (price

××

intensity CO COof price 22 ×

65

0.37t/MWh)-(25€/t ×

( )

9.7-

100087600.8

)10%52030520(21

=

××

×++−

- Fuel cost:

- Carbon cost:

- Fixed cost:

Power price

10001.45h)5900btu/kW(12.9

××−

( )per year hours 8760factor load

return requiredcost capitallife plantcost capitalM&Op

×

×+��

��+

= Clean spark spread (€/MWh) =3.25

Long term new entrant breakeven price is forecast at €65/MWh

This assumes gas at $9.6/mmbtu and carbon at €30/t

On current (spot) commodity prices this calculation shows a new entrant would not breakeven at €65/MWh

Therefore

If commodity costs stay high, power prices will have to rise to encourage new build

If not, gas prices will need to fall to $9.6/mmbtu for a new entrant to breakeven at €65/MWh

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Economics - LRMC

European system adequacy

Nordel

UK

UCTE

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UCTE system adequacy forecast

* Includes:Installed capacity (GW)

Germany 122.3 Austria 18.3 Greece 11.8 Bosnia Herzegovina 3.9France 116.4 Switzerland 17.5 Bulgaria 11.2 Slovenia 2.9Italy 90.3 Romania 17.2 Serbia 8.9 Western Ukraine 2.5Spain 76.4 Czech Republic 16.3 Hungary 8.1 Luxembourg 1.7Poland 32.4 Belgium 16.2 Slovakia 6.8 Macedonia 1.2Netherlands 22.1 Portugal 13.9 Croatia 3.9 Montenegro 0.9

UCTE - Union for the Co-ordination of Transmission of Electricity

Association of transmission system operators in continental Europe* (i.e. excluding the UK and Scandinavia)

50 years of joint activities

Synchronous operation of interconnected transmission grids

Publishes data on forecasts of the security of supply over the next 15 years

Publication: UCTE System Adequacy Forecast 2007-20

Starts with stated build/ close plans for power plants

Then looks at potential development in demand, average load evolution

Also factors in expected changes in transmission grids and interconnections

Updated annually at www.ucte.org

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Compared to the adequacy reference margin(ARM)

ARM (GW)= peak load – load at reference time+ minimum reserve capacity

Minimum reserve capacity= 5% of national generating capacity

3 reference points— 3rd Wednesday of January at 11:00— 3rd Wednesday of January at 19:00 (close to peak)— 3rd Wednesday of July at 11:00

Estimates under ‘normal climatic conditions’ (i.e. temperature and precipitation at long term averages)

Reserve margin = RC/NGCamount of unused available capacity at peak load as a percentage of total capacity

Generation adequacyGeneration adequacy

Remaining capacity (RC)

RC (GW)= national generating capacity (NGC)

– non-usable capacity

- maintenance and overhauls

- outages

- system services reserve

– reference load

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Imports can support a system provided there is sufficient import and export capacity

Overall ‘not an obstacle to power balance management’ in the UCTE area

Sufficient transmission capacity

Import and export capacity looks likely to satisfy (RC – ARM)

Transmission adequacyTransmission adequacy

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UCTE generation adequacy forecast

Minimum reserve capacity

5%

2007E 2008E 2010E 2015E 2020E

58.9

52.2

60.7 61.3

53.7

60.765.2

57.7

67.9

41.9

34.6

42.6

-9.7

-17.6

-3.6

-30

-20

-10

0

10

20

30

40

50

60

70

80

January11:00 am

January7:00 pm

July 11:00am

January11:00 am

January7:00 pm

July 11:00am

January11:00 am

January7:00 pm

July 11:00am

January11:00 am

January7:00 pm

July 11:00am

January11:00 am

January7:00 pm

July 11:00am

rem

ain

ing

cap

acit

y(G

W)

Source: UCTE System Adequacy Forecast 2007-20

Without considerable new build/ life extension the system will be out of balance in continental Europe post-2015

5% seen as minimum ‘adequate’ to limit the risk of system interruptions such as

Brown outs (voltage dips) or

Black outs (system collapse)

NB. 1GW = 1000MW, or one large coal power station

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UCTE retrospect: reserve margin There has been large oversupply across Europe in the past

The reserve margin is expected to fall below 5% post-2015

Therefore significant reinvestment in generation capacity is needed

Source: UCTE System Adequacy Retrospect 2001-2006 and System Adequacy Forecast 2007-20All readings 3rd Wednesday at 11:00am

Minimum reserve capacity

5%

-2%

0%

2%

4%

6%

8%

10%

12%

14%

2001A 2002A 2003A 2004A 2005A 2006A 2007E 2008E 2010E 2015E 2020E

rese

rve

mar

gin

JanJuly

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Nordel system adequacy forecast

Nordel – organisation for the Nordic Transmission System Operators

Publication: Nordel Power Balances 2008-11

N.B. looks at MWh/h equivalent to the available capacity in MW

From 2008 to 2011, the Nordic system ‘is able to meet the estimated consumption… in average conditions… without imports’

Sufficient to cover ‘simultaneous peak demand without import’ in 2010-11E

Estimated production (MWh/h) – that which is available at peak

Peak Demand (MWh/h) = maximum one hour load in temperature circumstances with occurrence probability one winter during 10 years

Net power export (MWh/h)

= estimated production

- peak demand

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Nordel system adequacy forecastTemperatures corresponding to the coldest day in 10 years

Forecast net importer under peak conditions in 2008-10

Forecast to become a net exporter in 2010-11

Source: Nordel Power Balances 2008/09, 2009/10 and 2010/11Large increase in production in 2010/11 is due to a new nuclear plant in Finland

71000

72000

73000

74000

75000

76000

77000

78000

79000

2008/09E 2009/10E 2010/11E

Esti

mat

ed p

rodu

ctio

n/ p

eak

dem

and

(MW

h)

-2500

-2000

-1500

-1000

-500

0

500

1000

1500

2000

2500

Net

pow

er e

xpor

t (M

Wh)

Estimated production

Peak demand

Net power export

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UK system adequacy forecast

Publication: National Grid Seven Year Statement (SYS) 2007

3 different generation background forecasts:

SYS based total capacity (GW)

= existing generation projects

+ those proposed new generation projects for which an appropriate Bilateral Agreement1 is in place

Consents based total capacity (GW)

= existing generation projects

+ those proposed new generation projects been granted the necessary consents under Section 36 of the Electricity Act 1989 and Section 14 of the Energy Act 1976 for connection to the network

Existing or under construction total capacity (GW)

1 An agreement between National Grid and a generator for future connection to the transmission system

Existing or under construction

Consented

SYS22T

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ACS (average cold spell) peak demand base case (GW) - the combination of weather elements that give rise to a level of peak demand within a year that has a 50% chance of being exceeded as a result of weather variations alone, with base case assumptions of economic growth

Plant margin - amount by which the installed generation capacity exceeds the peak demand as a proportion of peak demand

N.B. this is a very different calculation to UCTE/ Nordpool and not wholly comparable

As generating units are not available to generate 100% of the time, in the past, large integrated power system utilities (e.g. the Central Electricity Generating Board in England and Wales) sought to achieve a plant margin of ≈ 24%

Now, the operational plant margin requirement for real time generation is generally ≈ 10% depending on prevailing circumstances

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Source: National Grid Seven Year Statement 2007

Plant margin is likely to exceed 24% over the entire forecast period, even under the conservative existing/ under construction background

This is a significant contrast to the UCTE

0

20

40

60

80

100

2007/08E 2008/09E 2009/10E 2010/11E 2011/12E 2012/13E 2013/14E

Cap

acit

y/ d

eman

d (G

W)

"SYS based" total capacity

"Consents based" total capacity

"Existing/ under construction based"

ACS peak demand (base case)

24%

0

10

20

30

40

50

60

2007/08E 2008/09E 2009/10E 2010/11E 2011/12E 2012/13E 2013/14E

Plan

t m

argi

n (%

) =

capa

city

-pea

k de

man

d/pe

ak d

eman

d

"SYS based" plant margin

"Consents based" plant margin

"Existing/ under construction based"

24TH

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Technology - thermal power generationThermal generation –

Electricity produced using a steam generating boiler

Steam drives turbine

Turbine generates electricity via an alternator (an electromechanical device that converts mechanical energy into alternating current)

Coal, oil, gas, nuclear, solar thermal, biomass, geothermal

Non-thermal generation -

Turbine is driven by energy other than steam

Hydro, wind, solar photovoltaicThermal efficiency - efficiency

with which the energy content (measured in gross calorific value) of the input fuel is turned into electrical energy by the generating station

Source: www.tva.gov

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Electricity generation resources - solid fuel

CoalCoal

Source: www.tva.gov

Hard coalCan load follow

Dense so can be sourced globally

LigniteRelatively more sulphur and ash

Less energy per tonne so needs to be alongside the mine

Lignite has a fixed cost of production so not at the mercy of the global coal market

Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, IEA, Alstom, JP Morgan estimates

Typical thermal efficiency (btu/KWh)

Typical thermal efficiency (%)

Where in load

Load factor (%)

Load factor (hr/a)

Start up time

CO2 (t/MWh)

Hard coalOld technology 9,000 38% Midmerit 66% 5,782 1-3 days 0.90New technology 7,757 44% Midmerit 66% 5,782 0.86LigniteOld technology 11,000 31% Baseload 80% 7,008 1-3 days 1.25New technology 8,100 42% Baseload 80% 7,008 1.10

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Electricity generation resources – gaseous fuel

OCGT (open cycle gas turbine) – old style, can start up quickly during peak demand

CCGT (combined cycle gas turbine) - by-product heat is used to generate additional electricity via steam cycle, optimally run base load or mid merit

CHP (combined heat and power) - by-product heat is used to warm local homes or businesses

Source: powergeneration.siemens.com

GasGas

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Electricity generation resources – gaseous fuel

Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, IEA, GEpower.com, JP Morgan estimates

The cleanest fossil fuel from a pollution perspective

CCGT can be baseload or midmerit

Latest CCGTs are highly efficient but still have relatively high operating costs in the current commodity price environment

GasGas



Where in load

Load factor (%)

Load factor (hr/a)

Start up time (from

cold)

CO2 (t/MWh)

OCGTOld technology 10,500 33% Peak load <20% <1,752 5-10 mins 0.70New technology 9,250 37% Peak load <20% <1,753 0.60CCGTOld technology 7,000 49% Midmerit 50-60% 4,380-5,256 1-2 hours 0.43New technology 5,700 60% Midmerit 50-60% 4,380-5,256 0.37

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Electricity generation resources – liquid fuel

Can start quickly during peak demand

Highest operating costs due to:

Low thermal efficiency

Low number of hours to amortise fixed costs across

Most polluting

Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, IEA, JP Morgan estimates

Source: www.tva.gov

OilOil



Where in load

Load factor (%)

Load factor (hr/a)

Start up time

CO2 (t/MWh)

Oil 12,000 28% Peak load <20% <1752 1-2 mins 0.82

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Electricity generation resources – nuclear overview

Advantages

Security of supply – reduces dependence on finite, and often imported fossil fuels

Long term resource

Environment protection – zero CO2 emissions

Uranium reserves are mostly located in stable countries and are abundant

Could be almost unlimited due to uranium’s multiple energy potentialDepends on prevalence of reprocessing

Up to 96% of spent fuel can be recycled

High capital cost but very low operating costs

Disadvantages

Take 1-3 days to start so only shut down when necessary

Need to be refuelled every 12-18 months

Chequered safety and operation history although image and statistics do not always match

NuclearNuclear

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International Nuclear Event Scale

0 – no safety significance

1 – anomaly (e.g. minor defects in pipework)

2 – incident

3 – serious incident (e.g. radioactive doses to workers sufficient to cause acute health effects)

4 – accident without significant off-site risk

5 – accident with off-site risk (e.g. severe damage to the installation)

6 – serious accident

7 – major accident (e.g. external release of a large quantity of radioactive material)

Areva estimates:

Operational incidents (e.g. uncontrolled boron dilution): 1 in 100 chance per reactor per year

Infrequent accidents (e.g. control rod withdrawal at full power): 1 in 100 to 1 in 10,000

Hypothetical accidents (e.g. control rod ejection): 1 in 10,000 to 1 in 1,000,000

Source: www.iaea.org/Publications/Factsheets/English/ines.pdf, Areva Technical Days

NuclearNuclear

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Public acceptance in the US

The political climate is favourable towardsRenewal of nuclear operating licenses and

Construction of new nuclear plants

There is much more sympathy for nuclear power now than there was a couple of years ago in terms of:

Siting (building new plants adjacent to existing ones)

Safety concerns

Environmental benefits (a key issue will be the way cap-and-trade and Renewable Portfolio Standards are implemented in the US)

The private sector is willing to build new nuclear, however…… investors are hesitant to put up capital due to the time-scale of building a plant,…

… the latest Energy Bill from Congress makes federal loan guarantees available to build several nuclear plants, but not on an extensive scale…

… Congress has not done anything about long-term storage of nuclear waste since the Yucca Mountain storage site was effectively blocked and …

… the Nuclear Regulatory Commission, which has to approve new plants and extensions of old plants, is currently profoundly under-resourced

NuclearNuclear

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Public acceptance in Europe – examples of opinionNuclearNuclear

Pro

UK government consulted on the future of nuclear power

Nuclear operators will have to cover the full costs of decommissioning and their share of the management and disposal costs

France

80% of generating capacity is nuclear

Has been generally positive as there have been no accidents and wholesale prices have been remarkably low

Nordic countries - unquestionable shift in favour

Low support for a phase-out in Sweden, despite negative attitudes in the early 1980s

2002 public debate and resulting new build in Finland

Baltics – smaller demand base seems to be leading to multinational cooperation

Anti

German nuclear closure program remains controversial

Public increasingly considering the policy unrealistic

Full moratoria in Italy and Spain

Potential for change but unlikely to be soon

Belgium

No new build after closure of the existing two plants scheduled to run til 2015-25, with potential life extension to 2025-2035

Austria - vehemently anti-nuclear

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TechnologyReliable base-load generation at stable and low cost

A complex nuclear fission process ≈an atomic kettle attached to a steam turbine

Generation I: reactors mainly being shut down end of this decade (Magnox)

Generation II: 1970s – 2050s (AGR)

Generation III: 1990s – at least 2050s (PWR, BWR)

Generation III+: improved safety and reliability, 1990s – at least 2060s (EPR)

Generation IV: will be ready to market between 2020 and 2030 (VHTR, PMBR, Fast breeder reactors)

Fusion reactors post 2050 (ITER): experimental plant under construction

Electricity generation resources – nuclear technology

Source: Areva Technical Days

NuclearNuclear

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Source: Creative Commons

AGR (Advanced gas-cooled reactor)Generation II (1960s)

Mostly used in the UK

Graphite is the moderator, CO2 is the coolant

The moderator slows down the neutrons released by the uranium fuel preventing run-away reactions

Gas picks up the heat generated by the fission reaction

Hot gas circulates past the heat exchanger

Final steam conditions at the boiler stop valve are identical to that of conventional thermal plants

… so the same design of turbo-generator is used

The control rods can be raised or lowered to adjust the reactor power 1. Charge tubes

2. Control rods3. Graphite moderator4. Fuel assemblies5. Concrete pressure vessel and

radiation shielding6. Gas circulator7. Water8. Water circulator9. Heat exchanger10. Steam

NuclearNuclear

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NuclearNuclear

BWR (Boiling water reactor)Generation III

Pressurized boiler

Light water (‘normal’ water i.e. H2O not 2H2O) is the moderator and the coolant

Bundles of uranium-filled fuel rods

Heat is produced by a fission chain reaction

Water circulating from the bottom to the top of the reactor is brought to 290°C

Generates steam, which drives the turbine

Series of strong, leak-tight physical barriers shield against radiation

— Metal cladding of fuel rods

— Metal enclosure of reactor primary circuit

— Containment of reactor

Net power output 1250MW

Reactorcore

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PWR (Pressurized water reactor)Generation III

More complex than a BWR

2 circuits

Light water is the moderator and the coolant

Water under constant pressure so it doesn’t boil –155bar higher than a BWR

Primary circuit of water at 313°C

Secondary circuit of steam heated by the primary circuit completely separate and closed

Water and steam circulate so constantly cooling down and heating back up

Unchanging and uninterrupted

Cooling circuit removes residual heat from the core –part of this water evaporates



NuclearNuclear

37TH

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EPR (European pressurised reactor)Generation III+Takes advantage of the latest operating experience and incorporates the results of French and German R&D programsHigher power, efficiency and life expectancyGenerating cost per kWh 10% lower than Areva’s latest PWRMore advanced passive safety & lower risk of human-errorLower waste production


BeyondGeneration IV potential designs:

— ‘Fast breeder’ reactors – fast neutron reactor without moderator, fully closed cycle, minimises production of long-lived waste, gas-, lead- or sodium-cooled

— Pebble Bed Modular Reactor (PMBR) – smaller size, no super-criticality risk but as-yet unproven— Advanced water designs, e.g. the very high temperature reactor (VHTR), with water at 1000°C, also allows hydrogen

production

Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, IEA, Areva-np.com, wikipedia, JP Morgan estimates

NuclearNuclear



Where in load

Load factor (%)

Load factor (hr/a)

Start up time

CO2 (t/MWh)

Nuclear - AGR 8,300 41% Baseload 60-80% 5,256-7,008 1-3 days 0.01BWR 9,200 37% Baseload 80-90% 7,008-7,884 1-3 days 0.01PWR 10,000 34% Baseload 80-90% 7,008-7,885 1-3 days 0.01EPR 9,500 36% Baseload 80-90% 7,008-7,886 1-3 days 0.01

38TH

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Electricity generation resources – renewables

Wind blows and sets the turbine blades in motion, generating power that can be converted into electricity

A steel or concrete tower with a nacelle that turns horizontally in a way such that the rotor (usually equipped with two or three blades) always faces the wind

Generation depends on:

cube of wind speed (double wind speed gives eight times more power)

square of rotor diameter (double rotor diameter gives four times more power)

density of the air (If the air is 10°C colder, density and power production increase by ≈3%. Moist air is less dense and so will lower power production)

mechanical efficiency of generator

aerodynamic shape of blades

Source: EC Energy Research

WindWind

39TH

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Source: Vestas.com

Typical hub height 80m

Typical blade length 40m

1. Rotor lock2. Pillow block3. Main frame4. Impact noise insulation5. Hydraulic parking brake6. Coupling7. Generator frame8. Control panel9. Heat exchanger10. Generator11. Gearbox12. Yaw drive13. Rotor shaft14. Rotor hub15. Pitch drive16. Nose cone

WindWind

40TH

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Biomass

Plant-derived organic matter (fix CO2 as they grow, so their use does not add to the levels of atmospheric carbon on a life-cycle basis)

E.g. forest residues, agricultural residues, pulp and paper operation residues, animal waste, landfill gas and energy crops

Co-firing in existing power plants (usually coal) can be used to reduce average CO2 emissions and potentially get ‘green certificates’

Burnt in conventional steam boilers

Biofuel

Many different conversion technologies to produce solid, liquid and gaseous fuels

Biomass gasification (release via heat)

Anaerobic digestion (release via bacteria)

Biomass & biofuelBiomass & biofuel

41TH

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Conventional geothermal applications rely on the geological coincidence of water-bearing, hot permeable rocks occurring at economically accessible depths

At fluid temperatures of 85 - 150°C, electricity generation requires the use of binary cycles, in which a working fluid is heated and vaporised in a closed circuit

The vapour drives a turbine, before being cooled and condensed, and the cycle begins again

At fluid temperatures >150°C steam can be used to drive turbines

Source: Energy Manager Training

GeothermalGeothermal

42TH

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Enhanced Geothermal Systems utilize heat stored in rocks that are technically accessible but lack the natural permeability

Hence they allow geothermal generation to be used in a wider range of locations than before

A well is drilled into >180°C fractured basement rock and stimulated to enhance the natural permeability of the fracture network and create a heat exchanger into which additional wells are drilled

Water circulated through the wells gathers heat

Source: EC Energy Research

GeothermalGeothermal

43TH

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Solar photovoltaic

PV cells transform the photon energy in solar radiation directly into electrical energy without an intermediate mechanical or thermal process

Technology is currently very expensive

Concentrated solar/ solar thermal

Optical devices focus direct solar radiation onto an area where a receiver is located

The radiation is transformed into heat in a medium (oil) and then to steam and electricity as per thermal power

Continues to work after dark until collected heat dissipates

Technology requires a very large area

Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, www.geo-energy.org/aboutGE/powerPlantCost.asp, JP Morgan estimates

SolarSolar

Load factor (%)

Load factor (hr/a)

Start up time

Build cost (€m/MW)

Offshore wind 30-40% 2,628-3,504 <30 sec 2.1

Onshore wind 20-30% 1,752-2,628 <30 sec 1.3

Biomass 40-70% 3,504-6,132 1 hour 0.8-1.2

Geothermal 95% 8,322 1 day 2.1

Solar PV 10-25% 876-2,190 instant 6.0-7.0

Concentrated solar 10-35% 876-3,066 instant 4.0

44TH

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Run-of-the-river (r-o-r)

Natural flow and elevation drop of a river are used to generate electricity

‘free fuel’

Reservoir

Energy extracted depends on the volume and on the head (difference in height between the source and the water's outflow)

Pumped storageRequires energy to pump water into reservoir - when the wholesale price is low (hence not ‘free fuel’)

Supplies peak demand - when the wholesale price is high

Not pumped Uses reservoirs that are naturally elevated

Marine

TidalUtilizes the daily rise and fall of water

Highly predictable

Not yet economically viable

WaveUtilizes the effect of the wind on the sea

Not yet economically viable

Electricity generation resources – hydroelectric

HydroHydro

45TH

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Electricity generation resources – hydroelectric

Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, JP Morgan estimates

Source: www.tva.gov

1-2 mins131415%Peak loadStorage

1-2 mins613270%BaseloadR-o-R

Start up time

Load factor (hr/a)

Load factor (%)

Where in load

HydroHydro

46TH

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Electricity generation resources in Europe

Germany, Poland and Spain have historically had large domestic coal industries

The UK, Norway and the Netherlands have been major producers of oil and gas

UK and Netherlands now in decline

New sources: Russia by pipeline, Liquefied Natural Gas by boat for elsewhere in the world

‘Dash for gas’ – gas power station new build

UK, Spain, Italy

Cleaner, cheaper, more efficient than coal

In the Nordic region ≈60% of generation comes from hydro

France (dearth of natural resources) has developed the largest nuclear capacity in Europe

Germany has launched a drive to install Europe’s largest wind fleet

Other major wind players: Spain, Denmark

47TH

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OECD Europe generation mix (see ‘European Utilities Basics - Country Profiles’ for more)

Output (2004A, TWh)Output (2004A, TWh)

Low load factor → output on average proportionally lower than capacity e.g. hydro

High load factor → output on average proportionally higher than capacity e.g. nuclear

Source: IEA and EIA

nuclear, 137.5, 17%gas, 168.4, 21%

renewables, 41.2, 5%

oil, 31.9, 4%

coal, 254.9, 32%

hydro, 169.5, 21%

gas, 663.0, 19%

nuclear, 992.5, 28.6%

oil, 132.0, 4%renewables,

160.7, 5%

hydro, 526.5, 15%

coal, 994.4, 28.7%

Capacity (2005A, GW)Capacity (2005A, GW)

48TH

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Distribution


Distribution

Dua

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Fuel

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Generation


Supply

Supply

49TH

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50TH

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Gas sourcing

Natural gas is a regional commodity

Its physical properties make it hard to transport, particularly intercontinentally without liquefaction

Most natural gas is transported in gaseous form via pipeline

Gas markets still regional rather than continental or global

European natural gas is priced using an oil-referenced formula

The widespread adoption of Liquefied Natural Gas should change the gas market from regional to global

Large natural gas consumers (especially power plant operators and retail suppliers) have incentives to hedge their physical commodity exposure as well as the basis (location) risk associated with dealing in different markets

Exploration and productionExploration and production

Source: JP Morgan ‘Oil&Gas Basics Presentation’

51TH

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Gas sourcing

Exploration and productionExploration and production

Why be involved in upstream gas?

No indigenous supply

Security

Economic hedge

If not involved upstream, generators tend to be beholden to very long term contracts (≈20 years - whereas the coal market is spot-based) with NOCs (National Oil Companies)

Major market drivers

Weather is both a demand and supply factorDemand for central heating

Hydro conditions in areas that depend on hydropower drive requirement for CCGT power

Oil price – long term contracts tend to be oil-based, take-or-buy decisions impact the natural gas market

52TH

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Gas sourcing

Natural gas is stored in inventory underground under pressure in 3 types of facilities

Depleted reservoirs in oil/ gas fields

Aquifers

Salt cavern formations

Each storage type has its own characteristics which govern its suitability

Physical (capacity, deliverability rate, porosity, permeability, retention capability)

Economic (site preparation and maintenance costs, deliverability rates, and cycling capability)

System integrity maintenance – meeting baseload requirements

Seasonal storage

Excess supply in the summer traditionally stored to meet winter demand

Increasing prevalence of air conditioning in many countries has lowered seasonality but increased demand

System balancing – meeting peakload requirements

Smoothing day-to-day

Buffer to meet unexpected demand surges

StorageStorage

53TH

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Gas sourcing

Gas providers can…

Carry out exploration and production themselves

Have a stake in a project operated by another party

Receive gas from a pipeline under contract e.g. Siberia → Spain

Receive gas from an LNG train e.g. Australia → USLNG is natural gas that is stored and transported at atmospheric pressure and a temperature of –260°F

Liquefaction Boat transportation Regasification

UK daily consumption is 301,000,000m3 (gaseous volume) of natural gasSo one tanker is enough for ≈ 1/3 of a day’s demand

One LNG boat ≈150 000m3

(liquid volume) of LNGVolume increases ≈600 times

Source: IEA, JPMorgan

54TH

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Gas sourcing

The global LNG market is small but growing rapidly

Declining US gas production means LNG is vital to satisfy demand growth and prevent price appreciation

Low European natural gas prices have historically led to a flood of shipments to US terminals

The last 2 years have seen a growing trend toward increased US imports in the spring

Major market drivers

Upstream additions (Equatorial Guinea, Egypt)

Demand patterns (hydro conditions in Spain, Norwegian flows into the UK)

Asian demand (economic growth, major Japanese nuclear plant outages)

Trans-Atlantic arbitrage

Crude oil arbitrage

Operating performance at liquefaction, export and import terminals

LNG projects are among the most expensive energy projects

Constructing a liquefaction and regasification terminal costs >€1b so there is a minimum distance threshold (compared to pipelines)

Regasification may be regulated or merchant

LNGLNG

Source: JP Morgan ‘Oil&Gas Basics Presentation’55T

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Distribution


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Generation


Supply

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56TH

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Trading

Why do utilities trade?

Risk managementFinancial

Operational

Profit opportunity

Some companies dynamically manage their energy portfolios

e.g. EdF’s trading has been very profitable

Strong correlation between oil, gas, electricity and CO2 prices

companies can enter into multi-commodity swaps

Gas price = f(oil, temperature)

Power price = f(gas, coal, CO2, temperature, precipitation)

CO2 price = f(gas, coal)

Therefore coal, oil, gas, power and CO2 can be traded in ‘pairs’ or ‘swaps’

57TH

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Distribution


Distribution

Dua

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Generation


Supply

Supply

Fuel

sou

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58TH

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Electricity transmission & distribution

2.3 – 3kV

Transmission towers

115 – 345kV

120 - 240V

Power station Step up transformer

Step down substation

Local substation

Homes and small

businesses

Distribution pole

2.3 – 34kV

Commercial and industrial

customers

Source: JPMorgan

59TH

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Drivers of network build

Growth of demand

Improvements in qualityMaintaining voltage, security of supply, preventing blackouts

Investment to make the system more robust

Change in supply profile, e.g. renewables: route grid → mesh grid

Interconnector security

Transmission network build choices

Overhead or undergroundUnderground cable installation is 2x more expensive at 11kV, 20x more expensive at 400kV than an equally rated overhead line2

Route or meshPartly a function of geography, load centres and resources

International interconnector requirement


2 Source: energynetworks.org

60TH

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Germany has a mesh grid

Italy has a route grid


Cost

System security

Source: JPMorgan

61TH

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RegulationRegulation

Needed for networks as they’re natural monopolies

Also end customer prices where competition is not effective (See ‘Energy supply’ pp. 72-80)

Main concerns

Costs for customers

Security of supply – short and long term

Government policy on energy mix, climate etc

Network regulation varies significantly:

Cost plus (a specific allowed return based on actual realised costs) e.g. France, Germany (changing next year), most US states

Incentive (regulator sets allowed revenue – may be based on current costs or what the regulator believes costs ‘ought’ to be)

e.g. UK. There are a whole range of degrees of incentive strengths

May (UK) or may not (Spain) have an explicit regulated asset value in remuneration formulae

Unitary (per MWh) or absolute (€m)

Single or multi-year

62TH

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Network regulation – key concepts

Regulatory asset/capital value/base

Allowed Return

+ Opex

+ Capex or Depreciation

= Revenue or price cap

x WA

CC

Source: JPMorgan

63TH

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RAV

Allowed Return

x WA

CC

Allowed return may be unitary (per MWh) or absolute (€m)

Has to cover interest expense and dividends

Regulatory Asset Value normally scaled over time (by depreciation and capex), may include inflation link

Weighted average cost of capital (WACC) may be

Pre- or post-tax

Real or nominal (i.e. with or without inflation)

64TH

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RAV

Allowed Return

Opex

x WA

CC

Operating expensesActual in cost plusAllowed in incentiveMay be volume based or absolute

65TH

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RAV

Allowed Return

Opex

Capex or Depreciation

x WA

CC

Capital expenditureBased on agreed outcomes in incentiveBased on defined budget in cost-plusMay be volume based or absolute

66TH

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RAV

Allowed Return

Opex

Capex or Depreciation

Revenue or price cap

x WA

CC

Revenue or price capProvides potential for outperformanceOften multi-year

67TH

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Revenue or price cap in year 1

OpexCapex or

Depreciation

Network regulation – key conceptsRAV

Allowed Return Opex Capex or Depreciation

x WA

CC

Allowed Return

Revenue or price cap in year 5

Often a downward price trajectory to induce efficiency improvements

68TH

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Opexefficiencies

Capexoutcome below

Budgetor Depreciation

longer asset life

Achieved WACCOutperformance


Allowed Return Opex Capex

x WA

CC

Year 1

Year 2

69TH

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Opexefficiencies

Achieved return(above allowed return)

If can reduce opex and/or capex, can make an achieved return > the allowed return

→ assets worth > RAB

Have outperformed the regulator’s assumptions ☺

Normally can retain outperformance in, or across periods (2 – 5 years)

Of course, with tough regulation the opposite can occur Opex

efficiencies


Allowed Return Opex Capex or Depreciation

x WA

CC

Achieved WACCOutperformance

Capexoutcome below


longer asset life

Capexoutcome below


longer asset life

70TH

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Network regulation – detailsThe regulator defines

Regulated Asset Base / Capital Value / Asset Value (RAB, RCV, RAV)

Not necessarily equivalent to the true value or book value of the assets

E.g. in UK based on EV after privatisation + capex – depreciation

In Sweden based on a computer model of optimal network as if built ‘from scratch’

Allowed return

Regulator makes assumptions on gearing, cost of debt, cost of equity

Pre or post tax?

Real or nominal?

If the regulator is correct in all assumptions (efficiency, cost of operations and capital projects, cost of capital) then the value of the business, by definition, is its RAB

Valuations are based on a premium/ discount to RAB methodology

Recent M&A transactions have occurred at a premium to RAB i.e. assuming outperformance

Revenue = allowed opex + allowed capex + allowed return

71TH

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Ways to outperform on opex

Raise employee productivity

e.g. reduce headcount

Minimise wage inflation

Invest in IT infrastructure

Reduce network losses (but not always in regulated opex)

Improve service time on maintenance

e.g. In the 2007 Gas Distribution Price Control Review, Ofgem’sconsultants (PB Power) proposed an 11% reduction in total GDN opex for 2008/09 – 2012/13, including

Work management -10.6%

Emergency -11.0%

Repairs -14.2%

Maintenance -14.1%

Opex

Opex

Year 1

Year 2

72TH

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Ways to outperform on capex

Procurement

Use an established network of suppliers

Economies of scale e.g. ‘buy in bulk’

R&D

Invest in innovative, more efficient technologies

e.g. In the 2007 Gas Distribution Price Control Review, consultants proposed an 18% reduction in total GDN net capex for 2008/09 – 2012/13, including

Local Transmission System & storage -23.4%

Connections -22.9%

Mains reinforcement -12%

Capex

Year 1

Year 2Capex

73TH

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Ways to outperform on WACC

Capital structure

Higher gearing than the regulator assumes

Lowers pre-tax WACC and provides tax shields

Cost of debt

Cheaper financing than the regulator assumesIndex-linked debt

Covered bonds

Derivatives (optimal strategy may depend on market conditions e.g. demand for different currencies)

— Fixed-floating swaps— Forex swaps

x WA

CC

Year 1

Year 2

x WA

CC

6.55%7%WACC

9%9%Cost of equity

5.5%5%Cost of debt

70%50%D/EV

AchievedRegulated

74TH

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Distribution


Distribution

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Generation


Supply

Supply

Fuel

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75TH

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Electricity and gas supplySale of electricity to the final customer

Commercial

Residential

Metering, billing and customer relationship

Retail price is ≈ sum of generation and transmission so very little value added here

Competitive metering in many countries – suppliers compete on price and service

Dual-fuel (gas and electricity) contracts

Consumer services often also provided to generate additional revenue e.g. boiler breakdown cover

76TH

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Retail / Consumer tariff regulation

In a fully competitive market there are advantages of:

Cost control (low prices)

Investment incentives

Consumer choice

Quality of service improvement

However markets are not always competitive…

… and governments like to intervene…

… therefore often tariffs are ‘managed’ or regulated

77TH

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EU tariff regulation

EU Electricity Directives

History of regulated tariffs - recent trend towards liberalisation of generation and supply

UK pioneered privatisation, deregulation and liberalisation of utilities – has not had controls on retail prices since 2002

EU pushing for free competition throughout the region‘From July 2007 at the latest, all consumers will be free to shop around for gas and electricity supplies’

In theory tariff regulation should not exist, in reality it does

Third EU competition directive for electricity and gas will seek to stamp out tariff regulation –although not immediately

78TH

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EU tariff liberalisationEC Benchmarking Report (2006) conclusions

Nordic countriesLiberalisation fully embraced

GermanyBroad acceptance – all gas and electricity customers are free to choose supplier

Pressure for unbundling of RWE and E.ON’s distribution activities

Domination by a few large players prevents effective competition

ItalyMany calling for more control of prices

Tariffs are adjusted on a quarterly basis to reflect commodity prices

FranceCentrally controlled tariffs

Liberalisation in theory but not really in practice

EdF and GdF only partially privatised

SpainTariff deficit system

The Directives have not been transposed

The regulatory framework does not allow for effective competition

79TH

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Tariff deficit

Occurs when the regulated price is < the market price

Represents both a system failure and possible upside depending on what the market prices in

We forecast shortfall in Spain: 2008E tariff deficit of €3bn

Due to internalised cost of CO2 by companies lowering sector revenues

Spanish legislation requires that utilities are reimbursed

In France GDF have forecast a gas tariff deficit of ≈€1bn

The shortfall of regulated revenues from the tariffs versus revenue that would be realised by prevailing market prices

80TH

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Unbundling

Many countries have pursued a regulatory policy of unbundling

Separation of transmission and distribution from generation and supply

Intended to increase competition by improving the fairness of network access

Many countries and corporates have resisted unbundling citing

Diversification of risk

Scale/ scope economies

Legal/ management unbundling ‘should’ be sufficient

Regulatory/ compliance oversight may be used

81TH

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The end customer bill – retail power

Taxes•VAT•Environmental•Public service

Network access•Regulated fee•Balancing costs•Transmission ¼•Distribution ¾

Generation•Pool / spot price•Cost-plus basedGas sourcing•L.T. contracts•Oil / coal link

Unliberalised – France (2007E)Total: €120/MWh

Taxes = €37/MWh•VAT

•Local taxes•CTA for pensions

•CSPE for public services

Network access = €49/MWh•7.25% pre-tax

•No inflation link•Cost plus

•Review mid 2007

Generation = €34/MWhCost plus based

Features 80% nuclearRemainder bought in Germany

Liberalised – Germany (2008E)Total: €217/MWh

Taxes and levies = €82/MWh•VAT (32.5)

•Concession fee (17.9)•Electricity tax (20.5)

•CHP act (2.9)•Renewables act (8.2)

Network access = €62/MWh•6.5% post-tax

•Inflation link for old assets•Moving to incentive

•Reviews due April 06 & new system July ‘06

Generation = €67/MWhBased on EEX

Mostly a coal systemNeed for coal / gas to replace

nuclearCO2 approx €8/MWh for gas and

€18/MWh for coalSales/marketing = €6.5/MWh

Typical retail consumer uses 3.5MWh/a

(29)

(8)

Source: JPMorgan estimates82T

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The end customer bill - European comparison

65.410.754.7Bulgaria

68.910.658.3Latvia

75.011.563.5Estonia

76.710.965.8Lithuania

71.85.766.1Greece

100.715.285.5Romania

115.027.387.7Finland

106.217.588.7Slovenia

105.615.889.8Czech Republic

120.728.692.1France

120.025.594.5Poland

121.220.8100.4Spain

118.116.2101.9Hungary

150.945.9105.0Austria

167.458.6108.8Sweden

255.4138.4117.0Denmark

156.133.2122.9Belgium

131.05.6125.4UK

151.922.7129.2Slovakia

181.645.5136.1Norway

229.089.0140.0Netherlands

149.07.0142.0Portugal

189.646.3143.3Germany

167.020.5146.5Ireland

221.856.0165.8Italy

Price with taxTaxPrice ex tax€/MWh

Comparison of power prices – Pan-Europe, 3.5MWh domestic customer, €/MWh, 2007A

Comparison of power prices – Pan-Europe, 3.5MWh domestic customer, €/MWh, 2007A

Source: Eurostat

Affordability - Retail power price % GDP/capita, 2006A

Affordability - Retail power price % GDP/capita, 2006A

Source: Eurostat

1.0%Greece

1.4%Norway

1.4%Finland

1.5%Estonia

1.5%France

1.6%UK

1.6%Latvia

1.6%Slovenia

1.6%Ireland

1.7%Austria

1.7%Spain

1.8%Lithuania

1.8%Belgium

1.8%Czech Republic

1.9%Sweden

2.4%Germany

2.4%Bulgaria

2.4%Netherlands

2.6%Hungary

2.9%Portugal

2.9%Denmark

3.1%Italy

3.1%Poland

3.2%Slovakia

3.6%RomaniaPower cost % GDP

Increasing power costs as a proportion

of GDP →political

pressure on utilities

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YV

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CH

AI

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Climate change regulation

1992 – UNFCCC (UN Framework Convention on Climate Change) established

1997 - Kyoto Protocol signed

41 industrialised countries (‘Annex 1 countries’) agreed to reduce their greenhouse gas emissions (GHGs: CO2, NOx, methane, CFCs) by a specific percentage by 2008-2012 from 1990 levels

5% cut in total globally

8% cut for EU-15 and most other European countries

These targets define each country’s volume of ‘allowed’ emissions (AAUs)

Burden sharing principle

Use of flexible mechanisms (market mechanisms, cap-and-trade schemes)

Clean Development Mechanism (CDM) – system for pollution reduction schemes in developing economies

Permits : Certified Emission Reductions (CERs)

Joint Implementation (JI) – system for pollution reduction schemes in developed economiesPermits : Emission Reduction Units (ERUs)

Emissions Trading Scheme (ETS) – EU emission permits trading schemePermits: EU Emission Allowances (EUAs)

CERs can be transferred into EUAs etc. but the total number of AAUs is fixed

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AE AE AAUAAU

CERs

EUAs

CERs EUAs

GermanyBrazil

If Germany’s actual emissions are higher than its assigned allocation it can purchase CERsfrom Brazil and transfer them into EUAs

Total AE = total AAU

AE – actual emissions

AAU – assigned allocation unit

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EU target

8% by 2010 from 1990 levels

20% by 2020 or

30% by 2020 if a broad-based global agreement on GHGs can be reached

Emissions Trading Scheme was set up

Member states are given National Allocation Plans (NAPs) for CO2 permits

Covers power, paper, steel, iron, mining, oil and cement

Import allowance for CDM/JI subject to certain limits

CO2 emission permits can be traded within each phase with banking also possible between phases 2 and 3

Phase 1: 2005-07

Phase 2: 2008-12

Phase 3: 2013-20— Includes new sectors such as airlines, aluminium, petrochemicals, etc.

Note other trading schemes will probably emerge globally, but may not necessarily be fungible with the EU ETS

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EUA price forecast

Estimation:

Long-term demand for permits

A function of EUA shortage vs demand

Allocation plans

Compliance buyers including governments

Non-compliance buyers

CER/ERU balance

Abatement opportunities – various methods of abatement have different costs

CDM/JI permits – trade at a discount to EUAs due to project failure risk

UK coal-to-gas switching

German lignite-to-coal switching

Industrial abatement (N.B little willingness for this from industrials so far)

Existing and new plants

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EUA price forecast

2008 abatement stack

Demand for abatement

The price of CO2 is determined by the

Demand for abatement

Supply of abatement

Forecast €25/t for phase 2

UK c-t-g summer

Industrial, <€20/t


UK c-t-g winter Industrial, <€27.5/t Industrial, <€30/t


German l-t-g

0

5

10

15

20

25

30

35

40

45

50

0 50 100 150 200 250 300 350 400

Volume (mt/a)

Pric

e (€

/t)

Source: JPMorgan estimates

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Carbon capture and sequestration‘Clean coal’

Capture via post-combustion, pre-combustion or oxyfuel combustion

Storage in deep geological formations, deep oceans or mineral carbonates (although UN unlikely to approve ocean & carbonation

Technology for large scale capture of CO2 already commercially available, problem is pipeline and regulation

Capturing and compressing CO2 requires energy lowers overall thermal efficiency

There are firm plans for around 8.3GW of CCS-type capacity – 51mt/year of abatement

Abatement cost estimate €28-30/t a function of:

Margin loss

(CCS plant new build cost – coal ex-CCS plant new build cost + energy loss) x CO2 avoided

Estimate: €16-17/MWh output or €24/t of CO2

Transport cost

Estimate: €2-2.5/t

Storage cost

Estimate: €3-3.5/t

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Climate change regulation outcomes

Phase 1 ETS was effectively bankrupt since there has been a surplus of permits

Currently phase 2 permits are trading at around €20-25/t

We forecast €25/t for phase 2

Emissions of 2,300mt/a, a 10% cut in NAPs vs. phase 1, 160mt total extra demand from airlines, a shortfall of 210mt/a on average and CDM/JI permit deliveries of 780mt total

Phase 3 deeper and broader

Emergence of subnational and national schemes

Extension to other GHGs, other industries

Utility sector the most impacted

Positive for revenues

Negative for costs – depending on free allocations/ auctioning

Free allocations have been positive for profits overall, but unlikely post 2012

Although windfall for low / zero CO2 emitting plants will remain

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Climate change regulation outcomes

Impact on utilities’ profits:

Marginal cost pricingHigher variable costs per MWh and higher long-term power prices

Revenue will include 100% of the price of a permit

Windfall profits are incurred if permits are allocated to thermal plants for free…

… and non-thermal plants are price takers

Degree of forward contractinge.g. E.ON and RWE have already sold forward a large part of 2008 and 2009 output so the impact of volatility of phase 2 CO2 on them will be minimal

Change in load stackA higher CO2 price will move gas-fired power plants further into the baseload compared to coal-fired

Coal-fired plants will suffer from lower volumes and hence lower profits and fixed costs per MWh

Carbon intensity relative to average will drive valuationExposure to coal vs. nuclear etc.

Exposure to generation vs. networks and supply

For more information, see our series ‘All you ever wanted to know about carbon trading’ at www.jpmorgan.com/climatechange

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EU thermal regulation: LCPD (2001)Large Combustion Plant Directive

Applies to combustion plants with a thermal output of >50 MW

Aims to reduce acidification, ground level ozone and reduce aerosol particulates throughout Europe by controlling emissions of sulphur dioxide (SO2), nitrogen oxides (NOx) and dust

Using emission limit values (ELVs)

The UK’s National Grid has warned the extra costs of coping with the implementation of LCPD could substantially increase transmission constraint costs

Set to have an impact on system costs of around £15m

≈12GW of capacity has opted out of the LCPD

Running hours of these plants will be limited on a chimney stack basis (either the whole plant is running or not) to 20,000 hours across the 8 year period to 2015

NG says it expects operators will look to maximize earnings from the remaining 20,000 hours by optimizing running and operating multiple units as a single block at the same time

Coal plant will be the most affected

For opted out coal units, the 20,000 hour limit is likely to act as a constraint on output and the costs of reserve will rise

NG has put forward 2 possible scenarios for plant operations:Summer-cold regime – generators decide to run the units over the winter and make them unavailable over the summer, either on maintenance or moth-balled

Year-round running regime – generators will focus their running hours on the peak power price periods across the year, irrespective of season

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Mapping the renewable energy space

Drivers : Climate change; Energy Security; Economics

Renewable / Alternative Energy

Transportation

Electricity

Biofuels Hybrids / Plug-ins

Traditional

New Tech

Clean Thermal

Policy regimes: Standards; Pricing/support; R&D

Nuclear Mini hydro

Wind

Onshore Offshore

Solar

PV Thermal

Equipment

Operators

Autos

Big oil

New entrants

Utilities

New entrants

Marine

BiomassCCS

Concepts Technologies Corporates95R

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Renewables

Renewables

Climate change concerns

Energy security concerns

Solar, wind, r-o-r hydro and geothermal technologies do not emit any GHGs

Pumped storage hydro uses a small amount of electricity

Biomass combustion emits CO2, but unlike fossil fuel combustion, this has not been ‘out’ of the carbon cycle for a long time

By definition, renewable energy is not finite

It allows a country to reduce its reliance on foreign imports of electricity/coal/oil/gas

Hence governments have been very keen to encourage investment in renewable energy capacity…

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Renewables capacity support mechanisms

Feed-in tariffs – fixed pricing framework with a cap-and-floor of floating prices to provide a return well over WACC

e.g. Spain RD486 and RD661

Green certificate schemes— Energy suppliers required to submit certificates to show they have sourced a certain % of supplies from

renewables— Certificates bought from a pseudo market ‘buy-out fund’

e.g. Renewable Obligation Certificates in UK

Tax credits – levy charged on all suppliers unless they qualify for an exemption

e.g. Production Tax Credit in US, CCLECs in UK

Capital subsidies – can by-pass state aid rules

e.g. Greece: 35-55% of capital cost

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EU renewables targetsEC proposals on member state targets for renewable energy as a proportion of all energy consumptionEC proposals on member state targets for renewable energy as a proportion of all energy consumption

The targets proposed on 23rd

January were harsh but widely expected and the horizon is far out

A proposal for tradeable‘Guarantee Of Origin’ (GOO) certificates would allow suppliers to meet their obligations with output from another country

Positive for suppliers and generators with pipeline in low tariff/high deliverability countries

Negative for generators in green certificate/ low deliverability countries e.g. Italy and the UK

2005 RES 2020 Target-RES Basis points/year % CAGR

Austria 23.3% 34% 71.3 2.6%

Belgium 2.2% 13% 72 12.6%

Bulgaria 9.4% 16% 44 3.6%

Cyprus 2.9% 13% 67.3 10.5%

Czech Republic 6.1% 13% 46 5.2%

Denmark 17.0% 30% 86.7 3.9%

Estonia 18.0% 25% 46.7 2.2%

Finland 28.5% 38% 63.3 1.9%France 10.3% 23% 84.7 5.5%Germany 5.8% 18% 81.3 7.8%Greece 6.9% 18% 74 6.6%Hungary 4.3% 13% 58 7.7%Ireland 3.1% 16% 86 11.6%Italy 5.2% 17% 78.7 8.2%Latvia 34.9% 42% 47.3 1.2%Lithuania 15.0% 23% 53.3 2.9%Luxembourg 0.9% 11% 67.3 18.2%Malta 0.0% 10% 66.7Netherlands 2.4% 14% 77.3 12.5%Poland 7.2% 15% 52 5.0%Portugal 20.5% 31% 70 2.8%Romania 17.8% 24% 41.3 2.0%Slovakia 6.7% 14% 48.7 5.0%Slovenia 16.0% 25% 60 3.0%Spain 8.7% 20% 75.3 5.7%Sweden 39.8% 49% 61.3 1.4%UK 1.3% 15% 91.3 17.7%EU 27 6.4% 20% 90.8 7.9%

Source: European Commission, JPMorgan estimates

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Business driversValuation driversTypical catalysts

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Business drivers

What makes a successful utility?

Generation

Transmission and distribution

Supply

Big vs. small

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GenerationGeneration

‘Success’ mainly derives from operations rather than business model

New build on time/budget

Minimise outages

Efficient fund sourcing

Efficient operating costs

Off take contracting, e.g. fixed cost contracts, PPAs ideally

Returns/ sustainability a function of type

Carbon ‘clean’ vs. ‘dirty’

Fuel price volatility/ availability

‘Correct’ funding

Diversity in a given region is important

Exposure to fuel vs. price setter

Development potential

Plant improvements - operational, environmental

Life extensions

Expansion via new plant including new regions

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NetworksNetworks

Regulatory relationshipDelivery

Constructive dialogue

Reliability

Health and safety

OpexIT – management of inventory

Sourcing at a low cost

Optimal staffing

CapexPurchasing at a low cost

Pipeline delivery within budget and on time

Partly exogenousPolitics and type of regulation

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SupplySupply

Competitive upstream sourcing

A function of the competitive environmentPeer group behaviour

Degree of consolidation

Politics

Pricing for margin vs. pricing for market share

Superior customer service to peers

Dual fuel contracts

Well hedged exposure to wholesale power prices

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Load (lower fixed costs per MWh)

Economies of scale in procurement

Economies of scale in financing

Reputation and brand nameLarge customer base

R&D possibilities, patents

Integrated utilities tend to be largerUpstream/downstream hedging

Management cost savings

Expertise

Operational diversification

Geographical diversification

Advantages of scaleAdvantages of scale

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Valuation methodsAbsolute

Discounted cash flows (DCF)/ dividend discount model (DDM) – utilities generate long term cash flows with high visibility

Premium/ discount to RAB

Sum of the parts (SOP) – useful in diversified utilitiesMultiples

DCF/ DDM

RAB-based

Relative

Traditional relative multiples – limited usefulness due to diversityP/E – more useful under IFRS

Dividend yield – generally income stocks with growth

EV/EBITDA – traditional measure, free cash flow (FCF) yield important given capex cycle

Utilities-specific multiples – according to assetSupply: EV/#customers

Generation: EV/MW, Nuclear Relative Multiples

Networks: EV/RAB

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Utilities stock price catalystsRegulation

Tariffs: e.g. unexpected (or earlier than expected) changes, politics

Networks: RAB and allowed return, e.g. expectations of a forthcoming review

Carbon: pricing and allocations

Raw materials prices

Coal, oil, gas, uranium, equipment

Wholesale power prices

Demand growth

Weather

Temperature affects demand

Precipitation drives hydroelectric generation

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Utilities stock price catalystsManagement strategy

Opex and capex plans

Short/ medium term targets

Trading statements

M&A prospects

Re-gearing potential, buy-backs, dividends

Interest rates and taxes

Development of competitive market

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AcronymsGlossaryAbbreviationsConversionsMetricsKey websitesBloomberg & Reuters codes

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Acronyms

emission limit valueELV

new electricity trading arrangementsNETAexploration and productionE&P

national allocation planNAPcombined heat and powerCHP

molten salt reactorMSRCertified Emission ReductionCER

long run marginal costLRMCClean Development MechanismCDM

liquified natural gasLNGcarbon capture and sequestrationCCS

lead fast breeder reactorLFRclimate change levy exemption certificateCCLEC

local distribution zoneLDZcombined cycle gas turbineCCGT

large combustion plant directiveLCPDboiling water reactorBWR

Joint ImplementationJIBritish electricity trading and transmission arrangementsBETTA

gas fast breeder reactorGFRadequacy reserve marginARM

EU Emission AllowanceEUAaverage revenue per userARPU

Emissions Trading SchemeETSadvanced gas cooled reactorAGR

Emission Reduction UnitERUaverage cold spellACS

European pressurised reactorEPRAssigned Allocation UnitAAU

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Acronyms

very high temperature reactorVHTR regulated asset valueRAV

UN Framework Convention on Climate ControlUNFCCCregulated asset baseRAB

Union for the Co-ordination of Transmission of ElectricityUCTEpressurised water reactorPWR

third party accessTPAphotovoltaicPV

seven year statementSYSproduction tax creditPTC

short run marginal costSRMCpublic service obligationPSO

sodium fast breeder reactorSFRpublic service contractsPSCs

super-critical water reactorSCWRpower purchase agreementPPA

renewable portfolio standardRPSEngland and Wales water regulatorOFWAT

renewable obligation certificateROCBritish electricity and gas regulatorOFGEM

royal decree (Spain)RDopen cycle gas turbineOCGT

regulated capital valueRCVnational oil companyNOC

remaining capacity RCnotification of inadequate system marginNISM

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GlossaryAdequacy reference margin = margin against the peak load +minimum reserve capacity

British thermal unit – a unit of heat equal to ≈ 252 calories, enough heat to raise the temperature of one pound of water 1°F

Load curve – order in which different plants are called upon to run based on their variable operating cost

Minimum reserve capacity = 5% of national generating capacity

Margin against the peak load = peak load – load at reference point

Plant margin - amount by which the installed generation capacity exceeds the forecast peak demand

Remaining capacity = reliably available capacity – reference load

Reliably available capacity = total generating capacity – non-usable capacity – maintenance and overhauls –outages – system services reserve

Reserve margin – amount of unused available capacity of an electric power system at peak load, expressed as a percentage of total capacity

Tariff deficit – the shortfall of regulated revenues from tariffs versus the revenues that would be realised by prevailing market prices

Thermal efficiency - efficiency with which the energy content (measured in gross calorific value) of the input fuel is turned into electrical energy by the generating station

Thermal generation – electricity production using a steam-driven turbine

Windfall profits – additional profits due to free CO2 allocations

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Abbreviations

per day/d

per year/y or /a

megawatt hoursMWh

terrawattTW

gigawattGW

megawattMW

kilowattKW

British thermal unitBtu

billion tonnes of oil equivalentBtoe or Gtoe

million tonnes of oil equivalentMtoe

tonne of oil equivalenttoe

thousand barrelskb

thousand boekboe

barrel of oil equivalentboe

million tonnesMt

million cubic feetMcf

metric tonnet

billion cubic metresbcm

cubic feetcf

barrelb or bbl

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Conversions

10.07690.1070.10.14293.9711634.1870.685Gcal

13.0011379.001.251.793349.781459052.528.58tonnes of LNG

9.350.000710.00090.00130.036110.580.03810.0062m3 of gas

100.79711099.2711.429539.681163141.876.84toe

70.5576768.990.6995127.768136.1129.294.79tce

0.25190.020127.700.02520.03601293.071.05510.1724mmBtu

0.00090.00010.090.00010.00010.003410.00360.0006kWh

0.23880.019026.250.02390.03410.95277.7810.1634GJ

1.45990.1165160.680.14620.20895.8017006.121boe

Multiply byFrom:

Gcaltonnes of

LNGm3 of gastoetcemmBtukWhGJboeTo:

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Electricity margin metrics

Reserve margin (%) = capacity reserve / demand

Capacity margin (%) = capacity reserve / available capacity

Output = Capacity x Time

[kWh] = [kW] x [h]

capacityInstalled

generatedyElectricitfactorLoad =

Load factor ≠ 1

Power plants sometimes have technical problems and have to shut down

The wholesale price may be too low for it to be economical to run the plant

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Key websites

Dti.gov.uk/energy/statistics/index.html

Iea.org

Eia.doe.gov

System adequacyUcte.org

Nordel.org

Nationalgrid.com/uk/Electricity/SYS/

TechnologyAlstom.com

Powergeneration.siemens.com

Gepower.com

Areva.com/servlet/finance/investorrelations/arevatechnicaldays-en.html

Vestas.com

EUhttp://ec.europa.eu/research/energy/index_en.htm

http://ec.europa.eu/energy/electricity/benchmarking/index_en.htm

http://epp.eurostat.ec.europa.eu

http://ec.europa.eu/environment/climat/climate_action.htm

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Bloomberg tickers

SX6P (Dow Jones Stoxx European Utilities index)

ERIXP (renewable energy index)

EMIT (electricity emission allowance)

EPWR (European electricity prices)

PWNX (French electricity prices)

ELEU (UK electricity prices)

ELGE (German electricity prices)

ELNF (Nordpool electricity prices)

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Analyst Certification:The research analyst(s) denoted by an “AC” on the cover of this report certifies (or, where multiple research analysts are primarily responsible for this report, theresearch analyst denoted by an “AC” on the cover or within the document individually certifies, with respect to each security or issuer that the research analyst coversin this research) that: (1) all of the views expressed in this report accurately reflect his or her personal views about any and all of the subject securities or issuers; and(2) no part of any of the research analyst’s compensation was, is, or will be directly or indirectly related to the specific recommendations or views expressed by theresearch analyst(s) in this report.

Important Disclosures

Price Charts for Compendium Reports: Price charts are available for all companies under coverage for at least one year through the search function on JPMorgan'swebsite https://mm.jpmorgan.com/disclosures/company or by calling this toll free number (1-800-477-0406).

Explanation of Equity Research Ratings and Analyst(s) Coverage Universe:JPMorgan uses the following rating system: Overweight [Over the next six to twelve months, we expect this stock will outperform the average total return of thestocks in the analyst’s (or the analyst’s team’s) coverage universe.] Neutral [Over the next six to twelve months, we expect this stock will perform in line with theaverage total return of the stocks in the analyst’s (or the analyst’s team’s) coverage universe.] Underweight [Over the next six to twelve months, we expect this stockwill underperform the average total return of the stocks in the analyst’s (or the analyst’s team’s) coverage universe.] The analyst or analyst’s team’s coverage universeis the sector and/or country shown on the cover of each publication. See below for the specific stocks in the certifying analyst(s) coverage universe.

Coverage Universe: Chris Rogers: British Energy (BGY.L), Centrica (CNA.L), Drax Group Plc (DRX.L), E.ON (EONG.DE), EEN (EEN.PA),Fortum (FUM1V.HE), International Power (IPR.L), National Grid (NG.L), RWE (RWEG.F), Scottish & Southern Energy (SSE.L)

JPMorgan Equity Research Ratings Distribution, as of December 31, 2007

Overweight(buy)

Neutral(hold)

Underweight(sell)

JPM Global Equity Research Coverage 45% 41% 14%IB clients* 50% 51% 38%

JPMSI Equity Research Coverage 41% 47% 12%IB clients* 71% 64% 49%

*Percentage of investment banking clients in each rating category.For purposes only of NASD/NYSE ratings distribution rules, our Overweight rating falls into a buy rating category; our Neutral rating falls into a hold rating category; and ourUnderweight rating falls into a sell rating category.

Valuation and Risks: Please see the most recent company-specific research report for an analysis of valuation methodology and risks on any securitiesrecommended herein. Research is available at http://www.morganmarkets.com , or you can contact the analyst named on the front of this note or your JPMorganrepresentative.

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Country and Region Specific DisclosuresU.K. and European Economic Area (EEA): Issued and approved for distribution in the U.K. and the EEA by JPMSL. Investment research issued by JPMSL has beenprepared in accordance with JPMSL’s Policies for Managing Conflicts of Interest in Connection with Investment Research which outline the effective organisational andadministrative arrangements set up within JPMSL for the prevention and avoidance of conflicts of interest with respect to research recommendations, including informationbarriers, and can be found at http://www.jpmorgan.com/pdfdoc/research/ConflictManagementPolicy.pdf. This report has been issued in the U.K. only to persons of a kinddescribed in Article 19 (5), 38, 47 and 49 of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (all such persons being referred to as "relevantpersons"). This document must not be acted on or relied on by persons who are not relevant persons. Any investment or investment activity to which this document relates isonly available to relevant persons and will be engaged in only with relevant persons. In other EEA countries, the report has been issued to persons regarded as professionalinvestors (or equivalent) in their home jurisdiction Germany: This material is distributed in Germany by J.P. Morgan Securities Ltd. Frankfurt Branch and JPMorgan ChaseBank, N.A., Frankfurt Branch who are regulated by the Bundesanstalt für Finanzdienstleistungsaufsicht. Australia: This material is issued and distributed by JPMSAL inAustralia to “wholesale clients” only. JPMSAL does not issue or distribute this material to “retail clients.” The recipient of this material must not distribute it to any third party

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or outside Australia without the prior written consent of JPMSAL. For the purposes of this paragraph the terms “wholesale client” and “retail client” have the meanings givento them in section 761G of the Corporations Act 2001. Hong Kong: The 1% ownership disclosure as of the previous month end satisfies the requirements under Paragraph16.5(a) of the Hong Kong Code of Conduct for persons licensed by or registered with the Securities and Futures Commission. (For research published within the first ten daysof the month, the disclosure may be based on the month end data from two months’ prior.) J.P. Morgan Broking (Hong Kong) Limited is the liquidity provider for derivativewarrants issued by J.P. Morgan International Derivatives Ltd and listed on The Stock Exchange of Hong Kong Limited. An updated list can be found on HKEx website:http://www.hkex.com.hk/prod/dw/Lp.htm. Japan: There is a risk that a loss may occur due to a change in the price of the shares in the case of share trading, and that a lossmay occur due to the exchange rate in the case of foreign share trading. In the case of share trading, JPMorgan Securities Japan Co., Ltd., will be receiving a brokerage fee andconsumption tax (shouhizei) calculated by multiplying the executed price by the commission rate which was individually agreed between JPMorgan Securities Japan Co., Ltd.,and the customer in advance. Financial Instruments Firms: JPMorgan Securities Japan Co., Ltd., Kanto Local Finance Bureau (kinsho) No. [82] Participating Association /Japan Securities Dealers Association, The Financial Futures Association of Japan. Korea: This report may have been edited or contributed to from time to time by affiliates ofJ.P. Morgan Securities (Far East) Ltd, Seoul branch. Singapore: JPMSI and/or its affiliates may have a holding in any of the securities discussed in this report; for securitieswhere the holding is 1% or greater, the specific holding is disclosed in the Legal Disclosures section above. India: For private circulation only not for sale. Pakistan: Forprivate circulation only not for sale. New Zealand: This material is issued and distributed by JPMSAL in New Zealand only to persons whose principal business is theinvestment of money or who, in the course of and for the purposes of their business, habitually invest money. JPMSAL does not issue or distribute this material to members of"the public" as determined in accordance with section 3 of the Securities Act 1978. The recipient of this material must not distribute it to any third party or outside NewZealand without the prior written consent of JPMSAL.

General: Additional information is available upon request. Information has been obtained from sources believed to be reliable but JPMorgan Chase & Co. or its affiliatesand/or subsidiaries (collectively JPMorgan) do not warrant its completeness or accuracy except with respect to any disclosures relative to JPMSI and/or its affiliates and theanalyst’s involvement with the issuer that is the subject of the research. All pricing is as of the close of market for the securities discussed, unless otherwise stated. Opinionsand estimates constitute our judgment as of the date of this material and are subject to change without notice. Past performance is not indicative of future results. This materialis not intended as an offer or solicitation for the purchase or sale of any financial instrument. The opinions and recommendations herein do not take into account individualclient circumstances, objectives, or needs and are not intended as recommendations of particular securities, financial instruments or strategies to particular clients. The recipientof this report must make its own independent decisions regarding any securities or financial instruments mentioned herein. JPMSI distributes in the U.S. research published bynon-U.S. affiliates and accepts responsibility for its contents. Periodic updates may be provided on companies/industries based on company specific developments orannouncements, market conditions or any other publicly available information. Clients should contact analysts and execute transactions through a JPMorgan subsidiary oraffiliate in their home jurisdiction unless governing law permits otherwise.

“Other Disclosures” last revised January 2, 2008.

Copyright 2008 JPMorgan Chase & Co. All rights reserved. This report or any portion hereof may not be reprinted, sold or redistributed without thewritten consent of JPMorgan.

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