jpmorgan electricitygasindustryoverview

1 O C T O B E R 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] Casali +44 20-7325 9023 [email protected]

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

For full J.P. Morgan Global Utilities Team details, please see inside cover

See page 133 for analyst certification and important disclosures, including investment banking relationships.J.P. Morgan 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.

E U R O P E A N U T I L I T I E S B A S I C S 2.0 - 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

J.P. Morgan Securities Ltd

Global utilities team

Chris Rogers - Germany, Nordic, France, UK, [email protected] Garrido - Spain, [email protected] Casali – UK [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]

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] [email protected]

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

USAUSA

Latin AmericaLatin America

RussiaRussia

Asia PacificAsia Pacific

AustraliaAustralia

EuropeEurope

EU

RO

PE

AN

UT

ILIT

IES

BA

SIC

S-

EL

EC

TR

ICIT

Y&

GA

SIN

DU

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Agenda

Page

Appendix

Valuation and drivers

Renewables

Climate change

The energy value chainElectricity generation…………………………………………………………………………………………………………………… 4Natural gas upstream sourcing……………………………………………………………………………………………………… 61Energy trading……………………………………………………………………………………………………………………………… 69Transmission and distribution……………………………………………………………………………………………………… 71Supply…………………………………………………………………………………………………………………………………………… 88

2

97

107

112

124

EU

RO

PE

AN

UT

ILIT

IES

BA

SIC

S-

EL

EC

TR

ICIT

Y&

GA

SIN

DU

ST

RY

OV

ER

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W

Business drivers…………………………………………………………………………………………………………………………… 111Valuation methods………………………………………………………………………………………… …………………………… 116Stock price drivers……………………………………………………………………………………………………………………… 117Major M&A over the last decade………………………………………………………………………………………………… 121

Acronyms…………………………………………………………………………………………………………………………………… 125Glossary……………………………………………………………………………………………………………………………………… 127Abbreviations……………………………………………………………………………………………………………………………… 128Conversions………………………………………………………………………………………………………………………………… 129Metrics………………………………………………………………………………………………………………………………………… 130Key websites………………………………………………………………………………………………………………………………… 131Bloomberg codes………………………………………………………………………………………………………………………… 132

1

Agenda

Page


Renewables

Climate change

The energy value chain

Electricity generation………………………………………………………………………… 4Natural gas upstream sourcing……………………………………………………………61Energy trading…………………………………………………………………………………… 69Transmission and distribution…………………………………………………………… 71Supply………………………………………………………………………………………………… 88

2

97

107

112

2EU

RO

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AN

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ILIT

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BA

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EL

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SIN

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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: J.P. Morgan

Generation

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Distribution


Distribution

Dua

l-fu

el c

ontr

acts

Fuel

sou

rcin

g

Generation


Supply

Supply

Source: J.P. Morgan

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Electricity generation

i. Economics

The load curve……………………………………………………………………………………………………… 6

The merit order…………………………………………………………………………………………………… 7

Short run margin cost – wholesale prices, spreads……………………………………………… 8

Long run marginal cost – system adequacy/ reserve margins……………………………… 14

i. Technology………………………………………………………………………….……. 26

Solid fuel – coal………………………………………………………………………………………………… 28

Gaseous fuel – gas……………………………………………………………………………………………… 37

Liquid fuel – oil…………………………………………………………………………………………………… 39

Nuclear………………………………………………………………………………………………………………… 40

Renewables…………………………………………………………………………………………………………… 49

Wind………………………………………………………………………………………………………… 50

Biomass & Biofuel…………………………………………………………………………………… 52

Geothermal……………………………………………………………………………………………… 53

Solar………………………………………………………………………………………………………… 55

Marine……………………………………………………………………………………………………… 56

Hydro………………………………………………………………………………………………………… 57

i. In Europe……………………………………………………………………………………… 59

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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: J.P. Morgan

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: J.P. Morgan 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

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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

OCGT&

CCGT

New CCGT

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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 power

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Economics - spreads

“Spark” corresponds to gas

“Dark” corresponds to coal

“Quark” corresponds to nuclear

“Dirty” = “brown”

“Clean” = “green”

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

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* Worked example – Central European spreads *

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

×

×+

+

73

0.72t/MWh)-(27€/t×

( ) ( )

3.025.7- 22.7

100087600.8

)10%1144501144(43

−==

××

×++−

- Fuel cost:

- Carbon cost:

- Fixed cost:

0.3257)/1.55-(140.3 ×+

Power price

= Clean dark spread (€/MWh) =22.7

Long term new entrant breakeven price is forecast at €73/MWh

This assumes API2 coal at $140/t and carbon at €27/t

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 $140/t for a new entrant to breakeven at €73/MWh

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Please see our 1 July 2008 report European Utilities – Most of what you need to know about power prices for more

* 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 ×

68

0.37t/MWh)-(27€/t×

( ) ( )

-1.812.9-11.1

100087600.8

)10%52030520(21

==

××

×++−

- Fuel cost:

- Carbon cost:

- Fixed cost:

Power price

10001.55h)5900btu/kW(12.3

××−

( )per year hours 8760factor load

return requiredcost capitallife plantcost capitalM&Op

×

×+

+

= Clean spark spread (€/MWh) =11.1

Long term new entrant breakeven price is forecast at €68/MWh

This assumes gas at $12.3/mmbtu and carbon at €27/t

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 $12.3/mmbtu for a new entrant to breakeven at €68/MWh

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Please see our 1 July 2008 report European Utilities – Most of what you need to know about power prices for more

Economics - LRMC

European system adequacy

i. Nordel

ii. UK

iii. UCTE

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UCTE system adequacy forecastUCTE - 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 12 years

Publication: UCTE System Adequacy Forecast 2008-20

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

Source: UCTE

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* The UCTE region includes: Installed capacity (GW)Germany 128.3 Austria 19.2 Greece 12.0 Bosnia Herzegovina 4.1France 115.9 Switzerland 17.5 Bulgaria 10.5 Slovenia 2.8Italy 93.6 Romania 16.2 Serbia 8.4 Western Ukraine 2.5Spain 84.3 Czech Republic 16.5 Hungary 8.4 Luxembourg 1.7Poland 32.5 Belgium 16.3 Slovakia 7.3 Macedonia 1.4Netherlands 22.3 Portugal 14.0 Croatia 3.8 Montenegro 0.9

UCTE system adequacy forecast

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

Terms

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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UCTE forecast: generation adequacy

Source: UCTE System Adequacy Forecast 2008-20

Without considerable new build/ life extension beyond current estimates 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

77.7

69.6

78.9 77.6

69.6

78.9

87.1

78.5

87.8

75.9

66.8

75.0

30.0

21.8

33.1

0

10

20

30

40

50

60

70

80

90

100

January

11:00 am

January

7:00 pm

July

11:00 am

January

11:00 am

January

7:00 pm

July

11:00 am

January

11:00 am

January

7:00 pm

July

11:00 am

January

11:00 am

January

7:00 pm

July

11:00 am

January

11:00 am

January

7:00 pm

July

11:00 am

2008 2010 2013 2015 2020

Rem

aini

ng c

apac

ity

(GW

)

5%

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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 reports 2001-2007 and System Adequacy Forecast 2008-20All readings 3rd Wednesday at 11:00am

Minimum reserve capacity

5%

-2%

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

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

rese

rve

mar

gin

JanJuly

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UCTE system adequacy forecast

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

New buildNew build

Source: UCTE, J.P. Morgan estimates. Based on UCTE forecast capacity. Positive = net new build, negative = net retirements.

GW By 2015 By 2020Net additions ( = new build - retirements) 107 114Of which:

Wind 47.3 62.7Gas 36.8 38.4Renewables ex wind and hydro 14.8 21.0Hard coal 14.2 4.9Oil 13.1 13.3Hydro 8.7 11.8Non attributable 0.5 0.5Mixed oil/ gas -12.3 -12.5Lignite -12.2 -13.4Nuclear -3.9 -13.3

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Nordel system adequacy forecast

Nordel – organisation for the Nordic Transmission System Operators

Publication: Nordel Power Balances 2008-12

Conclusions:

From 2008 to 2012, the Nordic system ‘is sufficient to handle the peak demand situation even in very cold conditions’

In practice the net export balance will depend on Nordic and neighbouring electricity market conditions

Terms:

Looks at MWh/h equivalent to the available capacity in MW

Available capacity (MWh/h)

= installed – unavailable - reserves

Peak consumption (MWh/h)

= maximum one hour load in very cold conditions (probability one winter in 10 years)

Net power export (MWh/h)

= available capacity - peak consumption

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Nordel system adequacy forecast

Temperatures corresponding to the coldest day in 10 years

Forecast net importer under peak conditions in 2008-10

New nuclear unit in Finland expected to be in operation in 2011

Forecast to become a net exporter in 2010-11

GW By 2011Net additions 7.5Nuclear 2.8Wind 2.1Other thermal 1.8Hydro 0.7

Source: Nordel Power Balances 2008/09, 2009/10, 2010/11 and 2011/12

Based on capacity decided and planned. Source: Nordel Power Balances 2011/12, J.P.

Morgan estimates

70000

71000

72000

73000

74000

75000

76000

77000

78000

79000

80000

2008/09E 2009/10E 2010/11E 2011/12E

Avai

labl

e pr

oduc

tion

or

peak

dem

and

(MW

h/h)

-3000

-2000

-1000

0

1000

2000

3000

4000

5000

6000

Net

pow

er e

xpor

t (M

Wh/

h)

Available production (lhs)

Peak demand (lhs)

Net power export (rhs)

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UK system adequacy forecastPublication: National Grid Seven Year Statement (SYS) 2008

Terms:

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

SYS

Based on SYS forecast capacity. Source: National Grid Seven Year Statement 2008

GW By 2015Net additions 30.2Of which:

CCGT 13.9Onshore wind 6.2Offshore wind 5.9Coal 3.3Other 0.9

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UK system adequacy forecast

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 2008

-

20,000

40,000

60,000

80,000

100,000

120,000

2007/08E 2008/09E 2009/10E 2010/11E 2011/12E 2012/13E 2013/14E 2014/15E

Cap

acit

y/ d

eman

d (G

W)

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Plan

t m

argi

n (%

)

Existing, underconstruction,consented and notconsented plantsExisting, underconstruction andconsented plants

Existing and underconstruction only

ACS peak demand(base case)

Existing, underconstruction,consented and notconsented plantsExisting, underconstruction andconsented plants

Existing and underconstruction only

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Source: National Grid Seven Year Statement 2008

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

24%

0%

10%

20%

30%

40%

50%

60%

70%

2007/08E 2008/09E 2009/10E 2010/11E 2011/12E 2012/13E 2013/14E 2014/15E

Plan

t m

argi

n (%

) =

capa

city

-pea

k de

man

d/pe

ak d

eman

d

Existing, under construction, consented and not consented plants

Existing, under construction and consented plants

Existing and under construction only

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Power generation technologyThermal 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 photovoltaic

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

Source: www.tva.gov

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Power generation technology

Electricity generation resources

Solid fuel – coal…………………………………………………………………………… 28

Gaseous fuel – gas………………………………………………………………………… 37

Liquid fuel – oil………………………………………………………………………………39

Nuclear………………………………………………………………………………………… 40

Renewables…………………………………………………………………………………… 49

Wind……………………………………………………………………………………… 50

Biomass & Biofuel………………………………………………………………… 52

Geothermal……………………………………………………………………………53

Solar……………………………………………………………………………………… 55

Marine…………………………………………………………………………………… 56

Hydro…………………………………………………………………………………… 57

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Electricity generation resources - solid fuel

CoalCoal

Source: www.tva.gov

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

Advantages

World coal reserves are large

c. 164 years of supply (when used at current rates)

vs. only 63 years for natural gas

and 48 years for oil

Can load follow

Dense so can be sourced globally

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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Coal is formed when plant material is covered by a layer of sediment, preventing complete decomposition

The weight of the overlying layers produces various chemical changes that force out oxygen and hydrogen, leaving behind a layer of carbon-rich coal

Coal deposits vary significantly by their:

Heating value – determined mainly by carbon content

Ash content (the lower the better)

Sulphur and other impurities (sulphur dioxide can be removed from emissions by ‘scrubbers’)

Moisture content (can be removed by heating)

and many other chemical and physical properties

Electricity generation resources - solid fuelCoal - formationCoal - formation

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Steam/thermal coal is pulverised and burnt for power generation

Coking/metallurgical coal is used in steel production

There are four general categories/ ranks:

Coal-to-Liquids

Highly capital intensive projects

Have been used successfully outside the US

Well suited to countries with large coal reserves but limited liquid fuels reserves e.g. South Africa

Electricity generation resources - solid fuelCoal - usesCoal - uses

Source: J.P. Morgan, American Society for Testing and Materials

Rank Steam or coking

Age Carbon content

Heat value (BTU/lb)

Moisture content

Use

Lignite/ brown coal Steam Youngest 26 - 52% 8,300 Highest Less energy per tonne so used for mouth of mine generation, e.g. in GermanyRelatively more sulphur and ashFixed cost of production so not at the mercy of the global coal market

Sub-bituminous Steam Older 37 - 56% 8,300-11,500 Less Industrial uses, attractive for generation due to low sulphur content

Bituminous Both Older 45 - 86% 10,500-15,400 Less Electricity generation and production of coke for steel

Anthracite/ hard coal Steam Oldest 81 - 98% 13,500-15,300 Lowest Domestic heating, industrial uses

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API#4 – 6,000kcal/kg coal at Richards Bay, South Africa ($/t)

API#2 - 6,000kcal/kg coal delivered to Amsterdam/Rotterdam/Antwerp Cost, Insurance, Freight ($/t)

Contract spread a proxy for global freight market

Electricity generation resources - solid fuelCoal - contractsCoal - contracts

0

50

100

150

200

250

2001 2002 2003 2004 2005 2006 2007 2008

$/t

0

5

10

15

20

25

30

35

40

$/t

API2 one year forward (LHS) API4 one year forward (LHS) Freight (RHS)

Source: Bloomberg, J.P. Morgan estimates

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Near term the global coal market remains very tight:

In real terms current commodity prices are in the range seen when serious industrialization is underway

Infrastructure constraints (rail and port)

Shipping capacity delays

Growing demand especially from the BRIC countries (we believe global resources are currently scaled to supply the Americas, Europe and Japan only)

Supply shortage to be met by exports from the US, Columbia and Indonesia

It could take several years before new capacity is built as producers are yet to commit capital based on higher prices

Electricity generation resources - solid fuelCoal - market outlookCoal - market outlook

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Longer term (2010-12):

Significant new investment to improve freight infrastructure

We expect imports to India to decrease as the effect of the nationalisation of reserves is reversed

Older mines, labour issues and rising strip ratios (units of overburden that must be removed to access a unit of coal) could bring problems on the mining front

J.P. Morgan coal price forecasts

Electricity generation resources - solid fuelCoal - market outlookCoal - market outlook

$/t 2007A 2008E 2009E 2010E 2011E Long termInternational thermal coal new 55.7 125 150 125 100 70

old 55.7 120 100 80 70 60

Excluding freight. Source: J.P. Morgan estimates

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Years of coal in the ground (based on current production)Years of coal in the ground (based on current production)

US and

Canada

20%

Russia

5%

China

41%

Australia

7%

India

6%

Indonesia

3%

Others

13%

US and

Canada

28%

Russia

18%China

14%

Australia

9%

India

7%

South Africa

6%

Indonesia

1%

Others

17%

South Africa

5%

Electricity generation resources - solid fuelCoal - reservesCoal - reserves

Production

Reserves

Source: BP Statistical Review of World Energy 2008

Percentage of world production and reservesPercentage of world production and reserves

25

45

95

97

118

178

194

234

332

500

0 100 200 300 400 500 600

Indonesia

China

Canada

Colombia

India

South Africa

Austalia

US

Kazakhstan

Russia

Years

Source: BP Statistical Review of World Energy 2008

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Electricity generation resources - solid fuelCoal – major global marketsCoal – major global markets

US and Canada – largest reserves but second largest coal producer – production growth has been sluggish

Abundance of coal keeps costs relatively low except for mature Appalachian coal fields

CAPP (Central Appalachian) – primarily bituminous

PRB (Powder River Basin) – sub-bituminous, fastest growing coal producing region, among the cheapest energy sources per BTU, lower sulphur, utilities have been slowly switching to this over the last 20 years

Russia - second largest coal reserves in the world – has the greatest potential for increasing exports

But majority of coal basins are located in the central part of the country, far from the eastern ports

Domestic consumption increasing

China – worlds largest coal producer but expected to be a net importer for 2008 and has only 48 years of reserves left

Cap on coal exports has been imposed

Current infrastructure makes importing from Indonesia cheaper than transporting coal from North China (where the price is R200/t) to South (R700/t)

Australia - world’s largest exporter to the seaborne metallurgical coal trade, mostly from Newcastle

Recent cost pressures and supply side problems from delay of Dalrymple Bay terminal expansion

Longer term - infrastructure and port expansion projects to improve the logistics chain

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Electricity generation resources - solid fuelCoal - major global marketsCoal - major global markets

India – growing demand for imports

Government has ambitious power addition target of 75GW 2007-12, most of which will be coal-fired

South Africa - world’s largest exporter to the seaborne thermal coal trade, mostly from Richards Bay

Richards Bay terminal is expected to expand to 91mt from 76mt by 1H09, however the movement of coal to the ports is constrained by the rail capacity

A growing percentage of exports are now reaching India, creating a supply gap in the Atlantic basin

A stronger AUD vs ZAR should make SA the more economic region for new coal supplies

Traditionally had mines that supplied either the export or the power market

Recently greater flexibility - new mines have planned to sell to both markets from the onset

Indonesia – world’s largest thermal coal exporter

Expected to provide the bulk of incremental supply to the Asian region

Development of new roads and ports should help

But government plans to cap coal exports will limit incremental supplies

Poland - no longer exporting to Europe but becoming a net importer from Russia

Columbia - biggest coal exporter in Latin America and could double its production by early next decade subject to getting infrastructure in place

36TH

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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, J.P. Morgan estimates

The cleanest fossil fuel from a pollution perspective

CCGTs 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% Base/ 50-60% 4,380-5,256 1-2 hours 0.43New technology 5,700 60% Base/ 50-60% 4,380-5,256 0.37

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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

Gas - technologyGas - technology

38TH

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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, J.P. 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

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 potential

Depends 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

Nuclear - pros & consNuclear - pros & cons

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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

Nuclear - safetyNuclear - safety

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Public acceptance in the US

The political climate is favourable towards

Renewal 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

Nuclear – public opinionNuclear – public opinion

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Public acceptance in Europe – examples of opinionNuclear – public opinionNuclear – public opinion

Pro

UK

Gvt 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 ex Denmark

Unquestionable shift in favour of new nuclear

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

Germany

Nuclear closure program remains controversial

Public increasingly considering the policy unrealistic

Spain

Full moratorium

Potential for change but unlikely to be soon

Italy

Nuclear power abandoned following 1987 referendum but current gvt has pledged to bring it back

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

43TH

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Reliable 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


Source: Areva Technical Days

Nuclear - technologyNuclear - technology

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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 tubes2. Control rods3. Graphite moderator4. Fuel assemblies5. Concrete pressure vessel and

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


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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

Reactor core

46TH

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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

Net power output 1600MW



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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

Net power output 1600MWBeyond

Generation 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, J.P. Morgan estimates




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

48TH

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Electricity generation resources – renewables

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

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

49TH

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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

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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

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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

52TH

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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

53TH

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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

54TH

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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

SolarSolar

55TH

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N Source: Solar Millennium AG, Erlangen

WaveUtilizes the effect of the wind on the sea

Not yet economically viable

TidalUtilizes the daily rise and fall of water

Highly predictable

Not yet economically viable

CurrentUtilizes

the temperature gradient between surface and deep sea water

the salinity gradient (pressure differential between seawater and fresh water


MarineMarine

56TH

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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’

ReservoirEnergy 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

Electricity generation resources – hydroelectric

HydroHydro

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Electricity generation resources – hydroelectricSource: Department for Business, Enterprise & Regulatory Reform Digest of

United Kingdom energy statistics 2007, J.P. Morgan estimatesHydroHydro

Where in load

Load factor (%)

Load factor (hr/a)

Start up time

R-o-R Baseload 70% 6,132 1-2 mins

Storage Peak load 15% 1,314 1-2 mins

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

Source: www.tva.gov

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Electricity generation resources in Europe

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

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

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

59TH

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European generation mixOutput (2005A, TWh)Output (2005A, 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

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

Nuclear, 133, 18%

Renewables, 133, 18%

Gas, 165, 22%

Oil, 31, 4%

Coal, 254.9, 32%

Hydro, 169.5, 21%

Gas, 721 , 21% Nuclear,

992.5, 28.6%

Oil, 135 , 4%Renewables, 160.7, 5%

Hydro, 526.5, 15%

Coal, 994.4, 28.7%

Please see our publication European Utilities Basics – Country Profiles for more detail on generation mix

60TH

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Distribution


Distribution

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Generation


Supply

Supply

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Gas sourcing

i. Exploration and production (E&P)

ii. Storage

iii. Liquefied natural gas (LNG)

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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 (LNG) 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: J.P. Morgan ‘Oil&Gas Basics Presentation’

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Gas sourcing


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

64TH

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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, J.P. Morgan


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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

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Gas sourcing

The global LNG market is small but growing rapidly: c. 250bcm/y, 7% of global gas supply

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: J.P. Morgan ‘Oil&Gas Basics Presentation’

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Gas sourcing

* An example of corporate LNG capacity *

Source: 2007 company reports

LNGLNG

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Gas Natural GDF SuezTankers Owned 11 16

Under construction 5 5Regas capacity existing bcm / y 10.9 21.6

projected bcm / y 16.0 n.aLiquefaction capacity bcm - 1.4Long term LNG supply contracts bcm / y 15.0 23.3






Distribution


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Supply

Supply

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69TH

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Trading

Why do utilities trade?

Risk management

Financial

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’

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Distribution


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71TH

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Electricity transmission & distribution

2.3 – 3kV

Transmission towers

115 – 345kV

(AC current)

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: J.P. Morgan

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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

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Germany has a mesh grid

Italy has a route grid


Cost

System security

Source: J.P. Morgan

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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

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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: J.P. Morgan

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Network regulation – key conceptsRAV

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)

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Allowed Return

Opex

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

RAV

x WA

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Allowed Return

Opex

Capex or Depreciation

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

RAV

x WA

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Allowed Return

Opex

Capex or Depreciation

Revenue or price cap

Revenue or price capProvides potential for outperformanceOften multi-year

RAV

x WA

CC

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Revenue or price cap in year 1

OpexCapex or

Depreciation


Allowed Return Opex Capex or Depreciation

x WA

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Allowed Return

Revenue or price cap in year 5

Often a downward price trajectory to induce efficiency improvements

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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

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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 > RAV

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

Opexefficiencies


Allowed Return Opex Capex or Depreciation

x WA

CC

Achieved WACCOutperformance

Capexoutcome below


longer asset life

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Capexoutcome below


longer asset life

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 RAV

Valuations are based on a premium/ discount to RAV methodology

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

Revenue = allowed opex + allowed capex + allowed return

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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

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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

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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

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Distribution


Distribution

Dua

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Generation


Supply

Supply

Fuel

sou

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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

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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

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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

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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

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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

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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

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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 (2009E)Total: €125/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

Generation = €39/MWhCost plus based

Features 80% nuclearRemainder bought in Germany

Liberalised – Germany (2009E)Total: €235/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

•Review due April/May 2008 for 2009-13 pricing period

Generation = €82/MWhBased on EEX

Mostly a coal systemNeed for coal / gas to replace

nuclearCO2 approx €8/MWh for gas and

€18/MWh for coalSales/marketing = €9/MWh

Typical retail consumer uses 3.5MWh/a

(29)

(8)

Source: J.P. Morgan estimates95T

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The end customer bill - European comparison

Power cost % GDP

€/MWhPrice ex

tax TaxPrice

with tax

Italy 165.8 44.6 210.4

Ireland 146.5 19.7 166.2

Germany 143.3 46.3 189.6

Portugal 142.0 8.0 150.0

Netherlands 140.0 89.0 229.0

Norway 136.1 42.6 178.7

Slovakia 129.2 25.5 154.7

UK 125.4 6.1 131.5

Belgium 122.9 34.8 157.7

Denmark 117.0 138.4 255.4

Sweden 108.8 58.6 167.4

Austria 105.0 49.8 154.8

Hungary 101.9 22.1 124.0

Spain 100.4 22.1 122.5

Poland 94.5 27.9 122.4

France 92.1 28.4 120.5

Czech Republic 89.8 16.5 106.3

Slovenia 88.7 19.8 108.5Finland 87.7 27.8 115.5

Romania 85.5 18.8 104.3

Greece 66.1 6.0 72.1

Lithuania 65.8 11.8 77.6

Estonia 63.5 11.5 75.0

Latvia 58.3 3.5 61.8

Bulgaria 54.7 11.2 65.9

Based on final domestic customer with 3.5MWh annual consumption, €/MWh, 2007A

Based on final domestic customer with 3.5MWh annual consumption, €/MWh, 2007A

Source: Eurostat

Affordability - Retail power cost/ GDP per capita, 2007A

Affordability - Retail power cost/ GDP per capita, 2007A

Source: Eurostat

Increasing power costs as a proportion of GDP →political

pressure on utilities

Power cost % GDPRomania 3.7%

Slovakia 3.2%

Poland 3.2%

Italy 2.9%

Denmark 2.9%

Portugal 2.9%

Hungary 2.7%

Netherlands 2.5%

Bulgaria 2.4%

Germany 2.3%

Sweden 1.9%

Czech Republic 1.9%

Belgium 1.9%

Lithuania 1.8%

Spain 1.7%

Austria 1.7%

Ireland 1.6%

Slovenia 1.7%UK 1.6%

France 1.6%Latvia 1.5%

Estonia 1.5%

Finland 1.4%

Norway 1.4%

Greece 1.0%

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Renewables

Climate change


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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 98CL

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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 II and III

Phase I: 2005-07

Phase II: 2008-12

Phase III: 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)

Carbon capture and sequestration…

Existing and new plants

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EUA price forecast

‘Clean coal’

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

Storage in deep geological formations, deep oceans or mineral carbonates away from the atmosphere (although UN unlikely to approve ocean & carbonation)

Alternatively the gas captured may be sold for various industrial uses

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

Carbon capture and sequestrationCarbon capture and sequestration

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EUA price forecast

2008 abatement stack

The price of CO2 is determined by the

Demand for abatement

Supply of abatement

We expect EUAs to trade at c. €27/t for Phase II and c. €33/t for Phase III

Source: J.P. Morgan estimates

0

10

20

30

40

50

60

70

80

90

0 20 40 60 80 100 120

€/t

Cement production

Steel production

Oil refining

UK Coal to Gas Switching, Summer

Paper production

German Lignite to Coal

Switching

UK Coal to Gas Switching,

Winter

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Climate change regulation outcomes

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

Currently Phase II permits are trading at around €25-27/t

We expect c. €27/t for Phase II

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

Phase III 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 II 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 (LCPD)

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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Climate change


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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 Corporates108R

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Renewables – raison d’être

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 23 Jan 08 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, J.P. Morgan estimates

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Business drivers…………………………………………………………………………………111Valuation methods……………………………………………………………………….... 116Stock price drivers…………………………………………………………………………….117Major M&A over the last decade………………………………………………………121

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Business drivers - what makes a successful utility?

i. Generation

ii. Transmission and distribution

iii.Supply

iv.Big vs. small

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What makes a successful utility?

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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Transmission & Distribution networksTransmission & Distribution networks

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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DR

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ER

S


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

117VA

LU

AT

IO

NA

ND

DR

IV

ER

S

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

118VA

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AT

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NA

ND

DR

IV

ER

S

Utilities stock price drivers – the five forces1. Energy prices

Raw materials prices - Coal, oil, gas, uranium, equipment

Wholesale power prices

2. Regulation

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

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

Carbon: pricing and allocations

3. Politics

Electricity and gas often perceived to be public goods, with lots of political levers available:

Windfall taxes

Competition reviews

Mainstream tariff controls

Social assistance

State operator action

119VA

LU

AT

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NA

ND

DR

IV

ER

S

Utilities stock price drivers – the five forces4. Macroeconomics

Dividend yield spread over Treasuries – in the absence of newsflow utility stocks can trade as a bond proxy

Demand growth

Weather

Temperature affects demand

Precipitation drives hydroelectric generation

Interest rates and taxes

5. Corporate strategy

Opex and capex plans

Short/ medium term targets

M&A prospects

Re-gearing potential, buy-backs, dividends

120VA

LU

AT

IO

NA

ND

DR

IV

ER

S

Major M&A over the last decade - UKAnnouncement Date

Completion Date

Target Target BusinessTarget Nationality

Acquiror Acquiror BusinessAcquiror Nationality

Divestor Divestor BusinessDivestor Nationality

Deal Value $m

Stake%

23-Nov-98 31-Dec-99London Electricity

Supplies and distributes electricity to 2m customers in London. Subsidiary ofUS-based Entergy UK EDF Integrated electricity France Entergy Corp

Global integrated energy company US 3,173.554 100

25-Sep-00 09-Nov-00 Thames Water

Water and waste, design, consultancy and construction UK RWE AG

Energy, mining, raw materials, petroleum, chemicals, waste disposal, engineering and construction Germany 8,882.396 100

09-Apr-01 28-Jun-02 PowerGen

Generation and sale of electricity, engineering, oil and gas in the North Sea UK E.ON AG

Electricity generation and distribution Germany 13,814.937 100

22-Mar-02 27-May-02 Innogy Holdings Integrated energy UK RWE AG

Energy, mining, raw materials, waste, engineering and construction Germany 7,374.519 100

22-Apr-02 21-Oct-02 Lattice Group

275,000km of gas grids, LNG storage facilities, telco and fiberoptic networks UK

National Grid Group

Operates the electricity transmission system UK 17,441.637 100

18-Jun-02 29-Jul-02 SEEBOARD

Distribution and supply of electricity, retail of electrical goods UK EDF

Generates and distributes electricity France

American Electric Power Co Inc

Electric utility holding company US 2,059.180 100

01-Oct-03 17-Jan-05British Energy (97.5%)

Owner and operator of nuclear power stations UK Creditors Creditors UK 2,880.383 97.5

16-Oct-06 01-Dec-06Thames Water Holdings

Water and wastewater services UK

Macquarie, Kemble Water

Investment, commercial and retailbanking in Australia and around the world Australia RWE AG Integrated energy Germany 14,849.188 100

28-Nov-06 24-Apr-07 Scottish Power

Integrated electricity, gas supply, water and teleco services UK Iberdrola SA Integrated electricity Spain 22,954.919 100

22-Nov-07 08-Feb-08 Kelda Group Water and waste water services. UK

Citigroup AI, GIC SI, HSBC, Infracapital Partners Investment company UK 10,602.933 100

04-Jan-08 15-Feb-08Airtricity Holdings Renewable energy Ireland

Scottish&Southern Energy International energy UK 2,142.542 100V

AL

UA

TI

ON

AN

DD

RI

VE

RS

Source: Dealogic

Major M&A over the last decade - EuropeAnnouncement Date

Completion Date




Deal Value $m

Stake%

22-Sep-05 27-Jul-06Union Fenosa SA (22.07%)

Electric power generator and distributor. Spain ACS

Construction, engineering and environmental services to the public and private sectors Spain

Banco Santander Central Hispano Commercial bank Spain 2,709.081 22.07

18-Aug-06 18-Aug-06Endesa SA (3.4%) Electric utility Spain

Deutsche Bank AG

Retail and investment bank Germany 1,238.168 3.4

02-Apr-07 05-Oct-07Endesa SA (46.05%) Electric utility Spain ENEL, Acciona Integrated electricity Italy

Caja Madrid (9.9% - 2.9%), SEPI Savings bank Spain 52,625.922 46.05

30-Jul-08Union Fenosa SA

Electric power generator and distributor Spain

Gas Natural SDG SA

Supplies, stores, transmits and distributes natural gas Spain

CAM (45.3% / 5.15%), ACS

Savings and commercial bank Spain 35,854.814 100

13-May-05 26-Oct-05Edison SpA (30.462%) Integrated energy Italy EDF

Electricity generation and distribution Italy EDF Electric utility France 3,301.580 30.462

04-Jun-07 20-Dec-07ASM Brescia SpA

Electricity and gas supply Italy AEM SpA

Generates and distributes electricity and natural gas in the Milan area Italy

Comune di Brescia (69.238%) Brescia city hall Italy 5,721.018 100

17-Nov-99 07-Feb-01 EnBW (25.01%)

Integrated energy, water, waste and telco Germany EDF Integrated electricity France

State of Baden-Wuerttemberg Germany 2,484.538 25.01

17-Nov-99 17-Nov-99 VIAG AG (10%)

Power and gas services, packaging, chemicals, logistic and telcos Germany Veba AG

Generates and distributes electricity, gas, district heating and water services Germany

Federal State of Bavaria Germany 1,638.738 10

03-Jul-02 07-Mar-03Ruhrgas AG (40%) Gas distribution Germany E.ON AG

Integrated emergy and water, oil exploration and production Germany

Royal Dutch/Shell, Exxon Mobil, TUI Investors International 4,043.791 40

27-Feb-06 22-Jul-08 Gaz de France Natural gas utility France Suez SAEnergy, water, waste and telco services France

Republic of France (79.45%) France 58,705.279 100

19-Aug-99 08-Dec-99Tractebel SA (47.8%)

Integrated energy and water Belgium

Suez Lyonnaise des Eaux

Water supply and treatment, electricity,waste management and communication France 7,326.309 47.8

09-Aug-05 08-Dec-05

Electrabel SA/NV (49.92%)

Generates and supplies electricity, distributes gas, provides cable TV services Belgium Suez SA

Energy, water, waste and telco services France

Intermixt (4.56%)

Group of local authority energy suppliers Belgium 13,871.498 49.92V

AL

UA

TI

ON

AN

DD

RI

VE

RS

Source: Dealogic

Major M&A over the last decade - miscAnnouncement Date

Completion Date




Deal Value $m

Stake%

06-Oct-04 28-Apr-06

Slovenske Elektrarne(66%)

Generates and distributes electricity

Slovak Republic ENEL SpA Integrated electricity Italy Slovak Republic

Slovak Republic 3,855.155 66

15-Sep-07 15-Oct-07OGK-4 OAO (69.34%)

Electric power generator Russia E.ON AG

Electricity generation and transmission, gas, oil, water, waste disposal, chemicals and telecos Germany

Unified Energy System of Russia Integrated energy Russia 5,775.407 69.34

28-Feb-08 TGK-10 OAO Electric utility Russia Fortum Oyj International energy Finland

Unified Energy System of Russia (23.34%) Integrated energy Russia 5,067.361 100

27-Feb-06 20-Oct-06 KeySpan Corp

Holding company for group involved in gas distribution US National Grid

Electricity and gas networks. 2002 merger between Lattice Group and National Grid UK 12,421.290 100

27-Mar-07 03-Jul-07Horizon Wind Energy LLC Wind farm developer US EDP Integrated electricity Portugal

Goldman Sachs Group Inc

Global investment banking and securities US 2,330.000 100

04-Oct-07 18-Dec-07Airtricity, N America Electric utility US E.ON AG

Electricity generation and transmission, gas, oil, water, waste disposal, chemicals and telecos Germany Airtricity Wind farm developer Ireland 1,400.000 100

123VA

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AT

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NA

ND

DR

IV

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Source: Dealogic

Agenda

Page

Appendix


Renewables

Climate change


124

Acronyms………………………………………………………………………………………… 125Glossary…………………………………………………………………………………………… 127Abbreviations…………………………………………………………………………………… 128Conversions……………………………………………………………………………………… 129Metrics……………………………………………………………………………………………… 130Key websites…………………………………………………………………………………… 131Bloomberg codes…………………………………………………………………………….. 132

2

97

107

112

124

EU

RO

PE

AN

UT

ILIT

IES

BA

SIC

S-

EL

EC

TR

ICIT

Y&

GA

SIN

DU

ST

RY

OV

ER

VIE

W

Acronyms

emission limit valueELV

new electricity trading arrangementsNETAexploration and productionE&P

national allocation planNAPcombined heat and powerCHP

molten salt reactor MSRCertified Emission ReductionCER

long run marginal costLRMCClean Development MechanismCDM

liquified natural gasLNGcarbon capture and sequestrationCCS

lead fast breeder reactor LFRclimate 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 reactor GFRadequacy 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 reactor VHTR 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 reactor SFRpublic service contractsPSCs

super-critical water reactor SCWRpower 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

1 TWh

= 1,000 GWh

= 1,000,000 MWh

= 1,000,000,000 kWh

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To: LNGFrom: kWh MWh therm mmbtu kJ GJ kcal Gcal ft3 bcf m3 bcm boe mboe toe mtoe tce mtce tonne

kWh 1 0.001 0.0341 0.00341 3,600 0.0036 860 0.00086 3.3 3.3E-09 0.093 9.3E-11 0.00059 5.9E-10 0.00008 8E-11 0.00014 1.4E-10 0.000066MWh 1,000 1 34.12 3.412 3,600,000 3.6 859,845 0.8598 3,300 0.0000033 93 0.000000093 0.59 0.00000059 0.08 0.00000008 0.14 0.00000014 0.066therm 29.31 0.0293 1 0.1 105,506 0.1055 25,200 0.0252 96.2 9.62E-08 2.72 2.72E-09 0.17 0.00000017 0.0024 2.4E-09 0.004 0.000000004 0.0019

mmbtu 293.07 0.293 10 1 1,055,060 1.0551 252,000 0.252 962 0.000000962 27.2 2.72E-08 1.7 0.0000017 0.024 0.000000024 0.04 0.00000004 0.019kJ 0.000278 2.778E-07 0.00000948 9.478E-07 1 0.000001 0.2388 2.388E-07 0.0091 9.1E-12 0.000026 2.6E-14 0.00000016 1.6E-13 0.00000016 1.6E-13 0.000000038 3.8E-14 0.000000018

GJ 277.8 0.2778 9.48 0.948 1,000,000 1 238,800 0.2388 9,100 0.0000091 26 0.000000026 0.16 0.00000016 0.16 0.00000016 0.038 0.000000038 0.018kcal 0.00116 0.000001163 0.00003968 0.000003968 4.19 4.1868E-06 1 0.000001 0.0038 3.8E-12 0.00011 1.1E-13 0.00000066 6.6E-13 0.000000093 9.3E-14 0.00000016 1.6E-13 0.000000076

Gcal 1163 1.163 39.68 3.968 4,186,800 4.19 1,000,000 1 3,800 0.0000038 110 0.00000011 0.66 0.00000066 0.093 0.000000093 0.16 0.00000016 0.076ft3 0.3 0.0003 0.0104 0.00104 1,097 0.00109726 262 0.00026 1 0.000000001 0.0283 2.834E-11 0.00017 1.7E-10 0.000024 2.4E-11 0.000042 4.2E-11 0.00002bcf 300,000,000 300,000 10,400,000 1,040,000 1.09726E+12 1,097,260 2.62E+11 262,000 1,000,000,000 1 28,340,000 0.0283 170,000 0.17 24,000 0.024 42,000 0.042 20,000m3 11.0 0.011 0.367 0.0367 38722 0.0387 9,249 0.00925 35.29 3.529E-08 1 0.000000001 0.0061 6.1E-09 0.00083 8.3E-10 0.0015 1.5E-09 0.00071

bcm 11,000,000,000 11,000,000 3.67E+08 36,700,000 3.8722E+13 38,722,000 9.249E+12 9,249,000 35,290,000,000 35.29 1,000,000,000 1 6,100,000 6.1 830,000 0.83 1,500,000 1.5 710,000boe 1,700 1.7 60 6 6,300,000 6.3 1,500,000 1.5 5600 0.0000056 160 0.00000016 1 0.000001 0.14 0.00000014 0.23 0.00000023 0.1

mboe 1,700,000,000 1,700,000 60,000,000 6,000,000 6.3E+12 6,300,000 1.5E+12 1,500,000 5,600,000,000 5.6 160,000,000 0.16 1,000,000 1 140,000 0.14 230,000 0.23 100,000toe 12,700 12.7 425 42.5 45,000,000 45 11,000,000 11 42000 0.000042 1200 0.0000012 7.5 0.0000075 1 0.000001 1.7 0.0000017 0.8

mtoe 12,700,000,000 12,700,000 425,000,000 42,500,000 4.5E+13 45,000,000 1.1E+13 11,000,000 42,000,000,000 42 1200000000 1.2 7,500,000 7.5 1,000,000 1 1,700,000 1.7 800,000tce 7,100 7.1 250 25 26,000,000 26 6,300,000 6.3 24500 0.0000245 700 0.0000007 4.3 0.0000043 0.6 0.0000006 1 0.000001 0.5

mtce 7,100,000,000 7,100,000 250,000,000 25,000,000 2.6E+13 26,000,000 6.3E+12 6,300,000 24,500,000,000 24.5 700,000,000 0.7 4,300,000 4.3 600,000 0.6 1,000,000 1 500,000tonne 14,000 14 520 52 55,000,000 55 13,000,000 13 52,000 0.000052 1,400 0.0000014 8.9 0.0000089 1.2 0.0000012 1.9 0.0000019 1

Power CoalTherms Joules Calories Natural gas Oil

Electricity margin metrics

Reserve margin (%) = capacity reserve / demand

Capacity margin (%) = capacity reserve / available capacity

Output = Capacity x Time

[kWh] = [kW] x [h]

capacity Installedgeneratedy Electricit

factor Load =

Load factor ≠ 100%

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

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

www.Iea.org

www.Eia.doe.gov

System adequacywww.UCTE.org

www.Nordel.org

www.Nationalgrid.com/uk/Electricity/SYS/

Technologywww.Alstom.com

www.Powergeneration.siemens.com

www.Gepower.com

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

www.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 codes

SX6P Index (Dow Jones Stoxx European Utilities index)

ERIXP Index (renewable energy index)

EPWR (European electricity prices)

PWNX (French electricity prices)

ELEU (UK electricity prices)

ELGE (German electricity prices)

ELNF (Nordpool electricity prices)

EGAS (European gas prices)

UGAS (UK gas prices)

CLCL (global coal prices)

EMIT (EU emission allowances)

132AP

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133

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, the research 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 covers in 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 the research analyst(s) in this report.

Important Disclosures

Explanation of Equity Research Ratings and Analyst(s) Coverage Universe:

J.P. Morgan uses the following rating system: Overweight [Over the next six to twelve months, we expect this stock will outperform the average total return of the stocks 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 the average 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 stock will 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 universe is 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), CEZ (CEZP.PR), Centrica (CNA.L), E.ON (EONGn.DE), EDP Renovaveis (EDPR.LS), EEN (EEN.PA), Fortum(FUM1V.HE), Iberdrola Renovables (IBR.MC), National Grid (NG.L), Pennon (PNN.L), RWE (RWEG.F), Scottish & Southern Energy (SSE.L), Severn Trent (SVT.L), United Utilities (UU.L), Veolia Environnement (VIE.PA)

J.P. Morgan Equity Research Ratings Distribution, as of June 30, 2008

*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 our Underweight rating falls into a sell rating category.

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General: Additional information is available upon request. Information has been obtained from sources believed to be reliable but JPMorgan Chase & Co. or its affiliates and/or subsidiaries (collectively J.P. Morgan) do not warrant its completeness or accuracy except with respect to any disclosures relative to JPMSI and/or its affiliates and the analyst’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. Opinions and 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 material is 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 individual client circumstances, objectives, or needs and are not intended as recommendations of particular securities, financial instruments or strategies to particular clients. The recipient of this report must make its own independent decisions regarding any securities or financial instruments mentioned herein. JPMSI distributes in the U.S. research published by non-U.S. affiliates and accepts responsibility for its contents. Periodic updates may be provided on companies/industries based on company specific developments or announcements, market conditions or any other publicly available information. Clients should contact analysts and execute transactions through a J.P. Morgan subsidiary or affiliate in their home jurisdiction unless governing law permits otherwise.

“Other Disclosures” last revised September 29, 2008.

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

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