EUROPEAN UTILITIES BASICS - ELECTRICITY & GAS INDUSTRY OVERVIEW 6 FEBRUARY 2008 European Utilities Research Team Chris Rogers AC +44 20-7325 9069 [email protected]Sarah Laitung AC +44 20-7325 6826 [email protected]Javier Garrido +34 91- 516 1557 [email protected]Sofia Savvantidou +44 20-7325 0650 [email protected]Nathalie Casali +44 20-7325 9023 [email protected]For specialist sales advice, please contact: Ian Mitchell +44 20-7325 8623 [email protected]For full JPMorgan Global Utilities Team details, please see inside cover See page 117 for analyst certification and important disclosures, including investment banking relationships. JPMorgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. The analysts listed above are employees of either J.P. Morgan Securities Ltd. or another non-US affiliate of JPMSI, and are not registered/qualified as research analysts under NYSE/NASD rules, unless otherwise noted. J.P. Morgan Securities Ltd.
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European Utilities Basics Electricity Gas Industry Overview[1]
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E U R O P E A N U T I L I T I E S B A S I C S - E L E C T R I C I T Y & G A S I N D U S T R Y O V E R V I E W
For full JPMorgan Global Utilities Team details, please see inside cover
See page 117 for analyst certification and important disclosures, including investment banking relationships.JPMorgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. The analysts listed above are employees of either J.P. Morgan Securities Ltd. or another non-US affiliate of JPMSI, and are not registered/qualified as research analysts under NYSE/NASD rules, unless otherwise noted.
BaseloadDemand present most of the time (c.80%)Baseload power plants operate continuously, even when it might not be economical to do soGeneration: nuclear, lignite, r-o-r hydro, CCGTs Gas: long term contracts with long distance suppliers
Mid-meritDemand present 30 – 80% of the time, predictable variabilityGeneration: coal, CCGTs. Gas: contracts with near distance suppliers, seasonal storage and spot
Peak loadComes on and off very quicklyDemand present <30% of the time, timing of peaks predictable, levels less soGeneration: oil, OCGTs, storage hydro. Gas: spot market and daily storage
RenewablesTend to be outside the load curve on a must-take basis – run when they canImpact on environment offset partly by need for balancing power
Source: JPMorgan
Shows the order in which different plants are called upon to run based
on their variable operating cost
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Economics - the merit order
The short run marginal cost (SRMC) of the last unit required to meet demand sets the marginal price of power at any given point in time
Drives day-to-day price, based only on cost of fuel & CO2 permits
Electricity demand has to be met instantaneously by supply - electricity cannot be stored
Price tends to be set by mid-merit plant for most hours of the day
Baseload plants (hydro, coal, nuclear) have large margins since the marginal unit is typically gas-fired, which tend to have higher costs
A unit with operating cost below the current price keeps the margin
However, the long term power price is driven by the long run marginal cost (LRMC)
The cost of generating a unit of electricity when all factors of production (i.e. including capital) can be varied
If new capacity is required, a profit margin (spread) sufficient to cover all capital costs is needed
We therefore need to look at future reserve margins (system adequacy) to determine where spreads need to be
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Economics - SRMC
price
time (hours)
merit order / load curve
demand
Source: JPMorgan 8760
Which type of power plant will set the power price?
Currently ≈indifferent between building a coal or gas plant in Central Europe as SRMC are the same at prevailing market fuel prices
Other considerations, e.g. Germany reliant on Russian gas, whereas Spain uses gas from a variety of sources (pipeline and LNG) so more inclined to build gas fired power plants
Indifference between building a new clean (i.e. using CCS technology) or dirty coal plant is a function of the CO2 emission permit price
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* Worked example: attractiveness of coal vs. gas
Source: RWE Factbook 20071 including renewables and CHP2 oil, OCGT, hydro, etc.
GermanyGermany UKUK
Large proportion of low SRMC plant Large proportion of high SRMC plant
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Interconnectorand must run1
Nuclear
New hard coal
Hard coal CCGT
New CCGT
Peaking2
Min MaxHourly demandPower price
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Must run1 Nuclear
New lignite
Lignite Hard coal
New hard coal
Min MaxHourly demandPower price
Peaking2
New CCGT
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OCGT&
CCGT
Economics - wholesale pricesPrice at which electricity generators/ gas producers sell to the market
Market arrangements are based on bilateral trading between generators, suppliers, traders and customers
such as BETTA in the UK
Power exchanges have been launched in recent years to provide screen-based anonymous 24 hour trading
EEX in Germany
Powernext in France
OMEL in Spain and Portugal
GME in Italy
APX in The Netherlands
UKPX (a subsidiary of APX) in the UK
Nordpool in Scandanavia
Generators have contracts with the transmission grid for
Connection
Use of the system
Balancing services including reactive power10T
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Economics - spreads
“Spark” corresponds to gas
“Dark” corresponds to coal
“Quark” corresponds to nuclear
“Dirty” = “brown”
“Clean” = “green”
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Dirty CleanSpark = power price = power price
- cost of gas - cost of gas - carbon price
Dark = power price = power price - cost of coal - cost of coal
- carbon price
* Worked example – Central European spreads
New hard coal, no CO2 capture, 2008ENew hard coal, no CO2 capture, 2008E
Nordel – organisation for the Nordic Transmission System Operators
Publication: Nordel Power Balances 2008-11
N.B. looks at MWh/h equivalent to the available capacity in MW
From 2008 to 2011, the Nordic system ‘is able to meet the estimated consumption… in average conditions… without imports’
Sufficient to cover ‘simultaneous peak demand without import’ in 2010-11E
Estimated production (MWh/h) – that which is available at peak
Peak Demand (MWh/h) = maximum one hour load in temperature circumstances with occurrence probability one winter during 10 years
Net power export (MWh/h)
= estimated production
- peak demand
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Nordel system adequacy forecastTemperatures corresponding to the coldest day in 10 years
Forecast net importer under peak conditions in 2008-10
Forecast to become a net exporter in 2010-11
Source: Nordel Power Balances 2008/09, 2009/10 and 2010/11Large increase in production in 2010/11 is due to a new nuclear plant in Finland
71000
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79000
2008/09E 2009/10E 2010/11E
Esti
mat
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eak
dem
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(MW
h)
-2500
-2000
-1500
-1000
-500
0
500
1000
1500
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Net
pow
er e
xpor
t (M
Wh)
Estimated production
Peak demand
Net power export
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UK system adequacy forecast
Publication: National Grid Seven Year Statement (SYS) 2007
3 different generation background forecasts:
SYS based total capacity (GW)
= existing generation projects
+ those proposed new generation projects for which an appropriate Bilateral Agreement1 is in place
Consents based total capacity (GW)
= existing generation projects
+ those proposed new generation projects been granted the necessary consents under Section 36 of the Electricity Act 1989 and Section 14 of the Energy Act 1976 for connection to the network
Existing or under construction total capacity (GW)
1 An agreement between National Grid and a generator for future connection to the transmission system
Existing or under construction
Consented
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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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UK system adequacy forecast
Source: National Grid Seven Year Statement 2007
Plant margin is likely to exceed 24% over the entire forecast period, even under the conservative existing/ under construction background
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 1600MW
BeyondGeneration IV potential designs:
— ‘Fast breeder’ reactors – fast neutron reactor without moderator, fully closed cycle, minimises production of long-lived waste, gas-, lead- or sodium-cooled
— Pebble Bed Modular Reactor (PMBR) – smaller size, no super-criticality risk but as-yet unproven— Advanced water designs, e.g. the very high temperature reactor (VHTR), with water at 1000°C, also allows hydrogen
production
Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, IEA, Areva-np.com, wikipedia, JP Morgan estimates
NuclearNuclear
Typical thermal efficiency (btu/KWh)
Typical thermal efficiency (%)
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
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Electricity generation resources – renewables
Wind blows and sets the turbine blades in motion, generating power that can be converted into electricity
A steel or concrete tower with a nacelle that turns horizontally in a way such that the rotor (usually equipped with two or three blades) always faces the wind
Generation depends on:
cube of wind speed (double wind speed gives eight times more power)
square of rotor diameter (double rotor diameter gives four times more power)
density of the air (If the air is 10°C colder, density and power production increase by ≈3%. Moist air is less dense and so will lower power production)
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
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Electricity generation resources – renewables
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
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Electricity generation resources – renewables
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
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Electricity generation resources – renewables
Solar photovoltaic
PV cells transform the photon energy in solar radiation directly into electrical energy without an intermediate mechanical or thermal process
Technology is currently very expensive
Concentrated solar/ solar thermal
Optical devices focus direct solar radiation onto an area where a receiver is located
The radiation is transformed into heat in a medium (oil) and then to steam and electricity as per thermal power
Continues to work after dark until collected heat dissipates
Technology requires a very large area
Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, www.geo-energy.org/aboutGE/powerPlantCost.asp, JP Morgan estimates
SolarSolar
Load factor (%)
Load factor (hr/a)
Start up time
Build cost (€m/MW)
Offshore wind 30-40% 2,628-3,504 <30 sec 2.1
Onshore wind 20-30% 1,752-2,628 <30 sec 1.3
Biomass 40-70% 3,504-6,132 1 hour 0.8-1.2
Geothermal 95% 8,322 1 day 2.1
Solar PV 10-25% 876-2,190 instant 6.0-7.0
Concentrated solar 10-35% 876-3,066 instant 4.0
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Run-of-the-river (r-o-r)
Natural flow and elevation drop of a river are used to generate electricity
‘free fuel’
Reservoir
Energy extracted depends on the volume and on the head (difference in height between the source and the water's outflow)
Pumped storageRequires energy to pump water into reservoir - when the wholesale price is low (hence not ‘free fuel’)
Supplies peak demand - when the wholesale price is high
Not pumped Uses reservoirs that are naturally elevated
Marine
TidalUtilizes the daily rise and fall of water
Highly predictable
Not yet economically viable
WaveUtilizes the effect of the wind on the sea
Not yet economically viable
Electricity generation resources – hydroelectric
HydroHydro
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Electricity generation resources – hydroelectric
Source: Department for Business, Enterprise & Regulatory Reform Digest of United Kingdom energy statistics 2007, JP Morgan estimates
Source: www.tva.gov
1-2 mins131415%Peak loadStorage
1-2 mins613270%BaseloadR-o-R
Start up time
Load factor (hr/a)
Load factor (%)
Where in load
HydroHydro
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Electricity generation resources in Europe
Germany, Poland and Spain have historically had large domestic coal industries
The UK, Norway and the Netherlands have been major producers of oil and gas
UK and Netherlands now in decline
New sources: Russia by pipeline, Liquefied Natural Gas by boat for elsewhere in the world
‘Dash for gas’ – gas power station new build
UK, Spain, Italy
Cleaner, cheaper, more efficient than coal
In the Nordic region ≈60% of generation comes from hydro
France (dearth of natural resources) has developed the largest nuclear capacity in Europe
Germany has launched a drive to install Europe’s largest wind fleet
Other major wind players: Spain, Denmark
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OECD Europe generation mix (see ‘European Utilities Basics - Country Profiles’ for more)
Output (2004A, TWh)Output (2004A, TWh)
Low load factor → output on average proportionally lower than capacity e.g. hydro
High load factor → output on average proportionally higher than capacity e.g. nuclear
Its physical properties make it hard to transport, particularly intercontinentally without liquefaction
Most natural gas is transported in gaseous form via pipeline
Gas markets still regional rather than continental or global
European natural gas is priced using an oil-referenced formula
The widespread adoption of Liquefied Natural Gas should change the gas market from regional to global
Large natural gas consumers (especially power plant operators and retail suppliers) have incentives to hedge their physical commodity exposure as well as the basis (location) risk associated with dealing in different markets
Exploration and productionExploration and production
Source: JP Morgan ‘Oil&Gas Basics Presentation’
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Gas sourcing
Exploration and productionExploration and production
Why be involved in upstream gas?
No indigenous supply
Security
Economic hedge
If not involved upstream, generators tend to be beholden to very long term contracts (≈20 years - whereas the coal market is spot-based) with NOCs (National Oil Companies)
Major market drivers
Weather is both a demand and supply factorDemand for central heating
Hydro conditions in areas that depend on hydropower drive requirement for CCGT power
Oil price – long term contracts tend to be oil-based, take-or-buy decisions impact the natural gas market
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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
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
Electricity transmission & distribution
2 Source: energynetworks.org
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Germany has a mesh grid
Italy has a route grid
Electricity transmission & distribution
Cost
System security
Source: JPMorgan
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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: JPMorgan
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Network regulation – key concepts
RAV
Allowed Return
x WA
CC
Allowed return may be unitary (per MWh) or absolute (€m)
Has to cover interest expense and dividends
Regulatory Asset Value normally scaled over time (by depreciation and capex), may include inflation link
Weighted average cost of capital (WACC) may be
Pre- or post-tax
Real or nominal (i.e. with or without inflation)
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Network regulation – key concepts
RAV
Allowed Return
Opex
x WA
CC
Operating expensesActual in cost plusAllowed in incentiveMay be volume based or absolute
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Network regulation – key concepts
RAV
Allowed Return
Opex
Capex or Depreciation
x WA
CC
Capital expenditureBased on agreed outcomes in incentiveBased on defined budget in cost-plusMay be volume based or absolute
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Network regulation – key concepts
RAV
Allowed Return
Opex
Capex or Depreciation
Revenue or price cap
x WA
CC
Revenue or price capProvides potential for outperformanceOften multi-year
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Revenue or price cap in year 1
OpexCapex or
Depreciation
Network regulation – key conceptsRAV
Allowed Return Opex Capex or Depreciation
x WA
CC
Allowed Return
Revenue or price cap in year 5
Often a downward price trajectory to induce efficiency improvements
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Revenue or price cap
Opexefficiencies
Capexoutcome below
Budgetor Depreciation
longer asset life
Achieved WACCOutperformance
Network regulation – key conceptsRAV
Allowed Return Opex Capex
x WA
CC
Year 1
Year 2
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Revenue or price cap
Opexefficiencies
Achieved return(above allowed return)
If can reduce opex and/or capex, can make an achieved return > the allowed return
→ assets worth > RAB
Have outperformed the regulator’s assumptions ☺
Normally can retain outperformance in, or across periods (2 – 5 years)
Of course, with tough regulation the opposite can occur Opex
efficiencies
Network regulation – key conceptsRAV
Allowed Return Opex Capex or Depreciation
x WA
CC
Achieved WACCOutperformance
Capexoutcome below
Budgetor Depreciation
longer asset life
Capexoutcome below
Budgetor Depreciation
longer asset life
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Network regulation – detailsThe regulator defines
Regulated Asset Base / Capital Value / Asset Value (RAB, RCV, RAV)
Not necessarily equivalent to the true value or book value of the assets
E.g. in UK based on EV after privatisation + capex – depreciation
In Sweden based on a computer model of optimal network as if built ‘from scratch’
Allowed return
Regulator makes assumptions on gearing, cost of debt, cost of equity
Pre or post tax?
Real or nominal?
If the regulator is correct in all assumptions (efficiency, cost of operations and capital projects, cost of capital) then the value of the business, by definition, is its RAB
Valuations are based on a premium/ discount to RAB methodology
Recent M&A transactions have occurred at a premium to RAB i.e. assuming outperformance
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)
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
Generation•Pool / spot price•Cost-plus basedGas sourcing•L.T. contracts•Oil / coal link
Unliberalised – France (2007E)Total: €120/MWh
Taxes = €37/MWh•VAT
•Local taxes•CTA for pensions
•CSPE for public services
Network access = €49/MWh•7.25% pre-tax
•No inflation link•Cost plus
•Review mid 2007
Generation = €34/MWhCost plus based
Features 80% nuclearRemainder bought in Germany
Liberalised – Germany (2008E)Total: €217/MWh
Taxes and levies = €82/MWh•VAT (32.5)
•Concession fee (17.9)•Electricity tax (20.5)
•CHP act (2.9)•Renewables act (8.2)
Network access = €62/MWh•6.5% post-tax
•Inflation link for old assets•Moving to incentive
•Reviews due April 06 & new system July ‘06
Generation = €67/MWhBased on EEX
Mostly a coal systemNeed for coal / gas to replace
nuclearCO2 approx €8/MWh for gas and
€18/MWh for coalSales/marketing = €6.5/MWh
Typical retail consumer uses 3.5MWh/a
(29)
(8)
Source: JPMorgan estimates82T
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LU
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HA
IN
The end customer bill - European comparison
65.410.754.7Bulgaria
68.910.658.3Latvia
75.011.563.5Estonia
76.710.965.8Lithuania
71.85.766.1Greece
100.715.285.5Romania
115.027.387.7Finland
106.217.588.7Slovenia
105.615.889.8Czech Republic
120.728.692.1France
120.025.594.5Poland
121.220.8100.4Spain
118.116.2101.9Hungary
150.945.9105.0Austria
167.458.6108.8Sweden
255.4138.4117.0Denmark
156.133.2122.9Belgium
131.05.6125.4UK
151.922.7129.2Slovakia
181.645.5136.1Norway
229.089.0140.0Netherlands
149.07.0142.0Portugal
189.646.3143.3Germany
167.020.5146.5Ireland
221.856.0165.8Italy
Price with taxTaxPrice ex tax€/MWh
Comparison of power prices – Pan-Europe, 3.5MWh domestic customer, €/MWh, 2007A
Comparison of power prices – Pan-Europe, 3.5MWh domestic customer, €/MWh, 2007A
Source: Eurostat
Affordability - Retail power price % GDP/capita, 2006A
Affordability - Retail power price % GDP/capita, 2006A
Source: Eurostat
1.0%Greece
1.4%Norway
1.4%Finland
1.5%Estonia
1.5%France
1.6%UK
1.6%Latvia
1.6%Slovenia
1.6%Ireland
1.7%Austria
1.7%Spain
1.8%Lithuania
1.8%Belgium
1.8%Czech Republic
1.9%Sweden
2.4%Germany
2.4%Bulgaria
2.4%Netherlands
2.6%Hungary
2.9%Portugal
2.9%Denmark
3.1%Italy
3.1%Poland
3.2%Slovakia
3.6%RomaniaPower cost % GDP
Increasing power costs as a proportion
of GDP →political
pressure on utilities
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Renewables
Climate change
The energy value chain
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Climate change regulation
1992 – UNFCCC (UN Framework Convention on Climate Change) established
1997 - Kyoto Protocol signed
41 industrialised countries (‘Annex 1 countries’) agreed to reduce their greenhouse gas emissions (GHGs: CO2, NOx, methane, CFCs) by a specific percentage by 2008-2012 from 1990 levels
5% cut in total globally
8% cut for EU-15 and most other European countries
These targets define each country’s volume of ‘allowed’ emissions (AAUs)
Burden sharing principle
Use of flexible mechanisms (market mechanisms, cap-and-trade schemes)
Clean Development Mechanism (CDM) – system for pollution reduction schemes in developing economies
Permits : Certified Emission Reductions (CERs)
Joint Implementation (JI) – system for pollution reduction schemes in developed economiesPermits : Emission Reduction Units (ERUs)
Emissions Trading Scheme (ETS) – EU emission permits trading schemePermits: EU Emission Allowances (EUAs)
CERs can be transferred into EUAs etc. but the total number of AAUs is fixed
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Climate change regulation
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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Climate change regulation
EU target
8% by 2010 from 1990 levels
20% by 2020 or
30% by 2020 if a broad-based global agreement on GHGs can be reached
Emissions Trading Scheme was set up
Member states are given National Allocation Plans (NAPs) for CO2 permits
Covers power, paper, steel, iron, mining, oil and cement
Import allowance for CDM/JI subject to certain limits
CO2 emission permits can be traded within each phase with banking also possible between phases 2 and 3
Phase 1: 2005-07
Phase 2: 2008-12
Phase 3: 2013-20— Includes new sectors such as airlines, aluminium, petrochemicals, etc.
Note other trading schemes will probably emerge globally, but may not necessarily be fungible with the EU ETS
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EUA price forecast
Estimation:
Long-term demand for permits
A function of EUA shortage vs demand
Allocation plans
Compliance buyers including governments
Non-compliance buyers
CER/ERU balance
Abatement opportunities – various methods of abatement have different costs
CDM/JI permits – trade at a discount to EUAs due to project failure risk
UK coal-to-gas switching
German lignite-to-coal switching
Industrial abatement (N.B little willingness for this from industrials so far)
Existing and new plants
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EUA price forecast
2008 abatement stack
Demand for abatement
The price of CO2 is determined by the
Demand for abatement
Supply of abatement
Forecast €25/t for phase 2
UK c-t-g summer
Industrial, <€20/t
Industrial, <€25/t
UK c-t-g winter Industrial, <€27.5/t Industrial, <€30/t
Industrial, <€35/t
German l-t-g
0
5
10
15
20
25
30
35
40
45
50
0 50 100 150 200 250 300 350 400
Volume (mt/a)
Pric
e (€
/t)
Source: JPMorgan estimates
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Carbon capture and sequestration‘Clean coal’
Capture via post-combustion, pre-combustion or oxyfuel combustion
Storage in deep geological formations, deep oceans or mineral carbonates (although UN unlikely to approve ocean & carbonation
Technology for large scale capture of CO2 already commercially available, problem is pipeline and regulation
Capturing and compressing CO2 requires energy lowers overall thermal efficiency
There are firm plans for around 8.3GW of CCS-type capacity – 51mt/year of abatement
Abatement cost estimate €28-30/t a function of:
Margin loss
(CCS plant new build cost – coal ex-CCS plant new build cost + energy loss) x CO2 avoided
Estimate: €16-17/MWh output or €24/t of CO2
Transport cost
Estimate: €2-2.5/t
Storage cost
Estimate: €3-3.5/t
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Climate change regulation outcomes
Phase 1 ETS was effectively bankrupt since there has been a surplus of permits
Currently phase 2 permits are trading at around €20-25/t
We forecast €25/t for phase 2
Emissions of 2,300mt/a, a 10% cut in NAPs vs. phase 1, 160mt total extra demand from airlines, a shortfall of 210mt/a on average and CDM/JI permit deliveries of 780mt total
Phase 3 deeper and broader
Emergence of subnational and national schemes
Extension to other GHGs, other industries
Utility sector the most impacted
Positive for revenues
Negative for costs – depending on free allocations/ auctioning
Free allocations have been positive for profits overall, but unlikely post 2012
Although windfall for low / zero CO2 emitting plants will remain
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Climate change regulation outcomes
Impact on utilities’ profits:
Marginal cost pricingHigher variable costs per MWh and higher long-term power prices
Revenue will include 100% of the price of a permit
Windfall profits are incurred if permits are allocated to thermal plants for free…
… and non-thermal plants are price takers
Degree of forward contractinge.g. E.ON and RWE have already sold forward a large part of 2008 and 2009 output so the impact of volatility of phase 2 CO2 on them will be minimal
Change in load stackA higher CO2 price will move gas-fired power plants further into the baseload compared to coal-fired
Coal-fired plants will suffer from lower volumes and hence lower profits and fixed costs per MWh
Carbon intensity relative to average will drive valuationExposure to coal vs. nuclear etc.
Exposure to generation vs. networks and supply
For more information, see our series ‘All you ever wanted to know about carbon trading’ at www.jpmorgan.com/climatechange
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EU thermal regulation: LCPD (2001)Large Combustion Plant Directive
Applies to combustion plants with a thermal output of >50 MW
Aims to reduce acidification, ground level ozone and reduce aerosol particulates throughout Europe by controlling emissions of sulphur dioxide (SO2), nitrogen oxides (NOx) and dust
Using emission limit values (ELVs)
The UK’s National Grid has warned the extra costs of coping with the implementation of LCPD could substantially increase transmission constraint costs
Set to have an impact on system costs of around £15m
≈12GW of capacity has opted out of the LCPD
Running hours of these plants will be limited on a chimney stack basis (either the whole plant is running or not) to 20,000 hours across the 8 year period to 2015
NG says it expects operators will look to maximize earnings from the remaining 20,000 hours by optimizing running and operating multiple units as a single block at the same time
Coal plant will be the most affected
For opted out coal units, the 20,000 hour limit is likely to act as a constraint on output and the costs of reserve will rise
NG has put forward 2 possible scenarios for plant operations:Summer-cold regime – generators decide to run the units over the winter and make them unavailable over the summer, either on maintenance or moth-balled
Year-round running regime – generators will focus their running hours on the peak power price periods across the year, irrespective of season
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Climate change
The energy value chain
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Mapping the renewable energy space
Drivers : Climate change; Energy Security; Economics
Renewable / Alternative Energy
Transportation
Electricity
Biofuels Hybrids / Plug-ins
Traditional
New Tech
Clean Thermal
Policy regimes: Standards; Pricing/support; R&D
Nuclear Mini hydro
Wind
Onshore Offshore
Solar
PV Thermal
Equipment
Operators
Autos
Big oil
New entrants
Utilities
New entrants
Marine
BiomassCCS
Concepts Technologies Corporates95R
EN
EW
AB
LE
S
Renewables
Renewables
Climate change concerns
Energy security concerns
Solar, wind, r-o-r hydro and geothermal technologies do not emit any GHGs
Pumped storage hydro uses a small amount of electricity
Biomass combustion emits CO2, but unlike fossil fuel combustion, this has not been ‘out’ of the carbon cycle for a long time
By definition, renewable energy is not finite
It allows a country to reduce its reliance on foreign imports of electricity/coal/oil/gas
Hence governments have been very keen to encourage investment in renewable energy capacity…
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Renewables capacity support mechanisms
Feed-in tariffs – fixed pricing framework with a cap-and-floor of floating prices to provide a return well over WACC
e.g. Spain RD486 and RD661
Green certificate schemes— Energy suppliers required to submit certificates to show they have sourced a certain % of supplies from
renewables— Certificates bought from a pseudo market ‘buy-out fund’
e.g. Renewable Obligation Certificates in UK
Tax credits – levy charged on all suppliers unless they qualify for an exemption
e.g. Production Tax Credit in US, CCLECs in UK
Capital subsidies – can by-pass state aid rules
e.g. Greece: 35-55% of capital cost
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EU renewables targetsEC proposals on member state targets for renewable energy as a proportion of all energy consumptionEC proposals on member state targets for renewable energy as a proportion of all energy consumption
The targets proposed on 23rd
January were harsh but widely expected and the horizon is far out
A proposal for tradeable‘Guarantee Of Origin’ (GOO) certificates would allow suppliers to meet their obligations with output from another country
Positive for suppliers and generators with pipeline in low tariff/high deliverability countries
Negative for generators in green certificate/ low deliverability countries e.g. Italy and the UK
new electricity trading arrangementsNETAexploration and productionE&P
national allocation planNAPcombined heat and powerCHP
molten salt reactorMSRCertified Emission ReductionCER
long run marginal costLRMCClean Development MechanismCDM
liquified natural gasLNGcarbon capture and sequestrationCCS
lead fast breeder reactorLFRclimate change levy exemption certificateCCLEC
local distribution zoneLDZcombined cycle gas turbineCCGT
large combustion plant directiveLCPDboiling water reactorBWR
Joint ImplementationJIBritish electricity trading and transmission arrangementsBETTA
gas fast breeder reactorGFRadequacy reserve marginARM
EU Emission AllowanceEUAaverage revenue per userARPU
Emissions Trading SchemeETSadvanced gas cooled reactorAGR
Emission Reduction UnitERUaverage cold spellACS
European pressurised reactorEPRAssigned Allocation UnitAAU
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Acronyms
very high temperature reactorVHTR regulated asset valueRAV
UN Framework Convention on Climate ControlUNFCCCregulated asset baseRAB
Union for the Co-ordination of Transmission of ElectricityUCTEpressurised water reactorPWR
third party accessTPAphotovoltaicPV
seven year statementSYSproduction tax creditPTC
short run marginal costSRMCpublic service obligationPSO
sodium fast breeder reactorSFRpublic service contractsPSCs
super-critical water reactorSCWRpower purchase agreementPPA
renewable portfolio standardRPSEngland and Wales water regulatorOFWAT
renewable obligation certificateROCBritish electricity and gas regulatorOFGEM
royal decree (Spain)RDopen cycle gas turbineOCGT
regulated capital valueRCVnational oil companyNOC
remaining capacity RCnotification of inadequate system marginNISM
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GlossaryAdequacy reference margin = margin against the peak load +minimum reserve capacity
British thermal unit – a unit of heat equal to ≈ 252 calories, enough heat to raise the temperature of one pound of water 1°F
Load curve – order in which different plants are called upon to run based on their variable operating cost
Minimum reserve capacity = 5% of national generating capacity
Margin against the peak load = peak load – load at reference point
Plant margin - amount by which the installed generation capacity exceeds the forecast peak demand
Remaining capacity = reliably available capacity – reference load
Reliably available capacity = total generating capacity – non-usable capacity – maintenance and overhauls –outages – system services reserve
Reserve margin – amount of unused available capacity of an electric power system at peak load, expressed as a percentage of total capacity
Tariff deficit – the shortfall of regulated revenues from tariffs versus the revenues that would be realised by prevailing market prices
Thermal efficiency - efficiency with which the energy content (measured in gross calorific value) of the input fuel is turned into electrical energy by the generating station
Thermal generation – electricity production using a steam-driven turbine
Windfall profits – additional profits due to free CO2 allocations
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Abbreviations
per day/d
per year/y or /a
megawatt hoursMWh
terrawattTW
gigawattGW
megawattMW
kilowattKW
British thermal unitBtu
billion tonnes of oil equivalentBtoe or Gtoe
million tonnes of oil equivalentMtoe
tonne of oil equivalenttoe
thousand barrelskb
thousand boekboe
barrel of oil equivalentboe
million tonnesMt
million cubic feetMcf
metric tonnet
billion cubic metresbcm
cubic feetcf
barrelb or bbl
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Conversions
10.07690.1070.10.14293.9711634.1870.685Gcal
13.0011379.001.251.793349.781459052.528.58tonnes of LNG
9.350.000710.00090.00130.036110.580.03810.0062m3 of gas
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