Introduction
This report analyses how the introduction of the EU Emissions Trading Scheme is influencing the way in which energy utilities will have to structure their generation and supply businesses between 2005-10. The purpose of the report is to offer utilities a set of actionable recommendations aimed at improving their efficiency and profitability in the new age of growing environmental pressures.
Scope of this report
- Geographic coverage includes EU25, with special focus on the six key liberalised markets: Germany, France, the UK, Italy, Spain and the Netherlands.
- The scope of this study is the entire electricity value chain, although in-depth analysis centres on the core stages of power generation and supply.
- The time frame covered includes the period between 2005-10, although some longer-term implications of emissions quotas are also considered.
- Analysis in the report is based on Datamonitors proprietary analytical models describing both the long-term and short-term power market equilibrium.
Research and analysis highlights
On current trends, CO2 emission caps would result in a 500TWh annual power production shortfall in EU25 by 2010, with Italy likely to be particularly affected. As a result, member states will need to radically change their generation portfolios to satisfy the growing demand while decreasing the carbon content of power production.
Multiple strategies are available to utilities in how to pass on the costs of compliance with emissions caps onto their customers. In each case, the optimal cost assignment mechanism will depend on the structure of a utilitys generation portfolio, its customer base and the severity of emissions reductions it is facing.
Carbon trading reinforces existing trends towards internationalisation of procurement and risk management activities by utilities. In the longer term, emissions quotas and the growth of renewable generation will require major investment in electricity networks.
Key reasons to read this report
- Detailed analysis of the impact carbon emissions capping and trading will have on Europes electricity sector between 2005-10.
- Actionable recommendations to utilities on minimising the costs of compliance with emissions quotas and on passing those costs onto their customers.
- Based on Datamonitors proprietary models that identify the short- and long-term optimum solutions for coping with emissions quotas.
CHAPTER 1 EXECUTIVE SUMMARY
This report identifies four key trends in EU power markets as a result of the introduction of carbon emissions trading in January 2005, and develops recommendations for how utilities should respond:
On current trends, by 2010 CO2 emission caps would result in a c.500TWh annual power production shortfall in EU25
EU members need to build more gas-powered capacity and buy additional emissions credits, Italy being the worst affected
Carbon trading reinforces existing trends towards internationalisation of procurement and risk management activities by utilities
Multiple strategies are available to utilities in passing the costs of compliance with emissions caps onto their customers
Recommendations
CHAPTER 2 INTRODUCTION
The report analyses the likely impact of the new EU emissions capping and trading regime on the regions power utilities, and is aimed at senior utility company executives
What is this report about?
Why did we write this report?
Who is the target reader?
Report coverage includes all of the 25 EU member states, with special attention to the six key carbon-trading markets
Datamonitor identifies the most significant impact of EU ETS as being on generation and end-user supply
Report structure and contents
CHAPTER 3 POWER MARKET OVERVIEW
On current trends, by 2010 CO2 emission caps would result in a c.500TWh annual power production shortfall in EU25
By 2010, power demand in EU25 will have grown by 16% from the 2002 base, with southern Europe seeing the fastest growth
The share of thermal generation in EU25 is expected to remain stable between 2002-10, at 59% and 56% of the total respectively
Generating portfolios vary widely between the six key markets, from coal-dependent Germany to nuclear-dependent France
Between 2002-05 changes in the structure of generating capacity by country have remained small and incremental
By 2010, renewables will grow across the board, while Italy will finally have become less dependent on oil-fired capacity
Little overall change is predicted in CO2 emissions within the EU power generation sector between 2002-10
In 2010 the EU will remain dependent on thermal power, but the fuel mix within the thermal sector will change significantly
Producing more power through the existing generating mix to meet growing demand is inconsistent with the EUs Kyoto commitment
CHAPTER 4 EMISSIONS TRADING FRAMEWORK
All of the key EU countries have challenging emissions reduction targets, which they may not be able to meet internally
EU ETS covers c.46% of the EUs CO2 emissions
International trade in emissions credits can ease some of the pressure on the largest EU15 markets between 2005-10
The German NAP does not differentiate between power generation and industrial installations at the macro level. Compared to "business as usual", Germany needs to save 97mt of CO2 per annum by 2010
The French NAP does not allocate enough quotas to new entrants into the power generation sector. Compared to "business as usual", France needs to save 25mt of CO2 per annum by 2010
The UK NAP is based on self-imposed targets that exceed the countrys burden-sharing commitment. Compared to "business as usual", the UK needs to save 54mt of CO2 per annum by 2010
The draft Italian NAP includes a generous allowance for new entrants into power generation. Compared to "business as usual", Italy needs to save 30mt of CO2 per annum by 2010
The Spanish NAP has been changed to accommodate the coal-reliant generators. Compared to "business as usual", Spain needs to save 90mt of CO2 per annum by 2010
The Dutch NAP looks to international carbon trade for meeting the countrys emissions requirements. Compared to "business as usual", the Netherlands needs to save 20mt of CO2 per annum by 2002-10
CHAPTER 5 POWER GENERATION
EU members need to build more gas-powered capacity and buy additional emissions credits, Italy being the worst affected
EU ETS will require a major switch from coal to gas within the regions power generation sector
Without carbon trade, national quotas would determine the long-term optimum fuel mix within conventional thermal generation
With trade in emissions allowances, long-term fuel prices determine whether a country is a net buyer or seller of emission credits
In the short term, relative fuel prices determine load factors of available generation capacity by fuel type, rather than the breakdown of total generation capacity
For most of the key EU markets, limiting the 2010 emissions credits shortfall requires substantial new CCGT capacity
Germany should build 8GW of gas-fired plant using it to replace lignite, and reconsider its nuclear phase-out plans
France should switch most of its coal-fired plant to gas, co-fire biomass, and buy 4mt of credits per annum
The UK should retain its nuclear capacity, build 11GW of gas-fired plant and buy 6mt of credits per annum
Even after building an extra 37GW of gas-fired capacity, Italy will need to buy some 17mt of emissions credits per annum
Spain should build 17GW of gas-fired plant and develop solar power, but will still need to buy 14mt of emissions per annum
The Netherlands should build 7GW of new gas-fired capacity, leaving it a net buyer of 4mt of emissions per annum
CHAPTER 6 PROCUREMENT, RISK MANAGEMENT AND NETWORKS
Carbon trading reinforces existing trends towards internationalisation of procurement and risk management activities by utilities
Management of carbon exposure is set to become central to utilities procurement and risk management strategies
The impact of emissions trading on network activities will remain limited in the medium term
CHAPTER 7 END-USER SUPPLY
Multiple strategies are available to utilities in passing the costs of compliance with emissions caps onto their customers
Utilities need to find optimal ways of assigning additional carbon costs to their customer base
Datamonitor has identified three alternative cost-assignment algorithms, each have its own relative advantages and disadvantages
The optimum carbon pricing strategy depends on utilitys retail volumes and on how optimal its generation portfolio already is
E.ONs 2001 attempt to use the cost-reflective approach was ahead of its time, but could be successfully revived now
Cost-reflective carbon pricing requires careful planning and initially may be best suited for larger end-users
Reasons for E.ONs failure
Key future success factors
CHAPTER 8 RECOMMENDATIONS
Introduction
All four of the key market trends examined are pertinent to utilities and affect the whole range of their activities
CHAPTER 9 APPENDIX
Supplementary data
Demand Trends
Supply Trends
Emissions Trends
Research methodology
Research methodology
Further readings
SPP writing team
How to contact experts in your industry
List of Tables
- Table 1: The main relative advantages and disadvantages of alternative carbon cost loading options
- Table 2: EU power demand forecast, 2002-10
- Table 3: EU power generation capacity by source, 2002
- Table 4: EU power generation capacity by source, 2005f
- Table 5: EU power generation capacity by source, 2010f
- Table 6: EU CO2 emissions forecast, 2002-10
- Table 7: Power generation CO2 emissions credits shortfall (surplus) on current trends, 2005-10
List of Figures
- Figure 1: Power demand (d) and supply (s) in the key EU markets, 2002-10
- Figure 2: Overview of carbon balancing solutions in the 6 key markets, 2010
- Figure 3: The impact of carbon management on utilities procurement and risk management function, 2005-10
- Figure 4: Suitability of alternative carbon-pricing mechanisms in end-user supply
- Figure 5: Markets covered in this report
- Figure 6: Elements of the power value chain on which this report focuses
- Figure 7: Electricity demand in the key EU markets, 2002-10
- Figure 8: EU generation portfolio, 2002-10
- Figure 9: Composition of the power generation portfolio, 2002 (key markets)
- Figure 10: Composition of the power generation portfolio, 2005f (key markets)
- Figure 11: Composition of the power generation portfolio, 2010f (key markets)
- Figure 12: Power generation CO2 emissions in the key EU markets, 2002-10
- Figure 13: Power demand (d) and supply (s) in the key EU markets, 2002-10
- Figure 14: The EU Emissions Trading Scheme is but one step in achieving the Kyoto emission reduction targets
- Figure 15: Power generation in relation to national CO2 emissions, 2005-10
- Figure 16: German sector quotas vs. current trend, 2002-10
- Figure 17: French sector quotas vs. current trend, 2002-10
- Figure 18: UK sector quotas vs. current trend, 2002-10
- Figure 19: Italian sector quotas vs. current trend, 2000-10
- Figure 20: Spanish sector quotas vs. current trend, 2002-10
- Figure 21: Dutch sector quotas vs. current trend, 2002-10
- Figure 22: Long-term relative costs of gas- vs. coal-fired generation in relation to national emission quotas (without carbon trade)
- Figure 23: Long-term relative costs of gas- vs. coal-fired generation in relation to national emission quotas (with carbon trade)
- Figure 24: Datamonitors Power Dispatch model - an example
- Figure 25: Summary of the process of deriving quantitative, country-specific recommendations
- Figure 26: Suggested carbon balancing solution for Germany, 2005-10
- Figure 27: Suggested carbon balancing solution for France, 2005-10
- Figure 28: Suggested carbon balancing solution for the UK, 2005-10
- Figure 29: Suggested carbon balancing solution for Italy, 2005-10
- Figure 30: Suggested carbon balancing solution for Spain, 2005-10
- Figure 31: Suggested carbon balancing solution for the Netherlands, 2005-10
- Figure 32: The impact of carbon management on utilities procurement and risk management function, 2005-10
- Figure 33: The impact of carbon management on investment in networks, 2005-15
- Figure 34: Alternative carbon pricing options
- Figure 35: Suitability of alternative carbon-pricing mechanisms in end-user supply
- Figure 36: The E.ON MixPower product, October 2001
