Report: The likely Impact of Carbon Emissions Trading Across the Electricity Value Chain: Responding to the Developing EU Environmental Agenda, 2005-10 TOC

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

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