Clearer signals ahead
Estimating CO2 prices in the first Kyoto budget period of 2008–2012 is now a key risk-management challenge for utility analysts. Abyd Karmali, Sebastian Foot and Nazim Osmancik look at what is likely to drive prices in this period
It is now accepted wisdom in the energy markets that the constraints on greenhouse gas emissions being imposed on the European power sector will have significant commercial implications for utilities and fuel suppliers alike. The EU Emissions Trading Scheme (ETS) is now moving to cruising speed, and clearer CO2 price signals are emerging for the period 2005–2007. So one of the key risk-management challenges utility analysts now face is understanding what is likely to drive the price of CO2 in the first Kyoto budget period of 2008–2012, since revenue forecasts in that period are very much material to any planned new power plant investment decisions.
Some analysts suggest planning for a CO2 price of O25/tonne. Recent analysis undertaken by ICF Consulting suggests, however, that fundamentals analysis of the market, policy and technology drivers can help provide significantly more robust estimates for the price of CO2 and can considerably reduce the uncertainties. Our view is that O25/tonne of CO2 represents more of a crisis scenario than one grounded in any realistic perspective on the various forces that will affect the price.
In the past three years, awareness of the impacts of carbon constraints has reached the mainstream investment community, and most investment banks’ equity research analysts highlight the impacts of carbon on the value of assets in the European power sector. Most of the attention has, however, focused on the launch of the so-called pilot phase of the EU ETS, which runs from 2005–2007. Since the Kyoto Protocol came into force on February 16, 2005 – and with it an increased likelihood of the European power sector being under carbon constraints for years to come – we submit that emphasis should now be placed on the likely impacts during the second phase of the EU ETS that corresponds to the first budget period of the Kyoto Protocol (2008–2012).
Variables
Undertaking a fundamentals analysis of the demand and supply for carbon during 2008–2012 is made more difficult by the plethora of variables involved, many of which depend on key policy decisions yet to be taken, including: the tightness of the overall cap for the EU ETS to be set during 2008–2012
the linkage between the market for EU Allowances (the currency of the EU ETS) and other carbon commodities created by the Kyoto Protocol (certified emission reductions (CERs), emission reduction units, (ERUs), and assignment amount units (AAUs)
the potential addition of other gases and sectors into the EU ETS
ICF Consulting’s approach incorporates these uncertainties. To determine the future price of CO2 our methodology considers the following:
The quantity of cost-effective abatement options available to participants in the CO2 market (represented by detailed marginal abatement cost curves – MACCs)
The likely shortfall of emissions within the carbon market(s) due to the tightness of the caps and the likely availability of credits from the project-based mechanisms of the Clean Development Mechanism and Joint Implementation (JI)
The impact of surplus allowances, commonly referred to as ‘hot air’, particularly from Russia and Ukraine entering the market
Any approach for analysing the price of carbon during 2008–2012 must consider the dynamic response of the European power sector. We have undertaken power market modelling using ICF Consulting’s in-house proprietary Integrated Planning Model (IPM).
The IPM can model several concurrent energy policy developments. For example, it considers progress over time from the renewables directive and the large combustion plant directive.
To estimate overall market demand for CO2 allowances, our analysis determines the relative shortfall in carbon within a given trading scheme; where more than one trading scheme is in operation the cumulative total shortfall is calculated based on regional carbon credit requirements. Calculating the shortfall within trading schemes is determined by measuring the expected demand for emission reductions, based on the national allocation plans (NAPs) for the EU and by applying a NAP-like approach to the rest of the world. This identifies the range of potential relative demand for emission reductions in countries under different scenarios. Demand is calculated by determining the following:
Trading sector shortfall in CO2 equivalent (CO2e – EU NAPs and NAP-like approach for rest of the world)
Government purchase of carbon credits (usually through CDM and JI initiatives)
Likely government policy on reducing emissions within the non-trading sectors (for example, the household, commercial, agricultural and transport sectors) Government purchase of credits and company purchases of carbon credits represent the total market demand, while non-trading sector reductions represent a reduction in demand for credits, since it reduces the burden on the trading sector and government purchase.
CO2e demand scenarios are combined with their equivalent MACC to determine the relative equilibrium price for carbon. Plotting demand points on the MACC should be viewed as dynamic, with the point being able to move along the MACC line as total demand changes within a trading period. Demand might increase or decrease as a result of upward pressure from exogenous variables such as weather fluctuations or fuel prices, or downward pressure from the introduction of additional carbon credits such as CERs. The resulting changes in demand may lead to an impact on the equilibrium price of CO2e.
Key assumptions we make during 2008–2012 are that all parties that have ratified the Kyoto Protocol meet their agreed targets and apply the policy measures they have pledged to undertake (including government purchase of CDM and JI credits.) We explore a variety of scenarios to establish total demand for carbon by considering the likely depth and breadth of participation in carbon trading. Different scenarios include:
Expanded EU ETS (potentially including the aluminium and chemical sectors)
EEA States (Norway, Iceland and Switzerland)
Other Annex I (Japan, Canada, New Zealand)
The 12 US states that have said they will implement measures to constrain CO2 emissions
The Australian territories that have indicated they will implement measures to meet the federal target.
Based on these variables, our analysis forecasts a total unmet demand in the range of 300–800 million tonnes of CO2/year during 2008–2012.
On the demand side, fuel prices are one of the critical determinants of the shape of the abatement cost curve within the power sector. Our scenarios considered different possibilities, including, for example, the prospect of a continuation of the moderate to high oil and gas prices that have been seen during the past 12 months.
Findings
The various scenarios we have explored for the price of carbon during 2008–2012 identify a series of key insights. In general, the trading period 2008–2012 is characterised by significant growth in the size of the market compared with 2005–2007, with further cuts being made to European trading sectors and additional cuts from other parties as the Kyoto Protocol commences trading. Consequently, the price of CO2e rises compared with 2005–2007.
Our analysis demonstrates that under all likely policy and market scenarios, within 2008–2012, two key variables set the price of CO2e in this period. The first is the introduction into the carbon market of, and the response to, so called ‘hot air’ allowances – AAUs – from Russia and Ukraine. The second is the implementation of cost-effective large scale power sector abatement options within Europe as load shifting from coal to gas accelerates and new combined-cycle gas turbine (CCGT) power plants come online in specific markets where high-value opportunities emerge.
During 2008–2012, Russia and Ukraine will have a significant amount of excess allowances of about 800 to 1,000 million tonnes of CO2 per year. Thus, hot air allowance supply exceeds market demand under all scenarios for carbon credits. Hot air credits are gained at no cost, which presents an opportunity for Russia and the Ukraine to behave in a monopolistic profit-maximising manner. A number of countries have now committed themselves to not purchasing hot air allowances, including Canada, Germany and the Netherlands. However, where there are enough market entry points for hot air allowances, overall demand for carbon will be dampened, and countries such as Russia and the Ukraine may find they effectively control the price of CO2e.
Another key insight from the analysis is that there is adequate availability of large-scale power sector fuel switching opportunity to reduce emissions, and these dominate the overall marginal abatement cost curve relative to the abatement potential from other sectors included in the scheme. Long-run fuel prices, and in particular the spread between coal and gas prices, is key to determining the level of abatement available in the power sector at specific cost levels. Generally, however, the available abatement options have the potential to meet all demand requirements when Russia and Ukraine hot air allowances are used in combination. Without the use of hot air allowances, however, the price of carbon would increase considerably (although still less than the O25/tonne forecast by some commentators.) Moreover, the price will likely be constrained in such scenarios by the increased use of CDM and JI credits, which would put downward pressure on the level of abatement required and ensure a lower price of carbon.
Figure 1 highlights the dynamic relationship of these dominant drivers on the price of CO2e during 2008–2012. Compared with the 2005–2007 market, where we expect to see higher price volatility given the pivotal role of weather and fuel prices, we anticipate low upside and downside price volatility during 2008–2012 as a result of the shift in balance between power sector abatement and excess hot air allowances entering the market.
Our analysis of the price of carbon for 2008–2012 has also identified several country-specific opportunities for players in the European power market. Power prices are heavily influenced by the price of carbon. In some countries, the level of carbon prices necessary to encourage new CCGT development is much higher than in others. Niche opportunities will emerge in a cascading type of way, reflecting the fact that different countries’ power markets are observed to differ significantly in their sensitivity to CO2 prices.
Given the materiality of the price of carbon to power plant valuation, companies in the energy markets need to develop explicit estimates for the future price of carbon over the expected life of existing and proposed assets and incorporate it into investment protocols. We propose that the term BAPEC (best available price estimate for carbon) now enter the energy risk management lexicon.
Abyd Karmali, Sebastian Foot, and Nazim Osmancik are respectively senior vice-president, consultant and analyst in the London office of professional services firm ICF Consulting
Emails: Akarmali@icfconsulting.com, Sfoot@icfconsulting.com, Nosmancik@icfconsulting.com
For more information on ICF Consulting’s study Scenarios for the Price of CO2 in 2008–2012, tel +44 20 7391 4700 or visit www.icfconsulting.com
Some analysts suggest planning for a CO2 price of O25/tonne. Recent analysis undertaken by ICF Consulting suggests, however, that fundamentals analysis of the market, policy and technology drivers can help provide significantly more robust estimates for the price of CO2 and can considerably reduce the uncertainties. Our view is that O25/tonne of CO2 represents more of a crisis scenario than one grounded in any realistic perspective on the various forces that will affect the price.
In the past three years, awareness of the impacts of carbon constraints has reached the mainstream investment community, and most investment banks’ equity research analysts highlight the impacts of carbon on the value of assets in the European power sector. Most of the attention has, however, focused on the launch of the so-called pilot phase of the EU ETS, which runs from 2005–2007. Since the Kyoto Protocol came into force on February 16, 2005 – and with it an increased likelihood of the European power sector being under carbon constraints for years to come – we submit that emphasis should now be placed on the likely impacts during the second phase of the EU ETS that corresponds to the first budget period of the Kyoto Protocol (2008–2012).
Variables
Undertaking a fundamentals analysis of the demand and supply for carbon during 2008–2012 is made more difficult by the plethora of variables involved, many of which depend on key policy decisions yet to be taken, including: the tightness of the overall cap for the EU ETS to be set during 2008–2012
the linkage between the market for EU Allowances (the currency of the EU ETS) and other carbon commodities created by the Kyoto Protocol (certified emission reductions (CERs), emission reduction units, (ERUs), and assignment amount units (AAUs)
the potential addition of other gases and sectors into the EU ETS
ICF Consulting’s approach incorporates these uncertainties. To determine the future price of CO2 our methodology considers the following:
The quantity of cost-effective abatement options available to participants in the CO2 market (represented by detailed marginal abatement cost curves – MACCs)
The likely shortfall of emissions within the carbon market(s) due to the tightness of the caps and the likely availability of credits from the project-based mechanisms of the Clean Development Mechanism and Joint Implementation (JI)
The impact of surplus allowances, commonly referred to as ‘hot air’, particularly from Russia and Ukraine entering the market
Any approach for analysing the price of carbon during 2008–2012 must consider the dynamic response of the European power sector. We have undertaken power market modelling using ICF Consulting’s in-house proprietary Integrated Planning Model (IPM).
The IPM can model several concurrent energy policy developments. For example, it considers progress over time from the renewables directive and the large combustion plant directive.
To estimate overall market demand for CO2 allowances, our analysis determines the relative shortfall in carbon within a given trading scheme; where more than one trading scheme is in operation the cumulative total shortfall is calculated based on regional carbon credit requirements. Calculating the shortfall within trading schemes is determined by measuring the expected demand for emission reductions, based on the national allocation plans (NAPs) for the EU and by applying a NAP-like approach to the rest of the world. This identifies the range of potential relative demand for emission reductions in countries under different scenarios. Demand is calculated by determining the following:
Trading sector shortfall in CO2 equivalent (CO2e – EU NAPs and NAP-like approach for rest of the world)
Government purchase of carbon credits (usually through CDM and JI initiatives)
Likely government policy on reducing emissions within the non-trading sectors (for example, the household, commercial, agricultural and transport sectors) Government purchase of credits and company purchases of carbon credits represent the total market demand, while non-trading sector reductions represent a reduction in demand for credits, since it reduces the burden on the trading sector and government purchase.
CO2e demand scenarios are combined with their equivalent MACC to determine the relative equilibrium price for carbon. Plotting demand points on the MACC should be viewed as dynamic, with the point being able to move along the MACC line as total demand changes within a trading period. Demand might increase or decrease as a result of upward pressure from exogenous variables such as weather fluctuations or fuel prices, or downward pressure from the introduction of additional carbon credits such as CERs. The resulting changes in demand may lead to an impact on the equilibrium price of CO2e.
Key assumptions we make during 2008–2012 are that all parties that have ratified the Kyoto Protocol meet their agreed targets and apply the policy measures they have pledged to undertake (including government purchase of CDM and JI credits.) We explore a variety of scenarios to establish total demand for carbon by considering the likely depth and breadth of participation in carbon trading. Different scenarios include:
Expanded EU ETS (potentially including the aluminium and chemical sectors)
EEA States (Norway, Iceland and Switzerland)
Other Annex I (Japan, Canada, New Zealand)
The 12 US states that have said they will implement measures to constrain CO2 emissions
The Australian territories that have indicated they will implement measures to meet the federal target.
Based on these variables, our analysis forecasts a total unmet demand in the range of 300–800 million tonnes of CO2/year during 2008–2012.
On the demand side, fuel prices are one of the critical determinants of the shape of the abatement cost curve within the power sector. Our scenarios considered different possibilities, including, for example, the prospect of a continuation of the moderate to high oil and gas prices that have been seen during the past 12 months.
Findings
The various scenarios we have explored for the price of carbon during 2008–2012 identify a series of key insights. In general, the trading period 2008–2012 is characterised by significant growth in the size of the market compared with 2005–2007, with further cuts being made to European trading sectors and additional cuts from other parties as the Kyoto Protocol commences trading. Consequently, the price of CO2e rises compared with 2005–2007.
Our analysis demonstrates that under all likely policy and market scenarios, within 2008–2012, two key variables set the price of CO2e in this period. The first is the introduction into the carbon market of, and the response to, so called ‘hot air’ allowances – AAUs – from Russia and Ukraine. The second is the implementation of cost-effective large scale power sector abatement options within Europe as load shifting from coal to gas accelerates and new combined-cycle gas turbine (CCGT) power plants come online in specific markets where high-value opportunities emerge.
During 2008–2012, Russia and Ukraine will have a significant amount of excess allowances of about 800 to 1,000 million tonnes of CO2 per year. Thus, hot air allowance supply exceeds market demand under all scenarios for carbon credits. Hot air credits are gained at no cost, which presents an opportunity for Russia and the Ukraine to behave in a monopolistic profit-maximising manner. A number of countries have now committed themselves to not purchasing hot air allowances, including Canada, Germany and the Netherlands. However, where there are enough market entry points for hot air allowances, overall demand for carbon will be dampened, and countries such as Russia and the Ukraine may find they effectively control the price of CO2e.
Another key insight from the analysis is that there is adequate availability of large-scale power sector fuel switching opportunity to reduce emissions, and these dominate the overall marginal abatement cost curve relative to the abatement potential from other sectors included in the scheme. Long-run fuel prices, and in particular the spread between coal and gas prices, is key to determining the level of abatement available in the power sector at specific cost levels. Generally, however, the available abatement options have the potential to meet all demand requirements when Russia and Ukraine hot air allowances are used in combination. Without the use of hot air allowances, however, the price of carbon would increase considerably (although still less than the O25/tonne forecast by some commentators.) Moreover, the price will likely be constrained in such scenarios by the increased use of CDM and JI credits, which would put downward pressure on the level of abatement required and ensure a lower price of carbon.
Figure 1 highlights the dynamic relationship of these dominant drivers on the price of CO2e during 2008–2012. Compared with the 2005–2007 market, where we expect to see higher price volatility given the pivotal role of weather and fuel prices, we anticipate low upside and downside price volatility during 2008–2012 as a result of the shift in balance between power sector abatement and excess hot air allowances entering the market.
Our analysis of the price of carbon for 2008–2012 has also identified several country-specific opportunities for players in the European power market. Power prices are heavily influenced by the price of carbon. In some countries, the level of carbon prices necessary to encourage new CCGT development is much higher than in others. Niche opportunities will emerge in a cascading type of way, reflecting the fact that different countries’ power markets are observed to differ significantly in their sensitivity to CO2 prices.
Given the materiality of the price of carbon to power plant valuation, companies in the energy markets need to develop explicit estimates for the future price of carbon over the expected life of existing and proposed assets and incorporate it into investment protocols. We propose that the term BAPEC (best available price estimate for carbon) now enter the energy risk management lexicon.
Abyd Karmali, Sebastian Foot, and Nazim Osmancik are respectively senior vice-president, consultant and analyst in the London office of professional services firm ICF Consulting
Emails: Akarmali@icfconsulting.com, Sfoot@icfconsulting.com, Nosmancik@icfconsulting.com
For more information on ICF Consulting’s study Scenarios for the Price of CO2 in 2008–2012, tel +44 20 7391 4700 or visit www.icfconsulting.com
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