UK: Moving towards a long-term carbon price

The agreement on climate change reached at the G8 summit in July 2005 gives new impetus to action to reduce greenhouse gas emissions. It acknowledges climate change as a "serious and long-term challenge" and states that "we know enough to act now to put ourselves on a path to slow and, as the science justifies, stop and then reverse the growth of greenhouse gases." Whilst not going as far as some would have liked, the agreement represents an important step forward in developing international co-operation to limit emissions.

The G8 agreement includes an action plan that recognises the importance of financing the transition to cleaner energy, and contains a commitment to use (where appropriate) "marketbased policy frameworks" to "provide confidence in the near and long-term value of investments to reduce emissions of greenhouse gases and/or pollutants". This is consistent with the statement of the World Economic Forum’s Climate Change Round Table of major companies, which urged G8 Governments to establish a long-term, market-based framework extending to 2030, and indicatively to 2050.

With the introduction of the EU Emissions Trading Scheme (EU ETS), progress has already been made on establishing market-based frameworks covering greenhouse gas emissions, including from the UK generating sector, and frameworks governing emissions are likely to continue to develop. The effect of such frameworks on the economics of nuclear plant or other means of emissions abatement can be substantial. For example, a carbon price will increase the marginal costs of generation from fossil fuels which, other things being equal, will tend to raise wholesale electricity prices. Depending on the extent of this effect and the balance of fossil fuel plant within the system, we estimate each €10/tCO2 increase in the carbon price could raise the rate of return of a nuclear plant by around one percentage point, or more, on a pre-tax basis. For a 2000MW plant this could increase the Net Present Value of the investment by around £400m or more.

Consequently, reinforcing investor confidence that some minimum carbon price will prevail could greatly assist the financing of nuclear plant and other long-lived investments. However, carbon prices and governmental commitment to emissions abatement are still relatively recent. Investors in long-lived nuclear assets will need to have confidence in longterm governmental commitment to carbon pricing, or other instruments, for policies to have an appropriate effect on investors’ decision making.

This paper considers how a number of market-based policy frameworks, of the form encouraged by the G8, rate against the twin objectives of (i) committing in a credible way to rewarding carbon abatement investment in the longer-term and (ii) fitting with wider policy objectives of ensuring efficient emissions reduction.

We consider here four policy instruments that reward investments by increasing the revenue earned for the investor as abated emissions increase. Subsidies may also be used to reward investment in emissions abatement, but are not considered here because they are not marketbased, and seem less likely to play a major role in the UK.

The four policy instruments we consider are set out below.

• Emissions trading schemes seek to limit total emissions, either in absolute terms or relative to a benchmark. By limiting the quantity of allowed emissions, they create a scarce commodity and therefore place a price on emissions. At present, the EU Emissions Trading Scheme (EU ETS) is the largest example of such a scheme, and is the example we consider below.

• Carbon taxes aim to price emissions directly. We consider the example of a carbon tax on the UK power sector.

• Obligations look to mandate emissions abatement, for example by obliging a certain amount of carbon-free generation. They may be implemented by means of tradable certificates or other processes such as competitive tender, so may be regarded as market-based. The Renewables Obligation is an example of such a scheme and we consider below an analogous obligation for a proportion of carbon-free generation.

• Financial risk management contracts issued by government seek tocomplement mechanisms such as taxes and emissions trading by helping to manage price risk, which arises in part due to policy uncertainty.

How well do these instruments provide a credible commitment to rewarding carbon abatement investment in the longer-term, allowing private sector investors to evaluate appropriately their long-term investment opportunities, while fitting wider policy objectives of ensuring efficient emissions abatement?

Since Phase 1 of the EU ETS came into effect in January 2005, generators have been required to hold an emissions allowance for each tonne of CO2 they emit. Prices of allowances have varied widely, rising from around €7/tCO2 earlier this year to over €20/tCO2 more recently, as highlighted in the chart above. Prices are likely to change again in Phase 2 of the scheme, which runs from 2008 to 2012, as cap levels implied by National Allocation Plans (NAPs) are set, and as fundamentals of supply and demand, including relative fuels prices, vary.

However, there is no clarity on the form of the EU ETS beyond Phase 2, which ends in 2012. Agreement within the EU will need to be reached against a background of uncertainty about the types of wider international arrangement that might be put in place to abate emissions. This uncertainty may make agreement on how to extend the EU ETS into the longer-term more difficult to reach.

The G8 agreement offers little here, establishing some high level principles that may influence any future agreement, but not more. It does nothing to commit to an international emissions trading regime, still less does it provide any guidance on the form of such a scheme, or the level of any caps that may be imposed.

Even if the EU were to extend the EU ETS into the longer-term, it would be unlikely to do so in a way that would give sufficient certainty over the time horizons relevant to investment in new nuclear generating plant, or other similarly long-lived investment. The level of prices into the long-term would be likely to depend on a series of future political negotiations on the level of caps on emissions under the scheme. The outcome of these negotiations is impossible to foresee. Prospects are even more uncertain for other aspects of the scheme that will affect wholesale power prices, notably the entitlement of generators to free allocations of allowances.

So, while the EU ETS has the advantage of already existing and of being binding on all EU Governments under EC law, it is still developing as an instrument of carbon abatement. Consequently, private sector investors may still assess the EU ETS as subject to significant political risk after 2012.

Another possible way of greatly reducing risk associated with the carbon price would be to impose a carbon tax on the UK power sector. Such a tax would provide strong incentives for emissions abatement provided the sector is sufficiently competitive. A tax on fuel input into power generation would be a suitable proxy for a tax on emissions for conventional plant, but the possibility of carbon capture would need to be recognised by appropriate exemptions from the tax.

Such a tax would not be a formally binding commitment to the carbon price, but the scale of the revenue raised might make it difficult for government to remove once it was in place. The revenue from a tax of €20/tCO2 on UK power generators would be some £2 billion p.a. with the present level of emissions. Commitment could potentially be further increased by building in an escalator, such as inflation or "inflation plus". If the tax were set at a relatively modest level, the Government could retain flexibility to increase levels in future should the requirements for incentivising carbon abatement imply a higher level is appropriate. However, even a moderate tax may be enough to improve materially the economics of new nuclear plant and other means of emissions abatement. The carbon price level under a tax would be relatively stable compared with the price under an emissions trading scheme. However, correspondingly there would be less certainty of meeting a certain threshold level of emissions.

Incentives could be made consistent with those prevailing in industry if the Climate Change Levy (CCL), which already applies to industrial consumers, were reformed to match any carbon tax introduced into the UK power sector. In particular, it would be desirable to relate the CCL to carbon emissions rather than energy. This would more accurately target the environmental externality that the CCL is intended to address. It would also be appropriate to remove the CCL on electricity consumption by industrial energy users if a tax were placed on fuel input into power generation. The level of the CCL and carbon tax in the power sector could be equalised to give consistent price signals across sectors. This would be in line with the recommendations made in the recent House of Lords Select Committee report on the Economics of Climate Change, which advocated replacing the CCL with a wider carbon tax.

There may be objections to generators having to buy both allowances and pay a carbon tax. However, such a regime is not necessarily economically inefficient or inequitable. For example, the cap imposed by the EU ETS could be less stringent than the optimal level of emissions abatement would require, or generators may gain from the allocation of free allowances. However, if it is considered inappropriate to oblige generators both to buy permits and pay a carbon tax in full, it would be possible in principle to address this issue, for example by rebating the carbon tax by the average EU ETS allowance price. There would, nevertheless, be significant issues to be resolved in calculating a rebate in practice. For example, the weighting of any average may be contentious, as may be the choice of reference price, especially if markets lack liquidity. A rebate would give the carbon tax some of the characteristics of a one-way Contract for Differences (CfD) on the carbon price, which is discussed further below, but unlike a CfD, the Government would gain revenue rather than make payments if the carbon price under the EU ETS was low.

The revenue raised from a carbon tax could be used to mitigate any undesirable effects caused by its introduction. For example, it could be used to reduce electricity bills for vulnerable residential consumers and to offset other taxes. It might also be used to enable the supply side, for example by funding developments in new technologies such as Carbon Capture and Storage (CCS), or rewarding those organisations which outperform others in securing emissions reductions.

In this respect, an extension of the carbon tax would have a great advantage over the Renewables Obligation. We estimate that payments by consumers over and above the market price of power under the Renewables Obligation are likely to total over £20 billion by 2020. However, no revenue is raised for Government under this scheme to help mitigate adverse consequences.

An obligation on suppliers to purchase a certain proportion of their requirements from carbon free sources into the longerterm could be introduced. Such a scheme existed for much of the 1990’s in the form of the Non-Fossil Fuel Obligation. It may also be re-introduced to assist investments in nuclear and other carbon-free generation in a similar form to the existing Renewables Obligation, but need not replicate all of its details. There would also be a need to consider co-ordination with the present Renewables Obligation, which seems likely to be retained given existing political commitments and a desire to avoid policy instability. Developing a carbon-free obligation separately from the Renewables Obligation would risk increasing fragmentation in the market. However co-ordination with the Renewables Obligation would need to avoid diluting the effectiveness of the RO if confidence in both instruments were to be retained.

There are a number of limitations to the economic efficiency of such an option. Unlike the EU ETS or a carbon tax, it would provide no signals for switching from coal to gas, or for constructing higher efficiency fossil fuel plant. It may also lead to higher cost carbon abatement compared with other sectors.

There are other potential problems with such a mechanism. For example, in practice it may oblige suppliers to buy from one of a relatively limited number of providers of new nuclear plant if other carbon-free technologies are not readily available. The weak negotiating position thus created may increase costs.

It may also be difficult to set such an obligation at an appropriate level. For example, the obligation may be set at too low a level. In the absence of other incentives, this may lead to cost-effective abatement opportunities being missed. On the other hand, the obligation may be set at too high a level, in which case it may become too costly relative to abatement in other sectors. Furthermore, varying the level of the obligation cost effectively over time may be particularly challenging, especially once the obligation has been established. For example, the costs of nuclear plant and other technologies such as CCS may decline as experience is gained around the world. It will be difficult to judge in advance when an obligation should seek to take advantage of this. However, there are also advantages to such an obligation. It provides strong incentives, and if the technology supply is adequate, guarantees certain outcomes. In this respect, it might be useful in ensuring that "clear wins" from abatement in the power sector are not missed, and this may make important contributions to overall emissions reductions.

A direct guarantee of the value of emissions abatement investment from the UK Government could take the form of a CfD on the carbon price. CfDs would result in payments, most probably a set amount per MWh of carbon-free generation, if the carbon price fell below a certain level. They could also require generators to make payments to the Government in the event that carbon prices were above a specified level, that is a CfD could be two-way rather than one-way. The size of payments could be calculated in various ways, for example based on an imputed level of emissions per MWh generated from Combined Cycle Gas Turbine (CCGT) plant. The contracts could be tradable, their market price reflecting prevailing expectations of carbon prices.

This mechanism could offer the required certainty to generators into the long-term because it would be in the form of a binding contract. It could be made neutral between different carbon-free generating technologies by making it available to all generators seeking to manage their carbon price risks.

However, such an instrument may have a narrower effect than other types of instrument in that it is likely to benefit investors in power plants rather than encourage conservation or investment in other sectors. In contrast, the EU ETS or a carbon tax consistent with a reformed CCL would run cross-sector.

There would also be challenges in designing and writing such a CfD in present circumstances because it may not be clear what instrument, or combination of instruments, would be included in the carbon price against which the difference was calculated. For example, the EU ETS may run alongside or be superseded by a wider international scheme that may involve more than one instrument, so have more than one implied "carbon price". However, if a carbon tax were in place it might be more straightforward to write a CfD against the cost per tonne of CO2 in the tax. There would also be significant challenges in operating a CfD in practice, especially if it were two-way, for example in areas such as margin call and cash flow management.

Other features of the potential design of carbon pricing regimes would need to be anticipated if CfDs were to give the necessary reassurance to investors in nuclear plant. For example, the carbon price might be high, so a CfD might not be triggered, or might even result in payments by generators of carbonfree electricity to the Government. This would be of concern if new fossil fuelled generating plant were givien free allocations of allowances under the EU ETS and, as a result the long run electricity price were relatively little affected by the carbon price. In such cases, nuclear plant would benefit neither from payments under the CfD nor from the affect of carbon prices on electricity prices.

The merits of these potential policy instruments against a range of assessment criteria, including long-term commitment, are summarised in the table below. This assessment is indicative, but illustrates the type of assessment that would need to be carried out in a full analysis of the options for establishing a market-based framework.

Given the potential for these policy instruments to influence the mix and type of plant within the UK, the implications for other policy objectives, such as security of supply would also need to be assessed.

The instruments are not necessarily mutually exclusive. For example, emissions trading may run alongside a carbon tax. A CfD could be used in combination with a carbon tax or emissions trading. A carbon-free generation obligation could be used to guarantee a certain level of new carbon-free power, with an expectation that the EU ETS or successor trading schemes will provide incentives to go beyond this minimum. Other combinations of instruments are also possible. Combinations of instruments such as these may help to find the right mix of certainty for investors and fit with other policy objectives.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.