Beyond the competition

Carbon dioxide capture and storage (CCS) can be viewed from a UK power industry perspective as a way of keeping coal in the energy mix while meeting EU emission targets. At a global level, though, it offers an alternative to making the very difficult decision between two choices we would otherwise face:

• Preventing the use of very significant amounts of available fossil fuel resources, essentially for ever.

• Failing to prevent fossil fuel use and seeing what happens at atmospheric CO2 concentrations above the 450 ppm level that is thought to give a reasonable chance of avoiding dangerous climate change.

It seems unlikely that major coal-based economies (eg, USA, China and India) will be able to commit to large emission reductions unless they are confident that CCS can be used. This is not a critical factor in the arrangements for the post-Kyoto period currently being negotiated, but it could be very important in the debate on the subsequent post-post-Kyoto phase, ie 2021 onwards.

A major strategic objective for CCS development could therefore be to have proven technologies and a nucleus of experience available by then, so that the technology can be rolled out rapidly once the political process has established rules that justify the large expenditure required.

This will need to be “Class 2” CCS technology, ie technology that actually improves things, as opposed to “Class 1” CCS technology, which merely stops things getting worse (see box, right). Class 1 CCS measures, typically for oil installations and synthetic fuel plants, are cheaper and easier and will probably soon become part of their “licence to operate” but have limited climate benefits.

Two learning cycles

Figure 1 shows how two CCS learning cycles, culminating in commercially available Class 2 technologies, might be obtained before rollout; two tranches of plants, building up capacity and experience, provide a much better basis than just one.

In this context, the UK government’s CCS competition1 is providing support for a first tranche project. A specific objective is to demonstrate technology for coal fuelled power plants that is relevant and transferable to key global markets, a factor that influenced the controversial stipulation of post-combustion capture (excluding pre-combustion projects, but not oxy-combustion) within the project specification.

But a second tranche of projects is required to take CCS beyond the initial demonstration phase. These would include fitting capture to a number of 800 MW supercritical units, instead of just half of one unit as funded by the UK competition, and probably building several of the 400-800 MW IGCC CCS projects that were originally proposed before the competition rules were announced, plus establishing several strategically located carbon dioxide pipelines that could serve these multiple installations economically.

How rapidly there will be a progression to full CCS implementation is also the major issue in the current debate about permitting new coal plants. Some NGOs, after “successes” in similar campaigns in the USA,2 appear to be motivated principally by a desire to make life so difficult for new coal plants that they just don’t get built. But more responsible commentators, such as the Royal Society, recognise that, given current conditions, plants may need to be built initially without full capture and that if the plants are not built at all then CCS development in the UK before 2020 is less likely. Their priority is then to see that the government gives reasonable assurances, when the plants are permitted, that the necessary provisions will be in place to allow CCS to retrofitted by no later than 2020.3

Design modifications to facilitate subsequent addition of capture are becoming established after a recent IEA GHG report on this topic4 and coastal sites have been selected for potential new coal plants in the UK to facilitate pipeline access to storage. The utilities have also indicated that 2020 is a feasible target date for adding CCS, assuming that the competition succeeds in demonstrating technological feasibility as well as regulatory approach and, importantly, that the additional costs involved can be recovered (eg, by participation in an international trading scheme for CO2 with a sufficiently high carbon price guaranteed for long enough to justify investment).

The general expectation in the EU is that CCS costs will be offset against the carbon price in the EU Emissions Trading Scheme (ETS) and that CCS will therefore be implemented on a large scale only when this price rises to a high enough level.

The size of the emissions cap for the EU ETS, and hence the likely price for auctioned emissions allowances (EUAs) is one of the factors determining when CCS might happen. But whether or not CCS is implemented should not directly affect the size of the emissions cap, and hence overall emissions attributed to the EU power sector, a fact that appears to be overlooked by most environmental activists commenting on this area. Of course, the availability of CCS as a proven option is likely to encourage tighter emissions caps in the future, in the EU and elsewhere. But this will probably not be a major consideration in negotiations to determine caps up to 2020. Nevertheless, as discussed above, it could be an important factor after that.

Other factors that will determine when the EU ETS will make CCS happen include the quantities of certified emission reductions (CERs) that can be imported from the Clean Development Mechanism (CDM). This will obviously reduce the pressure to make actual emission reductions within the EU. But if this is considered to be undesirable then the obvious remedy is to limit CER imports, not just to insist that local emission reductions, including CCS, happen anyway.

Another major factor affecting when EU ETS may support the implementation of CCS is the extent to which the required EU CO2 emission reductions up to 2020 will be achieved through the 20% renewable energy target and other measures that distort the EU ETS market, and also the renewable transport fuel and energy conservation targets. It appears likely that, if the 20% renewable energy target is met and only a 20% CO2 emission cut is targeted for 2020, then there will be little demand for additional reductions under the EU ETS.5

If the EU adopts a more stringent, 30%, reduction target for 2020, as part of global negotiations for the post-Kyoto period, then EU ETS caps will have to be much tighter, even with the large renewables target (although this stiffer target is also likely to be accompanied by greater levels of CER trading).

If the EU renewable energy target was modified to include other low-carbon energy supplies then this would also encourage CCS – but this is still a very contentious issue.

It is arguable that a target such as 15% renewables and 5% CCS by 2020 would be more effective for influencing key developing markets such as China and India. The lower renewables target, 15% instead of 20%, could well be more than offset by having made a significant start on CCS, a technology that is essential if these countries, with their heavy reliance on coal, are to achieve meaningful CO2 cuts themselves.

Even assuming, however, that the EU ETS produces carbon price levels that would, in the longer term, justify implementing CCS, many barriers exist for early movers, such as the high cost of first-of-kind plants. Just one tranche of initial commercial-scale demonstration projects, of the type to be funded under the UK CCS competition, is unlikely to be sufficient to bring costs down to the best that the industry can manage. An extended period of learning by doing, from a second tranche of commercial scale plants that are capturing significant volumes of CO2, will be required. Costs can be expected to reduce during this period as the OEM market develops, with the emergence of competition among suppliers. But if CCS was to be supported by the EUA price alone, a large initial increase in EUA prices above expected longer term CO2 price requirements would be needed while the industry was expanding and maturing. This is a very unlikely eventuality.

Additional incentive needed

Therefore, if CCS is to be reasonably widely adopted by 2020, some additional incentive is needed to address both the lack of a sufficiently tight emissions cap and the market failure due to the inability of early movers to recover the full benefits of learning from their more expensive projects.

This could take several forms. Capital grants are unlikely to be the best option since they do not encourage cost-effective construction, although some form of assistance (eg, loan or revenue guarantees) for the high up-front capital costs of large strategic CO2 pipelines and storage facilities may be necessary.

For capture plants and their dedicated infrastructure, supplementary payments based on performance are preferable. These could be made on the basis of electricity generated, by analogy with feed-in tariffs or renewables obligation certificates (ROCs). But these would require a rigid performance standard (eg, specific CO2 emissions of 100 kg CO2/MWh or less) to be applied. Given that in the long run carbon price is expected to be financing CCS, it appears logical to make supplementary payments that in effect boost the carbon price that early projects are receiving for CO2 stored, making it sufficiently high to cover their extra costs.

The additional costs and suggested form of such a payment is shown in the box above. For simplicity, this summarises the penalties and benefits for fitting CCS to an existing plant which continues to operate in the same way, but identical results would be obtained for a new build case.

For the same overall plant economics with capture the supplement must compensate for the difference between savings in EUA purchases required and the lost electricity revenue and the additional capture system costs.

We suggest that this supplementary payment is made per tonne of CO2 captured and stored, a readily measured quantity, instead of per tonne of CO2 abated. For a particular plant, the amount of CO2 captured will be almost linearly related to the additional costs over a range of capture levels. This contrasts with CO2 abated which can be more difficult to quantify since it depends critically on the baseline plant that CCS plant emissions are compared against.

The supplementary payment required will fall as the EUA price increases, but it should also be noted that it needs to be increased with higher electricity prices (due to the increase in lost profits associated with reduced plant output when CCS is operating).

This link to electricity prices suggests one way in which the cost of achieving environmental benefits with CCS can be reduced. Reductions in CO2 emissions can be averaged over long periods, but electricity prices vary significantly with time in many markets. By allowing the capture system to be bypassed or turned down at periods of high demand to allow additional electricity export6 the highest cost CO2 cuts can be avoided and additional cuts at periods of lower electricity prices can be substituted instead. It is therefore important that this flexible use of capture plant is not prevented by regulations that, for example, require continuous operation at any fixed capture level (ie, even low fixed levels are not economically efficient) or at such high average levels that periods of reduced capture are technically infeasible.

Support for first and second tranche CCS projects through supplementary payments per unit CO2 stored would need to be offered for a sufficient period to justify the capital investment involved and to give a reasonable expectation that carbon prices would then be sufficient to drive CCS. Fifteen years is typically being discussed.

The level of support required will vary between possible CCS projects, due partly to technology choice and location. To discover competitive rates, bids for support that specified both the quantity of CO2 to be stored over 15 years and the support rate required could be invited, to meet cumulative targets (eg, the UK might consider an average of 50 Mt CO2/y, about 7 GW of coal generation with CCS at 90% load factor7).

Some of the support would need to be allocated so as to ensure the development of a range of approaches, differentiated by capture technology and storage method. The purpose is to develop strategically useful technology options and capabilities, not to find the current lowest cost CCS technique. In particular, consideration would need to be given to how much Class 1 CCS (or storage of CO2 already available from industrial sources) would be supported. Class 1 CCS projects will have lower costs per unit CO2 captured and stored so will certainly be able to beat Class 2 and 3 CCS projects on price but, as already mentioned, in the long run they have only limited climate benefits.

Bidders should be able to build and operate plants flexibly, although it is reasonable to require that any CCS installations do not make it impossible for eventual operation of the power plant at a high capture level (eg, 90%) if that capability is not available from the outset. As discussed, this flexibility will reduce support levels required while maintaining environmental integrity. To avoid excessive subsidy the supplementary payment per tonne of CO2 stored should decrease with increasing carbon prices (averaged periodically) but also should increase by a fraction of average market electricity prices. This escalation/de-escalation with electricity price (or other indicators of market cost levels) is analogous to the situation that utilities would face when installing CCS in response to “normal” market signals, when the carbon price and other factors that triggered the decision would obviously also vary from their initial values.

A guaranteed, cost-indexed supplementary carbon price support payment per tonne of CO2 stored is superficially similar to the propositions being made to support CCS projects by allocating two or three EUAs per tonne of CO2 stored. The supplementary payment method is, however, effectively a “contract for differences”, with levels tailored to the needs of a strategic demonstration and capacity building exercise. It acts in a way that is linked to future market conditions and is set up so as to taper off to a smooth transition to a future EU ETS market with higher carbon prices. But even if a fixed allocation of EUAs happened to match the support needs of a particular project at the time it started – and clearly such a match could only occur for a limited proportion of such projects (unless banding is used), leading to a likely lack of diversity in activities supported – then the change in support level with time and changing carbon price cannot match actual subsequent CCS project costs.

A purely illustrative example is shown in Figure 2. The support provided by both a cost-indexed carbon price supplement and a “double EUA” allowance starts out at the same level, an additional £30/tCO2 stored. But as EUA price rises, an almost certain trend, the required cost-indexed supplement falls, to under £10/tCO2 for the assumed final carbon price of £45/tCO2, while the double EUA allowance value of course rises, to £90/tCO2. In the example shown the assumed increase in effective electricity price (time averaged value while the capture plant is operating) from £70/MWh to £100/MWh increases the carbon price supplement required to nearly £54/tCO2 so this is not entirely offset by the final EUA price, as might have been expected.

The risk/return profile for a CCS project bidding in to such an opportunistic “market” for support via extra EUA allocations would clearly be very different from projects receiving the supplemented carbon price, and quite unlike that for projects bidding into future conventional carbon markets. There also seems a strong likelihood that projects could not survive the sudden transition from very high expected support payments, due to increasing EUA prices, at the end of their guaranteed period to only the value of avoided EUA purchases. This might lead to a need for continued support at that time, to avoid a step change in low-carbon electricity supplies.

It appears reasonable, however, that funding for the carbon price supplement per unit CO2 stored could also come from the proceeds of EUA auctioning, as part of the 20% allocation being suggested by the EU Commission. Unfortunately, though, the UK Treasury (and apparently all other European finance ministries) are reluctant to allocate even this 20% for expenditure on low carbon energy, claiming it breaches Treasury principles against “hypothecation”. Some consequences of this reluctance are a rising UK public perception of the EU ETS as a “just another stealth tax”, and a pragmatic view by some supporters of CCS that issuing extra EUAs, despite its obvious imperfections, is the only way to get CCS moving. More imaginative measures, perhaps the establishment of an independent UK EU ETS administrator, may be needed to overcome problems such as these.

In the longer run, if the choice whether to undertake CCS or not is not left to the carbon market but additional performance standards are applied (eg, specifying CO2/MWh emission levels or a fraction of fuel carbon content captured), then market distortions and consequent economic inefficiencies will inevitably occur. These might, however, be reduced, while still maintaining environmental integrity, if the performance standards were expressed as an obligation to provide tradable certificates for CO2 capture and storage, probably from comparable Class 2 or 3 CCS projects (but not from Class 1 CCS projects), to get the equivalent short and longer term climate benefit. This would direct Class 2 or 3 CCS activities to the lowest cost locations and times. It would also allow CCS obligations to be extended to natural gas power plants, which as a transition arrangement would have the choice to pay for storage on coal and/or on natural gas plants in suitable locations.

The dangers of delay

Whether viewed in the context of tackling global climate change or keeping coal in the UK energy mix for a more balanced and reliable electricity supply, implementing CCS presents engineers, policymakers – and NGOs – with many challenges.

Even with a major initiative such as the UK CCS competition barely underway, pressure is already growing on government to map out the next stages in CCS deployment. But both power plant construction programmes and the tackling of climate change have very long timescales. Delay now in addressing the, admittedly difficult, question of how future CCS plants might be incentivised will impact directly on our ability to deliver reliable UK electricity supplies and CO2 emissions cuts (and therefore set a good example for global climate change negotiations) ten years or more ahead.

The recently-issued BERR consultation “Towards carbon capture and storage” reports that the EU is now taking a hand in determining how twelve first tranche (operation by 2015) demonstration plants will be funded.8 This does not, however, address the issue of how UK (and other EU) second tranche, and subsequent, CCS projects and their supporting infrastructure will be supported; the UK’s share of twelve projects (one or two?) is obviously too small to cover much of the country’s new fossil generation capacity. It is therefore likely that many responses to the consultation will recommend that additional incentive/support mechanisms to the EU measures are put in place, to allow full CCS on new UK coal plants by no later than 2020 if (as seems quite possible) EU ETS prices alone are not high enough. For some stakeholders this is likely to be an essential pre-condition for new coal plant construction to go unchallenged.