Emissions Performance Standards

Memorandum submitted by Professor Jon Gibbins and Hannah Chalmers (EPS 09)

I. CONTEXT AND BACKGROUND

The notes in this memorandum are based on a private document written as part of the preparation for a series of multi-stakeholder workshops on emission performance standards (EPS) run by Imperial College, Green Alliance and SCCS (Scottish Carbon Capture and Storage - http://www.geos.ed.ac.uk/sccs/) in 2009 and 2010.

The majority of these notes do not attempt to provide a ‘correct answer’ to questions that arise in discussing the development and deployment of an EPS. Instead, they are intended mainly to challenge immediate assumptions that may exist with regard to the following questions:

A. WHAT COULD BE MEANT BY AN EMISSION PERFORMANCE STANDARD?

B. WHAT COULD EMISSION PERFORMANCE STANDARDS BE INTENDED TO DO?

The range of each question is first explored, and the possible issues are then discussed individually in more detail.

The authors do, however, have a personal preference for EPS designs that would ultimately result in full CCS (i.e. highest reasonable capture levels) being applied to progressively more fossil power plants (gas and coal), in order of suitability. Facilitating a staged rollout of full CCS on a plant-by-plant basis across the entire fleet (rather than introducing a step-change in CCS requirements at all plants simultaneously or requiring gradually increasing levels of CCS at all plants simultaneously) is essential to avoid likely supply chain bottlenecks and/or inefficient investment and operating decisions that would lead to unnecessary costs for society.

The only reasonable exception to this might be the initial stages of some commercial-scale demonstration projects (e.g. as in the first UK Government CCS competition), where full CCS would require multiple copies of untried capture technology to be used. To reduce the cost to society of funding the initial trials it should be possible to conduct them on single examples of first-of-a-kind equipment, with progression to full CCS using additional, similar, units then subsequently taking place once a period for learning has elapsed.

Staged rollout of full CCS on a plant-by-plant basis is expected to offer the lowest overall costs for a given amount of CCS, but imposes those costs directly on the plants with CCS. The desirable situation for encouraging CCS use is, however, that fossil (and/or biomass) plants with CCS are at somewhat of a financial advantage compared to equivalent plants without CCS. This suggests that it is necessary to develop an approach for shifting, at least some of, the CCS costs to the rest of the market. This could, for example, be through a certificate scheme incorporated in the EPS or as part of wider market reforms.

Another desirable feature for an EPS, or other complementary measures, would be to ensure that power plants that have installed and are operating CCS are generally used in preference to unabated fossil fuel plants. The EU Emissions Trading Scheme (EUETS) may be a sufficient complementary measure to meet this criterion. Once CCS equipment and transport and storage infrastructure for a plant are in place then only the short run marginal costs of actually operating it (i.e. not the full costs, including construction charges) need to be covered for CO2 to be captured and stored. These marginal costs are expected to be of the order of half the total costs, so a much lower EUETS carbon price would be needed to incentivise running existing CCS plants than would be required to incentivise installing CCS.

II. OVERVIEW OF POSSIBLE ASPECTS IN RESPONDING TO QUESTION A:

WHAT COULD BE MEANT BY AN EMISSION PERFORMANCE STANDARD?

The following aspects, which will be discussed in more detail in Section IV, address many of the major issues that must be defined before the expected impact of an EPS proposal can be fully analysed. It should be noted, however, that other factors will also need to be considered as part of EPS design and implementation. For example, an organisation to be responsible for monitoring EPS compliance will need to be identified and a robust route for responding to non-compliance will need to be defined.

1. Emissions per what output measure?

1.1 Per unit energy Emissions per MWh supplied

1.2 Per unit CO2 produced Fraction of fossil fuel CO2 captured and stored

1.3 Per unit of generating capacity Tonnes of CO2 emitted per MW of capacity installed per year

2. Size of the entity which has to meet the standard

2.1 Generating unit

2.2 Stack1 (by analogy with LCPD opt-out regulations) – could include multiple plants and of different types (latter not common now but could be done if an advantage)

2.3 Site – could include multiple plants, even of different types

2.4 Company

2.5 Industry sector – nature of sector determines plant types

2.6 Country – will almost always include a range of different plant types

3. Can compliance be traded?

4. Time period over which emissions are averaged when calculating compliance with the EPS

5. How are the costs of compliance met?

6. Action required for compliance?

6.1 Don't do something – i.e. don't build or don't run a certain type of plant

6.2 Have to do something – i.e. capture a certain fraction of CO2 from any fossil plant; it could be argued that the need to capture CO2 could be entirely avoided if no fossil fuel plants were used at all, but this is currently not feasible in practice

7. Is the EPS based on capability or actual performance?

8. How is the EPS made more stringent over time?

III. OVERVIEW OF POSSIBLE ASPECTS IN RESPONDING TO QUESTION B:

WHAT COULD EMISSIONS PERFORMANCE STANDARDS BE INTENDED TO DO?

A useful starting point in this area is the different possible primary and secondary motivations that can be identified for different groups of EPS proposers. These motivations are useful since they can be linked potential objectives for an EPS. They can also conflict so it will be necessary for regulators to decide which objectives are intended to be achieved (or not) before an EPS can be designed. Examples of motivations that have been observed in the ongoing discourse on EPS include:

avoid leakage from a geographically-limited emission cap, make it impossible to build new coal without CCS, ensure that new coal plants do not run without full capture after 2020, avoid carbon lock-in, get the best use out of the limited 'safe' space left for CO2 in the atmosphere, drive a transition to a low-emission future, finance CCS development and deployment, overcome the limitations of a weak general emission limiting programme, get some new coal plants built to improve energy security, favour gas over coal, favour CHP over power only, generate a new instrument to trade, allow a simple and predictable carbon tax, give the UK (or other) government greater control, give investors and technology developers greater certainty.

IV. DISCUSSION OF ISSUES ARISING UNDER QUESTION A:

WHAT COULD BE MEANT BY AN EMISSION PERFORMANCE STANDARD?

There is no single obvious form for an EPS regulation. Some of the possible options are listed below; they could be used in combination in the final regulations. It is often asserted that these EPS policy measures can be ‘technology neutral’, but this is debatable as a philosophical point. Although the impact on different technologies may be a consequence rather than a driver for a particular policy measure, and the technology-related impacts of the policy may not have been foreseen, in most cases the actual policies will inevitably have different consequences for different technologies.

1. Emissions per what output measure?

1.1 Per unit energy Emissions per MWh supplied

This appears to be technology-neutral but if a technology can meet the standard without doing anything then this technology would be at an advantage compared to another technology that has to add CCS, switch fuels etc. Low emissions per MWh from one type of power generation may also be directly linked to higher emissions per MWh from another source. This is because there is generally a requirement to use a mix of generation types to provide satisfactory electricity network operation (e.g. security of supply, minimum overall cost of electricity supply etc). It can, therefore, be argued that some intermittent low-carbon sources should be treated as a unit combined with higher-carbon sources (e.g. wind with backup from gas-fired power generation, although the required level of backup for a given level of wind penetration is a contentious issue). It should also be noted, however, that not all renewables would require back-up from non-renewable sources. For example, hydro power is generally flexible and can provide backup itself for other intermittent sources.

1.2 Per unit CO2 produced Fraction of fossil fuel CO2 captured and stored

This approach was adopted in the final draft of the US Waxman-Markey climate bill that was passed by the Congress on 26th June, 2009 but has not yet progressed further2. Some stakeholders may want to consider how to account for CO2 from the 'extra' fuel used to run the capture plant and possibly also the base power plant efficiency (and consequent effects on fuel consumption per MWh) when considering the required level of capture.

1.3 Per unit of generating capacity Tonnes of CO2 emitted per MW of capacity installed per year

(or other extended time period)

This is close to a running hour limitation, but based on emissions. It might be a useful way to regulate plants that are kept mainly in reserve and only operate for limited hours per year. These could be open cycle gas turbines or other purpose-built peaking plants, or existing fossil fuel plants that 'opt out' of a future requirement that would otherwise oblige them to fit CO2 capture.

2. Size of the entity which has to meet the standard

In all cases it is critically important whether or not the EPS is applied to all plants or just to new ones (see also 8. below). For 2.2 to 2.6 it also becomes important what types of generating plant can be mixed in any multiple-unit and/or multiple-plant entity. For example, are only coal and gas plants considered or are emissions from fossil power generation, renewables and nuclear all taken into account when EPS compliance is assessed?

2.1 Generating unit

2.2 Stack3 (by analogy with LCPD opt-out regulations) – could include multiple plants and of different types (latter not common now but could be done if an advantage)

2.3 Site - could include multiple plants, even of different types

2.4 Company - will probably include different types of plant but depends on size of company (e.g. the company could be just a single plant or own many sites, including across countries)

2.5 Industry sector - nature of sector determines plant types

2.6 Country - will almost always include a range of different plant types

3. Can compliance be traded?

3.1 Averaging emissions across different units within an entity (see 2 for different entities) and averaging emissions over time are both implicit forms of compliance trading.

3.2 To some extent just implicit trading is likely to be unfair since some players will be able to take advantage of this opportunity and others won't (e.g. small companies vs large, mix of generation types operated by an entity or not).

3.3 Explicit trading of compliance would be expected to lead to a more efficient allocation of resources to achieve a given environmental outcome and should also allow as many players as possible to participate in trading, but concerns have been raised by some stakeholders about possible duplication between a tradable EPS and the EU Emission Trading Scheme (EUETS)4.

3.4 Trading compliance is an obvious way to fund low-carbon generation, but the scope for what types of low carbon generation could thus be funded depends on the form of the EPS.

3.5 A tradable per MWh standard applied to all power generation could fund all types of low-carbon generation, e.g. nuclear, renewables, CCS. It might even fund unabated natural gas combined cycle (NGCC) plant if the level of emissions allowed by the EPS was greater than the feasible minimum level of emissions that can be achieved by unabated NGCC (or unabated gas was used to complement other lower-emission generation plants)5.

3.6 A tradable standard based on fraction of CO2 captured for fossil plants would possibly fund CCS on coal in preference to CCS on gas. But if it also applied to other fossil fuels, the costs could be divided over all fossil generation and not just the coal fleet. Alternatively it could potentially cover all generation sources. .

3.7 It is likely to be very much more cost effective to fit full capture6 to a smaller number of plants (once any technology proving phase is over) rather than fit partial capture on all fossil plants. It is also much more feasible gradually to increase the stringency level of a traded EPS, since additional plants can be fitted with full capture rather than the level of capture at all plants having to be adjusted individually to meet a non-traded EPS.

3.8 Capturing CO2 from biomass utilisation always gives an environmental benefit unless the lifecycle emissions for the biomass production, transport etc are thereby increased by a larger amount than the CO2 captured (a possible, but very unlikely, outcome). Otherwise the issue is just whether or not using biomass with CCS to produce a carbon-free energy vector (electricity, heat or possibly hydrogen) gives more cost-effective abatement than direct biomass use or conversion to a carbon-based energy vector (e.g. methane, liquid biofuel). This must be recognised or perverse incentives to use biomass without CCS can result7.

4. Time period over which emissions are averaged when calculating compliance with the EPS

4.1 The time period over which the atmosphere averages the effect of CO2 emissions is very long, of the order of a century. It also does not matter where in the world the CO2 is emitted.

4.2 In practice accounting periods for CO2 emissions have to be shorter than the environment is sensitive to. Periods of around 1-5 years are established and these are currently extended further when EUETS Emission Allowances can be carried over from one period to a subsequent one.

4.3 But some emissions (e.g. SOx, NOx) are averaged over periods of 30 minutes under the LCPD (Large Combustion Plant Directive), partly since they have local environmental impacts and it, therefore, makes sense to require emissions levels to be constrained over much shorter time periods than for CO2. Thoughtless extension of these regulations to CO2 could therefore end up with a short period for averaging, but without any environmental justification at all in this case.

4.4 There is an argument to use the longest practicable accounting period for EPS since doing this is likely to reduce the cost of compliance while still achieving full environmental integrity. In some cases a single year could be sufficient to achieve close to maximum cost-effectiveness, but up to around five years might be useful with some non-traded-compliance EPS options and traded-compliance EPS options could benefit from even longer periods.

4.5 A special case would be a plant that achieved a time-averaged performance standard by operating for a period without CO2 capture and then fitting and operating capture. There is an obvious risk of the planned capture retrofit not taking place, but leaving that aside technical progress could make this a low-cost option. This type of EPS is already effectively being proposed and debated in connection with government policy for permitting new fossil (and biomass) plants in the UK as capture ready, often with particular attention paid to coal-fired power plants. Some stakeholders say that new coal plants without full capture from the start lock in years of high carbon emissions, others state that by making any capacity without CCS on the plants capture ready lifetime average emissions can be limited to satisfactory (implicitly time-averaged) levels.

5. How are the costs of compliance met?

If the costs cannot be met then existing plants will not be operated to meet an EPS - although that may be an intentional result, since it is still likely to qualify as compliance. In this case the plants simply close down – they become stranded assets. If the EPS applies only to new plants, or is likely to do so in the future, then potential new plants may not be built at all. In both cases there are obviously serious implications for project financing and/or decisions to go ahead with investment. Possible options for how the costs of compliance are met when a plant does operate and satisfy the requirements of an EPS are relatively limited, with the main options being:

5.1 Out of existing profit margins? i.e. taken from company shareholders? But if profits are not sufficient then cost ultimately has to be met by the customers?

5.2 From the tax base? An argument to do this is that the tax system is more equitable than the electricity billing system since only those who can afford to pay do. But there are also arguments against e.g. how do you avoid a windfalls problem, analogous to that in the first phase of EUETS, if money is supplied from the tax base, but companies also price according to marginal cost principles in the market? Taxes at a national level are also relatively easy for a different government to change so may not offer sufficient stability for investment. A tax at European level (and UK environmental law generally comes from Europe) is much more complex.

5.3 Passed through to customers? This is easy for a regulated utility (e.g. in the USA, provided the local Public Utility Commission agrees) and can happen automatically for a publicly-owned utility. Passing through full costs of any investment (including those that would be required to meet an EPS) can, however, be challenging in a competitive market since electricity prices tend to reflect short run marginal costs of the plants that are operating and will not necessarily be sufficiently high to cover long run costs such as those related to capital expenditure. It is perhaps worth noting that electricity cost increases due to ‘normal’ factors such as fuel price increase that are included in short run marginal costs are passed through to customers as a matter of course in market economies.

6. Action required for compliance?

6.1 Don't do something - i.e. don't build or don't run a certain type of plant.

6.2 Have to do something - i.e. capture a certain fraction of CO2 from any fossil plant. It could be argued that the need to capture CO2 could be entirely avoided if no fossil fuel plants were used at all, but this is not feasible in practice for the near and medium term.

7. Based on capability or on actual performance?

7.1 A major issue here is whether the metric is based on what the plant is capable of doing when operated to minimise CO2 emissions as much as possible, or on the actual emissions it achieves over a period of time.

7.2 For consumer products (e.g. cars, refrigerators) the capability is considered a useful and practicable measure. The Californian EPS for power generation is also based on plant design information but then not monitored when plant is constructed (although this is partly because the results of the Californian EPS has been to stop new coal and other plants can meet the standard at the current level without changing normal operating practices – see section V below).

7.3 Making a plant capture ready arguably goes some way towards being a performance standard based on capability rather than actual performance, although with caveats about whether or not capture will actually be fitted in the future8.

7.4 For non-fossil generation (renewables, nuclear) there is no need to monitor actual performance for a plant based standard since the emissions at the point of use are always essentially zero. There would be a need to know actual electricity output if, for example, a tCO2/MWh EPS is being averaged over a number of units including these types.

7.5 For fossil plants without capture, emissions can vary from some minimum value per MWh (usually at full load and hence maximum efficiency) to effectively an infinite amount per MWh when fuel is being consumed but no power exported (e.g. while the plant is starting up or being kept warm to allow rapid response). Often the highest emissions are, however, thought of as those occurring at the 'minimum stable generation' point for continuous part-load generation.

7.6 For fossil plants with CO2 capture the emissions per MWh would obviously depend on the capture technology and how it was operated, but also would depend on the operating pattern of the plant, e.g. baseload or providing support services to the electricity network.

8. How is the EPS made more stringent over time?

8.1 There is a general expectation that the stringency of the EPS will increase over time.

8.2 The long term end point for all EPS if cumulative CO2 emissions to the atmosphere are to be limited to minimise the risk of dangerous climate change is that any fossil fuel can only be used if a corresponding amount of CO2 is captured and stored (note this does not imply CCS if no fossil fuels are used).

8.3 Increased stringency could be that the EPS applies to more power plants, e.g. plants with different fuel types, existing plants as well as new plants.

8.4 It is difficult to see how the capture level at an individual plant could be increased progressively over time in a cost-effective manner, except in the case where certain novel components need first to be tried out and refined (e.g. one 400MW post-combustion capture unit on a 2 x 800MW power plant site). It might be technically feasible, but the capture plant would probably not be integrated efficiently as a result and for some of the time the capital investment for the CCS chain (probably including pipelines and injection facilities) would not be used at its full potential capacity.

8.5 At an individual plant level retrofitting full capture to a carbon capture ready (CCR) site would not involve any artificial cost increases. But having all CCR plants retrofitted within a narrow time window would add unnecessary cost increases since the equipment supply industry, pipeline construction, drilling industry etc. would be facing a boom and bust market situation rather than a period of sustained demand with gradual up and down changes.

V. DISCUSSION OF ISSUES ARISING UNDER QUESTION B:

WHAT COULD EMISSIONS PERFORMANCE STANDARDS BE INTENDED TO DO?

The discussion below covers possible interactions between an EPS and a cap and trade scheme, such as the EUETS. It does not examine the important legal point that an EPS might be considered an example of double regulation if an ETS also exists and so would not be allowed to be introduced. Instead, as noted in Section III, the focus is on different possible primary and secondary motivation for different groups of EPS proposers. These include:

1. Avoid ‘leakage’ from a geographically-limited emission cap by applying an EPS to imported electricity (or perhaps to the electricity used to produce imported goods). The 'original' Californian regulation was intended to stop utilities from renewing long-term contracts for coal-fired electricity from outside the state of California (CA) that would negate the effects of CA implementing a state cap and trade system. The per MWh emission performance standard was set at a level (1100 lbCO2/MWh or 500kgCO2/MWh) that would affect virtually no generation plants within CA (natural gas, nuclear, hydro, other renewables).

2. Make it impossible to build new coal without CCS (and if the costs of CCS cannot be recovered, making it impossible to build new coal at all).

3. Ensure that new coal plants do not run without full capture after 2020 (or a similar date).

4. Avoid carbon lock-in; power plants being built now and that will be in operation for a long time will have low enough emissions from some specified point in the future onwards.

5. Get the best use (i.e. most electricity and possibly heat) out of the limited 'safe' space left for CO2 in the atmosphere since avoiding dangerous climate change is expected to require a limit to cumulative CO2 emissions over centuries (may also be used as an implicit way to get the best use out of perceived limited fossil fuel supplies).

6. Drive a transition from where we are now to a low-emission future where fossil fuels can only be used with CCS. This is not to say that fossil fuels have to be used, just that they can only be used in any quantity with this condition. As above, this reflects a growing understanding that accumulated CO2 emissions over time are what matters for the risk of dangerous climate change rather than the yearly emission rate, so to avoid dangerous climate change energy system emissions will eventually have to get close to zero. In fact, net power plant emissions and other CO2 emissions may even need to go below zero if it turns out that we have overshot the safe cumulative amount or need to offset greenhouse gas emissions from other sectors that are very difficult to reduce to zero, e.g. agriculture.

7. Finance CCS development and deployment in the UK (and other OECD countries) with a tradable standard so as to establish it as a viable option in future climate change negotiations.

8. Overcome the limitations of a weak general emission limiting programme such as a carbon tax with no caps or an ETS with weak caps or excessive 'safety valve' trading outside the cap, e.g. as has been suggested by some stakeholders for Certified Emission Reductions (CERs) from the Clean Development Mechanism (CDM) in the EUETS. Soft (or volatile) carbon prices that fail to incentivise investment are also an issue. These could be due to a weak cap or 'leakage' but could also result from the effect of other support measures for low carbon generation, such as ROCs (Renewable Obligation Certificates) or feed in tariffs if these are used in large quantities. It should be noted, however, that the nature of the EUETS is such that any reduction in emissions within the UK would be matched by a corresponding increase in emissions elsewhere in the EU (probably plus a transfer of value from the UK to the rest of the EU, since EPS compliance is presumably more expensive than the emission allowance (EA) purchase price or it wouldn't be necessary to have an EPS). If this problem is to be avoided the EAs saved by the EPS would need to be retired by the UK Government (reducing revenues from the EA allocation available for it to auction). Even in this case, strictly the EPS is not responsible for a climate benefit since EAs could, of course, be retired anyway without any EPS in place.

9. Encourage the building of new coal plants to improve overall UK fuel diversity and hence energy security (since potential investors have better understanding of the regulatory regime to be used for limiting CO2 emissions – also see further discussion below).

10. Favour gas over coal. Sell more gas or at a higher price, similar advantages for gas power plant suppliers, and for utilities with a high level of natural gas in their portfolio. In principle an EPS could also be seen as favouring non-fossil generation (renewables, nuclear) over fossil (gas, coal) but in practice an EPS that restricts unabated natural gas power generation (and even existing coal, in the short to medium term) is impracticable for the foreseeable future (and quite likely to be beyond the time horizon of those organisations with a commercial interest in a pro-unabated-gas outcome; i.e. the short term gains for such organisations are likely to outweigh the longer term possibility that an EPS could adversely affect the economic prospects for gas vis-a-vis non-fossil energy sources).

11. Favour CHP over power only. This is typically suggested to be achieved by including heat supplied in the MWh output of the power plant used to determine EPS compliance and then setting the EPS stringency at a level that cannot be achieved by electricity generation alone. One fundamental problem with this approach is that it assigns the same value to energy in the form of low grade heat and to energy in the form of electricity, an equality which is justified neither on thermodynamic nor on economic grounds. This mis-assignment then opens up opportunities for gaming to extract the unwarranted value given to low grade heat. There is also the practical difficulty of matching low grade heat demand with power demand, especially in the summer. If the CHP is implemented in an industrial application with fairly constant heat demand (e.g. refinery, paper manufacture) then it is usually a logical economic option anyway, but with too limited an application to become a general standard. Similar CO2 mitigation (and fuel utilisation) results (better or worse depending on the situation) could also be achieved by combining pure electricity generation with heat pumps (which also has the additional artificial advantage of contributing to renewable energy targets, should they exist, since large amounts of ambient, renewable heat are supplied from the heat pump). CHP and district heating are obviously worth considering, in competition with other options to supply low-carbon heat, but an EPS that combines electricity and heat may not be the best way to do this. Although not mentioned elsewhere, a simple EPS that specifies a fraction of district heating might be a better alternative, although perverse incentives with respect to disadvantaging heat pumps would also need to be considered in this context.

12. Generate a new instrument to trade, and make money from this new market (despite obvious concerns from many stakeholders about multiple incentive markets).

13. Avoid traded instruments such as the EUETS and allow a simple and predictable carbon tax to be used, supplemented by an EPS to give more rapid/focussed cuts in CO2 emissions.

14. Give the UK (or other) government greater control over CO2 emissions from UK fossil-fired power plants. As already discussed, this outcome can be delivered in the strict sense if the EPS applies to the whole UK fossil power sector, but the nature of the EUETS is such that any reduction in emissions within the UK would be matched by a corresponding increase in emissions elsewhere in the EU unless the EAs saved by the EPS were retired by the UK Government

15. Give the UK (or other) government greater control over incentives for low-emission fossil generation technology that have been lost to Europe via the EUETS, also control over what sorts of power plants get built in the UK. The enhanced control appears feasible to some extent, at least until any UK laws are superseded by an EU EPS, but only 'positive' incentives that involve money being given to low-carbon fossil generation are likely to get significant results in most respects. Since no utilities operating in the UK have an obligation to build power plants in the UK, and most can also build power plants elsewhere in the EU and/or elsewhere in the world, the UK Government can certainly exercise a negative control over what happens but cannot so easily exercise a positive control if more attractive investment opportunities exist elsewhere.

16. Give investors in the UK electricity generation market greater certainty than is possible with the current mix of EU and local regulations. This could literally be feasible if the characteristics of the EPS and its date of implementation were announced a long time in advance, although the consequences of such increased certainty would depend on the terms of the EPS. It is, however, also worth noting that the level of uncertainty assumed by investors will also depend on their assessment of the likelihood that (potentially several) future UK governments would feel bound (or not) by undertakings made by previous governments. This could perhaps be resolved by some form of contractual agreement. Additional uncertainty is however introduced if the timing of the implementation of an EPS (and possibly some other parameters) are left to the discretion of the Environment Agency or some other body. Unless contractually binding terms are agreed anecdotal evidence suggest that 'bankable' certainty will not be increased and indeed an EPS could well be an additional uncertain factor that could strand an asset in the future, so it actually makes it harder to finance a plant.

17. Give technology developers greater certainty in future market needs. This may be literally true in some senses, but if the EPS requirement is for partial capture at an individual installation level (e.g. order 50% capture on coal) then the almost inevitable ‘lock-in’ from this, at least for some CO2 capture technology options, and likely focussing of technology development to meet more immediate market needs (i.e. partial capture) does not seem to conform to long-term environmental demands for full capture, even if subsequent tightening of the EPS can be foreseen. Additional caveats as above apply about uncertainty with respect to timing and future government policy changes etc. as well.

September 2010


[1] The power plant chimney, which may contain separate ducts for individual generating units on a site.

[2] http://www.govtrack.us/congress/bill.xpd?bill=h111-2454 e.g. ‘‘(3) COVERED EGUS INITIALLY PERMITTED FROM 2015 THROUGH 2019.—The owner or operator of a covered EGU that is initially permitted on or after January 1, 2015, and before January 1, 2020, shall be ineligible to receive emission allowances pursuant to this section if such unit, upon commencement of operations (and thereafter), does not achieve and maintain an emission limit that is at least a 50 percent reduction in emissions of the carbon dioxide produced by the unit, measured on an annual basis, as determined in accordance with section 812(b)(2).”

[3] The power plant chimney, which may contain separate ducts for individual generating units on a site.

[4] Note that the particular point here is concern with two trading mechanisms overlapping. There is also an additional consideration of whether double regulation of CO 2 is allowable and/or preferable. See Section V .

[5] T he value of t his level depends on a number of factors including the nature of the electricity market you are operating in, requirement for part load operation, numbers of starts/stops, need to fire on oil instead of gas etc, but probably lies somewhere between 350kgCO 2 /MWh and 450kgCO 2 /MWh.

[6] i.e. all the flue gas is processed, although capture levels will be less than 100% for technical reasons

[7] Biomass utilisation is treated as carbon-neutral and largely ignored in most regulatory regimes whereas in fact it may have significant fossil emissions involved in its production; but this is immaterial in determining whether to capture the CO 2 from the biomass instead of re-emitting it to atmosphere. Biomass combustion also usually has higher CO 2 emissions per unit energy (kgCO 2 /MWh) emitted at the power plant site than coal.

[8] The arguments about whether or not capture will be fitted in the future differ between the cases where any individual plant is being considered and where a national fleet as a whole is being considered. It is much easier to be certain that a fraction of the national fleet will have to be retrofitted if overall emissions are to be reduced.