Day: October 14, 2024

Once upon a time, UK energy policy revolved around the politics of dirty old coal.  But in the 21st century, it’s all about low carbon technologies like wind and nuclear – right?  Well – up to a point.  As a reminder that coal is sometimes still at the heart of the debate, take a look at the final stages of the passage of the Energy Bill through Parliament, where the arguments were not about wind or nuclear power, but about keeping open a group of coal-fired power stations that are all over 40 years old.

The Energy Act 2013, as it now is, received Royal Assent on 18 December 2013.  Amongst other things, it legislates for Electricity Market Reform (EMR).  As part of EMR, the Act imposes a limit on the quantity of CO₂ which fossil-fuel generating plant may emit each year.  This limit, the “emissions performance standard” or EPS, only applies to new plant.  The EPS is set at a level which makes it uneconomic to construct new coal-fired generating plant with a capacity of more than 50MW in the UK unless it has carbon capture and storage (CCS) fitted – because without CCS, a new coal-fired plant could only meet the EPS by running for too few hours each year to justify the cost of building it. 

In practice, there was arguably little danger of anybody constructing such plant even without the EPS, because existing planning policies require any new plant to include at least 300MW of CCS capacity.  The value of the EPS provisions, beyond simply reinforcing the policy position against new non-CCS coal plant, is that they apply to both gas and coal-fired plant, but in practice only “bite” on coal.  This is because the EPS is fixed, until 2044, in the Act itself, at a level that does not affect the economics of building a new gas-fired plant (either open or combined cycle).  In other words, the EPS regime is intended to reassure potential investors in new gas-fired plant.

But the House of Lords inserted an amendment into the EPS provisions.  This was not about gas, or about the new coal plant that the EPS is aimed at, but about existing coal-fired plant.  Under the amendment, an existing coal-fired plant would have become subject to the EPS if it fitted the equipment necessary to enable it to comply with the new limits on emissions that apply to existing plant under the Industrial Emissions Directive (IED) from 2016.  The IED is, of course, not about CO₂   emissions.  But supporters of the amendment argued that once a plant fitted the equipment necessary to comply with the IED limits on pollutants such as NO_x, it could be in a position to run for decades to come, with no statutory constraint on its CO₂ emissions – thereby potentially undermining the Government’s ability to substantially decarbonise the power sector by 2030.  By applying the EPS to such plant, the amendment would have made retrofitting existing plant for IED compliance almost as uneconomic as building new coal plant, so the existing plant would close.   

The Government succeeded in reversing the amendment, so the EPS will not prevent existing coal-fired plant staying in the generating mix.  This is arguably not ideal from a decarbonisation point of view, though it may have advantages in terms of security and affordability of electricity supply.  But the debate on old coal plant does not end there.  In future posts we will be looking at how decision-making by individual companies under the IED, and perhaps other parts of EMR, will determine the ultimate fate of these plants.

Only a few weeks ago, DECC announced the “final” strike prices that were to apply to contracts for difference (CfDs) for the various eligible renewable technologies under Electricity Market Reform (EMR) (see our earlier post on this).  But things move fast in the world of EMR.  On 16 January 2014, DECC announced that for those technologies considered “established”, there would be no guarantee of securing strike prices at the level of the figures fixed in December 2013. 

The group of “established” technologies for these purposes consists of onshore wind (>5MW), solar PV (>5MW), energy from waste with CHP, hydroelectric (>5MW and <50MW), landfill gas and sewage gas.  For these technologies, it is proposed that strike prices will be set by a process of competitive bidding for which the December figures will function as a cap.  For the “less established” technologies (offshore wind, wave, tidal stream, advanced conversion technologies, anaerobic digestion, dedicated biomass with CHP and geothermal) the December strike prices will apply.  A decision has yet to be made about strike prices for biomass conversion and Scottish islands projects.

Moreover, all technologies will have to apply for their CfDs through allocation rounds – i.e. at specified times, rather than whenever it is most convenient for them to do so.  There will be no initial period of “First Come, First Served” allocation of CfDs.  The draft CfD allocation framework, originally scheduled for publication in January 2014, will not now be published until March 2014.

The DECC announcement is cast as a consultation, but the key points look fairly firm.  Although the document lists a number of factors that have been taken into consideration, it is clear that the European Commission’s draft state aid guidelines have played a big part in DECC’s thinking (see our earlier post on the draft guidelines).  The draft guidelines place a heavy emphasis on the desirability of competition for subsidies to renewable generators.  

There can be no doubt that the change of approach on strike prices ought to improve the chances of gaining state aid clearance from the Commission for the CfD regime.  But what will be the practical and wider impacts of more projects having to compete on strike prices sooner? 

How “technology-specific” will each auction be?  How frequently will auctions take place? Some questions will have to wait for an answer until we have seen the allocation framework.  For some time now, it has been clear that the allocation framework will be a hugely important document.  Assuming that DECC sticks to its overall timetable, there will not be very much time to consult on the first allocation framework before the package of EMR secondary legislation that requires Parliamentary approval is laid before Parliament.

In the meantime, it is a fair bet that some projects which might have applied for a CfD will now opt for the more predictable support mechanism provided by the Renewables Obligation (RO) instead (as they will be able to do until 2017).  Many of these projects are not large and the process of competing on strike price can only add to the costs of a CfD application.  But if more opt for the RO from the outset, how will that affect the budget available for CfDs under the Levy Control Framework?  And what will be the implications for any state aid analysis of the RO if projects that fail to win CfDs in the auction process can go on and claim what turns out to be a higher level of support under the RO?