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The UK’s second capacity market auction – likely to deliver more of the same?

The initial results of the pre-qualification stage of the 2015 Capacity Market (CM) auctions, published on 25 September 2015, confirm the trend towards increasingly decentralised power generation.  Less than 3 GW of new projects will be competing for capacity agreements in December, but the total de-rated capacity of the pre-qualified bidders is only just greater than the target capacity identified by DECC in the auction parameters.*

CCGT: familiar disappointments

When the results of the 2014 auction were announced in January 2015, there was disappointment at how few sizeable CCGT projects had been successful.  The low auction clearing price of £19.40 was good for consumers (and a welcome supplement to the revenues of many existing plants), but too low to enable most large new-build projects to be viable.

Subject to the outcome of any pre-qualification appeals,** it appears that by one measure, only one** really new pre-qualified unit of “new” generating capacity with a capacity of more than 100 MW will participate in the “T-4 auction” for delivery in 2019.  This is 370 MW of CCGT capacity at King’s Lynn, but in the 2014 CM register, the same project was said to incorporate some “existing but overhauled and enhanced” elements. Meanwhile, three CCGT projects in the 1GW+ bracket (at Spalding**, Damhead Creek and London Gateway*) were all rejected in the T-4 pre-qualification process, as was a proposed new unit at Thorpe Marsh (640 MW).  The recently consented Hirwaun and Progress open-cycle projects (299 MW each) also failed to pre-qualify.***  Carrington (880 MW) will go forward to the auction, but although it is described as a “New Build” project in the CM Register, this is a project whose construction is already well advanced, so arguably does not represent the CM stimulating new investment.  Meanwhile, the T-4 2015 auction CM Register records about 1 GW of existing CCGT capacity that has opted out on the grounds that it will have decommissioned or otherwise ceased to operate by 1 October 2019.

A number of the rejected projects pre-qualified successfully for the 2014 auction, so their rejection seems puzzling given that the eligibility criteria are unchanged.  On the evidence of the pre-qualification results, it looks as if most, if not all, the new generating capacity will be connected to the distribution, rather than the transmission network, and will have a capacity of no more than 20 MW, often in the form of reciprocating engines that can be fuelled either by gas or diesel.*  Such plants can be developed relatively cheaply, and – being distribution-connected – can boost their revenues with “embedded benefits” such as Triad payments, or ancillary services contracts, in addition to power sales and CM payments.  It is interesting that even the 370 MW King’s Lynn project is described as being distribution-connected.

Coal carries on

The large volume of CCGT schemes consented over recent years were seen by some as the natural successors to the UK’s ageing fleet of coal-fired plants and, with new technology, better able to cope with fluctuations in demand in generating mix increasingly affected by the intermittent characteristics of renewables.  (In a recent interview with World Energy Focus, National Grid’s CEO, Steve Holliday, noted that three of NG’s four future energy scenarios have 20 GW of solar in the UK by 2035.)  But although the CM Register reminds us that by 2019, we will have lost over 5 GW of generating capacity with the closures of coal-fired plants at Eggborough, Longannet and Ferrybridge, it also highlights the point that we are still likely to have at least 13 GW of old coal-fired generation in 2020.

The same point emerges from the recent consultation on the UK’s Transitional National Plan (TNP) for compliance with the Industrial Emissions Directive (IED) as it affects large combustion plants).  It also appears from an Annex to the TNP consultation that some plants have still left themselves the option of either upgrading their SOx and NOx emissions abatement measures so as to meet the IED in a phased manner under the TNP, or taking the “limited life derogation” (LLD) and running for no more than 17,500 hours between 1 January 2016 and 31 December 2023, before closing for good.

So far, most seem to be choosing the TNP route, suggesting that we may have a significant rump of old coal-fired plant beyond 2020.  Those hedging their bets have until the end of the year to make their final choice as between TNP and LLD (or earlier closure).  Among the factors they will have to weigh up is how far low coal prices will offset the tax burden of the carbon price support rate of the Climate Change Levy; the reliability and maintenance costs of their ageing equipment; and whether there is a realistic prospect of new subsidy for biomass conversion or co-firing following e.g. the recent response to consultation on changes to the Renewables Obligation rules for those technologies.  Other generators may have to calculate how far the CM subsidies to coal may depress wholesale power prices, making the economics of CCGT more challenging and Contracts for Difference for low carbon plant more expensive per MWh.

New elements

Ofgem has now taken over the main responsibility for the complex rules that govern the CM.  Following the 2014 auction, a very large number of rule changes were suggested, and a significant number were made.  However, perhaps the two biggest changes in the 2015 process originated in DECC and European Commission policy decisions.

When the auctions take place later this year, the T-4 auction will be the second time that a CM auction has invited bids to provide reliable generating capacity four years ahead but the “Transitional Auction” will be the first specifically in support of Demand Side Response projects.  In fact, a number of DSR projects have been successful in both the T-4 auction and Transitional auction pre-qualifications.  These projects are a mixture of “behind the meter” generation and what is sometimes called “genuine” DSR in the form of load reduction.  Some are based around a single large industrial or commercial user, and others would aggregate the demand of multiple customers.  Both specialist aggregators such as Kiwi Power and “mainstream” electricity suppliers such as EDF and Smartest feature among the pre-qualified projects.  Given that the Transitional Auction is for first delivery in 2016/2017, it is interesting to note that a number of bidders have yet to specify exactly what their capacity market units will consist of.

The European Commission required the UK Government to include interconnectors in the CM, but accepted that this was not possible for the 2014 auction.  Following a consultation, a lot of work on how to approach the de-rating of interconnector capacity in the CM context, and some steps forward in Ofgem’s broader policy-making on various interconnector projects, a number of interconnectors were eligible, or required, to engage in the pre-qualification process for the 2015 T-4 auction.  The two Irish interconnectors (Moyle and East-West) opted out, BritNed’s application was rejected, and  among the proposed new interconnectors, only Nemo appears to have applied, and was rejected.****  The IFA has pre-qualified, but by definition it will be four years until its performance in the CM can inform further policy debate or the strategies of other interconnectors.  The case that national capacity markets will be easily compatible with the workings of the EU internal electricity market is perhaps not fully made out yet.

*Update note: since this blog post was first published, a number of new projects that were initially rejected for prequalification have been prequalified or conditionally prequalified – see the notes below.

**Update note: since this blog post was first published, National Grid has issued revised results reflecting Tier 1 Dispute Outcomes.  Amongst the changes from the 25 September 2015 results, the large-scale CCGT projects at Spalding, Damhead Creek and London Gateway are now listed as prequalified, or conditionally prequalified, for the T-4 2015 Auction, as has Thorpe Marsh CCGT Unit A.  This opens the prospect of there being 5 really new large-scale CCGT projects in the auction, rather than one as appeared from the 25 September results. 

***Update note: further to the appeals process, both these projects have now conditionally prequalified.

****Update note: Britned has now prequalified, and Nemo has conditionally prequalified.

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The UK’s second capacity market auction – likely to deliver more of the same?

Global perspectives on the energy sector

What is the future for traditional power utilities?  What can Europe learn from the US experience of capacity markets?  What is holding back the development of the power sector in Africa?  What are the key political and economic considerations for those investing in Middle East energy projects?  How should energy companies deal with cyber security risks?  How can they gain business advantage by engaging proactively with Human Rights law and international investment treaties?  Where is the oil price going and what does that mean for industry consolidation?  Will the Paris 2015 UN Climate Change talks succeed where others are perceived to have failed?  How can projects to prevent deforestation be made to pay their way?

For perspectives on these and other hot topics in the energy sector worldwide, see our Global Energy Summit London 2015: Key Themes report, based on presentations given on 21 and 22 April 2015 in Dentons’ London Office by a range of expert contributors.  Individual presenters’ slides are also available on our website.

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Global perspectives on the energy sector

Christmas to come late(r) for those seeking UK renewables CfDs

Two more milestones in the implementation of UK Electricity Market Reform (EMR) have been passed in the last 24 hours (15/16 December 2014): the first EMR Capacity Market auction began, and it became clear that the first auction of EMR Contracts for Difference (CfDs) has been postponed until February 2015.

The Capacity Market aims to secure the availability of 48.6GW of reliably despatchable generating plant from the autumn of 2018.  This is being procured by means of a series of bidding rounds in a “descending clock” auction which must be completed by 19 December 2014.  The auction pits existing coal, nuclear, CCGT and peaking plant against each other and against new build gas and diesel generators, but only new build plant and existing plant spending £125/kW or more on refurbishment can act as “price makers” in the bidding process (see further National Grid’s Auction User Guide).

According to the previously advertised timetable, the first CfD auction should already have taken place in early December, with results being notified to applicants between Christmas and the New Year.  Instead, the revised version of the Low Carbon Contracts Company’s GB Implementation Plan for CfDs, published on 15 December 2014, states that those seeking CfDs will be invited to submit their bids on 17 February 2015 (if, at that point, demand for CfDs exceeds supply under the allocation round budget).

The delay has been driven by appeals against decisions on the eligibility of applications.  The Implementation Plan notes that a longer delay is possible if “Tier 2” appeals are not completed by 6 February 2015.  It is interesting that DECC has chosen to delay the CfD auction rather than make use of the mechanism (provided for in Part 8 of the Allocation Regulations and Rule 21 of the Allocation Framework) that allows an auction to go ahead with disputed applications still “pending”.

While we await the eventual outcome of these two first-of-a-kind auctions, we can start to compare and contrast the CfD and Capacity Market processes.

One striking difference is in terms of transparency.  The Capacity Market prequalification process results in publication and regular updating on the EMR Portal of a full list of applicants (both successful and unsuccessful) and their plants.  By contrast, there is no published list of applications for CfDs or the decisions that have been made as to their eligibility to be allocated a CfD.  In some ways this mirrors the bidding processes themselves: the successive rounds of the Capacity Market auction are rather more interactive and offer bidders some (albeit limited) visibility of each other’s behaviour; in the CfD auction, applicants must effectively put everything into their initial sealed bid.

A second major difference is in the scrutiny to which applicants’ claims to have fulfilled the criteria that make them eligible to bid are subjected.  For example, under the CfD legislation, applicants’ claims to have the necessary planning permission for their generating stations have to be substantiated by submitting copies of the relevant documents, which will then be checked by National Grid (albeit possibly in a fairly mechanical way).  By contrast, compliance with the parallel obligations to have any requisite planning permission before bidding in the Capacity Market auction is simply self-certified.

No doubt there will be further debate about these and other design features during 2015.  Already, Ofgem is consulting on possible changes to the Capacity Market Rules.  It has identified as priority areas for consideration the possible streamlining of the prequalification process, price maker memoranda, and rules about demand side response.  Meanwhile, alleged discrimination against the demand side has prompted Tempus Energy to challenge the European Commission’s decision that the Capacity Market is compatible with EU state aid rules.

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Christmas to come late(r) for those seeking UK renewables CfDs

Coal still counts (2): decision time for generators (or it will be soon)

In a previous post we looked at how the UK’s existing fleet of coal-fired plant had been saved from being made subject to the “emissions performance standard” or EPS under the Energy Act 2013 provisions for Electricity Market Reform (EMR).  This happened when the Government reversed an amendment that would have applied the EPS to existing coal-fired plant if its operators were to choose to keep it running in the long term by fitting the equipment necessary for it to comply with the new limits on emissions (in particular of NOx) that will apply to it from 2016 under the Industrial Emissions Directive (IED).  In this post, we explore the choice which operators have to make under the IED – and why the Government may have thought it worth keeping them out of the EPS. 

Existing plant faces a choice under IED.  In broad terms, it must either upgrade to meet the new emission limits, or run for a limited number of hours – for example, by opting for the “limited life derogation” (LLD).  The LLD allows plant to run in its current form for 17,500 hours before closing no later than 2023.  Subjecting existing coal-fired plant to the EPS if and when it upgraded to comply with IED NOx limits would have made it likely that its operators would opt for the LLD rather than upgrading, and at the load factors at which UK coal plant has been operating recently, most plants would probably burn through their 17,500 hours by 2020, if not before.

Why should that worry us?  Wouldn’t it just be another example of EU legislation that isn’t about climate change being more effective at tackling CO2 emissions than the EU Emissions Trading System?  (Most UK coal plant closures to date have been driven by the Large Combustion Plants Directive, which the IED replaces, and which was designed to combat effects such as acid rain rather than “global warming”.)  To understand why the Government was so keen to keep existing coal plant out of the EPS, we have to look at the work it is doing in the generating mix. 

In 2012, the UK’s total combined cycle gas turbine (CCGT) capacity (35.57GW) exceeded its total coal and oil-fired “conventional steam” generating capacity (30.97GW) for the first time.  But that same year, gas’s share of electricity generation fell from 40% (in 2011) to 28% and coal’s rose from 30% to 39%.  (Greenhouse gas emissions from the UK energy supply sector increased by almost 6 per cent as a result.)  Coal’s high share of UK generation persisted, and appears to have increased slightly, in 2013. 

Why is this?  Coal-fired power over this period has simply been cheaper than gas-fired power (partly because the availability of shale gas has hit US coal prices).  It can keep the lights on at lower cost.

Much of our coal-fired electricity comes from just 10 coal-fired plants, with a combined capacity of over 18 GW – about a fifth of generating capacity connected to the grid.  Now that the 1 January 2014 deadline for indicating their operators’ intentions as regards the LLD has passed, and with the threat of EPS removed, we might expect that there would be some clarity as regards their future, but in fact there is still a degree of uncertainty about most of them.

  • The future plans of three (Drax, Eggborough and Rugeley, together representing some 6.8GW of capacity, and all owned by generators who are not in the “Big 6”) appear to depend in part on plans to convert to burning biomass.  The success of these plans is likely to depend on whether they are allocated EMR Contracts for Difference (CfDs), and meet the conditions for those CfDs to take effect (more on all this in a later post).
  • One (E.ON’s Ratcliffe, 2GW) appears fully prepared for IED compliance.  Another (SSE’s Fiddler’s Ferry, just under 2GW) has development consent to fit the necessary equipment.  A third (Scottish Power’s Longannet, 2.3GW) is testing new technology to comply with IED.
  • The operators of four of them (Aberthaw, Cottam, Ferrybridge and West Burton, representing together some 7.5GW) have provisionally decided not to invest in the equipment necessary to comply with the IED.  Instead, EDF, RWE and SSE have said they plan to use the LLD. 

The story is clearly not over.  EDF, RWE and SSE have all indicated that they may still choose to upgrade some of their plants to IED standards.  So their choice of the LLD may be more about keeping their options open than representing their preferred long-term option for these four plants.  RWE commented: “Only after we have political clarity on how the energy market will operate under the Government’s new energy legislation as well as any other political changes to be enacted, will we be able to make [a] final decision with confidence.”.

The reference to the uncertainties still surrounding a number of aspects of  EMR reminds us that some existing plant may be looking to the EMR capacity market as a means of funding investment in IED compliance.  More on how the capacity market may work for coal and other types of plant in further posts.  For the moment, though, note two more points.  First, if operators wish to revisit their decision to choose the LLD and opt back in to the IED, they will be relying on, and will need to fit in with, the UK’s Transitional National Plan (TNP).  The TNP permits plants to ease in to IED compliance by 2020 rather than 2016.  But the UK’s TNP has so far not been approved by the European Commission as required by the IED.  Second, according to Defra, RWE, EDF and SSE do not have to reach a final decision on IED until the end of 2015.  This may be a very convenient deadline, since it comes after the next election, when operators will know whether Labour’s ambitious “Green Paper” proposals for further market reform are likely to be enacted.   

So, we are a long way from having heard the last of the power-politics of coal – although there are a few more legal elements to the debate than there were in the good/bad old days of the 1960s and 1970s.  There is no doubt that coal still counts, but it looks as if we will have to wait a little longer to see how far we can still count on some of our existing coal-fired plant.

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Coal still counts (2): decision time for generators (or it will be soon)

Coal still counts (1): keeping options open in the Energy Act 2013

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 NOx, 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.

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Coal still counts (1): keeping options open in the Energy Act 2013