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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