On The Horizon 2014: UK Energy Law And Regulation – Electricity Sector Briefing

Introduction The need to resolve the "trilemma" of how to achieve power supplies that are secure, reasonably priced and sourced from low-carbon generating technologies has prompted, and continues to prompt, huge amounts of regulatory activity and reform in the UK electricity sector.

Over the course of 2013, the Government's proposed Electricity Market Reform (EMR) began to take a more definite shape. On 18 December 2013, the Energy Bill received Royal Assent as the Energy Act 2013 (the Energy Act) and, a day later, the first EMR Delivery Plan was published. However, the regulatory landscape remains in transition as we enter 2014 - not least because it remains to be seen how far the European Commission will judge the various elements of EMR to be compatible with the EU state aid rules.

In this note, we review some of the key regulatory events of the past and coming years in relation to security of supply, support for low carbon generation and wider reform of the UK wholesale and retail electricity markets.

Security of supply and UK electricity generation Analysis of the problem

At present, Great Britain has about 10 GW or more of reliably "despatchable" or "non-intermittent" plant than is needed to cater for peak network demand of around 59 GW. In June 2013, taking all the known future plant closures into account, Ofgem found that that comfortable cushion will all but disappear in a few years' time, leaving UK consumers vulnerable to "loss of load" and "controlled disconnections" in times of system stress, such as when plants are unexpectedly unavailable. A major reason for this loss of reliable generating capacity is the planned closure of existing nuclear and coal-fired generating assets in the short-to-mid term. In relation to coal-fired plant, a number of generating stations chose not to upgrade to the pollution control standards imposed in 2008 by the Large Combustion Plants Directive. Such plant now has only a small number of hours left to run; other coal-fired plants are likely to opt for a "limited hours derogation" when the Industrial Emissions Directive imposes stricter pollution control standards on existing plant from 2016 (see for example recent announcements on this subject by EDF, RWE and SSE).

However, while this reduction in spare capacity margin and the consequent threat to security of supply is of concern to Government, regulators and consumers, long-term pricing signals have not been sufficiently sharp to attract the required investment in new-build gas-fired generation. Yet, on some estimates, we may need an additional 9 GW of gas-fired generating plant by 2020 and 26 GW by 2030 (see the Government's December 2012 Gas Generation Strategy).

The EMR capacity market: a solution to the problem of security of supply?

The EMR programme, legislated for in the Energy Act, puts forward a capacity market as part of the solution to this problem. Operators of reliably despatchable generating plant and users of large amounts of electricity will be paid for providing capacity in times of system stress when required to do so by the system operator. Generators will provide capacity by generating; users will do so by reducing their usage of electricity. The aim will be to ensure that the market as a whole can meet an appropriate "reliability standard". The reliability standard is expressed as the number of hours a year (three) in which, over the long term, it is statistically expected - and regarded as acceptable in policy terms, given the costs of procuring extra capacity - that supply will not meet demand across the GB system. The fact that supply does not meet demand does not necessarily mean that "the lights go out", because there are ways of managing the shortfall without customers being disconnected. National Grid, as system operator, will set out how much capacity is needed to meet the reliability standard, taking into account the capacity of existing and projected future generating plant. Potential capacity providers will be screened in a pre-qualification process to determine whether they are eligible to bid for "capacity agreements". Capacity auctions will take place four years and one year ahead of each "delivery year". Delivery years will run from 1 October to 30 September, with the first delivery year beginning on 1 October 2018 and the first auction taking place in Q4 2014. All successful bidders will receive the price set by the most expensive successful bidder. A capacity provider who fails to provide capacity when required to do so will be liable to a financial penalty. Capacity agreements are likely to last for one or three years in most cases, but may last for up to 10 years for new entrants.

It is hoped by Government that the capacity market regime will encourage some older plants which may otherwise have closed to stay open as "peaking plants", and encourage developers to build some new plants which would otherwise not be economically viable. (For more information on the capacity market proposals, see Chapter 4 of DECC's October 2013 consultation on implementing EMR - the outcome of which, at least as far as the capacity market is concerned, has yet to be announced. See also "2014: delivery of the capacity market" below).

Individual non-intermittent technologies: generating mix

New gas-fired generation will continue to have a central role in the UK's generation mix for many years to come. However, from the point of view of the Government's plans to decarbonise the electricity generating sector, it is envisaged that conventional gas-fired plant will be used less and less for "baseload" generation, with its role being more and more confined to that of balancing the system - particularly given the increasing amount of intermittent renewable generating capacity projected to come on-line (most notably, offshore wind). Under this scenario, the role of baseload generation should be shared by new nuclear generation and coal or gas-fired plant fitted with carbon capture and storage (CCS) technology and (to the extent that the relevant generating technologies permit) renewables.

2013 saw some progress on both new nuclear and CCS, although neither of these technologies is likely to make a significant contribution to UK electricity generation before the 2020s. Ed Davey's decision in March to grant development consent for Hinkley Point C (HPC), the first new nuclear power station in a generation, survived scrutiny by the High Court (following a judicial review claim brought by The National Trust for Ireland), although the High Court's decision has since been appealed. DECC launched a new consultation on the process for identifying a site for long-term storage of nuclear waste. Agreement was reached on the strike price for power from HPC. The Government entered into an MoU with China for potential cooperation on nuclear projects; and the Energy Act has put the Office for Nuclear Regulation on a statutory footing. In December 2013, the Government's CCS Commercial-Scale Demonstration Programme took a step forward with the award of a front-end engineering and design contract to the White Rose consortium.

Those with an interest in the nuclear sector should also note that DECC is preparing proposed changes to the UK nuclear liabilities regime, implementing the 2004 protocols to the Paris and Brussels conventions. Investors and others involved in nuclear development need to understand the changes, which will affect the costs of compliance for nuclear site licence holders and assessment of residual liability risks for all industry participants. Key changes include coverage of a wider range of losses, (including reinstatement of impaired environment; a greater number of potential claimants, including those suffering damage in a non-convention state with no nuclear installations); higher liability caps; and longer limitation periods. DECC plans to lay a draft Order before Parliament later in Spring 2014 (see latest published draft order), but most of the changes will only come into force when the protocols are ratified simultaneously by all EU Member States. Significant issues remain to be resolved before ratification, notably in relation to the insurance market.

Security of supply considerations have presumably also influenced DECC's policy for supporting biomass generating plants. Biomass is rare among the renewable technologies currently widely deployed in the UK in being "despatchable", rather than intermittent like wind or solar. However, DECC has chosen to limit support for biomass under the EMR Contracts for Difference (CfD) regime to biomass CHP plant or converted former coal-fired plant. The conversion of coal plant to biomass enables some very large generating plant which might otherwise close to remain in service.

These converted plants have a limited remaining lifespan in any event, and are to be awarded CfDs of slightly shorter duration than other technologies (ending in 2027 in all cases, rather than being awarded the 15-year term which will apply to biomass with CHP and other technologies), indicating that they are not part of the long-term generation mix.

Balancing Significant Code Review

Ofgem's Electricity Balancing Significant Code Review also reflects concerns about security of supply, albeit from the slightly different perspective of within day balancing of the system. It focuses on "cash-out", the process used in the GB wholesale electricity market to settle all market participants' energy account imbalances. Market participants are exposed to "cash-out" prices (otherwise known as "imbalance charges") when they generate or consume more or less electricity than they have nominated/contracted for. This incentivises participants to match their nominated/contracted positions to sell or buy energy with physical generation or demand. Ofgem believes current cash-out prices do not sufficiently reflect the costs of balancing in times of system stress or provide the necessary...