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

Last Updated: 24 February 2014
Article by Charles Wood, Charles July, Mark Cheney and Adam Brown

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 EDFRWE 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 pricing incentive for sufficient investment in flexible generation capacity (i.e. gas-fired generating plant).

The Code Review project originated in 2011 and will not be finished until 2015, but during 2013 its scope was materially reduced and Ofgem announced the basis of its answers to the remaining problems under consideration. Cash-out prices would be made more "marginal" by calculating them using the most expensive action the System Operator (National Grid Electricity Transmission) takes to balance the system. Actions that are currently not costed, such as blackouts and brownouts, would be included in the cash-out calculation, based on the Value of Lost Load to consumers (starting at £3,000/MWh in 2015 and increasing to £6,000/MWh in 2018). It is proposed to pay domestic consumers £5 per hour and non-half-hourly metered business customers £10 per hour of disconnection, recognising that they provide an "involuntary demand side response" (DSR) service to the System Operator.

Labour Party proposals for a new Energy Security Board

The Labour Party evidently shares the general concern about security of supply. It has recently taken the relatively unusual step, for an Opposition party 18 months before a General Election, of publishing, for consultation, a set of detailed energy policy proposals in the form of a "Green Paper". Labour advocates the creation of a new statutory body to deal with security of supply: the Energy Security Board. Although it is, in part, envisaged as an energy security equivalent of the Committee on Climate Change, the way in which the Labour Green Paper describes the Board suggests that it could have more than an advisory function. Amongst other things, its remit would be to "ensure that there is adequate security and enough major generators with complete independence from each other to ensure competition between them".

2014: delivery of the capacity market

Introduction

It was apparent from DECC's October 2013 consultation on EMR (not least from the number of gaps and square brackets in the accompanying draft secondary legislation) that many points of detail remained to be settled as regards the organisation of the capacity market. In 2014, that legislation must be finalised and approved by Parliament before the summer recess. In the following five months, the pre-qualification process, appeals against pre-qualification decisions and the auction itself must take place.

There is not sufficient space here to discuss all the issues to be resolved in relation to the capacity market. We focus below on some of the larger questions that remain, which are likely to have a major impact on commercial attitudes to the new regime.

Penalties

The capacity market relies on those who have undertaken to provide capacity in times of system stress (whether by generating electricity or reducing their consumption of it) providing that capacity when called on to do so. DECC's proposals therefore include a regime of penalties where a capacity provider fails to provide its contracted amount of capacity.

Such a capacity provider will also face a cash-out price of £6,000/MWh under Ofgem's proposed Code reforms, so DECC has suggested that the additional capacity market penalty should be between £1,000/MWh and £3,000/MWh. It is also proposed that a unit's total exposure to such penalties in a delivery year should be limited to somewhere between 101% and 150% of its annual capacity revenue. This is to "prevent providers that never intended to perform from taking a gamble in the expectation of receiving capacity payments without facing significant penalties". However, a "soft" cap will work in conjunction with this hard cap to moderate the rate at which the cap is reached, and to ensure that delivery in subsequent events would reduce a provider's overall penalty liability so as to ensure that it remains incentivised to provide capacity even after the cap has been reached. Failure to perform will not incur a penalty if National Grid fails to issue a capacity warning at least four hours before an impending system stress event. It is proposed that there should only be limited delivery exceptions for force majeure events, being a National Grid constraint preventing delivery, a suspension of the electricity market or a delay in commissioning because the network operator has failed to connect the unit. Further, there is no allowance for adjustment to the capacity price, once a capacity agreement has been awarded, for subsequent changes in law. The limited force majeure and change in law protections may adversely impact the bankability of the capacity agreement.

Whilst there is in one sense a clear economic logic to the penalty proposals, the sums of money involved are clearly potentially very large. There is no doubt that they may serve to deter some potential capacity providers (particularly independent generators) and/or their potential financial backers. In any given year, a provider may not be required to provide capacity on a large number of occasions, but, with such substantial penalties in place, it would only take a few instances of "bad luck" to wipe out all the revenue that the provider would otherwise have derived from its capacity agreement. Moreover, banks may be unwilling to lend to potential capacity providers if the penalties cap is set at more than 101% of a generator's annual capacity revenue, particularly if performance is assessed on a portfolio basis so that financiers of one of an operator's plants could be exposed to poor performance of another of its plants over which they have no control. Whilst there are signs that DECC is aware of these problems and seeking to address these issues, a great deal remains to be done in a relatively short period of time if the first capacity auction is to be a success.

The capacity agreement

It is interesting that DECC has proposed that the maximum term for a capacity agreement for new plant be limited to 10 years unlike CfDs where the "standard" term is 15 years. This is likely to limit the tenor of bank debt to a shorter period than the term of the capacity agreement. As it is unrealistic to expect a project to repay its capital costs within such a shortened period, this will increase the hurdle rate for new market entrants, who (absent a tolling agreement) will be obliged to rely on uncertain market revenues to achieve the requested rate of return.

Plants under construction holding capacity agreements will be subject to additional constraints to ensure that they are incentivised to be available on time. New plants will be required to demonstrate that they have incurred at least 50% of the project expenditure scheduled to have been made as per their construction plan within a year of being awarded the capacity agreement. Failure to do so will result in termination of the capacity agreement and payment of a termination fee. Capacity providers will have to post collateral to cover such risks. Delay in commissioning will result not only in suspension of capacity payments, but also, since the term of the relevant capacity agreement will commence at the start of the delivery year, in a reduction in capacity revenues over the term of the agreement. Any new plant failing to have at least 50% of the capacity specified in its capacity agreement available within 18 months after the start of its first delivery year will be subject to termination and payment of a higher termination fee. Such terminated capacity could participate in subsequent auctions but only as a "price taker". In the case of refurbished plant, failure to meet its financial commitment milestone or achieve substantial completion within a prescribed period will result in the term of the capacity agreement being reduced to one year. The absence of force majeure relief in the above scenarios could impact on the bankability of the proposed capacity agreement as may the inability of capacity providers to pass through penalty payments and termination fees to EPC and O&M contractors, who will seek to cap their exposures to these risks. Finally, it would appear that penalty payments can be set off against subsequent capacity payments, but it is not clear whether such right, as per the CfD, is vested in the settlement body alone or may be exercised by the capacity provider as well.

State aid

A further layer of complexity is added by the fact that implementation of the capacity market requires the approval of the European Commission under the EU state aid rules. Helpfully, in December 2013, the Commission's DG Competition published for consultation draft guidelines on environmental and energy aid for 2014-2020, just a day before DECC's pre-Christmas release of EMR publications. The draft guidelines are part of the Commission's ongoing modernisation of the EU state aid framework.

The draft guidelines note that among the points to be taken into consideration in assessing a scheme such as the capacity market are whether operators from other Member States can participate and the avoidance of negative effects on the internal market. The draft guidelines also state that a scheme such as the capacity market "should in principle not reward investments in generation from fossil fuel plants unless it can be shown that a less harmful alternative to achieve adequate generation does not exist"; that it should "provide adequate incentives to both existing and future generators and to operators using substitutable technologies, such as demand-side response of storage solutions" and "be delivered through a mechanism which allows for potentially different lead times". There are clearly a number of points here that may be expected to give rise to intense scrutiny of DECC's state aid notification.

Interconnectors

One of the points stressed in the draft state aid guidelines is that a measure such as the capacity market should not reduce incentives to invest in interconnection capacity. Interconnectors are essential to the EU single market in energy, which is meant to be completed in 2014. They are also likely to be part of the solution to the problem of how to include non-UK providers in capacity market auctions, which may be an important point for the European Commission's state aid analysis. However, it will not be possible for interconnectors to participate in the first capacity auction because it is difficult for DECC to assess with any level of certainty their ability physically to deliver electricity at times of system stress due to the requirements of the EU's Target Model for market coupling (on which see below). For a discussion of a possible solution to this problem for future auctions, see the report on interconnection in the papers of the 17 December 2013 meeting of the DECC Expert Group on the capacity market.

DECC has just published More interconnection: improving energy security and lowering bills. Last year's EU Regulation on cross-border infrastructure should make it easier to get interconnectors built and funded (see the Commission's interactive map of "projects of common interest"). The new DECC paper and the Redpoint analysis that accompanies it show that, although interconnection is a difficult area for the UK, it is worth getting right: the possible impact of interconnectors on GB consumers ranges from potential net benefits of £9 billion to potential net costs of £9.5 billion.

Beyond new generation capacity: changes on the demand side

The capacity market is not just an opportunity for generators to provide reliable sources of power at times of system stress. It is also designed to reward those who are able to provide capacity in the market by reducing the amount of electricity they consume – to encourage demand side management and electricity demand reduction measures.

There are of course other reasons to focus on the demand side as well. There are the targets in the Energy Efficiency Directive (18.7% on 2007 levels by 2020 in the case of the UK). There is the fact that reducing usage is an effective way to reduce energy bills.

However, reducing or shifting demand requires behavioural change. The difficulty of stimulating such change with "top-down" measures is shown by the limited take-up to date of the Government's Green Deal and the continuing debate over the ECO scheme, which the Labour Party Green Paper proposes replacing with an "Energy Save Local" scheme.

In some ways the big target of these schemes is saving energy used for heating and, therefore, in many cases the consumption of gas. When it comes to electricity, it has always been hoped that (in addition to using more efficient appliances) it would be the richness of real-time information about energy use provided by smart meters that would encourage domestic consumers to change their behaviour, and that they would be helped in this by suppliers offering tariffs which differentiated price according to time of use.

However, there is a divergence between the way the smart meters would help the energy efficiency agenda (which is partly by introducing more sophistication and differentiation of the range of products and pricing options available) and the current political and regulatory emphasis on simpler bills and tariff structures (see below on Ofgem's Retail Market Review and the provisions on domestic tariffs in the Energy Act). It is therefore not clear how quickly, in the current climate, the potential for competitive differentiation which smart metering opens up will be realised. By the time full roll-out of smart meters is scheduled to have taken place (2019) there may be more appetite for the kinds of pricing differentiated by time of use that they can facilitate.

Policy support for low carbon generation

EU 2030 framework for climate and energy policies

On 22 January 2014, the European Commission proposed a new target to reduce EU greenhouse gas (GHG) emissions by 40% of their 1990 level by 2030. It also proposed that there should be an EU-wide target to produce 27% of EU energy from renewable sources by 2027. The new targets would succeed the three 2020 EU targets of a 20% GHG emissions cut from 1990 levels, a 20% share for renewable energy and energy savings of 20% from 1990 levels. However, by contrast with the 2020 targets, the proposed new package would not impose binding renewables targets on Member States – which have clearly done much to drive the deployment of renewable generation in the UK and elsewhere. It therefore remains to be seen what mechanisms are to be put in place to ensure that the 27% target is achieved.

Within the 2030 framework, the Commission has also proposed to establish a market stability reserve for Phase 4 of the EU Emissions Trading Scheme (commencing in 2021). The reserve is intended to address the surplus of emission allowances that has built up in recent years and to regulate the auctioning of emissions allowances within Phase 4.

The 2030 framework is expected to be considered by the European Council in March.

UK carbon budget

The UK has its own legislative system of targeting reductions in GHG emissions in addition to those required by EU law. Carbon budgets were introduced as part of the Climate Change Act 2008 to help the UK reduce GHG emissions by at least 80% by 2050. Each carbon budget limits the total amount of GHGs the UK can emit over a five-year period. The UK is the first country to set legally binding carbon budgets of this kind. Government has set the first four carbon budgets in legislation, covering the period from 2008 to 2027. It has also committed to reducing UK emissions by 50% relative to 1990 levels during the Fourth Carbon Budget period (2023 to 2027).

The Fourth Carbon Budget is subject to review in 2014, once uncertainties at the EU level have been resolved. However, the Committee on Climate Change advised in December 2013 that there has been no change in the circumstances upon which the Fourth Carbon Budget was originally set in 2011 that would justify a lowering of ambition.

Carbon price floor

The original EMR proposals included the Government's plans for a "carbon price floor", and this was the first part of the EMR package to be implemented. It is intended to increase certainty for investors in low-carbon generation by putting a minimum price on the GHGs emitted by the power sector. In December 2013, HM Revenue & Customs announced that the "carbon price support" rates which are applied to the Climate Change Levy to give effect to the carbon price floor had been recalculated because of an earlier statistical error. The rates will be amended in the Finance Act 2014.

Emissions performance standard

Consistent with Government's decarbonisation objectives in the electricity sector, the Energy Act also introduced an emissions performance standard (EPS) to limit the annual amount of carbon dioxide emitted by new fossil-fuel generating plant (to a level equivalent to emissions of 450g/kWh operating at baseload). While this level may be revised and reduced in the future (although it will take another Act to do so), Government intends to "grandfather" this level (for plant subject to this level at the time it was granted development consent) until 2045 so as to provide regulatory certainty to investors in new fossil-fuel generation capacity.

Funding for new low carbon plant: Electricity Market Reform

Contracts for Difference (CfDs)

On 18 December 2013, the Energy Bill received Royal Assent. The provisions in the Bill on CfDs, which are designed to be the primary support mechanism for low carbon generation under EMR, were amended extensively during its passage. On 19 December 2013, DECC issued a number of publications that made it clearer how some features of the CfD regime will work. These included the EMR Delivery Plan, updated draft CfD terms and a consultation on the regulations that will give CfDs legal effect. But there is still some way to go before the support landscape for UK renewables will be settled. Amongst other things, a number of key topics are still the subject of consultation, secondary legislation required to implement the regime is yet to be made fully available even in draft and EU state aid clearance has yet to be given.

Allocation of Contracts for Difference

The ongoing fluidity of some aspects of the CfD regime was clearly demonstrated on 16 January 2014, when DECC published a consultation on the allocation of CfDs. It proposes that all CfDs in the "enduring regime" (as opposed to Investment Contracts, on which see below) will be allocated from the outset on the basis of "allocation rounds" – not, as had previously been stated, initially on a "first come, first served" basis. This means that there will be set times for applying for all CfDs. The overall CfD budget will be determined through the funding available under the Government's Levy Control Framework (LCF), on which the National Audit Office reported in November 2013. The table below (drawn from Table 2 in the EMR Delivery Plan) shows how the overall amounts available for each year under the LCF are likely to be divided between the various new and existing support schemes which it covers.

Table 1: LCF expenditure/projected funds available for new renewable and low carbon plant

 £m 2011/2012 prices 2015/2016 2016/2017 2017/2018 2018/2019
  £ % £ % £ % £ %
 Total LCF Cap: Renewables Obligation (RO), Feed-in Tariff (FIT), CfD 4,300 100 4,900 100 5,600 100 6,450 100
 Committed FIT expenditure1 760 18 760 15 760 14 760 12
 Committed RO expenditure1 2,900 67 2,790 57 2,790 50 2,790 43
 Projected new FIT expenditure 40 1 130 3 200 4 260 4
 Renewables Investment Contracts2 260 6 450 9 720 13 1.010 16
 New RO projects, other CfDs 340 8 770 16 1,130 20 1,630 25
  1. Estimated figures.
  2. Maximum possible allocation to FID Investment Contracts for renewables: any underspend will be reallocated to other CfDs.


The allocation process will divide the overall amounts available for CfDs between "established technologies" (onshore  wind and solar PV above 5 MW, energy from waste with CHP, hydro-electric between 5 and 50 MW, landfill and sewage gas) and "less established technologies" (offshore wind, wave and tidal stream, advanced conversion technologies, anaerobic digestion, dedicated biomass with CHP and geothermal). Applicants in the "established technology" categories such as solar PV and onshore wind can no longer regard it as a given that the strike prices they are awarded on their CfDs will be the "administrative" strike prices published on 4 December 2013. Instead, for these technologies, the administrative strike prices are likely to serve as caps in an auction process.

The consultation closes on 12 February 2014. The change in approach is, in part, designed to ensure the CfD structure is compatible with EU state aid legislation (see "RO, Investment Contracts and CfDs: state aid considerations" below).

DECC will provide further details of the CfD auction process in the coming weeks, with a draft CfD allocation framework to be published in March 2014. Although it will not be set out in legislation, the allocation framework has emerged as one of the key components of the CfD regime, since it will set out, amongst other things, how the auction process will work. DECC envisages secondary legislation being made in July 2014, with the application process for CfDs to open in October 2014 and first CfDs to be awarded in late 2014/early 2015.

Investment Contracts

To facilitate investment decisions for generation assets being made ahead of the implementation of the CfD regime, the Energy Act confers a power on the Secretary of State to let Investment Contracts to qualifying projects under the Final Investment Decision enabling programme for renewables.

In December 2013, DECC announced that 16 renewables projects had provisionally qualified for Investment Contracts, now shortlisted to nine "Provisionally Affordable Projects". Final draft Investment Contracts are to be circulated to applicants by 31 March 2014 before binding applications for Investment Contracts are made, with DECC then to down-select successful applicants and sign Investment Contracts (subject to Parliamentary approval). (See further DECC's webpage on Investment Contracts.)

Investment contracts require state aid clearance, with generators entitled to terminate them in August 2014 or August 2015 if clearance has not been received by those dates. DECC has proposed that, subject to certain conditions, generators whose Investment Contracts have terminated due to lack of state aid approval will be eligible for accreditation within the RO and will have an additional period of 12 months after the closure of the RO on 31 March 2017 in which to achieve accreditation under the RO.

Backstop PPAs

DECC is developing proposals for an Offtaker of Last Resort to provide independent renewable generators with a "Backstop PPA" route-to-market at a price set at a fixed discount to a market reference price, with certain licensed suppliers to be obliged to enter into Backstop PPAs on specified terms. This is in response to concerns that independent renewable generators will have difficulty in securing Power Purchase Agreements (PPAs), particularly those that have a long enough tenor and favourable enough terms to attract limited recourse finance.

DECC has established advisory groups to feed into the design process of the Offtaker of Last Resort mechanism and Backstop PPA terms and launched a consultation on the proposals for the Offtaker of Last Resort mechanism on 11 February 2014. The consultation closes on 24 March. Generators, investors and financiers will welcome DECC's stated intention to allow all renewable CfD generators (irrespective of size or technology type) to access the Backstop PPA mechanism. However, key design features remain to be confirmed, particularly around contract terms, risk allocation and price.

The acceptability and "bankability" of these proposals to the debt markets, licensed suppliers and independent generators remains an open point, with the pricing of imbalance risk likely to be a key topic for discussion – particularly for intermittent generation technologies in light of Ofgem's ongoing Electricity Balancing Significant Code Review (see above). Risk allocation and "route to market" certainty is also likely to be a key factor for equity investors (including secondary market investors) in independent renewable generation projects.

Renewables Obligation (RO)

Transition from the RO to the CfD

The RO and CfD will both be open for applications from new renewable generating capacity until 31 March 2017. It is proposed that the RO will close to new generating capacity on 31 March 2017, subject to certain grace period arrangements (which would allow qualifying projects to be accredited under the RO within defined timeframes after 31 March 2017).

DECC issued a consultation paper on RO grace periods on 7 November 2013, setting out the Government's proposals for closure of the RO to new generating capacity on 31 March 2017.

This consultation closed on 28 November 2013, with Government's stated objective being to lay a Renewables Obligation Closure Order before Parliament in Spring 2014, using the powers to do so conferred on the Secretary of State by the Energy Act. The making of such an Order would be subject to Parliamentary approval and any state aid clearances that may be required.

DECC has not yet published its response to this consultation, but has confirmed that the end date for the RO will not extend beyond 2037, meaning that any "grace period generating station" accredited under the RO after 31 March 2017 would receive less than 20 years of RO support.

RO: transition to a certificate purchase scheme

The Energy Act also confers a power on the Secretary of State to transition from the RO to a fixed price certificate purchase scheme. In its July 2013 consultation on RO transition, DECC sought views on its then current plan to implement the fixed price scheme in 2027 and the alternative of bringing the implementation of the fixed price scheme forward to 2017. DECC has yet to publish a response to this consultation.

DECC's stated intention is to publish a further consultation in Spring 2014 on the secondary legislation required to implement the certificate purchase scheme and associated arrangements for the fixed price scheme, with secondary legislation to be in place by April 2015.

The absence of date or price certainty around the certificate purchase scheme provides ongoing challenges for developers with projects scheduled to complete before 31 March 2017 and who are considering the comparative economics of developing projects within the RO or the CfD regime. Similar challenges are faced by developers whose projects have pre-qualified for Investment Contracts, but which may yet fall within the RO regime if state aid clearance for Investment Contracts is not forthcoming (see "Investment Contracts" above).

The Renewables Obligation (Amendment) Order 2014

In August 2013, DECC issued the Government's response to a consultation on proposals to enhance the sustainability criteria for biomass feedstocks under the RO.

A Renewables Obligation (Amendment) Order is to be laid before Parliament in early 2014 and, subject to Parliamentary approval and any necessary state aid clearance, is intended to enter into force on 1 April 2014. DECC has published an illustrative draft of this Order.

The legislative changes will cover changes to reporting requirements, the sustainable forest management criteria and the requirement for biomass generators to provide an independent audit report. It is proposed that compliance with the sustainability criteria should be a prerequisite for the issue of Renewable Obligation Certificates from 1 April 2015. A similar approach is to be taken to sustainability requirements under the CfD regime for biomass plants (although the relevant provisions are missing from the latest published version of the CfD standard terms and conditions).

The Government has also stated its intention that there should be "no further unilateral changes" to the sustainability criteria before April 2027.

RO, Investment Contracts and CfDs: state aid considerations

As noted above, the development of EMR coincides with the European Commission's ongoing "modernisation" of the EU state aid framework. On 18 December 2013, the same day that the Commission published its draft guidelines on environmental and energy aid for 2014-2020, the Commission also announced the opening of two in-depth state aid investigations: one into a German scheme reducing renewables surcharges to energy-intensive users and the other into the UK's proposed aid to EDF's Hinkley Point C nuclear power station. Both the draft guidelines and the two ongoing investigations are relevant to EMR.

The draft guidelines are more extensive than the 2008 document they aim to replace. Like the Commission's November 2013 guidance to Member States on state intervention in electricity markets, they reflect suspicion that, notwithstanding "the challenges of the climate change agenda", some national subsidy regimes for renewables are "overcompensating" what are now "mature" technologies; that new schemes designed to ensure security of supply may end up supporting plants that are unnecessary or inefficient; and that Member States too readily opt for subsidies rather than pursuing demand reduction options or the potential for EU market integration. They give a clear indication of the approach that the Commission is likely to take in deciding whether to approve those parts of EMR which require state aid clearance (i.e. most of it), and what changes to require DECC to make as a condition of such clearance.

The influence of the Commission's thinking is already apparent in the Government's recent decision to make the allocation of CfDs in certain technologies subject to competitive bids from the outset. The principle that "aid is granted in a genuinely competitive bidding process" is top of the Commission's list of criteria for "aid granted by way of a feed-in-premium or feed-in-tariff" for "deployed technologies producing electricity from renewable sources". However, it remains to be seen what the Commission will make of the likely impact of awarding CfDs on a competitive basis for technologies such as onshore wind and solar PV above 5 MW when, for the next three years, they remain eligible for support under the RO.

Another area where the Guidelines are highly relevant to implementation of EMR is the Government's proposals to exempt certain categories of energy intensive industrial users from paying the costs of EMR measures that would otherwise form part of their bills as a result of the supplier levy that will fund payments to generators under CfDs. Whilst the Guidelines acknowledge that this kind of arrangement can be acceptable, they stress that the reduction in costs as a result of this form of aid cannot exceed the funding of support to energy from renewable sources. They also state that it should be "targeted to avoid that without a reduction in the cost burden, certain sectors are at risk of relocating outside the EU" and "limited to sectors that are exposed to significant risk of carbon leakage due to the funding of support to energy from renewable sources". This is similar to the EU ETS State Aid Guidelines, which have helped to inform the Government's approach in this area.

It is instructive to compare the Commission's decisions to open detailed investigations into the German surcharge reduction scheme and into the proposed Hinkley Point Investment Contract. The letter to the German authorities maps out fairly clearly the kinds of information and analysis that the Commission will want to see about the costs and other pressures facing EU energy intensive industries before it grants approval for a measure reducing their contributions towards renewables subsidies. The letter to the UK authorities suggests that DECC faces an uphill task in securing Commission approval for the Hinkley subsidy arrangements in their current form. It expresses serious doubts about both the level of support under the proposed strike price and the structure of the contract: some of these are specific to the Hinkley proposals; others may be relevant to state aid analysis of the wider CfD regime.

Offshore transmission

Offshore wind is targeted to play a crucial part in achieving the UK's renewable generation targets, with four offshore wind projects having been identified by DECC as "provisionally affordable projects" for Investment Contracts (see above). However, with DECC's announcement in December that the deployment of 10 GW of offshore wind by 2020 is "achievable" (relative to previous assessments of between 8 and 16 GW of potential offshore wind deployment by 2020) and the recent cancellation of the Atlantic Array offshore wind project due to project economics, the timing and volume of offshore wind generating capacity coming to market through to 2020 and beyond remains uncertain.

Offshore developments were given some regulatory assistance in 2013 by the issuing of new planning guidance (designed in part to facilitate the consenting of "oversized" transmission infrastructure that could both save money and reduce the environmental impacts of staged projects).

More recently, in January 2014, Ofgem has published a consultation on "non developer-led Wider Network Benefit Investment" and has sought developers' views on their plans for future offshore transmission projects.

On 24 January 2014, Ofgem published its final proposals on the implementation of the "Generator Commissioning Clause" in the Energy Act. This is designed to ensure that, following "full commencement" of the offshore transmission regime, a generator developer can lawfully commission and operate offshore transmission assets before transferring them to an offshore transmission asset owner (OFTO) (given the unbundling requirements under the EU's Third Energy Reform package, which largely prohibits the ownership of electricity generation and transmission assets). This consultation is open to responses until 24 February 2014.

Offshore transmission Tender Round Three will also be launched by Ofgem in late February 2014.

Renewable Heat Incentive

The renewable heat market has been identified as a sector that could provide around a third of the Government’s target of 15% of energy from renewables by 2020 and also help meet longer-term decarbonisation targets. The Renewable Heat Incentive (RHI), first launched with a non-domestic scheme in 2011, is the Government's policy response to this potential opportunity, which aims to achieve a step change in the uptake of renewable heat generating technologies and prepare the market for mass roll-out in the 2020s.

In Spring 2014, following consultations in 2013, the domestic version of the scheme will be launched and a number of changes to the non-domestic scheme will take effect, including increases in the support available for renewable CHP, large biomass boilers (over 1 MW), deep geothermal, ground source heat pumps, solar-thermal and biogas combustion, as well as new support for air-water heat pumps and commercial and industrial energy from waste.

At the moment, the rates of support for the RHI compare favourably with those available for many forms of renewable electricity generation. This raises the prospect of a shift in supply. For example, a producer of biogas may find it more profitable to sell that gas for injection into the grid than to use it to power a small generating plant and sell electricity, with accompanying RO or Feed-in Tariff (FIT) benefits. This may be a positive result from a DECC policy point of view, but DECC will need to make sure that the RHI does not fall victim to its own success, as the FIT scheme did when the original level of feed-in tariffs proved to be too attractive to be affordable.

Measures focused on consumers

Retail Market Reform

In keeping with Ofgem's principal objective of protecting the interests of energy consumers, Retail Market Reform (RMR) aims to enable consumers to get a better deal from energy companies.

RMR is part-way through a phased implementation:

  • from 26 August 2013, suppliers were required to abide by new domestic Standards of Conduct;
  • from 2 October 2013, new consumer protection rules have been in place;
  • from 31 December 2013, the number and complexity of tariffs has been reduced;
  • from 31 March 2014, new rules will ensure consumers are regularly provided with information about the cheapest tariff for them with their current supplier;
  • by 30 June 2014 any consumers who are on old, expensive, evergreen tariffs that are no longer open to new customers (so-called "dead tariffs") will be switched to their supplier’s cheapest variable rate; and
  • suppliers will have to check, on an annual basis, after that date to ensure any customers who remain on a dead tariff are not paying more than the supplier’s cheapest variable rate. The first of these checks will have to happen by 30 June 2015.

Debate over domestic tariffs – Energy Act provision

The Ofgem RMR proposals are the result of a long period of consideration and consultation. By contrast, the licence modification power conferred on the Secretary of State by the Energy Act in relation to domestic tariffs was the product of a rather more rapid policy development process. The resulting provisions in the Energy Act have been drafted in broad terms and include powers for the Secretary of State to require suppliers to adopt standard tariffs, restrict the number of tariffs they can offer, and regulate the terms of any supply contract. It remains to be seen what use future Secretaries of State will make of these supposedly "backstop" powers.

Meanwhile, Labour's Green Paper asks for views on the introduction of a standardised tariff structure comprising a single unit price and regulated standing charge – and, of course, a 20-month price freeze until January 2017 to allow time for its other proposed market reforms (see "Labour: Energy policy proposal" below) to be legislated for and brought into effect.

Physical and financial regulation of wholesale markets

Liquidity review

Following its review of liquidity in the electricity wholesale markets, Ofgem is proposing to introduce a new special licence condition into the generation licences of the eight largest electricity generating companies: Centrica, Drax, EDF Energy, E.On, GDF Suez, RWE npower, SSE and ScottishPower. The "Secure and Promote" licence condition aims to improve supplier access to the wholesale electricity market by requiring these companies to follow a set of "Supplier Market Access" rules when trading with small independent suppliers. It also aims to ensure that the market provides the products and price signals needed to compete effectively through a market-making obligation on the (vertically integrated) "Big 6".

In November 2013, Ofgem consulted on the new licence condition. The consultation closed on 18 December 2013 and on 23 January 2014 Ofgem issued a decision letter. Ofgem will direct the modification to the generation licences to take effect on 31 March 2014.

The "Secure and Promote" licence condition includes a review clause enabling the licensee to request Ofgem to review the impact of changes in financial regulation – specifically MiFID II (the Markets in Financial Instruments Directive) and EMIR (the European Market Infrastructure Regulation) on licensees' ability to comply with some of the new requirements.

The convergence of physical and financial regulation in the wholesale energy markets is a recurring theme – from the liquidity review to REMIT (see below) and the need for energy traders and suppliers to analyse whether their trading and/or supply activities are likely to fall within the scope of MiFID II and EMIR, particularly those that trade commodity derivatives and emissions and that currently rely on exemptions for own account dealing and ancillary trading.

For further information and updates on financial regulatory developments, see our newsletters on Financial Regulatory Developments.

REMIT

The Regulation on wholesale market integrity and transparency (REMIT) came into force on 28 December 2011.

The main objective of REMIT is to increase transparency in the wholesale energy market and to prevent the use of inside information and other forms of market abuse which distort wholesale energy prices and may result in higher energy costs for businesses and consumers. REMIT is intended to complement existing (and equivalent) EU legislation relating to transparency and the prevention of market abuse in the financial markets.

Ofgem is the National Regulatory Authority for Great Britain under REMIT and has been granted new powers to investigate and enforce breaches of REMIT by the Electricity and Gas (Market Integrity and Transparency) (Enforcement etc.) Regulations 2013.

Ofgem published a policy statement on REMIT penalties and on procedural guidelines for its investigatory and enforcement powers in November 2013. The conclusions of Ofgem's Enforcement Review are likely to be relevant in this area.

Since REMIT is an EU Regulation, it became law in all Member States as soon as it came into force. However, under REMIT:

  • the European Commission is required to adopt further implementing acts to give effect to the reporting requirements within Article 8 of REMIT (relating to the transactions to be reported, uniform rules on reporting and the timing and format of such reporting) and these reporting obligations will not come into force until the date falling six months after the relevant implementing acts are adopted (Article 22); and
  • national regulators are, under Article 9 of REMIT, to establish national registers of market participants within three months of the European Commission adopting the relevant implementing acts under Article 8.

These implementing acts have not yet been adopted, but were due to be so adopted in 2013. Given this, the obligation to register as a market participant is not likely to occur until Q2 2014 (at the earliest); and reporting obligations under Article 8 of REMIT are not likely to be imposed until Q3 2014 (at the earliest).

Wholesale power trading

UK power trading: migration from EFA calendar

In October 2013, the Futures and Options Association announced that the UK power market is taking the step to switch trading in wholesale UK power from the EFA calendar to the more widely used standard Gregorian calendar. This change is being made to align the UK power markets with continental European power markets and the UK NBP gas market, with Winter 2014 being the earliest delivery period for trading in Gregorian products.

Price coupling of regions: North-Western European Price Coupling

Part of EU plans to create a harmonised European wholesale electricity market and to implement the "Third Package" of EU single energy market legislation is a Europe-wide single price coupling project. The project is being undertaken in conjunction with the Target Model (framework guidelines for the integration of wholesale and balancing markets) and the development of Network Codes to establish common technical and commercial rules governing access to energy networks and to remove barriers to trade between Member States.

The North-Western European Price Coupling (NWE) project is the first of a series of "price-coupling" projects in this area. It is designed to couple the day-ahead power markets across Central Western Europe (CWE), Great Britain, the Nordic countries, the Baltic countries, and the SwePol link between Sweden and Poland. NWE was launched on 4 February 2014.

Competition

The announcement that Ofgem, the Office of Fair Trading (OFT) and the newly created Competition and Markets Authority (CMA) would conduct annual reviews of competition in energy markets was presented as part of the Government's response to Ed Miliband's announcement of Labour's policy proposal of a price freeze on domestic energy bills. The first assessment is due in March 2014. In December 2013, the three regulators published an assessment framework setting out their proposed approach. The work is presented as a natural follow-on from earlier investigations by Ofgem into aspects of energy market competition: its "Energy Supply Probe" of 2008 and ongoing Retail Markets Review.

The Probe looked for evidence of collusion between suppliers but found none – whilst noting that some of the features of the market did not make for strong competition, including poor selling practices, a lack of information, and weak competitive constraints in terms of either a "competitive fringe" of suppliers to challenge the "Big 6" or the threat of significant consumer switching. The Retail Markets Review has since addressed – or is in the process of addressing – some of these areas. However, it remains to be seen whether the market is found to be displaying the kinds of features that the framework identifies as the indicators of a well-functioning energy market in the shorter and longer term. These include high customer engagement, good service, clear communications, pressure on supplier costs and margins, the ability for new entrants to grow in the market, tariffs responding to consumer needs, dynamic rivalry, new business models and high levels of consumer trust. It also remains to be seen how far the three authorities can get in analysing these markets in a relatively short period of time when they are subject to regulatory change and, quite possibly, without recourse to any of their powers to require the provision of sensitive commercial information.

Labour: Energy policy proposal

Regulatory uncertainty has been identified as the primary cause of an "investment hiatus" in the UK power markets. Whilst many of the reform measures discussed above should conclude (or substantially conclude) in 2014, a further package of energy market reform could be on the horizon in 2015, depending on the outcome of the 2015 General Election.

As noted above, the Labour Party issued a Green Paper in November 2013 entitled "Powering Britain: One Nation Labour's plans to reset the energy market". This paper outlines 10 key actions that a Labour Government intends to take in relation to the energy markets. Labour has sought detailed comments and views on its proposals by 31 March 2014.

The actions proposed (some of which are already referred to above) include:

  • ring-fencing supply and generation businesses within vertically integrated companies;
  • requiring all wholesale electricity to be sold or purchased via an open exchange or pool;
  • increasing transparency in the wholesale markets through the publication of anonymised details of all uncleared OTC gas and electricity trades;
  • further simplification of energy tariffs;
  • the abolition of Ofgem and its replacement by a new regulatory body;
  • setting a 2030 power sector decarbonisation target; and
  • creating an Energy Security Board,

as well as implementing an energy price freeze from the date of the General Election until January 2017.

These proposals would impact on virtually all of the currently contemplated reforms within the physical and financial energy markets (from EMR, through Ofgem's liquidity review and Retail Market Review to REMIT, EMIR and MiFID II), potentially extending regulatory uncertainty in the UK energy markets to 2015 and beyond – as well as providing an early opportunity to test the notably detailed provisions on "change in law" in the EMR CfD contracts.

Following future developments

Almost all the initiatives covered in this note are "work in progress", and 2014 will no doubt see the introduction of further new regulatory proposals as well. For information and commentary on the UK energy regulatory scene as it develops, subscribe to our new blog at www.TargetUKEnergy.com.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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