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Big data in the energy sector: GDPR reminder for energy companies

On 18 September, Dentons hosted an Energy Institute event in our London office with the title “The Clash of Digitalisations”. Speakers from Upside Energy, Powervault and Mixergy spoke about the Pete Project, an initiative funded by Innovate UK, that is exploring the potential of domestic hot water tanks and batteries to provide flexibility services to National Grid.  Fascinating as the technological and energy-regulatory aspects of this kind of household demand-side response aggregation services are, a key common theme of the evening was the central role played in them by the analysis of large amounts of “personal data”, and whether recent changes in privacy legislation help or hinder the development of such services.  We produced this short article to put that discussion in context.

The General Data Protection Regulation (GDPR) came into force across the European Union (EU) on 25 May 2018 and is intended to overhaul the way that companies collect and use personal data. GDPR puts the onus on companies to ensure that they have a lawful basis to collect and process personal data. It also requires mechanisms to allow data subjects to exercise the new rights available to them under GDPR.

Breach reporting requirements have been strengthened with a requirement to report most breaches to the relevant supervisory authority within 72 hours. Supervisory authorities have increased enforcement powers including the ability to impose fines of 20 million Euros or 4% of total worldwide annual turnover.

Compliance with the requirements of GDPR presents a particular challenge within the energy sector. One high profile example is in connection with the use of smart meters and smart grids. Smart grids when combined with smart metering systems automatically monitor energy usage, adjust to changes in energy supply and provide real-time information on consumer energy consumption. The EU aims to have 80% of electricity meters converted to smart meters by 2020. As such, the volume of personal data collected in the energy sector is set to increase.

What is Big Data?

Big data has been defined in various ways including by reference to the “three V’s”. This refers to volume being the size of the dataset, velocity being the real-time nature of the data and variety referring to the different sources of the data.

However, this definition does not accurately describe all big data. An alternative is to define big data as an extremely large data set that cannot be analysed using traditional methods. Instead such big data is analysed using alternative methods (such as machine learning) in order to reveal trends, patterns, interactions and other information that can be used to inform decision-making and business strategy.

The key to big data is the analysis and resulting output. Big data analytics can be achieved using machine learning where computers are taught to “think” by creating mathematical algorithms based on accumulated data. Machine learning falls broadly into two categories, supervised and unsupervised. Supervised learning involves a training phase to develop algorithms by mapping specific datasets to pre-determined outputs. Alternatively machine learning can be unsupervised where algorithms are created by the machine to find patterns within the input data without being instructed what to look for specifically.

Big data is a particular issue following the Facebook / Cambridge Analytica story and the public concern about mass data capture and exploitation.

Below, we consider the 7 key issues surrounding big data from a data protection perspective within the energy sector.

Key issues

1. Fairness and transparency

One of the principles of GDPR is that personal data must be processed in a fair and transparent manner.

In practice this means that companies processing personal data must provide a privacy notice to individuals that sets out how and why personal data is being processed. This raises a practical issue in connection with big data analytics because often the purposes of processing are not always known at the outset.

In addition, machine learning algorithms are often conducted in what is known as a “black box”. This means that the algorithm itself is unknown to the data controller and cannot be interrogated to determine how the output was selected or decision made. This likely means that the privacy notice may not be GDPR compliant.

2. Lawful basis for processing

The processing of personal data must have a lawful basis at the outset. There are a number of legal bases available (listed out in A6 and A9 GDPR).

Consent is unlikely to be an option when big data analytics are involved. The analysis of big data sets is often conducted to discover trends within that data set and if those trends were known prior to the analysis, the analysis would not need to be conducted. Machine learning algorithms are often impossible for humans to understand as they cannot be translated into an intelligible form without losing their meaning.  Consent must be freely given, specific, informed and unambiguous to be valid under GDPR. If the information regarding how personal data is processed cannot be understood then this cannot be translated into a meaningful consent.

In addition, under GDPR, data subjects have the right to withdraw consent and have a company cease processing their personal data. This would be difficult, if not impossible, in a big data context if the machine-learning algorithm is opaque and there is no ability to segregate personal data relating to a specific individual. As such, consent is highly unlikely to be a viable lawful basis for processing big data.

A potential alternative would be reliance on “legitimate interests”. This is available where processing of personal data is necessary for the pursuance of the legitimate interests of the company determining how and why the personal data is held and processed. The legitimate interests of the company need to be balanced against the interests, rights and freedoms of the individual (with particular care taken where data relates to children). A legitimate interests assessment should be conducted to determine whether legitimate interests can be relied upon. This should be documented.

An issue with legitimate interests as a basis for processing big data is that processing must be “necessary” for the purpose pursued by the company. In some instances big data analytics are pursued because the output may reveal a new correlation of interest. However, processing data because it may be “interesting” is unlikely to be sufficient to qualify as a legitimate interest that needs to be pursued by the controller.

3. Purpose limitation

GDPR requires that personal data be collected for specified, explicit and legitimate purposes and not further processed in an incompatible manner.

Big data analytics by their very nature often result in processing of data for new and novel purposes. These may be incompatible with the original purpose for which the data was collected. The issue then arises as to how and when privacy notices should be refreshed and brought to the attention of individuals.

Where material changes are made to a privacy notice or the reasons and methods by which personal data are processed these need to be actively brought to the attention of the data subject in advance of the processing. If the novel purposes or outcome is not known prior to analysis of the personal data then there is no logical way for a privacy notice to be refreshed or brought to the attention of an individual.

In addition, the personal data may have been obtained in bulk from a third party. This poses an additional challenge as it may be difficult or difficult to contact those individuals to whom the personal data relates.

4. Data minimisation

Big data analytics involves the collection and use of extremely large quantities of information. This is potentially problematic from a data minimisation perspective because GDPR requires that personal data held and processed should be limited to the minimum required for the purposes for which they were collected.

However, there are solutions to this issue. Personal data could be anonymised such that individuals are no longer identifiable from the information. A benefit of big data analytics is that it is often not dependent on the identification of specific individuals but rather of overall trends within the data population. Once personal data is anonymised it is no longer “personal data” for the purposes of GDPR and could be used and analysed as needed without the requirement for further refreshed privacy notices or legitimate interest assessments in relation to such processing. However data subjects should be told how their data may be used including that it may be anonymised and the purposes of subsequent usage.

5. Individual rights

There are practical issues around how data subjects can exercise their rights under GDPR in relation to big data. Data subjects have various rights under GDPR including the right to request confirmation that their personal data is being processed, access copies of personal data held, to correct inaccuracies, the “right to be forgotten”, to restrict processing, to have personal data “ported” to another entity and the right to object to processing.

The exercise of many of these rights requires business systems and processes that enable the identification and segregation of personal data relating to a specific individual. If personal data is being processed within an opaque algorithm then segregation of that personal data (e.g. to erase it) will be difficult.

Given the quantities of personal data held in the context of big data any exercise of individual privacy rights is likely to be a time consuming exercise and potentially a costly administrative burden.

There are also specific rules on automated decisions which are made concerning an individual that may have a legal (for example a mortgage rejection or acceptance) or other similarly significant effect. In practice this would involve explicitly referencing the automated decision-making within a privacy or other notice and gaining the explicit consent of the data subject (unless it is necessary for performance of a contract or otherwise authorised by EU or Member State law). As discussed above, consent is a tricky concept in connection with big data analytics and gaining a meaningful consent to the proposed automated decision making would be difficult.

Depending on the nature of the automated decision-making and its effect on the individual, one argument may be that the decision does not have a legal or similarly significant effect on the data subject. This would need to be carefully considered in the context of the automated decision-making and the effect on the individual.

6. Accuracy

GDPR requires that personal data held be accurate and that every reasonable step must be taken to ensure that personal data is accurate (and suitably erased or rectified to remove inaccuracies).

Whilst a level of inaccuracy may have minimal impact where large data sets are analysed to reveal general trends, there will be a significant impact when processing is used to analyse a specific individual.

An additional issue is that drawing conclusions or correlations from large data sets, even if the data itself is accurate, may still lead to inaccurate conclusions. This is a particular problem where the input data is not representative of the entire population.

The machine-learning algorithm may include hidden biases that will lead to inaccurate predictions. Consider Ethics Committee input and user testing to mitigate this risk.

Although there is no quick fix to rectify inaccuracies in data sets, the above highlights the importance of ensuring personal data and other information are both accurate and representative of the population sampled to ensure that the outputs and conclusions drawn from big data analytics are accurate.

7. Security

Security and the risk of hacking and data breaches are inherent to any business that is processing personal data. This risk is only increased where the personal data held consists of extremely large quantities of personal data. Any high profile organisation that holds large quantities of personal data will be a bigger target for hackers and also at higher risk of human error within the business resulting in the inadvertent loss of personal data.

It is therefore essential that companies within the energy sector review security measures and procedures to minimise the ability of hackers to breach systems and any resulting impact of a data breach. This will inevitably involve a combination of upgrades to security systems and regular training to ensure staff know how to hold and transmit personal data and what to do in the event of a breach.

Conclusion

The energy sector faces significant challenges if it wants to both utilise and benefit from large data sets available to it, comply with GDPR and protect the rights of individuals.

However, despite the challenges, the benefits of big data analytics for both the company and the individual in the energy sector mean that solutions to these issues must be considered in order to facilitate the growth of domestic demand-side response services, to manage energy consumption more efficiently and respond to changes in local usage and give individuals greater visibility and control over their individual energy consumption. A balance needs to be found between the needs of the sector and privacy of individuals, and a proper GDPR analysis can help you achieve that.

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Big data in the energy sector: GDPR reminder for energy companies

Low carbon heat: if not now, when (and how)?

Decarbonising the UK’s heat supply is a massive challenge, but like other aspects of the energy transition, it also presents significant opportunities for investors, developers, consumers and others. On 3 July 2018, an Energy Breakfast event at Dentons’ London office explored the subject of investing in low carbon heat.  The speakers were Richard Taylor of E4Tech, co-authors of a recent study on future heat infrastructure costs for the National Infrastructure Commission (NIC), Stuart Allison of Vattenfall’s newly established UK heat business, Jenny Curtis of Amber Infrastructure and Nick Allen of the Department for Business, Energy and Industrial Strategy (BEIS).  We summarise here some of the key issues from their presentations and the lively discussion that followed, as well as one or two related subsequent developments.

Why decarbonising heat is important – and difficult

It may seem perverse to try to debate policy on any form of artificial heating at a time when much of the UK has been enjoying near-record high temperatures for what feels like several weeks, but it was only a few months ago that the country saw an almost equally notably cold start to spring. The heat sector, at present mostly fuelled by burning natural gas, accounts for about one-third of UK greenhouse gas emissions.  The sector’s emissions will have to be largely, if not completely, eliminated by 2050 if the UK is to meet the emissions reduction targets set under the Climate Change Act 2008 – let alone the more demanding targets that may flow from the 2015 UNFCCC Paris Agreement objective of keeping increases in average global temperatures well below 2oC.

One way of decarbonising heat would be to substitute hydrogen for methane as a fuel. It is possible to mix some hydrogen (or biomethane) with natural gas and still use existing pipeline networks and appliances.  But full decarbonisation by this route would require significant investment at both the wholesale and end user levels (replacement of metal with plastic pipes, new boilers).  And that is just the start.  The hydrogen has to be produced on a large scale – probably using methane as a feedstock, which would produce a stream of CO2 that would need to be captured and either stored or used in a way that avoids its being released into the atmosphere: in other words, more investment in substantial infrastructure, and the commercialisation of technologies (such as CCS) which have so far been slow to develop, even though they would appear to be an important part of the future of the oil and gas industry.  Significant changes to existing downstream gas regulation are also be required, to accommodate both blending of hydrogen with methane and full conversion.  And all this assumes that popular misconceptions about the safety of hydrogen do not prevent its widespread deployment.

Alternatively, decarbonisation of heat could be achieved by switching from boilers to a system built around heat pumps and storage, and running the heat pumps on decarbonised electricity. This would require significant action at the wholesale level (e.g. additional generating and network capacity) and a radical change in infrastructure at the end user level (e.g. each household either acquires a heat pump of its own or becomes part of a district heat network attached to a much larger heat pump).

Between the scenarios focused primarily on hydrogen or electrification, there are some hybrid options, and it is arguable that the replacement of existing natural gas-based heating could efficiently take different forms in different parts of the country (for example, those areas not connected to the existing gas grid are likely to be more cost-effectively served by heat pumps than by hydrogen). But it is clear that unlike in the case of electricity generation, where the Government has been able to adopt a broad policy of encouraging a range of low carbon technologies and regulating the pipeline of new capacity by adjusting the level of subsidy and the ease or difficulty of obtaining planning permission for each of them, in relation to heat it is likely to have to make some fundamental, long-term choices at the outset between the competing pathways to decarbonisation.  Put at its starkest, in the next 30 years, existing gas pipeline networks are likely to have either to decarbonise or cease to operate.

All of this points to the conclusion that decarbonising heat will be harder than decarbonising the generation of electricity.  At the wholesale or system level, it will be very hard for Government to avoid making major strategic choices between competing heat technology options, rather than just letting the technology mix evolve within a managed framework.  End users will have to take (or be coerced into taking) a much more active role in the heat decarbonising process than the vast majority of them have had to play in decarbonising electricity.  Finally, as further explained below, the interaction of decarbonising heat with adjacent areas of activity is likely to be harder to predict and manage.

Expert assessments

In one sense, none of this is news. In the ten years since the Climate Change Act, the independent Committee on Climate Change (CCC) have repeatedly highlighted the challenges of the heat sector in their reports.  In their latest progress report to Parliament, published on 28 June 2018, the CCC invite the Government to “apply the lessons of the past decade or risk a poor deal for the public in the next”.  Examples from the heat sector feature in support of each of the four key messages that the report delivers: support the simple, low-cost options; commit to effective regulation and strict enforcement; end the chopping and changing of policy; and act now to keep long-term options open.

The CCC note that progress on decarbonisation to date has been heavily focused on electricity generation. Heat and other sectors will need to catch up if the fourth and fifth carbon budgets (set under the Climate Change Act for the years 2023-2027 and 2028-2032 as staging posts on the way to the final 2050 target of 80% emissions reduction against 1990 levels) are to be met.

The CCC identify a number of specific actions required of Government to be on track to meet the fourth and fifth carbon budgets.  In the shorter term, they highlight the need for further action to deliver cost-effective uptake of low-carbon heat, including low-carbon heat networks in heat-dense areas (e.g. cities) and increased injection of biomethane into the gas grid.

The long-term choice between heat decarbonisation technologies and the desirability of low-regrets measures such as energy efficiency measures and low carbon heat networks in areas of dense heat demand are reviewed in an Imperial College report for the CCC (the executive summary of which was published alongside the CCC’s 28 June 2018 report as well as in E4Tech / Element Energy’s report for the NIC.  Both cite the CCC’s 2016 visual representation of these measures and choices.  Element Energy / E4Tech’s version of this is reproduced below.

In his presentation of the E4Tech / Element Energy conclusions, Richard Taylor stressed that although the hydrogen scenarios appeared to be slightly cheaper, significant uncertainties remained around the level of additional costs associated with each of the long-term options, shown below in comparison with the “no change” option of maintaining a natural-gas based heating sector.

Both reports have a wealth of more detailed analysis.  For example, this chart from the Imperial College report highlights the potential implications for the optimal levels of installed capacity in the electricity generation sector of different heat technology / intensity of emissions reduction scenarios (the figures 30, 10 and 0 underneath each bar refer to target CO2 emissions in Mt).  Unsurprisingly, significantly more capacity is required in the electricity based scenarios, but it is also interesting, for example, how much the nuclear element in the mix varies between options, and that even the electricity based scenarios include a substantial hydrogen component in the form of open and combined cycle gas turbine plant using hydrogen rather than natural gas as a fuel.

All of this, and related issues such as the role of “flexibility” technologies (some of which, like thermal storage of energy, have implications for both the heating and power production technology mix and the way that heat and power networks are developed) highlights the interdependency of infrastructure investment choices across different parts of the energy sector.  The CCC are clear on what this means. They observe: “If emissions from heating are to be largely eliminated by 2050, a national programme to switch buildings on the gas grid to low-carbon heating would need to begin by around 2030 at the latest, requiring Government decisions on the route forward to be made by the mid-2020s.” (emphasis added).  At the same time, they highlight one of the obvious points that threatens the taking of that decision in the timeframe that they recommend, noting that “There will be important questions to be resolved around how to pay for heat decarbonisation.

Heat networks: how low is the low-hanging fruit hanging?

Why is the development of heat networks identified as a “low regrets” option for the shorter-term, more or less regardless of what choices the Government may make about heat in the longer term? A heat network is a system comprising a heat production unit and a network of pipes and heat exchangers through which the heat that it produces is distributed, in the form of steam or hot water, to the heating and hot water appliances in a number of different customers’ premises (rather than each customer’s system of such appliances having its own heat production unit).

The concept of a heat network is technology-neutral. The heat production unit could, for example be a boiler (fuelled by methane, woodchips or hydrogen) or a heat-pump (sourcing its heat from the air, the ground, or a body of water such as a river or lake, or the water that collects in old mine workings).  Broadly speaking, whatever technology you use to produce heat, in areas where the demand for heat is sufficiently dense, it is likely to be more efficient (and – where the technology involves combustion –to result in lower carbon emissions) if the heat is generated in bulk and distributed to individual buildings or households around a local network (as steam or hot water) rather than each building or household having its own heat production equipment (e.g. boiler or heat pump).

Heat networks are obviously easiest to install when a building is first constructed, although retrofitting may also be cost effective in some cases.  If care is taken in designing a heat network, it may well also be possible to switch between heat production technologies at a lower overall cost at a network level than it would be for an individual building or household to do so (for example, by replacing a single large gas-fired unit with a single large heat pump or a hydrogen-fired unit, rather than replacing the heat production equipment in each individual customer’s premises). Moreover, consumer research commissioned by BEIS shows that those served by heat networks are overall as satisfied with their heating as those who are not.

Heat networks, then, have much to commend them.  There is considerable investor interest in heat networks.  BEIS has even published a list of 10 infrastructure investors who are actively interested in investing in them.  Planning policy both at central and local government level has for many years encouraged the installation of heat networks in new residential and commercial developments and the seeking out by those building new thermal electricity generating plant of potential network uses for their waste heat.  And yet, at present, only 2% of UK demand is connected to a heat network, although as much as 20% of demand may be sufficiently densely located to benefit from a heat network solution.  An increase in heat network capacity features in all three clean growth pathways in the BEIS Clean Growth Strategy.  But connecting 20% of demand to a heat network by 2050 would imply an annual growth rate of 8-10%.  Will this be feasible?

The short answer is: feasible, yes – but not easy, for a number of reasons.

  • Complexity:  It is easier for a developer to arrange a gas supply to a group of new premises and fit each of them with its own natural gas-fired boiler than to establish a heat network to serve them.  Opting for a network solution immediately raises a series of questions and requires a much wider range of issues to be taken into account.  Who will design, build, own and operate the network?  Whoever does each of these things, more contracts will need to be negotiated than for a non-network solution, where all that is needed is a gas connection and a contract to supply / fit some boilers.  In many new developments, there are a lot of different stakeholder interests to balance (the developer, others with responsibility for the network, different landlord and tenant interests, local authorities and so on).  If the same organisation does not have responsibility for all aspects of the network, agreement will have to be reached on a whole series of risk allocations.  One common solution is for a developer to install a network but then to seek to recover some of the expense of doing so by selling it (or the right to operate it) to an energy services company (ESCO), but the building of a network by a party that will not operate it in the long-term can result in poor quality installation.
  • Lack of standardisation: Heat network projects can therefore quickly develop lengthy risk registers, but there is no universal approach to or methodology for allocating those risks, and, as a result, not as much standardisation of contractual provision – on terms that strike a fair balance between competing stakeholder interests – as is desirable to keep costs under control in a sector where most transactions have a relatively small value.
  • Economics: The economics of what may at first appear to be promising heat network projects sometimes do not quite stack up. The relatively small size of transactions can make it hard to leverage debt in.
  • Perceived shortcomings of the technology: Notwithstanding that there appears to be no overall problem of customer satisfaction with heat networks, concerns remain about the lack of customer control (e.g. over heating, in networks where the necessary valves have not been fitted in individual premises).  As in any consumer market, one or two prominent bad reports, e.g. of poor service or over-charging, can unfairly skew stakeholders’ views of the technology as a whole.

However, none of these problems is insuperable and, as we shall see below, steps are being taken to address all of them.

Go Dutch – and regulate for growth?

Discussion about the UK’s failure – so far – to make the most of heat network opportunities often includes reference to other countries, including a number in Continental Europe, where their use is widespread and longstanding. The inference is that since we have failed to see the benefits of heat networks for so long, it will be an uphill struggle to do better now: it’s too late for us to become Denmark / Poland / [insert your European heat network exemplar country of choice].

However, Vattenfall’s experience suggests that it is possible to spread heat networks through a major European city, starting from scratch. Before 1994, Amsterdam had no significant heat network provision.  Since then, starting with the use of waste heat from a new energy from waste plant, the city has been steadily building out a heat network which is expected to help it to go “gas-free” by 2050 –  and the trend is spreading elsewhere in the Netherlands as well.

There are perhaps only three major structural differences between the UK and Netherlands markets. The first is that the supply of natural gas in the Netherlands is taxed more heavily, providing an additional economic incentive for heat networks, particularly those using non-methane energy sources.  The second is that strategic planning for the rollout of heat networks in Amsterdam is considerably facilitated by a joint venture between a Vattenfall entity and the city itself.  The third is that heat supply / networks are regulated in the same way as electricity and gas networks / supply.

In the UK, the heat networks sector is not currently subject to the same kind of regulations as comparable services such as electricity and gas, and this has raised concerns about standards of quality and consumer protection.

The Heat Network (Metering and Billing) Regulations 2014 offer some consumer protection including by imposing billing obligations and the requirement for all new heat network customers to be given a heat meter, however they do not provide for a standard of customer service or recourse to an independent complaints review process for unsatisfied customers.

The heat network industry also has its own consumer protection scheme, the Heat Trust, which sets a common standard for the quality and level of customer service, and provides for a complaints handlings system, including access to an independent complaints review by way of access to the Energy Ombudsman. However, the scheme has no statutory underpinning, membership of it is voluntary and it currently only covers a small proportion of the existing heat network customer base.

In December 2017, the Competitions and Markets Authority (CMA) announced they were launching a market study into domestic heat networks to ensure that consumers using heat networks are getting a good deal.  The study set out to examine whether consumers are aware of the costs of heat networks both before and after moving into a property; whether heat networks are natural monopolies and the impacts of offering different incentives for builders, operators and customers of heat networks; and the prices, services quality and reliability of heat networks.

  • The CMA published its initial findings on 10 May 2018.It notes that, overall, the average prices on the majority of heat networks within the sample considered were the same or lower than that of comparable gas-heating, and the overall satisfaction (and dissatisfaction) of customers was in line with that of consumers not on heat networks. Nevertheless, there were instances of poor service quality and cases where customers were paying “considerably more” than for non-network heat.
  • The CMA is concerned that the factors driving instances of poor performance or unduly high pricing should not become “embedded”, to the detriment of customers, as the sector expands.  Specifically, it looks at “misaligned incentives between property developers, heat network operators and customers of heat networks”; the monopoly nature of heat networks and the delivery models used for them; and lack of transparency on prices “both pre-transaction and during residency”.
  • It finds that regulation is needed to ensure that heat network customers receive levels of protection comparable to those afforded to customers in the gas and electricity sector.  The report recommends the introduction of a statutory framework, which would give formal powers to a sector regulator.  This conclusion echoes some of the recommendations and analysis of a 2017 report by Citizens Advice Scotland.
  • The CMA’s recommendations also go beyond the imposition of a regulatory framework for network operators to encompass possible changes to planning and building regulations, leasehold arrangements and property sales disclosures (including energy performance certificates) to take into account the specifics of heat networks. Changes to regulations in this area would give greater pre-contractual transparency to purchasers and tenants of properties to understand the implications of living in properties serviced by heat networks.

A consultation on the CMA’s initial findings closed on 31 May 2018, with a full report expected by the end of the summer. There is clearly at least a substantial body of opinion in the industry that supports the conclusion that it would benefit from sectoral regulation: a well-designed regulatory scheme, rather than unduly burdening operators, would boost consumer confidence and help the industry to expand.  Regulation could ultimately mean that operators’ returns may be capped, but the predictability that comes with well-designed and administered regulation could encourage investment.  There would likely be other benefits as well: operators in economically regulated industries are typically also given a range of statutory powers that makes it considerably easier for them to do their jobs – such as compulsory purchase powers and “statutory undertaker” rights under legislation governing planning and street works.

It seems unlikely that a sectoral regulation scheme for heat networks could be introduced without primary legislation, and there must be some doubt as to whether the Government will find the policy resource and Parliamentary time necessary to put such legislation in place in the short term.  For the moment, the CMA has decided not to launch a formal “market investigation” – a step which would open up the possibility of imposing some remedies (but probably not an overall scheme of regulation) on the sector itself for any adverse effects on competition it found.  However, the CMA has reserved the right to revisit this decision and those setting up heat network schemes may do well to take account of the conclusions of the current market study in any event.

More immediate Government support

Attention to the CMA’s work and its possible inconclusive outcome in the short term should not distract from the valuable work that BEIS has been undertaking to remove or reduce some of the other key barriers to expansion of the sector.

Earlier in 2018, BEIS provided details of a scheme to provide “gap funding” for heat network projects. The Heat Networks Investment Project (HNIP) is the vehicle for disbursing £320 million of Government money that was first earmarked for this use some time ago, building on the results of an earlier pilot scheme, and leveraging in about “£1 billion of private and other investment”.

Following the appointment of a delivery partner, the scheme will formally launch in the autumn. Funding may take the form of grants, corporate loans or project loans.  A number of criteria (both economic and technical / environmental) have been established for applicants to satisfy, perhaps the most important of which are those relating to “additionality”, designed to demonstrate that the applicant’s project would not go ahead without HNIP support – either because it could not otherwise raise the capital or achieve an adequate IRR, or because it would not otherwise be possible to fund additional technical or commercial features that are not required through planning obligations.

On the same day as our Energy Breakfast took place, BEIS published over 750 pages of useful guidance for those contemplating heat network schemes, comprising:

The intention is that HNIP funding will create a pipeline of investable projects that will help the sector to become self-sustaining by 2021. As ever, success will lie in the quality of the implementation, but HNIP is a well-designed scheme that addresses many of the key issues facing heat network projects.

Two other initiatives, not focused on heat networks, but also aimed at reducing barriers to lower carbon heat investments in the near term, are also worth mentioning.

  • On 5 July 2018, BEIS published a response to consultation the confirmed the Government’s intention to help to introduce a support scheme to “overcome key barriers, and increase industry confidence to identify and invest in opportunities for recovering heat from industrial processes” (the Industrial Heat Recovery Support Programme).
  • As part of a series of reforms to the Renewable Heat Incentive (RHI) subsidy regime for domestic premises, BEIS has brought into force changes to the rules on third party funding for heat pumps and other renewable heating systems. From 27 June 2018, under a procedure known as “assignment of rights”, the owners of such systems may assign the RHI subsidy payments to which they are entitled to a “nominated registered investor”.  A model form of contract will be provided for doing so.  It remains to be seen whether this will have the desired effect of encouraging more third party finance of heat pump installation and therefore materially greater uptake of heat pumps as a technology.

A long-term, holistic approach

At a time when it is easy to criticise Government for an apparent lack of action on some aspects of energy policy, this series of concrete steps taken towards encouraging investment in low carbon heat is a positive development in an area where action is much needed and has been long awaited.  Of course, much also remains to be done.  For example, the CCC point out that:

  • there is no financial support framework for heat pumps and biomethane in place yet for the period after 2021 (when the current funding for the RHI comes to an end – the RHI as currently constituted being dependent on direct Government grants rather than a more or less automatic system of funding from a levy on energy suppliers like the historic renewable electricity generation subsidy schemes, the Renewables Obligation and Feed-inTariffs);
  • international comparisons suggest that the use-based payments for renewable heat systems such as the RHI might not be the ideal way of encouraging uptake and that a system of capital payments may be preferable;
  • whilst the Government’s acknowledgment of the need to look at the long-term technology options for moving towards a much lower carbon heat sector and to make some choices between them is welcome, there needs to be a more formal governance framework to drive enduring decisions on heat infrastructure in the early 2020s.

In short, Government has made a good start, but must follow through.  Moreover, in looking at the next steps for heat policy, Government and others need to take a holistic approach.

  • We noted earlier the apparent importance of hydrogen in all three long-term heat decarbonisation pathways. Work carried out by Alstom also indicates the potential for hydrogen (which is much more energy dense than any battery) to be used in fuel cells to replace diesel as the fuel for trains on lines that have not been electrified and that it may never make sense to electrify.  Is there not a case for incentivising the large-scale production of hydrogen (and CCS for the associated CO2 by-product) – perhaps through a contract for difference where the strike price is benchmarked against wholesale natural gas prices?
  • Government is not just responsible for energy and transport policy. It has other, currently under-used levers at its disposal to encourage technologies that will decarbonise heat.  The embedding in building standards of tougher rules on energy efficiency and an absolute requirement for low carbon heat supply to be part of all new buildings (and the rigorous enforcement of such standards), are obvious – but as yet untaken – steps that would increase demand for low carbon heating technology.  There is of course an important interaction between energy efficiency improvements and heat networks, particularly in retrofitting situations where significant reductions in heat demand driven by improved building energy efficiency could undermine the business case for a marginal heat network project.
  • With as with other areas of energy policy, sharper incentives from carbon pricing would speed up decarbonisation. In the heat sector, ways of preventing any higher taxation of gas from increasing the burdens on vulnerable customers would have to be part of the package.
  • Finally, any long-term decision-making by Government or the private sector will also have to consider the need to accommodate, and perhaps encourage, the introduction of new business models, and the possibility that the market of the future may, and perhaps should, be less uniform than it is at present.  Now, most consumers buy kWh (or cylinders) of gas (or in some cases, heat) and kWh of electricity (with a few of them generating a proportion of their electricity demand).  Energy efficiency is largely a separate market, with the occasional imposition on gas and electricity suppliers of obligations to undertake a certain amount of more or less targeted energy efficiency improvement works for consumers.  In the future, consumers might specify a set of outputs (e.g. availability of up to X amount of electricity, maintenance of indoor temperatures within a certain range) and sets of constraints or variables (e.g. payment profiles, willingness to allow the installation of particular equipment or energy efficiency measures, or to accept occasional deviations from the prescribed temperature range) and invite a range of suppliers to offer them a monthly price for home energy-related services for a certain period of time.  These services could include anything from utility supplies of energy to the installation of new energy production equipment or energy efficiency measures.  In a market where it will become ever easier for consumers to become “prosumers”, generating, storing and using their own electricity, companies that currently simply retail electricity and gas to consumers on a £/kWh basis may need to diversify their offering and learn a number of new skills if they are to maintain their relevance play a full part in the energy transition of the heat sector.

If you would like to explore any of the issues raised in this post further with us, please get in touch.

The assistance of Jennifer Cranston, a trainee in our London office, in the preparation of this post, is gratefully acknowledged.

Low carbon heat: if not now, when (and how)?

Talking points in the solar market

A Dentons team from the UK, Germany, the Netherlands and Turkey had a good day at Intersolar Europe towards the end of June, which is a great conference for meeting old friends and making new connections.

For those who didn’t make the trip to Munich, here are a few thoughts on the key talking points.

  • Solar PV is clearly a very healthy industry – there were over 850 exhibitors, spread over 6 exhibition halls. The panel manufacturers were particularly impressive, with Canadian Solar, SMA and others having large stands.

 

  • Key new target markets in Europe include Ireland (with a subsidy policy decision expected to be announced imminently); Spain (driven by merchant sales and PPAs, rather then Government tenders); and France (where the industry is increasingly being seen as a Government priority with its #PlaceAuSoleil plan).

 

  • Competition remains fierce, with Q-Cells (Hanwha) announcing its new half-cell technology (winning the conference award for innovation), and a number of suppliers (e.g. Jinko and First Solar) marketing panels with increased efficiency.

 

  • Storage attracts attention, but is still not part of the mainstream – the focus was much more towards smart vehicle charging (with the conference running alongside the Smarter-E convention), than having batteries within the home itself (or indeed on a commercial scale).

 

  • There is continued uncertainty regarding the future of solar panel anti-dumping – the current EU measures expire in September, though there is the possibility of a further review (extending existing minimum import prices for at least a year). The EU restrictions also have potential to be part of a global trend, with the US currently reviewing its position on solar cells and modules with the possibility of a 25% tariff.

 

  • There is quite a bit of concern about the recent sudden withdrawal of Chinese subsidies. Given the huge growth in new domestic projects in recent years this perhaps points towards greater exports and falling prices (together with the possibility of a limited number of panel supplier insolvencies). There may be some local government subsidies available, though many projects will be put on hold.

We have been seeing a number of these issues first-hand on our current projects. Do get in touch if you would like to discuss any of them.

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Talking points in the solar market

Bankability issues with Solar PV leases in emerging markets

In any solar PV development in emerging markets (whether in Africa, Latin America or elsewhere) attention is immediately drawn to project revenues. Government or utility tender packages focus on mark-ups to power purchase agreements with the offtaker, the strength of any government support agreement, and the terms of any other credit support. It is not uncommon for a project to be well advanced before the developer turns to the “less exciting” project agreements, with land rights frequently one of the most problematic. The site may be split over dozens of parcels of land (many of which are either stuck in probate or not properly registered), the model form of lease may be unintelligible, or the land sporadically crossed by grazing animals.

Most project stakeholders are either invested and actively interested in the success of the project (e.g. the offtaker), or experienced and sophisticated counterparties (e.g. EPC contractors) – the lessor(s) of land rights may be less equipped to quickly agree the required documents.

Recently we have been working on a number of solar PV projects across Africa in jurisdictions with a limited track record of international project finance. Key areas in which we often find that a landowner’s model form of lease does not provide sufficient protection for the project are listed below. Although we have used terminology that will be familiar to lawyers used to common law systems, the same issues arise – and should ultimately be capable of being resolved – in any legal system.

Term 

The term of the lease should be sufficient to cover the asset life of the project, the term of key approvals (e.g. the generation licence, planning permission) and any decommissioning period (whether after an early termination or expiry of the term).  If asset life is extended then ideally the lessee will also have the option to extend the term of the lease.

Pre-conditions/early obligations 

The lease rental payments are ideally structured in such a manner that they are not payable until all government authorisations and permits and third party consents required for the development and operation of the project have been obtained. If early works are required (e.g. an environmental impact assessment) in order to be granted the necessary permits then the lease will need to cater for this or such works will need to be authorised under a separate lease, lease option or licence.

Easements  

If the route of the cable connecting the project to the grid is not included in the site and the Lessor has rights over the relevant land, the Lessor should grant the Lessee and any third party nominated by it easements over the land as required for the connection of the solar PV plant to the relevant electricity transmission lines. Similar rights may also be needed to allow a route from the site to the public highway for construction and maintenance. For these purposes it is critical to confirm that all local land which may be required for an easement is in the control of the Lessor.

Permitted Use  

The Lessee should be allowed to carry out activities related to, in connection with, or for the purpose of, the design (including site appraisal), construction, operation (including export of power), maintenance and decommissioning (and handover, if applicable) of the solar PV plant.

The site subject to the lease should also be sufficient for project use, i.e. it should cover the solar PV panels, ancillary equipment (including e.g. inverters, CCTV and substations).

Lessor’s covenant  

The Lessor should not do or permit to be done any act which has or may have the effect of reducing or interfering with the capability of the power station to generate its maximum potential of electricity. This may extend to limiting rights to cross the site, including prohibiting the grazing of livestock (to the extent not needed by the Lessee to avoid grass cutting), and providing assurances that neighboring land will not shadow the site (e.g. with new buildings or trees).

To the extent that the Lessor is a government agency it may also be reasonable for it to provide assurances that third parties (e.g. local farmers) will not attempt to access the site, possibly alongside local content and/or community benefit provision to ensure local support.

Pre-existing liabilities 

The Lessor should be liable for, and should indemnify the Lessee against, any pre-existing liabilities associated with the site (e.g. environment liabilities). Where possible the Lessor may also need to do its own property searches and title checks (e.g. to check there is no compulsory purchase order affecting the site).

Termination 

Ideally the Lessor shall either have no right to terminate the lease, or its termination rights should be restricted to failure to pay rents (if not cured within a reasonable period upon notice) – remedies for other breaches by the Lessee should be compensation rather than termination.

Direct Agreement

The Lessor will need to covenant that it will at the request and reasonable cost of the Lessee enter into a direct agreement with any lender providing financing for the project such that the lender has a right to step in and novate before the Lessor exercises its rights under the lease, including any right to terminate the lease (if any) or re-enter the site.

The authors are grateful to Gillian Goldsworthy, Senior Associate in the Real Estate team of Dentons’ London office, for her assistance with this piece

 

 

 

 

 

 

 

 

Bankability issues with Solar PV leases in emerging markets

Ofgem on storage as generation (On the way to a smart, flexible energy system? Part 2)

On 29 September 2017, Ofgem published two storage-related consultations on possible modifications to the standard licence conditions of electricity generation and distribution licences.

Ofgem and the Department for Business, Energy and Industrial Strategy (BEIS) are minded to classify storage as a sub-set of the regulatory category of generation.  Clarifying the regulatory framework for electricity storage: licensing elaborates on this proposition and comes with a full set of generation standard licence conditions marked up to show the resulting changes.

Consistent with this approach, Ofgem takes the view that distribution network operators (DNOs) should not operate storage facilities – just as (with only minor exceptions) they are not permitted to operate generating stations.  Enabling the competitive development of storage in a flexible energy system: changes to the electricity distribution licence provides some more detail in this area and includes a draft standard licence condition 43B to keep generation and storage generally separate.

Take generation first. To begin with, Ofgem gives us a definition of storage: “the conversion of electrical energy into a form of energy, which can be stored, the storing of that energy, and the subsequent reconversion of that energy back into electrical energy”.  This comes with a list of technologies that Ofgem thinks the definition covers, which seems fairly comprehensive.  The definitions of “generating station”, “generation business” and “generation set”, would all be revised to include reference to storage.

A huge number of generating stations that are connected to DNO networks in GB operate without holding a generation licence. Clearly it would not be practicable for every household with a few solar panels on its roof to be required to hold a generating licence, but plenty of commercial generation operators also benefit from the statutory licence exemption regime.  Exemption from the obligation to hold a generation licence is more or less automatic up to 50 MW and is frequently granted by BEIS up to 100 MW.  It is generally thought that a licence-exempt generator stands to gain more than it loses by not holding a licence.  Licensees must shoulder a greater regulatory burden, complying with a range of industry codes such as the Balancing and Settlement Code.  This potentially gives them a voice in industry self-governance, but few small generators have the resources to make much of that opportunity, and many prefer simply to avoid the associated costs of code compliance.  Among the other, relatively limited perks of licensed status is the ability to use compulsory purchase powers against recalcitrant landowners in order to develop infrastructure.

It is conceivable that some storage providers may find those compulsory purchase powers useful. Of perhaps more general interest is the prospect that as a licensed storage operator, you would not be subject to “final consumption levies” (FCLs) – the charges that are imposed on suppliers (and therefore in most cases passed through to their customers) to fund the Renewables Obligation, Feed-in Tariffs, Contracts for Difference and Capacity Market payments to generators / capacity providers.  That could persuade some who would not otherwise have to apply for a new storage-friendly generation licence to do so: the rationale is that those who are only operating an intermediate stage in the value chain between generation and final consumption should not be liable for FCLs just because their interaction with the wholesale electricity markets comes through a licensed supplier.

But this is where it starts to get tricky. Storage technology, particularly some kinds of batteries, are becoming significantly cheaper.  Ofgem does not want every large industrial user, for example, to go out and buy a battery as a way of avoiding FCLs.  So a new Condition E1 is proposed: “The licensee shall not have self-consumption as the primary function when operating its storage facility.”  But as Ofgem notes, the notion of a facility’s “primary function” could be defined in many ways.

More generally, it is unfortunate that BEIS and Parliament do not currently have time to regularise matters fully by incorporating the new generation and storage definitions into the relevant legislation, but on balance, Ofgem’s approach of starting with the licence provisions seems a legitimate and pragmatic first step given the importance of clarifying this area.

Turning to the DNOs. According to Ofgem, the existing rules “are clear that the DNOs cannot directly own or operate large-scale storage over 100MW. However, because generation below this threshold does not require a generation licence, there is a grey area where DNOs can own smaller scale storage”.  The underlying rationale of Ofgem’s approach is that since they “control the infrastructure needed to trade energy and flexibility services”, DNOs “have the ability to restrict the activities of market participants by denying (or otherwise impeding) their network access”.  DNOs should therefore not operate storage facilities, as they may be tempted to use their position to gain an unfair advantage over competing storage providers.

This extends the conventional thinking that DNOs should not operate generating stations, and the principle that the monopoly and competitive parts of the electricity supply chain should be kept in separate hands – embodied in the “unbundling rules” set out in EU and UK legislation. Exceptions to the general principle are made in the case of emergency equipment such as uninterruptible power supplies.  These would continue.  It would also be possible for a company that formed part of a DNO’s corporate group to operate a storage facility subject to suitable legal separation from the DNO business and compliance with the existing unbundling rules.

Ofgem does not close the door on a third category of exception to the general rule, which would have to be individually applied for where the market is not able to provide an efficient solution, storage is the most economic and efficient solution, and conflicts of interest are minimised. Guidance is proposed to flesh out these principles.  Meanwhile, a way will be found to deal with the existing DNO owned and operated storage facilities built under Low Carbon Network innovation funding.

DNOs are particularly well placed to know where storage would be most useful in their networks. It must make sense to regulate in a way that encourages competition in providing storage, even where its primary purpose is to improve the functioning of a DNO network.  But the intensity of that competition will be determined in part by other ongoing regulatory workstreams (for a list, see the previous post in this series).

Ofgem on storage as generation (On the way to a smart, flexible energy system? Part 2)

On the way to a smart, flexible GB energy system? Part 1 (overview and storage)

Things may be starting to move a bit faster in the world of GB energy policy after what you could be forgiven for thinking was a Brexit-induced slowdown. On 24 July 2017, the UK government’s Department for Business, Energy and Industrial Strategy (BEIS) and the energy regulator Ofgem published a number of documents that reveal their evolving thinking about the future of the GB electricity system. These publications followed on from some significant initiatives by Ofgem and National Grid. This is the first of series of posts assessing where all this activity may be leading.

The full holiday reading list from 24 July was as follows.

Other recent official publications that are relevant in this context and referred to below include:

Overview

The Response and the Plan cover a broad range of subjects; many of the other documents are rather more monothematic. We will follow the topic headings in the Response, referring to the other documents where they are relevant. However, it is helpful to start by framing some of the key themes underlying this area of policy by turning to the Pöyry / Imperial Report.

The CCC has recommended that in order to achieve the ultimate objective of the Climate Change Act 2008 (reducing UK greenhouse gas emissions by 80% by 2050), the carbon intensity of the power sector should fall from 350 gCO2/kWh to about 100 gCO2/kWh by 2030.  Pöyry / Imperial observe that in any future low carbon electricity system, “we should anticipate:

  • a much higher penetration of low-carbon generation with a significant increase in variable renewable sources including wind and solar and demand growth driven by electrification of segments of heat and transport sectors;
  • growth in the capacity of distribution connected flexibility resource;
  • an increased ‘flexibility’ requirement to ensure the system can efficiently maintain secure and stable operation in a lower carbon system;
  • opportunities to deploy energy storage facilities at both transmission and distribution levels; and
  • an expansion in the provision and use of demand-side response across all sectors of the economy.

System flexibility, by which we mean the ability to adjust generation or consumption in the presence of network constraints to maintain a secure system operation for reliable service to consumers, will be the key enabler of this transformation to a cost-effective low-carbon electricity system. There are several flexibility resource options available including highly flexible thermal generation, energy storage, demand side response and cross-border interconnection to other systems.”.

This explains why technologies and mechanisms that can increase system flexibility are a dominant theme in current GB electricity sector policy-making. But Pöyry / Imperial then go on to discuss the extent of the uncertainty that, based on their modelling, they consider exists about how much the main types of flexible resource may be needed on the way to achieving the CCC’s target. This is clearly shown in the table, reproduced below, setting out their assessment of “the required range of additional capacity of different flexible technologies to efficiently meet 2030 carbon intensity targets”.

With the exception of interconnectors, the table shows the amounts of each flexible technology in the low and high scenarios, at each of the three dates, varying by a factor of 5 or more. As regards interconnectors, an illustration of the potential uncertainties in the different scenarios modelled by National Grid in FES 2017 is provided by the two FES 2017 charts below.


Source: National Grid, FES 2017


Source: National Grid, FES 2017

The need for more flexible resources is clear, and Pöyry / Imperial calculate that integrating them successfully, as compared to the use of “conventional thermal generation based sources of flexibility”, could save between £3.2 billion and £4.7 billion a year in a system meeting the CCC’s 2030 target.  But it is also clear that there are many different possible pathways that could be followed to achieve this level of flexibility, and that even if we get to 100 gCO2/kWh by 2030 – which is by no means guaranteed – there will inevitably be, at least relatively speaking, “winners” and “losers” in terms of which flexible technologies, and which individual projects, end up taking a greater or lesser share of what could be loosely called the “flexibility market”.

What will determine who wins or loses out most in this competition will be the same factors as have driven changes in the generation mix in the UK and elsewhere in recent years – in particular, the interplay of regulation and technological change.  In 2016, as compared with 2010, the UK consumed 37% less power generated from fossil fuels and more than twice as much power generated from renewable sources: see the latest Digest of UK Energy Statistics. That shift is the result of subsidies for renewable generating capacity and reductions in the cost of wind and solar plants combined with other regulatory measures that have added to the costs of conventional generators. But whereas in the initial stages of decarbonising the generating mix, the relationship between regulatory cause and market impact has been relatively straightforward, making policy to encourage flexible resources is more complex: it is like a puzzle where each piece put in place changes the shapes of the others.

This is perhaps why the actions recommended by Pöyry / Imperial as having a high priority, summarised below, all sound difficult and technical, and require a large amount of collaboration.

Pöyry / Imperial recommended high priority actions for the flexibility roadmap (emphasis added)
Action Responsible Time frame
Publish a strategy for developing the longer-term roles and responsibilities of system operators (including transitional arrangements) that incentivises system operators to access all flexibility resource by making investments and operational decisions that maximise total system benefits. Ofgem in conjunction with industry 2018
Periodical review of existing system planning and operational standards for networks and generation, assessing whether they provide a level-playing field to all technologies including active network management and non-build solutions (e.g. storage and DSR), and revise these standards as appropriate. Industry codes governance and Ofgem Initial review by 2019
Review characteristics of current procurement processes (e.g. threshold capacity level to participate, contract terms / obligations) and the procurement route (e.g. open market, auctioning or competitive tendering) that enable more efficient procurement of services without unduly restricting the provision of multiple services by flexibility providers. Ofgem in conjunction with SO, TOs and DSOs By 2020
Assess the materiality of distortions to investment decisions in the current network charging methodology (e.g. lack of locational charging, double-charging for stored electricity), and reform charging methodology where appropriate. SO, DSOs and Ofgem By 2020
Assess the materiality of distortions to investment decisions in the absence of non-network system integration charging (i.e. back up capacity and ancillary services) and implement charging where appropriate SO, DSOs and Ofgem By 2020
Publish annual projections (in each year) of longer-term future procurement requirements across all flexibility services including indication of the level of uncertainty involved and where possible location specific requirements, to provide greater visibility over future demand of flexibility services SO and DSOs 2020 onwards

Storage

We looked at the current issues facing the UK energy storage sector and recent market developments in some detail in a recent post, so we will not dwell too much on the background here.

Storage – conceptually if not yet in practice – is the nearest thing there is to a “killer app” in the world of flexible resources.  It has the potential to be an important asset class on a standalone basis, but it can also be combined with other technologies (from solar to CCGT) to add value to them by enabling their output to match better the requirements of end users and the system operator.

In GB, as in a number of other jurisdictions, there is intense interest in developing distributed storage projects based on battery technology (for the moment at least, predominantly of the lithium ion variety), and a strong focus on doing so in a way that allows projects to access multiple revenue streams. There is also a general feeling that the regulatory regime needs to do more to recognise storage as a distinct activity but at the same time to do less to discriminate against it in various ways.

So, what do the Response and the Plan tell us about the vision for storage?

  • The Response points to National Grid’s SNaPS work, “which specifically considers improving transparency and reducing the complexity of ancillary services”.
  • It also points to work that has been done and/or is ongoing to clarify how storage can be co-located with subsidised renewable electricity generating projects and to provide guidance on the process of connecting storage to the grid. BEIS / Ofgem note that they see no reason why a network operator should not “promote storage…in a connection queue if it has the objective of helping others…to connect more quickly or cheaply”, and point out that Ofgem can penalise DNOs who fail to provide evidence that they are engaging with and responding to the needs of connection stakeholders.
  • BEIS / Ofgem highlight the proposals in the TCR Consultation on reducing the burden faced by storage in terms of network charges, notably the removal of demand residual charges at transmission and distribution level, and reducing BSUoS charges, for storage. A response to that consultation is to be published “in the summer”.
  • In relation to behind the meter storage, BEIS / Ofgem observe that at present: “technology costs and the limited availability of Time of Use (ToU)/smart tariffs are greater barriers…than policy or regulatory issues”. This may invite the response from some readers that it is precisely a matter for policy and regulation to promote time of use / smart tariffs: the CEPA Report makes interesting reading in this context.
  • BEIS / Ofgem “agree with the view expressed by many respondents” that network operators should be prevented from directly owning and operating storage” whilst slightly fudging the extent to which this may already be the case as a result of existing EU-based rules on the unbundling of generation from network operation, but “noting” the current EU proposals in the November 2016 Clean Energy Package to prohibit ownership of storage by network operators except in very limited circumstances and with a derogation from the Member State.
  • Flexible connections “should be made available at both transmission and distribution level”.
  • BEIS / Ofgem agree that the lack of a legal definition or regulatory categorisation of storage is a barrier to its deployment. Legislation will be introduced to “define storage as a distinct subset of generation”. This will enable Ofgem to introduce a new licence for storage before the changes to primary legislation are made. The “subset of generation” approach will also “avoid unnecessary duplication of regulation while still allowing specific regulations to be determined for storage assets” – such as whether the threshold for requiring national rather than local planning consent should be the same for storage as for other forms of generation.
  • The prospect of storage facilities benefiting, as generation, from relief from the climate change levy is also noted – although since the principal such relief (for electricity generated from renewable sources) no longer applies, this may be of limited use to most projects.

What the Response says about storage is typical of its approach to most of the issues raised in the CFE. If one wanted to be critical, it could be said that although, on the whole, BEIS / Ofgem engage with all the points raised by stakeholders, there is rarely an immediate and decisive answer to them: there is always another workstream somewhere else that has not yet concluded that holds out the prospect of something better than they can offer at present. On the other hand, perhaps that just highlights the points implicit in the Pöyry / Imperial Report’s recommendations: no one body can by itself create all the conditions for flexibility to be delivered cost-effectively, and it will be difficult fully to judge the success of the agenda that BEIS and Ofgem are pursuing for another two or three years.

But wait a minute.  On the same day as it issued the Response and the Plan, BEIS also published the CM Consultation. The sections of the Response on storage say nothing about this document, but it is potentially the most significant regulatory development in relation to storage for some time.

  • The Capacity Market is meant to be “technology neutral”. Above a 2 MW threshold, any provider of capacity (on the generation or demand side) that is not in receipt of renewable or CCC subsidies can bid for a capacity agreement in a Capacity Auction that is held one year or four years ahead of when (if successful) they may be called on to provide capacity when National Grid declares a System Stress Event.
  • A key part of the calculations of any prospective bidder in the Capacity Market, particularly one considering a new build project, who is hoping that payments under a capacity agreement will partly fund its development expenses, is the de-rating factor that National Grid applies – the amount by which each MW of each bidding unit’s nameplate capacity is discounted when comparing the amount of capacity left in the auction at the end of each round against the total amount of capacity to be procured, represented by the demand curve. Some of the de-rating factors applied in the 2016 T-4 Auction are set out below.
Technology class Description De-rating Factor
Storage Conversion of imported electricity into a form of energy which can be stored, the storing of the energy which has been so converted and the re-conversion of the stored energy into electrical energy. Includes pumped storage hydro stations. 96.29%
OCGT / recip Gas turbines running in open cycle fired mode.
Reciprocating engines not used for autogeneration.
94.17%
CCGT Combined Cycle Gas Turbine plants 90.00%
DSR Demand side response 86.88%
Hydro Generating Units driven by water, other than such units: (a) driven by tidal flows, waves, ocean currents or geothermal sources; or (b) which form part of a Storage Facility. 86.16%
Nuclear Nuclear plants generating electricity 84.36%
Interconnectors IFA, Eleclink, BritNED, NEMO, Moyle, EWIC, IFA2, NSL (project specific de-rating factors for each interconnector) 26.00% to 78.00%
  • In the table above, storage has, for example, a de-rating factor approximately 10 percentage points higher than DSR and hydro and, if successful at auction, would receive correspondingly higher remuneration per MW of nameplate capacity than those technologies.
  • The typical potential storage project competitor in the Capacity Market is now more likely to be a shed full of batteries than a pumped hydro station. This has prompted industry participants to question whether such a high de-rating factor is appropriate to all storage. Ofgem, in considering changes to the Capacity Market Rules proposed by stakeholders, declined to take a view on this, deferring to BEIS.
  • BEIS, in the CM Consultation, finds merit in the arguments that (i) System Stress Events may last longer than the period for which a battery is capable of discharging power without re-charging; (ii) batteries degrade over time, so that their performance is not constant; (iii) a battery that is seeking to maximise its revenues from other sources may not be fully charged at the start of a System Stress Event. It proposes to take these points into account when setting de-rating factors for the next Capacity Auction (scheduled to take place in January 2017, and for which pre-qualification is ongoing), and splitting storage into a series of different categories based on the length of time for which they can discharge without re-charging (bands measured in half-hourly increments from 30 minutes to 4 hours). Bidders will be invited in due course to “self-select” which duration-based band they fall into.
  • Of course, deterioration in performance over time is not unique to batteries – other technologies may also perform less well by the end of the 15 year period of a new build capacity agreement than they did at the start. And, as with other technologies, such effects can be mitigated: batteries can be replaced, and who knows by what cheaper and better products by the late 2020s. However, a fundamental difficulty with the CM Consultation is that it contains an outline description of a methodology, based around the concept of Equivalent Firm Capacity, but no indicative values for the new de-rating factors.
  • It may be that BEIS’s concerns about battery performance have been heightened by the fact that the parameters for the next Capacity Market auctions show that it is seeking to procure an additional 6 GW of capacity in the T-1 auction (i.e. for delivery in 2018). There is reason to suppose that battery projects could make a strong showing in this auction, given their relatively quick construction period and the number of projects in the market, some of which may already have other “stacked” revenues (see our earlier post). Clearly it would be undesirable if a significant tranche of the T-1 auction capacity agreements was awarded to battery storage projects which then failed to perform as required in a System Stress Event.
  • It is arguable that the three potential drawbacks of battery projects are not necessarily all best dealt with by de-rating. For example, the risk that a battery is not adequately charged at the start of a System Stress Event is ultimately one for the project’s operator to manage, given that it will face penalties for non-delivery. Nor is it only battery storage projects that access multiple revenue streams and may find themselves without sufficient charge to fulfil their Capacity Market obligations on occasion: pumped hydro projects do not operate only in the Capacity Market, and even though they may be able to generate power for well over four hours, they too cannot operate indefinitely without “recharging”.  Moreover, National Grid is meant to give 4 hours’ notice of a System Stress Event, which may provide battery projects with some opportunity to prepare themselves.
  • However, the real objection to the de-rating proposal is not that it is not addressing a potentially real problem, but that it is only doing so now – given that the issue was raised by stakeholders proposing Capacity Market Rules changes at least as long ago as November 2016 – and with no published numbers for consultees to comment on.
  • The de-rating proposal illustrates a fundamental feature of the flexible resources policy space: one technology’s problems provide an up-side for competing technologies. Self-evidently, what may be bad news for batteries is good news for other storage technologies to the extent that they are not perceived to have the same drawbacks.
  • Seen in this light, the CM Consultation appears to be the main (perhaps only) example of a policy measure that supports the “larger, grid-scale” storage projects (using e.g. pumped hydro or compressed air technology) about which the Response has relatively little to say. However, a few percentage points more or less on de-rating may not make up for the lack of e.g. the “cap and floor” regulated revenue stream advocated by some for such projects.

In Part 2 of this series we will focus on the role of aggregators (featuring the analysis in the CRA Report on independent aggregators) and the demand-side more generally.

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On the way to a smart, flexible GB energy system? Part 1 (overview and storage)

Strong and stable, or storing up trouble? The outlook for energy storage projects in the UK

While strength and stability have taken rhetorical centre stage in the run-up to the UK’s snap General Election on 8 June, the GB energy system faces radical uncertainty on a number of fronts at a time when its stakeholders need it least. So far, the main election focus on energy has inevitably been price caps for household gas and electricity bills. But once the excitements of the campaign and polling day are over, the new government will need to make up for lost time on some less potentially vote-grabbing issues that are central to the continued health of the GB energy sector. None of these is more pressing than how to respond to the possibilities opened up by energy storage technology.

This post will summarise the benefits of energy storage as an enabler of system flexibility, look at the technology options and market factors in play and consider both some of the practical issues faced by developers and the regulatory challenges that – General Election and Brexit notwithstanding – urgently need to be addressed by the government and/or the sector regulator Ofgem.

Benefits of energy storage

The most widely cited benefit of energy storage is the ability to address the intermittency challenge of renewable sources. For more than 100 years, the general lack of bulk power storage in the GB electricity system (other than a small amount of pumped hydro capacity) did not matter. Fluctuations in demand could easily be met by adjusting the amount of power produced by centralised fossil fuel plant that generally had fairly high utilisation rates. But in a power industry transformed by the rise of wind and solar technology, things are different. As a greater proportion of the generating mix is made up of technologies that cannot be turned on and off at will, often in areas where grid capacity is limited, storage offers the possibility that large amounts of power could be consumed hours or days after it is generated, reducing the otherwise inevitable mismatch between consumers’ demands for electricity and the times when the sun is out, the wind is blowing or the waves are in motion.

In a world that increasingly wants to use low carbon sources of electricity which are inherently less easy to match to fluctuations in demand than fossil fuelled generation, storage reintroduces an important element of flexibility. More specific advantages of energy storage range across value chain.

  • For generators, power generated at times of low demand (or when system congestion makes export impossible) can be stored and sold (more) profitably when demand is high, exploiting opportunities for arbitrage in the wholesale market and potentially also earning higher revenues in balancing markets. But storage does not just help wind and solar power. It can also help plants using thermal technologies that work most efficiently operating as baseload (such as combined cycle gas turbines or nuclear plants), but which may not find it economic to sell all their power at the time it is generated. Even peaking plants can use storage to their advantage by avoiding the need to waste fuel in standby mode (using e.g. battery power to cover the period in which they start up in response to demand).
  • For transmission system operators and distribution network operators, energy storage can mitigate congestion, defer the need for investment in network reinforcement and help to maintain the system in balance and operating within its designated frequency parameters by providing a range of ancillary or balancing services such as frequency response.
  • For end users, particularly those with some capacity to generate their own power, and providers of demand-side response services who aggregate end users into “virtual power plants”, energy storage can increase household or business self-consumption rates. And in a world of tariffs differentiated by time of use (enabled by smart metering), storage opens up the possibility of retail-level arbitrage or peak shaving: buying power when it is cheaper (because not many people want it) and storing it for use it at times when it would be more expensive to get it from the grid (because everybody wants to use it).

What could all that mean in practice? Estimates in National Grid’s Future Energy Scenarios 2016 suggest that over the next 25 years, deployment of storage in the UK could grow at least as rapidly as deployment of renewables has grown over the last 20 years. Also in 2016 the Carbon Trust and Imperial College London published a study that modelled the implementation of storage and other flexible technologies across the electricity system, and showed projected savings of between £17 billion and £40 billion between now and 2050. In a consultation published in May 2017, distribution network operator Western Power Distribution (WPD) invited comment on its proposed planning assumptions for the growth of storage in GB from its current capacity of 2.7 GW (all pumped hydro plants): these are a “low growth” scenario that anticipates 4-5 GW (6-15 GWh) by 2030 and a “high growth” scenario of 10-12 GW (24-44 GWh) by that date. Growth of storage at that higher rate would see it outstripping or close to matching current government estimates for the development of new gas-fired or nuclear generation, or new interconnection capacity over the same period. (Although it should be noted that the government’s own projections for the growth of storage are more in line with WPD’s low growth scenario: see this helpful analysis by Carbon Brief.)

Technology options

As is the case in Europe and the rest of the world, energy storage in the UK is currently mostly supplied by pumped hydropower plants, which account for almost all storage capacity and are connected to the transmission system. Until very recently, the much less frequently deployed technique of compressed air energy storage (CAES) was the only other commercially available technology for large-scale electricity storage. The two technologies are similar in that both use cheap electricity to put a readily available fluid (water or air) into a state (up a mountain or under pressure) from which it can be released so as to flow through a turbine and generate power. They differ in that pumped hydro requires a specific mountainous topography, whereas CAES can use a variety of geologies (including salt caverns, depleted oil and gas fields and underground aquifers).

But it is batteries that are currently attracting the keenest investor interest in storage. There are many different battery technologies competing for investment and market penetration. Those based on sodium nickel chloride or sodium sulphur have made advances, but most storage attention surrounds batteries based on lithium-ion structures, also the battery of choice for the electric car industry, where competition has driven down costs. Just before the General Election got under way, the Department of Business, Energy and Industrial Strategy (BEIS) announced £246 million of funding for the development and manufacture of batteries for electric vehicles. Electric car batteries need to be able to deliver a surge of power far more rapidly than those deployed in the wider power sector: in Germany, car manufacturers are already exploring the use of electric car batteries that no longer up to automotive specifications in grid-based applications. In the North East of England, distribution network company Northern Powergrid is collaborating with Nissan to look at how integration of electric vehicles can improve network capacity, rather than just placing increased demands on the grid.

The cost of batteries has come down because of improvements in both battery chemistry and manufacturing processes, as well as the economies of scale associated with higher manufacturing volumes such as with Tesla and Panasonic’s new battery Gigafactory in Nevada. Underlining rising global expectations about low cost and set-up time for battery production, in March 2017 Tesla’s Elon Musk offered to build a 100 MWh battery plant in Australia within 100 days, or to give the system away for free if delivery took any longer.

Batteries are ideally suited to many applications, but they also have some drawbacks. They are less good at providing sustained levels of power over long periods of discharge, and on a really large scale, than CAES or pumped hydro. The non-battery technologies also have other selling points. For example, CAES also has a unique ability, when combined with a combined cycle gas turbine, to reduce the amount of fuel it uses by at least a third. Given the likelihood that the UK power system will continue to need a significant amount of new large-scale gas fired plant, even as it decarbonises, and given the current slow development of carbon capture and storage technology, the potential reduction in both the costs and the carbon footprint of new gas-fired power that CAES offers is well worth consideration by both developers and government. Finally, as regards future alternative technology options, hydrogen storage and fuel cells are the subject of significant research efforts and funding. Most enticing from a decarbonisation perspective, is the prospect of electrolysing water with electricity generated from renewables to produce “green hydrogen”, which can then be used to generate clean power with the same level of flexibility as methane is at present.

Models and market factors

In the abstract, it might be thought that energy storage projects could be categorised into five basic business models:

  • integrated generator services: storage as a dedicated means of time-shifting the export of power generated from specific generating plants (renewable, nuclear or conventional), with which the storage facility may or may not be co-located, and so optimising the marketing of their power (and in some cases, where there are grid constraints, enabling more power to be generated, and ultimately exported, than would otherwise be the case);
  • system operator services: providing frequency response and other ancillary or balancing services to National Grid in its role as System Operator (and potentially, in the future, to a distribution system operator that is required to maintain balance at distribution level): a distinction can be made between “reserve” and “response” services, the latter involving very quick reaction to instructions designed to ensure frequency or voltage control;
  • network investment: enabling distribution networks to operate more efficiently and economically, for example by avoiding the need for conventional network reinforcement. This was notably successfully demonstrated by the 6 MW battery at Leighton Buzzard built by UK Power Networks (UKPN). The results of WPD’s Project FALCON were a little more equivocal, but it is trying again, using Tesla batteries to test a range of applications at sites in the South West, South Wales and the East Midlands);
  • merchant model: a standalone storage facility making the most of opportunities to buy power at low prices and sell it at high prices, with no tie to particular generators, and perhaps underpinned by Capacity Market payments (see further below);
  • “behind the meter”: enabling consumers to reduce their energy costs (retail level arbitrage or peak shaving, as noted above, as well as maximising use of on-site generation where this is cheaper than electricity from the grid).

These models are far from being mutually exclusive. Indeed, at present, they are best thought of as simply representing different categories of potential revenue streams: the majority of storage projects will need to access more than one of these streams in order to be viable. Some will opt to do so through contracts with an aggregator, for whom a relationship with generation or consumption sites with storage, particularly if they have a degree of operational control over the storage facility, offers an additional dimension of flexibility.

In the short term, the largest revenue opportunity may be the provision of grid services. The need for a fast response to control frequency variations is likely to increase in the future as a result of the loss of coal-fired plant from the system.

Growing interest in energy storage also owes much to the decline in the UK greenfield renewables market, with the push factor of the removal or drastic reduction of subsidies previously available for new renewable energy projects and the pull factor of the battery revolution. According to a report published in May 2017 by SmartestEnergy, an average of 275 solar, wind and other renewable projects were completed in each quarter between 2013 and the last quarter of 2016, when the figure plummeted to 38. Only 21 renewable projects were completed in the first quarter of 2017.

So why, when UKPN, for example, report that between September 2015 and December 2016 they processed connection applications from 600 prospective storage providers for 12 GW of capacity, is the amount of battery capacity so far connected only in the tens of MW?

Tenders and auctions

It may help to begin by looking at another very specific factor that drove this extraordinary level of interest in a technology that had been so little deployed to date. This was National Grid’s first Enhanced Frequency Response (EFR) tender, which took place in August 2016. A survey by SmartestEnergy, carried out just before the results of the tender were announced, found that 70 percent of respondents intending to develop battery projects in the near future were anticipating that ancillary services would be their main source of revenue.

National Grid were aiming to procure 200 MW of very fast response services. Although “technology neutral”, the tender was presented as an opportunity for battery storage providers and as expected, storage, and specifically batteries, dominated. All but three of the 64 assets underlying the 223 bids from 37 providers were battery units. Perhaps less expected were the prices of the winning bids: some as low as £7/MWh and averaging £9.44/MWh. The weighted price of all bids was £20.20/MWh.

This highly competitive tender gave the UK energy storage market a £65 million boost. The pattern of bids suggested that alongside renewables developers and aggregators, some existing utilities are keen to establish themselves in the storage market, and are prepared to leverage their lower cost of capital and accept a low price in order to establish a first mover advantage.

Independent developers who regard storage as a key future market might also have been bullish in their calculations of long-term income while accepting lower revenues in the near term to compete in a crowded arena. For all bidders, one of the key attractions was the EFR contract’s four-year term, which makes a better fit with their expectations of how long it will take to recoup their initial investment than the shorter duration of most of National Grid’s other contracts for balancing / ancillary services.

Aspiring battery storage providers also responded enthusiastically to the regular four year ahead (T-4) Capacity Market (CM) auction when it took place for the third time in December 2016. To judge from the Register for the T-4 2016 auction, some 120 battery projects, with over 2 GW of capacity between them, were put forward for prequalification in this auction. (This assumes that all the new build capacity market units (CMUs) described as made up of “storage units” and not obviously forming part of pumped hydro facilities were battery-based.) Although almost two-thirds of these proposed CMUs are described on the relevant CM register as either “not prequalified” or “rejected”, of the remaining 33 battery projects, no fewer than 31 projects, representing over 500 MW of capacity between them, went on to win capacity agreements in the auction.

There are a number of points to be made in connection with these results.

  • Taking the CM and EFR together, the range of parties interested in batteries is noteworthy, as is the diversity of motivations they may have for their interest.  It includes grid system operators (UKPN), utilities (EDF Energy, Engie, E.ON, Centrica), renewables developers (RES, Element Power, Push Energy, Belectric), storage operators, aggregators / demand side response providers (KiWi Power, Limejump, Open Energi) and end-users, as well as new players who seem to be particularly focused on storage (Camborne Energy Storage, Statera Energy, Grid Battery Storage).
  • Developers of battery projects are evidently confident that the periods during which they may be called on to meet their obligations to provide capacity by National Grid will not exceed the length of time during which they can continuously discharge their batteries – in other words, that the technical parameters of their equipment do not put them at an unacceptable risk of incurring penalties for non-delivery under the CM Rules: a point that some had questioned.
  • The CM Rules are stricter than those of the EFR tender as regards requiring projects to have planning permission, grid connection and land rights in place as a condition of participating in the auction process. This is presumably one reason why fewer battery projects ended up qualifying to compete in the T-4 auction as compared with the EFR tender.
  • For batteries linked to renewable electricity generation schemes that benefit from renewables subsidy schemes such as the Renewables Obligation (RO), the EFR tender was an option, but the CM was not, since CM Rules prohibit the doubling up of CM and renewables support. So, for example, the 22 MW of batteries to be installed at Vattenfall’s 221 MW RO-accredited Pen-y-Cymoedd wind farm was successful in the EFR tender but would presumably not have been eligible to compete in the CM.
  • Accordingly, CM projects tend to be designed to operate quite independently of any renewable generating capacity with which they happen to share a grid connection. But some of these projects are located on farms that might have hosted large solar arrays when subsidies were readily available for them. Green Hedge, four of whose projects were successful in the T-4 2016 CM auction, has even developed a battery-based storage package called The Energy BarnTM. Others CM storage projects are located on the kind of industrial site that might otherwise be hosting a small gas-fired peaking plant. UK Power Reserve (as UK Energy Reserve), which has been very successful with such plants in all the T-4 auctions to date, won CM support for batteries at 12 such locations.
  • The Capacity Market may be less lucrative than EFR, measured on a per MW basis, but it offers the prospect of even longer contracts: up to 15 years for new build projects.
  • Batteries are still a fairly new technology. The clearing price of Capacity Market auctions has so far been set by small-scale gas- or diesel-fired generating units using well established technology. In a T-4 auction, the CMUs, by definition, do not have to be delivering capacity until four years later – although the Capacity Market Rules oblige successful bidders to enter into contracts for their equipment, and reach financial close, within 16 months of the auction results being announced. Other things being equal (which they may not be: see next bullet), it will clearly be advantageous to developers if they can arrange that the prices they pay for their batteries are closer to those prevailing in 2020 than in 2016. It has been pointed out that although internationally, battery prices may have fallen by up to 24 percent in 2016, the depreciation of Sterling over the same period means that the full benefit of these cost reductions may not yet be accessible to UK developers.
  • The proportion of prequalified battery-based CMUs that were successful in the T-4 2016 CM auction was remarkably high. But may not have been basing their financial models solely or even primarily on CM revenues. In addition to EFR and other National Grid ancillary services, such as Short Term Operating Reserve or Fast Reserve, and possible arbitrage revenues, it is likely that at least some projects were anticipating earning money by exporting power onto the distribution network during “Triad” periods. This “embedded benefit” would enable them to earn or share in the payments under the transmission charging regime that have been the main source of revenue for small-scale distributed generators bidding in the CM, enabling them to set the auction clearing price at a low level and prompting a re-evaluation of this aspect of transmission charges by Ofgem. From Ofgem’s March 2017 consultation on the subject, it looks as if these payments will be drastically scaled down over the period 2018 to 2020. This may give some developers a powerful incentive to deploy their batteries early (notwithstanding the potential cost savings of waiting until 2020 to do so) so as to benefit from this source of revenue while it lasts. Those who compete in subsequent CM auctions may find that the removal of this additional revenue leads to the CM auctions clearing at a higher price.
  • As with EFR, some developers may be out to buy first mover advantage, and most already have a portfolio of other assets and/or sources of revenue outside the CM. But what they are doing is not without risk, since the penalties for not delivering a CMU (£10,000, £15,000 or £35,000 / MW, depending on the circumstances) are substantial.
  • Meanwhile, a sure sign of the potential for batteries to disrupt the status quo can be seen in the fact that Scottish Power has proposed a change to the CM Rules that would apply a lower de-rating factor to batteries for CM purposes than to its own pumped hydro plant.

Finally, one other tender process, that took place for the first time in 2016, could point the way to another income stream for future projects. National Grid and distribution network operator Western Power Distribution co-operated to procure a new ancillary service of Demand Turn Up (DTU).

The idea is to increase demand for power, or reduce generation, at times when there is excess generation – typically overnight (in relation to wind) and on Summer weekends (in relation to solar). DTU is one of the services National Grid use to ensure that at such times there is sufficient “footroom” or “negative reserve”, defined as the “continuous requirement to have resources available on the system which can reduce their power output or increase their demand from the grid at short notice”.

National Grid reports that over the summer of 2016, the service was used 323 times, with “10,800 MWh called with an average utilisation price of £61.41/MWh”. The procurement process can take account of factors other than the utilisation and availability fees bid, notably location. Successful tenders in the 2017 procurement had utilisation fees as high as £75/MWh.

At present, the procurement process for DTU does not appear to allow for new storage projects to compete in DTU tenders, but once they have become established, they should be well placed to do so, given their ability to provide demand as well as generation. They could be paid by National Grid to soak up cheap renewable power when there is little other demand for it. If National Grid felt able to procure DTU or similar services further in advance of when they were to be delivered, the tenders could have the potential to provide a more direct stimulus to new storage projects.

Battery bonanza?

Those who have been successful in the EFR or CM processes can begin to “stack” revenues from a number of income streams. And the more revenues you already have, the more aggressively you can bid in future tenders (for example for other ancillary services) to supplement them.

But even if all the projects that were successful in the EFR and CM processes go ahead, they will still represent only a small fraction of those that have been given connection offers. Moreover, it looks as if the merchant and ancillary services models are the only ones making significant headway at present.  Why are we not seeing more storage projects integrated with renewables coming forward, for example? Why, to quote Tim Barrs, head of energy storage sales for British Gas, has battery storage “yet to achieve the widespread ‘bankable status’ that we saw with large-scale solar PV”?

Technology tends to become bankable when it has been deployed more often than batteries coupled with renewables have so far in GB. But even to make a business case to an equity investor, a renewables project with storage needs to show that over a reasonable timeframe the additional revenues that the storage enables the project to capture exceed the additional costs of installing the storage. What are these costs, over and above the costs of the batteries and associated equipment?  What does it take to add storage to an existing renewable generating project, or one for which development rights have already been acquired and other contractual arrangements entered into?

  • The configuration and behaviour of any storage facility co-located with subsidised renewable generation must not put the generator’s accreditation for renewable subsidies at risk because of e.g. a battery’s ability to absorb and re-export power from the grid that has not been generated by its associated renewable generating station. The location of meters is crucial here. According to the Solar Trade Association, only recently has Ofgem for the first time re-accredited a project under the RO after storage was added to it. While an application for re-accreditation is being considered, the issue of ROCs is suspended. Guidance has been promised which may facilitate re-accreditation for other sites. Presumably in this as in other matters, the approach for Feed-in Tariff (FIT) sites would follow the pattern set by the RO. For projects with existing Contracts for Difference (CfDs), there is no provision on energy storage. For those hoping to win a CfD in the 2017 allocation round, the government has made some changes to the contractual provisions following a consultation, but, as the government response to consultation makes clear, a number of issues still remain to be resolved.
  • An existing renewables project is also likely to have to obtain additional planning permission. There may be resistance to battery projects in some quarters. RES recently had to go to appeal to get permission for a 20 MW storage facility by an existing substation at Lookabootye after its application was refused by West Lothian Council. It will also be necessary to re-negotiate existing lease arrangements (or at least the rent payable under them), and additional cable easements may be required.
  • Unless it is proposed that the battery will take all its power from the renewable generating station (which is unlikely), it will be necessary to seek an increase in the import capacity of the project’s grid connection from the distribution network operators. Even if the developer does not require to be able to export any more power at any one time from the development as a whole, in order to charge the battery at a reasonable speed from the grid it will need a much larger import capacity than is normal for an ordinary renewable generating facility. The ease and costs of achieving this will vary depending on the position of the project relative to the transmission network. There may be grid reinforcement costs to pay for: UKPN has noted that there are few places on the network with the capacity to connect a typical storage unit without some reinforcement. They will also treat the addition of storage as a material change to an existing connection request for a project that has not yet been built, prompting the need for redesign and resulting in the project losing its place in the queue of connection applications.
  • A power purchase agreement (PPA) for a project with storage will need to address metering. For the purposes of the offtaker, output will either need to be measured on the grid side of the storage facility (the same may not be true of metering for renewable subsidy purposes), or an agreed factor will need to be applied to reflect power lost in the storage process. Secondly, in order to maximise the opportunities for arbitrage by time-shifting the export of its power, a project with storage may want more exposure to fluctuations in the wholesale market price, and even to imbalance price risk, than a traditional intermittent renewables project. The detail of how embedded benefits revenues are to be shared between generator and offtaker may also require to be adjusted if the addition of storage makes it more likely they will be captured.

For the moment, most renewables projects probably fall into one of two categories with regard to integrated storage.

  • On the one hand, there are those that are already established and receiving renewable generation subsidies, or which have been planned without storage and now simply need to commission as quickly as possible in order to secure a subsidy (for example, under RO grace period rules for onshore wind projects). For them, introducing storage into an existing project may be more trouble than it is worth for some or all of the reasons noted above. They have little incentive to deploy storage unless it is an economic way of reducing their exposure to loss of revenue as a result of grid constraints or to imbalance costs: these have been increasing following the reforms introduced by Ofgem in 2015 and will increase further as the second stage of those reforms is implemented in 2018, but for many renewable generators are a risk that is assumed by their offtakers.
  • On the other hand, for projects with no prospect of receiving renewable subsidies, it would appear that the cost of storage is not yet low enough, or the pattern of wholesale market prices sufficiently favourable to a business model built on  time-shifting and arbitrage to encourage extensive development of renewables + storage merchant model projects. If it was generally possible easily to earn back the costs of installing storage through the higher wholesale market revenues captured by – for example – time-shifting the export of power from a solar farm to periods when wholesale prices are higher than they are during peak solar generating hours, the volume and profile of successful storage + renewable projects in the CM and elsewhere would be different from what it now is.

However, battery costs will continue to fall, and wholesale prices are becoming “spikier”. It may only be a matter of time before GB’s utility-scale renewables sector, whose successful players have so far built their businesses on the predictable streams produced by RO and FIT subsidies, can get comfortable with business cases that depend more fundamentally on the accuracy of predictions about how the market, rather than the weather, will behave. Moreover, there is nothing to stop a storage facility co-located with a renewables project that has no renewable subsidy from earning a steady additional stream of income in the form of CM payments.

Arguably, the UK has missed a trick in not having adopted pump-priming incentives for combining storage with renewables, such as setting aside a part of the CfD budget for projects with integrated storage. But with the door apparently generally closed for the time being on any form of subsidy for large-scale onshore wind or solar schemes in most of GB, it is probably unrealistic to hope for any such approach to be taken in the near future.

Regulatory challenges

There are undoubtedly already significant commercial opportunities for some GB storage projects, but it does not feel as if the full power of storage to revolutionise the electricity market is about to be unleashed quite yet. This is perhaps not surprising.

Almost as eagerly awaited among those interested in storage as the results of the EFR tender was a long-promised BEIS / Ofgem Call for Evidence on how to enable a “smart, flexible energy system”, which was eventually published in November 2016. This Call for Evidence, the first of its kind, represented a significant step forward for the regulation of storage in the UK, but although it pays particular attention to storage and the barriers that storage operators may face it is not just “about” storage. It ultimately opens up questions about how well the current regulatory architecture, designed for a world of centralised and despatchable / baseload power generation, can serve an increasingly “decarbonised, distributed, digital” power sector without major reform. (At an EU level, the European Commission’s Clean Energy Package of November 2016 tries to answer some of these questions, and there is generally no shortage of thoughtful suggestions for reforming power markets, such as the recent Power 2.0 paper from UK think tank Policy Exchange, or the “Six Design Principles for the Power Markets of the Future” published by Michael Liebreich of Bloomberg New Energy Finance.)

However, whilst it is important to take a “whole system” approach, it would be unfortunate if the breadth of the issues raised by the Call for Evidence were to mean that there was any unnecessary delay in addressing the regulatory issues of most immediate concern to storage operators. Government and regulators have to start somewhere, and it is not unreasonable to start by trying to facilitate the deployment of storage since it could facilitate so many other potentially positive developments in the industry.

On 25 April Ofgem revealed that it had received 240 responses to the Call for Evidence, with around 150 responses commenting on energy storage. Barriers to the development of storage identified by respondents include the need for a definition of energy storage, clarity on the regulatory treatment of storage, and options for licensing. The response from the Energy Storage Network (ESN) offers a good insight into many of the issues of most direct concern to storage operators. Some of the other respondents who commented on storage also demonstrated an appetite for fundamental reform of network charging (described by one as “probably not fit for purpose in its current form”) and for significant shifts in the role of distribution network operators.

Interest in a definition of energy storage is unsurprising. It is arguably hard to make any regulatory provision about something if you have not defined it. But at the same time, the Institution of Engineering and Technology may well be correct when it says in its response to the Call for Evidence: “lack of a definition is not a barrier in itself…as the measures are developed to address the barriers to storage, it will become clear whether a formal definition is required and at what level…agreeing a definition should be an output of regulatory reform, not an input.”. In other words, how you define something for regulatory purposes – particularly if that thing can take a number of different forms and operate in a number of different ways – will depend in part on what rules you want to make about it.

Under current rules, energy storage facilities end up being classified, somewhat by default, as a generation activity – even though their characteristic activity does not add to the total amount of power on the system. But because storage units also draw power from the grid, they find themselves having to pay two sets of network charges – on both the import and the export – even though they are only “warehousing” the power rather than using it. Both these features of the current regulatory framework are strongly argued against by a variety of respondents to the Call for Evidence.

Treating storage as generation complicates the position for distribution network operators wishing to own storage assets. Under the current unbundling rules (which are EU-law based, but fully reflect GB policy as well), generation and network activities must be kept in separate corporate compartments. These rules are designed to prevent network operators from favouring their own sources of generation (or retail activities). The issue is potentially more acute when you have a storage asset forming part of the network company’s infrastructure and regulated asset base, but having the ability to trade on the wholesale power and ancillary services markets in its own right as well as to affect the position of other network users (by mitigating or aggravating constraints). UKPN considers that the approach it has adopted with its large battery project could provide a way around this problem for others as well – essentially distinguishing the entity that owns the asset from the entity responsible for its trading activity on the market. However, such an arrangement is not without costs and complexity, both for those involved to set up and for the regulator to monitor. The ESN has also made proposals in its response to the Call for Evidence about the conditions under which distribution network operators should be permitted to operate storage facilities.

It may be that the most useful contribution that transmission and distribution network operators could make to the development of storage would be to determine as part of their multi-year rolling network planning processes where it would be most beneficial in system terms for new storage capacity of one kind or another to be located. But the underlying question is whether at least some storage projects should be treated more as network schemes with fixed OFTO or CATO-like rates of return rather than being regarded as part of the competitive sector of the market along with generation and supply. (Similar concerns about the status of US network-based storage projects, admittedly in a slightly different regulatory environment, have been addressed by the Federal Energy Regulatory Commission in a recent policy statement and notice of proposed rulemaking.)

If storage is not to be treated as generation or necessarily part of a network (and required to hold a generation licence where no relevant exemption applies), what is it? Should it be recognised as a new kind of function within the electricity market? In which case, the natural approach under the GB regulatory regime would be to require storage operators to be licensed as such (again, subject to any statutory exemptions). That would require primary legislation (i.e. an Act of Parliament) to achieve, at a time when Parliamentary time may be at a premium because of Brexit – and then there would need to be drafting of and consultation on licence conditions and no doubt also numerous consequential changes to the various industry-wide codes and agreements.

The ESN’s Call for Evidence response has some helpful suggestions as to what a licensing regime for storage might look like. But is the licensing model is a red herring in this context? After all, the parallel GB regulatory regime for downstream gas includes no requirement for those wishing to operate an onshore gas storage facility to hold a licence to do so under the Gas Act 1986. And it is entirely possible to trade electricity on the GB wholesale markets (a key activity for storage facilities), without holding a licence under the Electricity Act 1989 (or even engaging in an activity requiring such a licence but benefiting from an exemption from the requirement to hold a licence).

As for some of the current financial disadvantages facing storage, it is encouraging that in consulting on its Targeted Charging Review of various aspects of network charging in March 2017, Ofgem provisionally announced its view that some double charging of storage should be ended. It consulted on a number of changes that, taken together, should have the effect of ensuring that “storage is not an undue disadvantage relative to others providing the same or similar services”. However, although welcome, these Ofgem proposals so far only cover the treatment of the “residual” (larger) element of transmission network charges for demand (applicable to distribution-connected projects), in respect of storage units co-located with generation. It remains to be seen whether – and if so, what – action will be taken to deal with other problems in this area, such the payment of the “final consumption” levies that recover the costs of e.g. the RO and FIT schemes by both the storage provider and the consumer on the same electricity when a storage operator buys that electricity from a licensed supplier. Storage operators can at present only avoid this cost disadvantage if they acquire a generation licence, which does not seem a particularly rational basis for discriminating between them in this context.

Speaking in March, the head of smart energy policy at BEIS, Beth Chaudhary, said that ending the double counting of storage “might require primary legislation”, adding that Brexit has made the progress of such legislation “difficult at the moment”. The General Election has only added to concerns of momentum loss, a sense of “circling the landing strip” in the words of the Renewable Energy Association’s chief executive, Dr Nina Skorupska.

“The revolution will not be televised”…but it probably needs to be regulated

What is the storage revolution? Storage will not turn the electricity industry into a normal commodity market, like oil, overnight – or indeed ever. We will still have to balance the grid. As before, what is being exported onto the grid will need to match what is being imported from it at any given moment. It’s just that storage will provide an additional source of power to be exported onto the grid (which was generated at an earlier time) and it will also facilitate more balancing actions by those on the demand side where they have access to it. It is also likely that increased use of micro grids, with the ability to operate in “island mode” as well as interconnected with the public grid, will result in the public grid handling a smaller proportion of the power being generated and consumed at any given time.

Of course, one could look at this and say: “Fine, but what’s the hurry?”. The UK developed a renewables industry when it was still a relatively new and expensive thing to do. Thanks to the efforts made by the UK and others, renewables are now both “mainstream” and relatively cheap. Those countries that are only starting to develop sizeable renewable projects now are reaping the benefit of the cost reductions achieved by the early adopters. Would it be such a bad thing if a GB storage revolution was delayed for a year or two while other markets experiment with the technology and help it to scale up, reducing the costs that UK businesses and consumers will pay for its ultimate adoption in the UK?

After all, we have to be realistic about the number of large and difficult issues the UK government and regulators can be expected to focus on and take forward at once. Is it not more important, for example, to reach agreement with the rest of the EU on a satisfactory set of substitute arrangements for the legal mechanisms that currently govern the UK’s trade in electricity and gas with Continental Europe (and the Republic of Ireland)? In addition, the General Election manifestos of each party prioritise other contentious areas of energy policy for action, such as facilitating fracking and reducing the level of household energy bills.

We do not deny the importance of these other issues, and BEIS and Ofgem resources are, of course, finite, but we would argue that storage and the complex of “flexibility” issues to which it is central should be high on the policy agenda after 8 June in any event.

  • GB distribution network operators have already done lot of valuable work on storage, much of it funded by various Ofgem initiatives (notably the Innovation Funding Incentive, Network Innovation Allowance and Low Carbon Networks funding). This has generated a body of published learning on the subject which continues to be added to and which it would be a pity not to capitalise on as quickly as possible.
  • Depending (at least in part) on the outcome of Brexit, we may find ourselves either benefiting from significantly more interconnection with Continental European power markets, or becoming more of a “power island” compared with the rest of Europe. In either case, a strong storage sector will be an advantage. Storage can magnify the benefits of interconnection but it would also help us to optimise the use of our own generating resources if our ability to supplement them (or export their output) through physical links to other markets was limited.
  • The UK has in some respects led the world on power market reform.  We have complex, competitive markets and clever companies that have learnt how to operate in them. Looking at storage from an industrial strategy point of view, the UK is may not make its fortune after by the mass manufacture of batteries for the rest of the world, but the potential for export earnings from some of the higher value components of storage facilities, and the expertise to deploy them to maximum effect, should not be neglected.
  • On the other hand, if the UK wants to maintain its position as an attractive destination for investment in electricity projects, it needs to show that it has a coherent regulatory approach to storage, both because storage will increasingly become an asset class in its own right and because sophisticated investors in UK generation, networks or demand side assets will increasingly want to know that this is the case before committing to finance them.
  • As the Call for Evidence and the other attempts to address the challenges of future power markets referred to above make clear, everything is connected. There is, arguably, not very far that you can or should move forward on any aspect of generation or other electricity sector policy without forming a view on storage and how to facilitate it further.
  • Finally, because some of the policy and regulatory issues are hard and resources to address them are finite, this will all take time, so that with luck, the regulatory framework will have been optimised by about the same time as the price reductions stimulated by demand from the US and other forward-thinking jurisdictions have started to kick in.

Almost whatever problem you are looking at, whether as a regulator or a commercial operator in the GB power sector, it is worth considering carefully whether and how storage could help to solve it. Storage has the potential, as noted above, to change the ways that those at each level in the electricity value chain operate, and with the shift to more renewables and decentralised generation, it has a significant part to play in making future electricity markets “strong and stable”. The “trouble” alluded to in the title of this post is change either happening faster than politicians and regulators can keep pace with, or innovation being stifled by the lack of regulatory adaptation as they find it too difficult to address the challenges it poses when faced with other and apparently more urgent priorities. Because the ways in which generators, transmission and distribution network operators, retailers and end users interact with each other is so much a function of existing regulation of one kind or another, it is very hard to imagine storage reaching its full potential without significant regulatory change. These changes will take time to get right, but since ultimately an electricity sector that makes full use of the potential of storage should be cheaper, more secure and more environmentally sustainable than one that does not, there should be no delay in identifying and pursuing them.

 

 

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Strong and stable, or storing up trouble? The outlook for energy storage projects in the UK

Financial parameters of auctions for renewable energy sources

On 3 April 2017, two regulations were published in the Journal of Laws which set out the financial parameters of auctions for renewable energy sources (RES) that will be held in 2017. The government is planning to spend more than PLN 27 billion (approximately €6.5 billion) on support for producers in auctions, which will generate more than 55 TWh of electricity during 15 years. The parameters of the auctions are set out below.

  1. Summary
  • In 2017, fourteen auctions will be organized, each of them dedicated to different groups of installations. Nearly 75 percent of the funds (PLN 20 billion) will be allocated to new installations. Nearly 63 percent of all funds (PLN 17 billion) will be allocated to large installations.
  • So-called stable installations will be the most favored group of installations. The largest part of the funds is allocated to a basket of high-efficiency installations (37 percent of funds in 4 auctions). Biomass installations are expected to be a dominant group in this basket. Significant funds (35 percent in 4 auctions) will be allocated to agricultural biogas installations.
  • It is planned to allocate funds to Waste-to-Energy projects, which should assure the construction of installations with nearly 150 MW of total capacity (one auction dedicated for new, large installations). Part of the funds will be allocated to a basket dedicated to hydro-electric plants, both existing and new (three auctions).
  • Another part of the budget is allocated to a basket for new installations covering “other installations” (15 percent of funds in two auctions). In this basket, two auctions are planned: the first for small installations that, according to the government’s intention, will result in the construction of 300 MW new photovoltaic projects, and the second for large installations, where support could be obtained by nearly 150 MW new wind projects. Significant competition is expected in these two auctions.
  • Installations participating in an auction cannot apply for higher support than the “reference price,” which is determined for each year. The reference price is set separately for 21 categories of installations. In 2017 for example, this price will be PLN 350 per MWh for large installations using wind and PLN 450 per MWh for small installations using solar energy.
  • Auctions will be announced by the President of ERO and cannot be organized earlier than 30 days after its announcement. In light of the RES Act, an auction could be organized at the earliest on 24 May 2017, but no announcements regarding auctions have been made to date.
  1. Auction support scheme

Under the Act of 20 February 2015 on renewable energy sources (RES Act), there are two support schemes for RES installations in Poland. Existing installations can obtain support in the form of certificates of origin (green certificates) and can sell electricity to designated entities at the officially determined price (system of certificates). New installations will compete for support allocated in auctions (auction system) organized by the President of the Energy Regulatory Office (ERO).

The auction system is dedicated mainly to new installations, but existing installations can also transfer to this system (in such case they lose a right to participate in the system of certificates). This system is intended to assure the future development of RES but in a controlled and predictable manner—this may be pursued through the allocation of budgets to auctions where installations favored by the government start and through the reduction of budgets for auctions for unwanted installations. The increase in RES in Poland, and the contemplated impact of auctions in 2017 on the installed capacity of RES, is presented in Figure no 1.

Figure no. 1     Increase in renewables capacity (MW) in Poland

Source: data from President of the ERO. The data concerning the capacity from the auction in 2017 presents only the estimation of the Ministry of Energy.
  1. Split of auctions and auction baskets in the auctions system

Auctions are conducted separately for installations qualified for particular “baskets” (or bands). There are five baskets (two additional baskets will be added from 1 July 2017, but no funds are allocated to them in 2017). The following existing baskets are dedicated to particular RES installations:

  • With a degree of utilization of the installed electricity generation capacity, irrespective of the level of CO2 emission, of more than 3504 MWh/MW/year (basket of high-efficiency installations)
  • Using, for the generation of electricity, biodegradable industrial waste and municipal solid waste of plant or animal origin, including waste from waste treatment systems and waste from water treatment and waste treatment, including in particular sludge, in accordance with the provisions on waste concerning classification of energy recovered from thermal waste treatment (basket of WTE installations)
  • In which emission of carbon dioxide does not exceed 100 kg/MWh, with utilization of total installed capacity of more than 3504 MWh/MW/year (basket of low-emission installations)
  • Using only agricultural biogas to generate energy (basket of biogas installations)
  • Other than those already specified (basket of other installations)

In each of those baskets, separate auctions are organized for existing installations and new installations. Moreover, separate auctions are organized for small installations and large installations. Separate auctions will be organized for so-called upgraded installations, but no budget has been provided in 2017. (as it was in 2016).

Therefore, in each year and in each basket, up to four auctions are possible and in total up to 20 auctions may be organized, each of them dedicated to different groups of installations (40 auctions including upgraded installations).

  1. Budget allocations for 2017

In 2017, the auction budget is PLN 27,177,622,626; support will be provided for the production of 55 562 607 MWh during the coming years. The individual budgets are presented in Table no 1 below:

Table no. 1 Budgets of auctions in 2017

Conclusions from the above data: In 2017, the auctions will be dedicated mainly to new installations—75 percent of funds are allocated to these installations. The most supported technologies are stable installations, i.e. with predictable generation, mainly from the basket for high-efficiency installations (37 percent of all funds) and from the basket for biogas installations (35 percent of all funds). Large installations will be dominant, as 63 percent of all funds have been allocated to these installations. A breakdown of funds between large vs. small and existing vs. new installations is presented in Figure no 2.

Figure no. 2 Breakdown of auction funds in 2017: large v. small and existing v. new installations

Source: Regulation of the Council of Ministers regarding the maximum volume and value of electric energy generated in renewable energy source installations which may be sold by auction in 2016.

A more detailed description of each of the auctions is provided in point 8 below.

  1. Reference prices

An RES installation producer cannot submit at auction a bid that is higher than the maximum ‘reference price’ per MWh. The reference price is determined for each year, separately for each of the 21 categories (42 if we take into account the additional 21 categories for upgraded installations). This division does not coincide with the division into technological baskets. The reference price is uniform for existing and new installations. Parts of the reference prices are determined separately for small and large installations, while others are the same for both categories.

Below, we present the reference prices for the installations that are intended to be supported by the government in 2017. A summary of all reference prices is set out in Appendix 1 below.

Table no. 2 Reference price for certain installations in 2017

  1. Possible auction dates

Under the RES Act, auctions are announced and organized by the President of the ERO. The announcement should be published in the Public Information Bulletin of ERO at least 30 days before the day of the auction starting. The auction cannot be conducted earlier than 60 days after publication of the reference prices.

The regulation determining reference prices in 2017 entered into force on 25 March 2017, therefore this year’s auction can be conducted at the earliest on 24 May 2017 (if the President of the ERO publishes the announcement on 24 April 2017 at the latest). Nevertheless, some media say that the main auctions will be organized in the second half of the year.

  1. The effect of winning an auction and support period

The producer that won the auction will receive support dependent on the capacity of the installation. Producers that have an installation with installed capacity of <500 kW will be entitled to sell their total electricity offered in the auction at the price established at auction to the designated entity (pay-as-bid mechanism). Producers that have an installation with installed capacity of >500 kW will have the right to cover the difference between the market price and the price established at auction in the scope of the volume offered in the auction (termed “return of negative balance”) with the obligation to return the surplus if the market price exceeds the auction price (contract-of-difference mechanism). The support is also not allocated, when the power exchange prices of electricity are lower than zero PLN (with some additional conditions).

The support period for new installations is determined annually together with reference prices. In 2017 it is 15 years. The support period for existing installations is also 15 years, but it is calculated from the date the first electricity is generated and fed to the grid, as confirmed by the issued green certificate.

If, after winning the auction, at least 85 percent of the quantity of electricity declared in the bid is not generated, a fine will be imposed calculated on the basis of the not delivered volume of electricity and a half of the auctioned bid price. In the case of installations with an assumed efficiency of 3504 MWh/ MW/year, a failure to reach declared capacity utilization leads to the obligation to return all public aid obtained through auctions.

  1. Auctions in particular baskets

Below, we present a short description of each basket, stating the types of installation supported in accordance with the government’s intention. Whenever the amount is given together with the name of a specific installation, it means the reference price for this installation. The grading of individual installations into baskets is given for illustration purposes only; we cannot guarantee that in fact the indicated types of installation will start in any given auction.

a. Basket of high-efficiency installations

Four auctions will be organized in this basket, but the funds for small installations (both existing and new) constitute only 9 percent; the funds for large installations dominate.
Auctions for large installations in this basket are dedicated mainly to plants combusting biomass. It is predicted that the following installations can participate in these auctions:

  • Dedicated co-firing combustion installations (DCCI) using biomass, biofuels, biogas or agriculture biogas (325 PLN)
  • Hybrid RES installation with aggregated installed capacity >1 MW (405 PLN)
  • Dedicated biomass combustion installations (DBCI) or biomass hybrid systems (HS) with aggregated installed capacity of up to 50 MW (both 415 PLN)
  • DBCI or HS in CHP with aggregated installed capacity >50 MW and up to 150 MWt of CHP (435 PLN)
  • DBCI or HS in CHP with aggregated installed capacity of up to 50 MW (450 PLN)

Potentially this basket may be joined by investors who plan to develop on-shore wind farms (350 PLN) installing new generation turbines. Some claim that in certain technical configurations it would be possible to achieve efficiency at the level required for this basket.

The government’s intention is a transfer of nearly 50 percent of existing installations combusting biomass (probably the DBCI, although this intention is not clearly stated), but taking into account the reference price it may turn out that the auction winner will be an installation co-firing biomass with coal (DCCI). Competition in this basket is expected, as due to the declining prices of green certificates, a transfer to the auction system may be financially profitable for existing installations.

In the scope of large, new installations, the government is planning to award funds that will result in the construction of approximately 100 MW of DBCI.

Funds for small installations are allocated to installations using biogas other than agricultural, hence for installations using biogas extracted from a landfill site (405 PLN) and biogas extracted from a sewage treatment plant (365 PLN). In the scope of new installations, it is planned to construct approximately 5 MW of capacity for each type of these installations.

b. Basket of WTE installations

In this basket only one auction for large, new installations will be organized. Funds from this basket are intended to provide support for waste incineration plants that produce energy (385 PLN). It is planned that results from the auction support will be given to installations with total capacity of 150 MW.

According to publicly available information, there are five waste incineration plants in Poland which produce nearly 334,000 MWh/year. (This data is an unconfirmed estimation due to the lack of official information in this respect.) Assuming that the winning installation will produce the same amount of MWh every year (which gives production of 309,600 MWh annually), contracting the total volume in this basket will result in an increase in the energy generation of those installations of 92 percent.

c. Basket of low-emission installations

In this basket three auctions will be organized, all addressed to hydro-electric installations (480 PLN) able to achieve at least 3504 MWh/MW/year. Hydro-electric installations below this threshold will need to participate in auctions in the basket of other installations. In addition, large offshore wind energy installations (470 PLN) may potentially take part in auctions in this basket—if such installations will be able to produce more than 3504 MWh/MW/year. Similarly, as in the case of the basket of high-efficiency installations, this basket may be joined by investors planning to install on-shore wind turbines (350 PLN) of a new generation, only if the information on sufficiently efficient technical setups is confirmed.

In the scope of existing installations, it is intended that as a result of the auctions from 2017 and 2016 approximately 80 percent of existing, small hydro plants will be transferred to the auction system. The budget for new installations will enable the construction of 10 MW of small installations and 10 MW of large installations (this indicates that offshore wind plants can take part in the auction only hypothetically).

d. Basket of biogas installations

In this basket four auctions will be organized, each solely for agriculture biogas installations (PLN 550).

The government in its rationale of regulations did not indicate the percent of existing installations that will be transferred to the auction system in this basket. In the scope of auctions dedicated to new installations, it is planned to allocate support to small installations with total aggregated capacity of 70 MW and to large installations with total aggregated capacity of 30 MW.

e. Basket of other installations

In this basket two auctions for new installations are provided.

The auction for small installations is addressed to solar energy installations, but other installations can also take part in this auction:

  • Small onshore wind energy Installations (320 PLN)
  • Small installations using solar energy (450 PLN)
  • Hydro-electric small installations (480 PLN)—installations with efficiency <3504 MWh/MW/year

The last auction in this basket, in December 2016, was the only auction where the bids outstripped available volume (from 152 bids only 84 were chosen). Keen interest is also expected this year, although funds allocated to the auction are nearly three times larger. It is planned that support will be obtained by installations with total capacity of approximately 300 MW in this auction. If solar plants obtain the said support, it will mark a significant increase in the capacity of these installations. The installed capacity of solar energy installations in Poland and the contemplated impact of the auction in 2017 on this capacity is presented in Figure no 3.

Figure no. 3 Installed capacity in PV plants in Poland (in MW)

Source: Data disclosed by President of the ERO. The data concerning the capacity from the auction presents only the estimation of the Ministry of Energy. In 2016 it was intended to support approx. 100 MW of new power, but only 84 offers were chosen in the auction. The aggregated capacity of these offers is unknown, but as the auction was addressed to small installations their aggregated capacity may not exceed 84 MW.

Keen competition is expected in the auction for large installations, which is addressed to wind energy plants. The following installations can take part in this auction:

  • Large onshore wind energy installations (350 PLN)
  • Large installations using solar energy (425 PLN)
  • Large offshore wind energy installations (470 PLN)—installations with efficiency <3504 MWh/MW/year

Keen competition is expected in this basket, which is dominated by onshore wind energy installations. There are two main reasons for this. First, the planned budget provides support for approx. 150 MW, which might be significantly lower capacity than available for existing projects that can submit bids in this auction. In practice, if bids are submitted in the auction for the new installations with higher effectiveness than the level used for the calculation by the government, the volume of offered electricity from these installations will be proportionally higher. In this case, support will be allocated to installations within limits closer to 100 MW of new generation capacity. Second, the negative approach of the current government to wind farms is not a secret. Therefore it is conceivable that the auction in 2017 will be the last one in a few years with funds allocated to this basket. Moreover, the entry into force of the Act of 20 May 2016 on investments concerning wind turbines stipulates that a building permit for wind turbines issued on the basis of zoning decisions will expire if the occupancy permit is not obtained for the wind turbine by 1 July 2019. Based on our own knowledge, quite a large number of wind turbines were developed on the basis of zoning decisions (not on the basis of local zoning plans, as required by the abovementioned Act). Therefore, in light of the time required to build wind turbines, this auction may be the last chance some wind farms have of obtaining the state aid they need to ensure financial profitability of the project, in light of the occupancy permit issue. Building permits for many projects face expiry, and it may prove impossible to obtain new building permits under the new Act.

Appendix no 1
Reference Prices obliging in 2017 (in PLN/MWh)

Appendix no 2
Summary of auctions in 2017 in the order set by the Minister of Energy

 


  1. There are RES installations which started production of renewable energy before 1 July 2016 (existing installations) and after 1 July 2016 (new installations);
  2. There are installations with capacity of up to 1 MW (small installations) and those with capacity of more than 1 MW (large installations).
  3. From 1 January 2018, only RES installations with a capacity less than 500 kW and agricultural biogas installations will be able to benefit from mandatory purchase of electricity.
  4. Taking into account that currently known connection conditions for off-shore installations book capacity around the 1000 MW threshold, exceeding many times the assumed budget of auctions, we treat participation of investors based on this technology as purely hypothetical.
Financial parameters of auctions for renewable energy sources

Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

On 30 November 2016, the European Commission officially unveiled the latest instalment of its ongoing Energy Union initiative, which will reform some of the central pieces of EU energy legislation.  Referred to in advance as the “Winter Package” (not to be confused with the rather more limited package released in February 2016), it has been published as the “Clean Energy for all Europeans” proposals and is the most significant series of proposals yet to emerge under the Commission’s “Energy Union” brand.  It will have far-reaching implications within and potentially beyond the existing EU single energy market.

There is a lot to consider in these proposals, and we will return to some of the issues they raise in more depth and from other perspectives in future posts. What follows is an overview and some initial thoughts from a predominantly UK-based viewpoint.

Important though it is, many of the Winter Package’s proposed reforms are evolutionary rather than revolutionary.  Some could even be criticised for lacking ambition.  The Commission’s proposals certainly provide opportunities for newer technologies such as storage and demand side response and for those seeking to make use of newer commercial models such as aggregation or community energy schemes, but all these groups are still likely to need to work hard in many cases to exploit the leverage that the new rules would give them.  It is interesting that what has been picked up most in early news reports of the Winter Package is the Commission’s move to end subsidies for coal-fired plant.  This is a significant step, but it is only one part of a complex and multi-layered set of draft legislative measures, and is one of the few instances in those measures of a provision that overtly tilts the playing field in favour of or against a particular technology in a new way.

The story so far

Let’s begin by reminding ourselves what Energy Union is about. The project is said to have five “dimensions”.  These are:

  • Security, solidarity & trust: the buzz-words are “diversification of supply” and “co-operation between Member States” – all informed by anxieties about over-dependence on Russian gas.
  • A fully-integrated internal energy market: going beyond the 2009 “Third Package” of gas and electricity market liberalisation measures (and their ongoing implementation through the promulgation of network codes) to achieve genuine EU-wide single gas and power markets.
  • Energy efficiency: using less energy can be hard, but it is the best way to meet environmental objectives and it can also be a significant source of new jobs and economic growth.
  • Climate action – decarbonising the economy: signing and ratifying the Paris CoP21 Agreement was the easy bit.  How is the EU going to achieve deep decarbonisation of not only its power but also its heat and transport sectors so as to meet its UNFCCC obligations?
  • Research, innovation & competitiveness: can European businesses still take the lead in developing technologies that will save the planet, and also make money out of commercialising them?

In other words, Energy Union is about everything that matters in EU energy policy.  To date, at least in relation to electricity markets, the initiative has involved a lot of consultation but not many concrete legislation proposals.  The new Winter Package goes a long way towards redressing this balance, but it shows there is still a lot of work to do.

What is in the Winter Package?

The documents published by the Commission (all available from this link) include legislative proposals and a range of explanatory and background policy documents.  The legislative proposals are for:

We comment below on what seem to us at this stage to be the most interesting points in these, and also on the Communication on Accelerating Clean Energy Innovation (the Innovation Communication).

The Revised IMED

Overall impressions

The legislative elements of the Winter Package are all inter-related, but the Revised IMED is as good a place to start as any.  Its early articles include two programmatic statements:

  • National legislation must “not unduly hamper cross-border flows of electricity, consumer participation including through demand-side response, investments into flexible energy generation, energy storage, the deployment of electro-mobility or new interconnectors”.
  • Electricity suppliers must be free to determine their own prices.  Non-cost reflective power prices should only apply for a transitional period to vulnerable customers, and should be phased out in favour of other means of support except in unforeseeable emergencies.

In some ways, this sets the tone for the more specific provisions that follow.  It often seems that the Commission never loses an opportunity to put forward legislation in the form of a directly applicable Regulation rather than in the form of a Directive that by definition requires Member States to take implementing measures in order fully to embed its effect within national regulation.  However, the revised IMED, like its predecessor, stands out as a classic old-school Directive, in which EU legislators tell Member States lots of results to be achieved, but do not prescribe many of the means by which this is to happen.  Moreover, even the expression of those objectives is (inevitably) qualified: in other words, get rid of the barriers to the Commission’s vision of Energy Union, except the ones you can justify.  Of course, that is slightly unfair: as noted below, there are at least one or two eye-catching points in the revised IMED, and there are significant changes proposed in other parts of the Winter Package that should further the objectives of the revised IMED, but it arguably demonstrates less willingness to get to grips with some of the most difficult of the longer-term and more fundamental changes in the market than the call for evidence on moving towards a smart, flexible energy system that was published on 10 November by the UK government and GB energy regulator Ofgem (although admittedly the UK authorities are only asking questions, not proposing solutions at this stage).

A market for consumers (and prosumers)

The revised IMED would enhance the rights of consumers generally in a variety of ways.  For example:

  • Price increases are to be notified and explained in advance, giving them the opportunity to switch before an increase takes effect.  Switching must take no longer than three weeks.
  • Termination fees may only be charged where a fixed term contract is terminated prematurely, and must not exceed the direct economic loss to the supplier.
  • All consumers are to be entitled, on request, to a “dynamic electricity price contract” which reflects spot market price fluctuations at least as frequently as market settlement occurs.  They will of course need smart meters to make this work (see further below).
  • All consumers are to be entitled to contract with aggregators, without the consent of their supplier, and to end such contracts within three weeks.

In addition, special consideration is given to two newly defined categories of persons.

  • “Active consumers” are defined as individuals or groups “who consume, store or sell electricity generated on their premises, including through aggregators, or participate in demand response or energy efficiency schemes”, but who do not do so commercially / professionally.
  • “Local energy communities” are defined as organisations “effectively controlled by local shareholders or members, generally non-profit driven or generally value rather than profit-driven…engaged in local energy generation, distribution, aggregation storage, supply or energy efficiency services, including across borders”.

Active consumers are to be:

  • entitled to undertake their chosen activities “in all organised markets” without facing disproportionately burdensome procedures or charges; and
  • encouraged to participate alongside generators in all organised markets.  Obviously in most cases they will do this through aggregators, who are to be treated “in a non-discriminatory manner, on the basis of their technical capabilities”.  For example, they are not to be required to pay compensation to suppliers or generators (contrary to some of the suggestions in the UK call for evidence referred to above).

Local energy communities:

  • are similarly not to be discriminated against;
  • may “establish community networks and autonomously manage them” and “purchase and sell electricity in all organised markets”;
  • must not make participation in a local energy community compulsory, or limit it to those who are shareholders in or members of the community; and
  • will be subject to the unbundling rules for distribution system operators if they are DSOs.

As in the original Directive 2009/72/EC, there are provisions requiring improvements to customer billing and encouraging the rollout of smart meters.

  • Customers should receive bills once a month where remote reading of the meter is possible.
  • Where a Member State has decided not to mandate smart meters for cost-benefit reasons, they are to revisit their assessment “periodically” and report the results to the Commission.
  • The draft Directive sets out functionalities that smart meters must include where a Member State mandates their rollout.  In such cases, the costs of smart metering deployment are to be shared between all consumers.  In other cases, every customer is entitled, on request, to receive a smart meter that complies with a slightly reduced set of functionalities.
  • The implementation of smart metering must encourage active participation of consumers in the electricity supply market (although this may be qualified by a cost-benefit analysis).
  • There are a number of provisions reflecting both concerns about cybersecurity and the importance of making useful data securely available to legitimate market participants.

DSOs (and EVs)

There has been no shortage of recent commentary on how the shift towards decentralised generation of electricity, combined with the potential for storage and more active consumer behavior, may require changes in the role of the 2,400 market participants that the IMED has always called distribution system operators, but which in many jurisdictions have historically not had, even within their own networks, the kind of “system operator” responsibilities of a transmission system operator.  The recent UK call for evidence on flexibility appears at least prepared to contemplate some significant realignment of the respective functions of DSOs and TSOs.  There is nothing so fundamental in the revised IMED, but there are a number of new provisions about DSOs.

  • DSOs are to be allowed, and incentivised, to procure services such as distributed generation, demand response and storage in order to make their networks operate more efficiently.  DSOs will be paid for this, and must specify standardised market products for these services.
  • Every two years, DSOs must update five to ten year network development plans for new investments, “with particular emphasis on the main distribution infrastructure which is required…to connect new generation capacity and new loads including re-charging points for electric vehicles”, as well as demand response, storage, energy efficiency etc.
  • DSOs serving isolated systems or fewer than 100,000 consumers can be excused from this requirement, but note that in general, those operating “closed distribution systems” are to be subject to the same rules as other DSOs under the revised IMED.

However, although DSOs are to facilitate the adoption of new technologies, such as storage and EVs, they are not encouraged to diversify into actually providing them to end users themselves.

  • Member States are to facilitate EV charging infrastructure from a regulatory point of view, but DSOs may only “own, develop, manage or operate” EV charging points if the regulator allows them to after an open tender process in which nobody else expresses an interest in doing so.  And even then, the service taken on by the DSO must be re-tendered every five years.
  • Similar rules would apply to the development, operation and management of storage facilities by either DSOs or TSOs.  For TSOs, there would be an additional requirement that the storage services or facilities concerned are “necessary” to ensure efficient and secure operation of the transmission system, and are not used to sell electricity to the market.

What makes these provisions significant is that until now, with the IMED in its original form silent on the subject of storage, the operation of storage facilities had been seen as potentially falling within the categories of generation or supply.  This appeared to make the involvement of DSOs or TSOs in storage projects (at least as investors) subject to the general unbundling restrictions, and so has tended to inhibit the progress of energy storage initiatives in a number of cases.  The proposed new rules are restrictive in some respects, but bring a degree of clarity and at least recognise storage as a distinct category.

The Revised Market Regulation

General organisation of the electricity market

Like the revised IMED, the Revised Market Regulation begins with firm statements of purpose: enabling market access for all resource providers and electricity customers, enabling demand response, aggregation and so on.  It goes on to list 14 “principles” with which “the operation of electricity markets shall comply” – starting with “prices are formed based on demand and supply” and finishing with “long-term hedging opportunities allow to hedge parties against price volatility risks”.

Entirely in keeping with these principles, the first specific provision is that all market participants are to be responsible for (or to delegate to a responsible third party) the consequences of any imbalance they create in the electricity system as a result of importing or exporting to or from the grid at a given time more or less than they had said would be the case at that time in previous notifications to the system operator.  This much-trailed provision may be a significant change for renewable generators in some jurisdictions (though not in GB, where imbalance charging reforms are already being implemented).  In an earlier draft, the Revised Market Regulation only permitted sub-500kW renewables or high-efficiency CHP to be exempted from this requirement.  In the published version, this exemption has been broadened to include RES projects that have received state aid that has been cleared by the commission and that have been commissioned before the Revised Market Regulation enters into force.  It also requires that “all market participants” are to have access to the balancing market on non-discriminatory terms, either directly or through aggregators.

There are a number of quite detailed provisions on the overall organisation of electricity markets. We pick out a few of the more notable ones below.

  • There is a shift from a national to a regional approach.  As the explanatory memorandum to the draft Directive puts it: “In certain areas, e.g. for the EU-wide ‘market coupling’ mechanism, TSO cooperation has already become mandatory, and the system of majority voting on some issues has proven to be successful…Following this successful example, mandatory cooperation should be expanded to other areas in the regulatory framework.  To this end, TSOs could decide within ‘Regional Operational Centres’…on those issues where fragmented and uncoordinated national actions could negatively affect the market and consumers (e.g. in the fields of system operation, capacity calculation for interconnectors, security of supply and risk preparedness).”.  Functions to be carried out at a regional level include “the dimensioning of reserve capacity” and “the procurement of balancing capacity”.
  • As far as possible, the organisation of markets is to avoid any rules that could restrict cross-border trading or the participation of smaller players.  So, for example, trades are to be anonymous and in a form that does not distinguish between bidders within and outside a bidding zone.  The minimum bid size is not to exceed 1 MW.
  • Market participants are to be able to trade energy as close to real time as possible, with imbalance settlement periods being set to 15 minutes by 1 January 2025.
  • Long-term (firm, and transferable) transmission rights or equivalent measures are to be put in place to enable e.g. renewable generators to hedge price risks across bidding zone borders.  Such rights are to be allocated in a market-based manner through a single allocation platform.
  • As a general rule, there must be no direct or indirect caps or floors on wholesale power prices, other than a cap at the value of lost load and a floor of minus €2000, or during a 2-year transitional period when a transitional maximum and minimum clearing price may be allowed.  Defined as “an estimation in €/MWh of the maximum electricity price that consumers are willing to pay to avoid an outage”, the value of lost load is to be defined nationally and updated at least every five years.  This concept will evidently need refinement, as there is a difference between what individual consumers may be prepared to pay and the kind of price spikes that it is reasonable for wholesale markets to bear for short periods of time.
  • Dispatching of generation and demand response is to be market-based.  Priority dispatch for renewables is to be brought to an end subject to certain exceptions (these are summarised in the section on the revised RED below).  On the other hand, where redispatch (changing generator output levels) or curtailment is imposed by the system operator other than on market-based criteria, the draft Regulation imposes restrictions on when RES, high-efficiency CHP and self-generated power can be redispatched or curtailed.
  • There is to be a review of the bidding zones within the single electricity market, so as to maximise economic efficiency and cross-border trading opportunities while maintaining security of supply.  In other words, the market coupling process should allow customers to benefit from the availability of lower-priced wholesale power in adjacent markets, but the bidding zone boundaries need to take account of “long-term structural congestion” in the network infrastructure for this to be workable and without adverse side-effects.  TSOs are to participate in the review, but the final decisions are to be taken by the Commission.
  • A significant piece of work is to be undertaken by ACER on “the progressive convergence of transmission and distribution tariff methodologies”.  This is to include, but not be limited to, some issues that have recently proved contentious in the GB context, including the respective shares of tariffs to be paid by those who generate and those who consume power; locational signals (how much more should generators pay if they are located a long way from where the power they generate used); and which network users should be subject to tariffs (would this, for example, open up the question of whether generators connected to the distribution network should pay a share of transmission network charges?).
  • Separately, the draft Regulation sets out some general principles about network charges and restricts both the circumstances in which revenue can be generated from congestion management and the uses to which such revenue can be put.

Resource adequacy (a.k.a. Capacity Markets)

The growth in the share of installed generating capacity in many Member States represented by intermittent renewable generators and the unattractive economics of new large-scale combined cycle gas-fired plant has left many governments in the EU concerned about security of power supply and turning to various forms of capacity market subsidy in order to ensure that the lights stay on.  The Commission has been concerned that capacity markets dampen the price signals that should drive new investment and potentially introduce new barriers to cross-border power flows.  A number of national capacity market regimes have been investigated by the Commission’s DG Competition; both the UK and French approaches to the problem have received state aid clearance.

The starting point of the draft Regulation in this area is an annual assessment of “the overall adequacy of the electricity system to supply current and projected demands for electricity ten years ahead”.  This European-level assessment will form the yardstick against which national proposals to introduce a capacity mechanism are to be judged.  If it has “not identified a resource adequacy concern, Member States shall not introduce capacity mechanisms” and no new contracts shall be concluded under existing capacity mechanisms.  Where capacity mechanisms are introduced, they must not distort the market unnecessarily; interconnected Member States should be consulted; and other approaches, such as interconnection and storage, should be considered first.

The draft Regulation prescribes common elements which capacity mechanisms must contain, including that they must be open to providers in interconnected Member States (unless they take the form of strategic reserves) and that the authorities of one country must not prevent capacity located in their territory from participating in other countries’ capacity mechanisms.  Those participating simultaneously in more than one capacity mechanism “shall be subject to two or more penalties if there is concurrent scarcity in two or more bidding zones that the capacity provider is contracted in”.  Maybe that will help to dampen industry’s appetite for capacity markets.

Finally, the draft Regulation sets an emission limit of 550 gCO2/kWh for plant on which a final investment decision is made after the Regulation enters into force.  Such plant must have emissions below this limit if it is to be eligible for capacity mechanism support.  The draft Regulation goes on to state that generation capacity emitting at this level or higher is “not to be committed in capacity mechanisms 5 years after the entry into force of this Regulation”.  These provisions may be motivated by laudable decarbonisation objectives, but they must at the very least risk precipitating a rush to take final investment decisions in new coal-fired generating capacity over the next two years.  It is possible, but unlikely, that they might stimulate further investment in carbon capture and storage (to bring the emissions of coal-fired plants below the threshold).  Previous experience with emissions limit rules also suggests that much will depend on how emissions are measured – the usual trick of polluting plant being to argue that they should be counted not per hour of generation, but averaged out over time so as to allow for plant to run above the limit for short periods.  This is bound to be an area for lively negotiations between Member States and in the European Parliament.

The Commission’s proposals in relation to capacity markets need to be read alongside DG Competition’s final report on its investigation and the accompanying Staff Working Paper.  We will look in more detail at this aspect of the proposals and how it might affect existing Member State initiatives in a future post.  For now, it is sufficient to note that although this part of the Winter Package is entirely consistent with the logic of the evolving single electricity market, for some, it may simply appear to be an unacceptable blow to the principle of Member States’ self-determination of their own generating mix.

Institutions

In addition to its existing roles, the TSO umbrella body, ENTSO-E, will acquire new responsibilities for the European resource adequacy assessment and in relation to the Regional Operational Centres, including adopting a proposal for defining the regions which each will cover, and generally monitoring and reporting on their performance.  A parallel umbrella body for DSOs, with consultative functions, is also to be set up.

The draft Regulation devotes a number of articles to the Regional Operational Centres. They will be limited liability companies established by TSOs (with adequate cover for potential liabilities incurred by the impact of their decisions).  Their role is to complement TSO functions by ensuring the smooth operation of the interconnected transmission system, but apparently from the perspective of planning and analysis rather than real-time  operational control.  Specific areas of their work (listed under 17 headings) include outage planning coordination, calculating the minimum entry capacity available for participation of foreign capacity in capacity mechanisms, and much else besides.

This area of the draft Regulation will need careful development and implementation if the proliferation of new bodies and functions is not to result in confusion and a lack of accountability.  However, the question of whether to grant Regional Operational Centres binding decision-making powers in relation to some of their potential functions is left to be decided by the national regulatory authorities of a system operating region.

The Revised RED

Target for 2030

The existing Renewable Energy Directive (2009/28/EC) sets out the binding national targets for each Member State to achieve a specified proportion of its energy consumption to be obtained from renewable energy sources (RES) by 2020, contributing to an EU-wide goal of 20% of final energy from RES.  The revised RED starts from a slightly different point, since EU leaders decided in 2014 to move away from legally binding national RES targets imposed at EU level but to set a goal of achieving at least 27% of energy from RES across the EU by 2030.  The starting point of the revised RED, therefore, is that “Member States shall collectively ensure” that the 27% target is achieved by 2030, whilst, individually, ensuring that they continue to obtain at least as high a proportion of final energy from RES as they were obliged to achieve by 2020.

At this point, you may ask what the enforcement mechanism is for meeting the new EU-wide target.  An answer (of sorts) is to be found in the Governance Regulation – see below.

Power (plus)

With reference to subsidies for RES, the revised RED builds on the principles set out in the Commission’s 2014 guidelines on state aid in the energy and environmental sectors: competitive auctions in which all technologies can compete on a level playing field are to be the norm, with traditional feed-in tariffs limited to small projects.

The revised RED also makes provision on two points that have led to disputes in connection with RES subsidies.  First, picking up on a point that has in the past given rise to litigation under general EU Treaty principles, it would set quotas for the proportion of capacity tendered in RES subsidy auctions that each Member State must throw open to projects from other Member States.  Second, with an eye to the numerous cases brought against Member States either under domestic constitutional / administrative law or under the Energy Charter Treaty, the revised RED attempts to outlaw retrospective reductions in support for RES once that support has been awarded, unless these are required because a state aid investigation by the Commission has found the subsidy received by a project is unduly generous.  Note that while the first of these rules appears to relate only to RES electricity subsidies, the second is expressed in a way that suggests that it relates to all RES projects.   An additional measure of reassurance for investors is a requirement to consult on and publish “a long-term schedule in relation to expected allocation for [RES] support” looking at least three years ahead.

Other points of interest in the draft Directive in connection with RES power include:

  • In a magnificently brief reference to one of the most important market trends in the renewable power sector, the revised RED would require Member States to “remove administrative barriers to corporate long-term power purchase agreements to finance renewables and facilitate their uptake”.
  • The process of applying for permits to build and operate new RES projects is to be streamlined, with a single point of contact co-ordinating the permitting process (including for associated network infrastructure) and ensuring that it does not last longer than three years.  This provision would confers on all RES projects (again, the current language of the draft Directive does not limit this to power sector projects) a benefit currently only conferred at EU level under the Infrastructure Regulation on those projects singled out as Projects of Common Interest – although in its current form it is questionable if it would give a developer thwarted by slow decision-making in a given case a useful remedy.
  • The permitting procedures for repowering of existing projects are to be “simplified and swift” (i.e. not to last more than 1 year), although this may not apply if there are “major environmental or social” impacts.  If you were hoping to be able to demand fast-track treatment for applications to repower existing wind farms with fewer, taller turbines generating more power, don’t hold your breath.
  • The existing RED rules on priority dispatch for RES generators are to be abolished.  This point is reiterated in the Revised Market Regulation.  However, that draft Regulation provides for “grandfathering” of priority dispatch rights for existing RES (and high efficiency CHP) generators until such time as they undergo “significant modifications”.  Exceptions are also permitted for innovative technologies and sub-500kW installations (from 2026, sub-250kW), if no more than 15% of total installed generating capacity in a given Member State benefits from priority dispatch (beyond that level, the threshold is 250kW or 125kW from 2026).
  • The revised RED likes prosumers, or as it calls them, “renewable self-consumers”.  They are to be entitled to sell their surplus power “without being subject to disproportionate procedures and charges that are not cost reflective”, to receive a market price for what they feed into the grid, and not to be regulated as electricity suppliers if they do not feed in more than 10MWh (as a household) or 500MWh (as a business) annually (Member States may set higher limits).
  • The revised RED also likes “renewable energy communities”.  The draft definition of these is a little complicated, but essentially they are locally based entities that are either SMEs or not for profit organisations, which are to be allowed to generate, consume, store and sell renewable electricity, including through PPAs.

Heat, cooling and transport

The revised RED seeks to “mainstream” RES in heating and cooling installations, and in the transport sector.  The means by which it seeks to achieve this are not, at first sight particularly dramatic, given the acknowledged scale and difficulty of the challenge of decarbonising these sectors.

In relation to heat and cooling, Member States are to identify “obligated parties amongst wholesale or retail energy and energy fuel suppliers” and require them to increase the share of RES in their heating and cooling sales by at least 1 percentage point a year.  The obligation should be capable of being discharged either directly or indirectly (including by installing or funding the installation of highly efficient RES heating and cooling systems in buildings).  This does not seem hugely ambitious.  Mention is made of “tradable certificates” – it feels a bit like a combination of the Renewables Obligation, but applied to heat and cooling, and the Clean Development Mechanism under the Kyoto Protocol.  It is also relevant in this context that the revised RED envisages that renewable guarantees of origin (REGOs or GoOs) will in future be available for the production and injection into the grid of renewable gases such as biomethane.

The rules aimed at the transport sector are also based on mandatory requirements on fuel suppliers – in this case to incorporate both a minimum (annually increasing) percentage of certain kinds of RES fuel, waste-based fossil fuel and RES electricity into the transport fuel they supply and to ensure that the parts of that supply that take the form of advanced biofuels and biogas from specified sources (which must constitute a certain part of the overall RES percentage) contribute to an increasing reduction in greenhouse gas emissions.  The provisions for calculating the various percentages are quite complex, involving as they do an element of lifecycle emissions calculation (e.g. considering the emissions from the generation of electricity used to produce advanced biofuels).

On district heating and cooling, the revised RED takes a three-pronged approach.

  • Member States are to ensure that authorities at local, national and regional level “include provisions for the integration and deployment of renewable energy and the utilisation of unavoidable waste heat or cold when planning, designing, building and renovating urban infrastructure, industrial or residential areas and energy infrastructure, including electricity, district heating, and cooling, natural gas and alternative fuel networks”.
  • The efficiency of district heating systems is to be certified.  Providers of such systems must grant access to new customers where they have the capacity to do so (unless they are new and meet exemption criteria based on efficiency and use of renewables).  Customers of systems that are not efficient may disconnect from them in favour of their own RES heat and cooling, but Member States may restrict this right to those who can demonstrate that the customer’s own heating or cooling solution is more efficient.
  • There is to be regular consultation between operators of district heating and gas / electricity networks about the potential to exploit synergies between investments in their respective networks.  Electricity network operators must also assess the potential for using district heating and cooling networks for balancing and energy storage purposes.

This is all unobjectionable.  It is not clear that in itself it will be enough to cause a major expansion of district heating and cooling where it does not already exist, or to significantly increase the take-up of RES heat and cooling options, but perhaps this is the kind of area where an effective policy push can only be delivered at national, or indeed municipal level.

Biomass

Following a trend that has been evident for some time in UK subsidies for RES electricity, the revised RED would appear to prohibit “public support for installations converting biomass into electricity” unless they apply high efficiency CHP, if they have a fuel capacity of 20 MW or more.  However, the precise words setting this out have been moved from the operative provisions of the draft Directive into a recital, which also clarifies that this would not require the termination of support that has already been granted to specific projects, but that new biomass projects will only be able to be counted towards renewables targets if they apply high efficiency CHP.

What is clear is that the revised RED would tighten the sustainability criteria applicable to biofuels and bioliquids at various points in the energy supply chain, with greenhouse gas emissions – for example those arising from land use to grow the raw materials that become biofuels – being designated as a distinct impact to be measured.  If you dig up soil with a high carbon content to grow something that will become biofuel, you may end up increasing rather than reducing overall GHG emissions, so this is obviously to be avoided.

The Governance Regulation

The Governance Regulation is meant to hold everything together.  In particular, it aims to give credible underpinning to the commitments on climate change that the EU as a whole has made under the Paris Agreement (but which must ultimately be delivered by Member State action) and to bridge the gap left by having an EU level 2030 renewables target but no correspondingly increased Member State level targets.  It also gives legislative expression to the EU’s Union-level energy and climate targets to be achieved by 2030, which are:

  • a binding target of at least 40% domestic reduction in economy-wide greenhouse gas emissions as compared with 1990;
  • a binding target of at least 27% for the share of renewable energy consumed in the EU;
  • a target of at least 27% for improving energy efficiency in 2030, to be revised by 2020, having in mind an EU level of 30%;
  • a 15% electricity interconnection target for 2030.

In outline, the Regulation works as follows.

  • Every 10 years, starting in 2019, each Member State is to produce an integrated national energy and climate plan covering a period of ten years, two years ahead (so e.g. the 2019 plan covers 2021 to 2030, and so on).  The plan is to set out, in relation to each of the five dimensions of the Energy Union, the current state of play in the relevant Member State; the national objectives and targets, policies and measures they have adopted; and their projections (including in relation to emissions) going forward to 2040.  The draft Regulation sets out in considerable detail the information which is required to be included.
  • In relation to RES and energy efficiency, Member States are expressly required to take into account the need to contribute towards achieving the relevant EU level targets, and to ensure, collectively, that they are met.  In relation to RES policies, they are also to take into account “equitable distribution of deployment” across the EU, economic potential, geographic constraints and interconnection levels.
  • The draft Regulation states that Member States must consult widely on the plans and suggests that there may also be a need for the preparation of and consultation on a strategic environmental assessment of the draft plans in some cases.
  • Every two years (starting in the first year to which the plans apply), Member States are to report to the Commission on the status of implementation of their plans; on GHG policies, measures and projections; on climate change adaptation and support to developing countries; on progress in relation to renewable energy, energy efficiency and energy security; on internal market benchmarks such as levels of interconnectivity; and on public spending on relevant research and innovation projects.  In addition, the draft Regulation specifies how Member States are to report annually on GHG inventories for UNFCCC purposes.
  • The plans and drafts are to be updated if necessary after five years (with the first draft update in 2023 and the first update in 2024), using the same procedures.  Updates cannot result in Member States setting themselves lower targets.
  • The plans are first to be submitted to the Commission for comment one year in advance, in draft (i.e. first draft by 1 January 2018).  Either at this point or in its annual State of the Energy Union reports, the Commission may make recommendations to individual Member States, for example about “the level of ambition of objectives and targets” in its draft plan, and Member States “shall take utmost account” of these when finalising the plan.  Member States are obliged to issue annual progress reports on their plans and these must include an explanation of how they have taken utmost account of any Commission recommendations and how it has implemented or intends to implement them.  Any failure to implement the Commission’s recommendations must be justified.
  • Member States whose share of RES falls below their 2020 baseline must cover the gap by contributing to an EU-level fund for renewable projects.  If it becomes clear by 2023 that the 2030 RES target is not going to be met, Member States must cover the gap in the same way, or by increasing the percentage of RES fuel to be provided by heat and transport fuel suppliers under the revised RED, or by other means.  Action may also be taken by the Commission at EU level.

The answer to the question of how the 2030 targets are enforced is therefore – and perhaps inevitably – somewhat incomplete.  Whilst one may doubt the usefulness, under the current RED, of the prospect of the Commission taking infraction proceedings against a Member State that fails to reach the required percentage of RES energy by 2020, there is arguably nothing in the Governance Regulation that has even this degree of legal bite when it comes to pushing recalcitrant Member States into action from the centre.  However, ultimately the whole edifice of the Paris Agreement, of which this is effectively a supporting structure, will only work on the basis of a combination of the economic attractions of better energy efficiency, cheaper renewables and other technological advances, and stakeholder pressure, including through democratic and judicial processes.  The Governance Regulation, like the UK’s Climate Change Act 2008 with its system of carbon budgets, certainly provides some scope for interested parties to challenge national authorities who are, for example, failing unjustifiably to implement Commission recommendations.

The Risk Regulation

The Risk Regulation exists to provide “a common framework of rules on how to prevent, prepare for and manage electricity crisis situations, bringing more transparency to the preparation phase and…ensuring that electricity is delivered where it is needed most”.  A common approach to identifying and quantifying risks is seen as essential to building the necessary “trust” and “spirit of solidarity” between Member States.  The draft Regulation would replace the rather less ambitious existing Directive 2005/89/EC.

ENTSO-E is tasked with developing a common risk assessment methodology, on the basis of which it is to draw up and update regional crisis scenarios such as extreme weather conditions, natural disasters, fuel shortages or malicious attacks.  Provision is made for emergency planning at both national and regional levels, with the Regional Operational Centres playing a significant role at various points.  As throughout the Winter Package, emphasis is laid on using market measures wherever possible, so that forced disconnections, for example, should be response of last resort, and Member States facing a crisis should not automatically seek to curtail outbound cross-border power flows.

The ACER Regulation

It comes as no surprise that the Winter Package proposes conferring more powers on ACER.  So, for example, the methodologies and calculations underlying the European resource adequacy assessment will require the approval of, and may be amended by, ACER – since, as one of the recitals to the draft Regulation notes, “fragmented national state interventions in energy markets constitute an increasing risk to the proper functioning of cross-border electricity markets”.  But the draft Regulation is far from representing a major transformation of ACER into an EU energy super-regulator.

The Innovation Communication

The Innovation Communication picks up on a number of the themes emphasised in the various legislative proposals.  It builds on existing initiatives, for example within the framework of the EU’s Horizon 2020 funding programme, for which it includes some new money.  The need to leverage more private sector investment in innovative energy-related technologies is noted, with some examples of where this has already been achieved.  The Communication also states that the Commission, with Member States, will take a leading role in two of the workstreams identified by the international Mission Innovation Initiative.

Four particular priorities are singled out as technology focus areas for EU innovation funding:

  • Energy storage solutions, including the (perhaps not unambitious) objective of “re-launching the production of battery cells in Europe”.
  • Electro-mobility and a more integrated urban transport system, which amongst other things will include tackling “fragmentation in the developing market of low-emission transport”.
  • Decarbonising the EU building stock by 2050: going beyond “today’s nearly zero-energy designs” to include e.g. the application of circular economy principles.
  • Integration of renewables: reducing the costs of existing established technologies; promoting new technologies like building-integrated photovoltaics; and intensifying efforts to integrate renewables through storage and the transport sector.

Energy Efficiency

Last but not least, energy efficiency. The two draft Directives on this make less wide-ranging changes to the existing legislation.

Under the revised Energy Efficiency Directive, Member States will be obliged to deliver the equivalent of 1.5% of annual energy sales (by volume) to final consumers over the period 2021-2030 – but with scope to determine how those savings are phased.

As regards the Energy Performance of Buildings Directives, there is an emphasis on encouraging the use of smart technologies.  There is also a requirement, when building or carrying out major renovations of buildings with more than 10 car parking spaces, to install one alternative fuel re-charging point for every 10 spaces in a non-residential context and to put in pre-cabling for re-charging points for EVs in all spaces in a residential context.  In the non-residential context at least, the re-charging point must be “capable of starting and spotting charging in relation to price signals”.  There are also some new requirements to monitor the energy efficiency of non-residential buildings, presumably in the hope that if their owners become aware of how much inefficiencies of design or operation are costing them, they will invest in improvements.

At the same time, the Commission has issued an ecodesign working plan for 2016-2019, reminding us as it does so that EU ecodesign and energy labelling deliver “energy savings equivalent to the annual consumption of Italy” and “save almost €500 per year” on household energy bills, as well as delivering approximately €55 billion extra revenue for industry.

Brexit

One of the many energy-sector questions raised by the UK’s decision to leave the EU is on what terms participants in the electricity markets in GB and Northern Ireland (and indeed the Republic of Ireland, until such time as it has a direct interconnection with Continental Europe) may be able to continue to participate in the EU’s single electricity market in a post-Brexit world.  Possible models for this include membership of the European Economic Area (as an EFTA, rather than an EU state) or joining the Energy Community (many of whose members are candidates for EU membership, but disputes within which are resolved by a political Association Council without reference to the Court of Justice of the EU).

The Winter Package in its published form casts no direct light on this subject.  However, in a version of the main legislative proposals that was leaked only a couple of weeks before they were published, a number of the draft measures (such as the draft revised IMED) included a couple of articles that appeared to offer some grounds for hope – if continued UK membership of the single EU electricity market is the sort of prospect that makes you hopeful.

  • Like the EU itself, the Energy Community is currently operating on (or is working towards) the version of the single electricity and gas markets set out in the Third Package of EU liberalisation measures adopted in 2009.  The leaked draft revised IMED set out a process for the Energy Community and the Commission to incorporate the revised Directive into the Energy Community’s legislative framework.  So if the UK was happy with the final form of the Winter Package legislation, the option of continuing to be subject to and getting the benefit of it as a member of the Energy Community would be a possible option.
  • On the other hand, once the UK ceases to be an EU Member State, and assuming it does not opt for EEA membership, it will simply become a “third country” (with or without the benefit of a bespoke EU / UK free trade agreement).  The leaked draft revised IMED suggested that third countries may participate in the single electricity market provided that they agree to adopt, and apply, “the main provisions” of the Winter Package legislation; EU state aid rules; the REMIT rules on wholesale energy market integrity; “environmental rules with relevant for the power sector”; and rules on enforcement and judicial oversight that require it to submit either to the authority of the Commission and the CJEU or “to a specific non-domestic enforcement body and a neutral non-domestic Court or arbitration body which is independent from the respective third country”.

Reading these provisions in the UK, it was hard not to see them as drafted with Brexit in mind.  Of course, the EU is, or aspires to be, physically connected to power systems in other non-EU countries as well (such as the potential solar energy exporters of North Africa), so it would be wrong to see them entirely in that light.

How the absence of such provisions, or the prospect of their potential reinsertion, will affect the dynamics of the UK’s participation in negotiations on the Winter Package (which is likely to take place while the UK is still a Member State) is another question.  In our view, the UK and its electricity industry stakeholders should in any event try to play a leading and constructive role in the whole of the negotiations on the Winter Package, as they have in negotiation on past internal energy market measures.

Maybe, in one sense, it is better that the draft provisions on third country participation have not been included at this stage.  Similar provisions could be negotiated on a standalone basis later, and include the gas as well as electricity single markets, for example.  By leaving them out of the Winter Package (for whatever reason), the Commission may have prevented the UK team from being unduly distracted from the main subject of the legislative proposals, or expending its negotiating capital on their Brexit dimension.

Provisional conclusions

The Winter Package covers a lot of ground, but then it needs to do so, since the next ten years are acknowledged to be crucial to the success of global efforts to avoid dangerous climate change.  It may not be as radical as some would like, but then whilst some of its requirements are already more or less met by a number of Member States, for others they may represent a considerable challenge.  In one sense it is a timely reminder of both the scope and the limitations of the European project.

There are a lot of links between the individual pieces of draft legislation.  There are also a number of areas where the drafting suggests that some key concepts have not yet been absolutely fully thought out.  Steering negotiations so as to result in a clear and coherent legal framework will be difficult.  The risks of (calculated or inadvertent) lack of clarity in the final texts may be higher than is usual with EU legislation, leading to wrangles with regulators and before the courts down the line – or simply having a chilling effect on what could be useful activity.  However, since the need for action is urgent, waiting for perfect legislation is not a luxury the EU can afford.  So it is vital that those with an interest in making Energy Union work scrutinise the parts of the Winter Package that matter to them carefully, and tell their national governments or MEPs where they find it wanting.

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Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

First flesh on the bones of the new UK government’s energy policy?

The UK Department of Business, Energy & Industrial Strategy (BEIS) chose 9 November 2016 to release a series of long-awaited energy policy documents.  The substance of some of the announcements, which primarily cover subsidies for renewable electricity generation and the closure of the remaining coal-fired generating plants in England and Wales, was first outlined almost a year ago when Amber Rudd, the last Secretary of State for Energy and Climate Change, “re-set” energy policy in outline in a speech of 18 November 2016.  Broadly speaking, the documents indicate that little has changed in the UK government’s thinking on energy policy following the EU referendum and the formation of what is in many respects a new government under Theresa May.

Contracts for Difference

BEIS has confirmed that the next allocation process for contracts for difference (CfDs) for renewable generators will begin in April 2017, aiming to provide support for projects that will be delivered between 2021 and 2023. There will be no allocation of CfD budget for onshore wind or solar, consistent with the Government’s view that these are mature and/or politically undesirable technologies which should no longer receive subsidies.  The only technologies supported will be offshore wind, certain forms of biomass or waste-fuelled plant (advanced conversion technologies, anaerobic digestion, biomass with CHP) wave, tidal stream and geothermal.

The budget allocation is a total of £290 million for projects delivered in each of the delivery years covered: 2021/22 and 2022/23. Details are set out in a draft budget notice and accompanying note.  CfDs are awarded in a competitive auction process, the details of which are set out in an “Allocation Framework” (the one used for the last auction, in 2014/2015, can be found here).  It is likely that most, if not all, of the budget will be taken up by a small number of offshore wind projects, as the size of the projects which could be eligible to bid in the auction is large in comparison with the available budget.

Competition for CfDs will be fierce and Government should be able to show progress towards achieving its target of reducing support to £85/MWh for new offshore wind projects by 2026. For the 2017 auction, “administrative strike prices” have been set at levels designed to ensure that “the cheapest 19% of projects within each technology” can potentially compete successfully.  Behind this terse statement and the methodology it summarises lies an extensive BEIS analysis of Electricity Generation Costs, underpinned or verified by studies or peer reviews by Arup, Imperial College, NERA, Prof Anna Zalewska, Prof Derek Bunn, Leigh Fisher and Jacobs and EPRI.

The heat is on

Alongside the draft budget notice, BEIS has published two documents about CfD support for particular technologies.

One of these is a consultation that returns to the long-unanswered question of what to do about onshore wind on Scottish islands: should it be regarded as just another species of onshore wind (and therefore not to receive subsidy, in line with post-2015 Government policy), or does it face higher costs to a degree that merits a special place in the CfD scheme, as was suggested by the 2010-2015 Government?  It comes as no surprise that the Government favours the former view: another item to add to the list of points on which the UK and Scottish Governments do not see eye to eye.

The second document is a call for evidence on the currently CfD-eligible thermal renewable technologies of biomass or waste-fuelled technologies (including biomass conversions), and geothermal.  These raise a number of issues, on which the call for evidence takes no clear stance.

  • Is continued support for the fuelled technologies in particular consistent with getting “value for money” by focusing subsidies on the cheapest ways of decarbonising the power supply (except onshore wind and solar), given that (with the exception of biomass conversions), they have a relatively high levelised cost of electricity generation?
  • Can they be justified on the grounds that they are “despatchable” (and so do not impose the same burdens on the system as “variable” renewable generation like wind and solar)?  Or on the grounds that (where they incorporate combined heat and power), they contribute to the decarbonisation of heat, as well as of power generation – an area in which more progress needs to be made soon in order to meet our overall target for reducing greenhouse gas emissions under the Climate Change Act 2008 (and the Paris CoP 21 Agreement)?
  • Is the current relationship between the CfD and Renewable Heat Incentive support schemes the right one in this context?  Is a CfD for a CHP plant unbankable because of the risk of losing the heat offtaker?
  • Are all these technologies about to be overtaken as potential ways of decarbonising the heat sector on a large scale by other contenders such as hydrogen or heat pumps (and if so, is that a reason to abandon them as targets for CfD or other subsidy)?
  • Should more existing coal-fired power stations be subsidised to convert to burning huge quantities of wood pellets (is that really “sustainable” – and would such subsidies comply with current EU state aid rules, for as long as they or something like them apply in the UK)?

Against this background, the draft budget notice proposes to limit advanced conversion technologies, anaerobic digestion and biomass with CHP to 150MW of support in the next CfD auction.

Kicking the coal habit

Finally, BEIS is consulting on the best way to “regulate the closure of unabated coal to provide greater market certainty for investors in the generation capacity that is to replace coal stations as they close, such as new gas stations”.  The consultation needs to be read alongside BEIS’s latest Fossil Fuel Price Projections (with supporting analysis by Wood Mackenzie).  These set out low, central and high case estimates of coal, oil and gas prices going forward to 2040.  BEIS has significantly reduced its estimates for all three fuels under all three cases as compared with those in its 2015 Projections.

We are talking here about eight generating stations, which between them can produce 13.9GW. Their share of GB electricity supply tends to fluctuate with the relative prices of coal and gas.  Most are over 40 years old.  All can only survive by taking steps to comply with the limits on SOx, NOx and dust prescribed by the EU Industrial Emissions Directive – at least for as long as the UK is within the EU.

The Government’s difficulty is how to ensure that these plants close (for decarbonisation purposes), but on a timescale and in circumstances that ensure that the contribution that they make to security of electricity supply is replaced without a gap by e.g. new gas-fired plant, of which so little has recently been built. BEIS evidently hopes that by the time this consultation finishes on 1 February 2017, the results of next month’s four-year ahead Capacity Market auction will have seen a significant amount of new large-scale gas fired power projects being awarded capacity agreements at prices that make them viable (when taken together with expectations of lower-for-longer gas prices).

Although BEIS professes confidence in the changes that it has made to the rules and market parameters for the next Capacity Market auctions, one cannot help but wonder how convinced Ministers are that the 2016 auctions will succeed in this respect where those of 2014 and 2015 failed.  Because from one point of view, if the Capacity Market does result in new large gas-fired projects with capacity agreements, and gas prices remain low, the market should simply replace the existing coal-fired plants – which, as the consultation points out, aren’t even as flexible as modern gas-fired plant.  Maybe if a newly inaugurated President Trump pushes ahead with his plans to revive the use of coal in the US, higher coal prices will help accelerate the closure of some of our remaining coal-fired plants: BEIS calculates that with relatively low coal prices and no Government intervention, they could run until 2030 or beyond.

So how will Government make the plants close? Two options are proposed.  One would be to require them to retrofit carbon capture and storage (CCS), the other would be to require them to comply with the emissions performance standard (EPS) that was set in the Energy Act 2013 for new fossil-fuelled plant with a view to ensuring that no new coal plant was commissioned.  Neither path is entirely straightforward.  As it seems unlikely that operators would invest the kinds of sums associated with CCS on such old plant, there must be a risk that in trying to make CCS a genuine alternative to complete closure, regulations could end up allowing operators to run a significant amount of capacity without CCS whilst taking only limited action to develop CCS capacity.  With the EPS approach, there would be some tricky questions to resolve around biomass co-firing, as well as biomass conversion, if that were to remain an eligible CfD technology and budget were to be allocated to it.

When it comes to consider how to ensure that coal closure does not involve a “cliff-edge” effect, the consultation seems to run out of steam a bit: having mentioned the possibility of limiting running hours or emissions, either on a per plant basis or across the whole sector, BEIS says simply that it would “welcome any views on whether a constraint [on coal generation prior to closure] would be beneficial and, if so, any ideas on the possible profile and design”.

What next?

Nothing stands still.  The period of these consultations / calls for evidence, and the next Capacity Market auctions, overlaps with other processes.  Over the next few months, the Government is scheduled to produce over-arching plans or strategies in a number of areas that overlap with some of the questions posed in these documents.  It will also continue to develop its strategy for Brexit negotiations with the EU; and the European Commission will publish more of its proposals on Energy Union (including new rules on renewables, market operation and national climate and energy plans).

The documents state more than once that while the UK is an EU Member State, it will “continue to negotiate, implement and apply” EU legislation. But – at least in relation to coal closure – the Government is trying to make policy here for the 2020s.  By that time, it presumably hopes, it will no longer be constrained by EU law.  It remains to be seen how Brexit will affect the participation of our remaining coal-fired plants in the EU Emissions Trading System, which is at present a significant feature of the economics of such plant.  In the short term, the coal consultation points to an announcement in the Chancellor’s 2016 Autumn Statement (23 November) of the “future trajectory beyond 2021” of the UK’s own “carbon tax”, the carbon price support rate of the climate change levy.

After a period in which we have been relatively starved of substantive energy policy announcements, things are starting to move quite fast, and decisions taken by Government over the next few months could have significant medium-to-long-term consequences for UK energy and climate change policy.

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