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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

Court rules Ofgem’s “embedded benefits” decision not flawed

In a judgment dated 22 June 2018, the High Court (Lavender J) dismissed a challenge brought by a number of electricity generators (the Claimants) against a decision of the Gas and Electricity Markets Authority (Ofgem) to approve proposed modifications to the Connection and Use of System Code (CUSC), under which charges for use of the GB transmission network are levied.

Ofgem’s decision

The modification proposals were formally made in May 2016; Ofgem’s decision was taken in June 2017; and it came into force on 1 April 2018. Its most noted effect was to remove (over a three year period) a key element of the revenues of small “embedded” generators (i.e. those connected to a distribution network rather than directly to the transmission network).

Under one part of the transmission charging framework, known as the Transmission Demand Residual (TDR) charge, payments are effectively made in respect of the amount by which the supply of power from small embedded generators reduces consumption of electricity from other, mostly transmission-connected, sources in the periods of peak demand (known as “Triads”) from which the charge is calculated. These negative charges, commonly referred to as “Triad payments”, are typically made to electricity suppliers (as the small embedded generators themselves are not parties to the transmission charging arrangements), but the suppliers typically pass on about 90% of their value.

The overall costs of the transmission network have increased significantly in recent years. So too have TDR charges and the amount of Triad payments accruing to small embedded generators.  The Claimants, some of whom had made the development of small generating plants designed to capture Triad payments into a business model, argued that the system was rewarding them fairly for reducing the need for investment in the transmission network.  Ofgem, drawing on work that had been done in preparing the CUSC modifications and a series of consultations leading up to its decision, formed the view that the small embedded generators were being rewarded excessively, ultimately at the expense of consumers of electricity.  Whilst Ofgem acknowledged that they do make some positive contributions in reducing the amount of reinforcement necessary at Grid Supply Points, it drastically reduced the level of transmission charging related benefits that will be available to them in the future.

The judgment

The judgment of Lavender J is worth reading.  At 36 pages, it is as concise a free-standing account of both the issues and the decision-making process as you are likely to find.

The Claimants were refused permission to challenge Ofgem’s decision on grounds of irrationality. Their remaining grounds were that Ofgem failed to take account of material considerations and/or facts; and that the decision unjustifiably discriminated against the small embedded generators.

On the first point, Lavender J found that rather than failing to take account of a material consideration by not understanding the argument the Claimants were making, Ofgem had engaged adequately with them and disagreed with their assessment of the contribution made by small embedded generation. (This had been in part a battle of expert economic appraisals, in which Ofgem’s decision was buttressed by LCP/Frontier Economics whilst the Claimants found support in criticisms of Ofgem’s approach made by NERA/Imperial College.)  It was also not an error of law for Ofgem to require the Claimants to provide evidence in support of their case rather than making its own inquiries to find such evidence.

The second point had two limbs. The Claimants argued that Ofgem should have treated them in the same way as providers of behind the meter generation (BTMG) and commercial demand side response (DSR), which, like them, reduce a supplier’s net demand for electricity – but that it had not done so.  They also argued that it was unlawfully discriminatory to treat small embedded generators as if they were in a comparable position to transmission-connected generators – when they were not.

The judge was satisfied that “looking in the round” there was “enough of a relevant difference between” small embedded generators and BTMG / commercial DSR on the one hand and transmission-connected generators on the other, to justify their different treatment by Ofgem.

What next?

On a reading of the judgment with no more knowledge of the parties’ submissions than the judgment itself reveals, it does not seem very likely that it will be successfully appealed. Some readers may disagree with some of the judge’s reasoning, for example in support of his findings of “relevant differences” between the small embedded generators and BTMG / commercial DSR / transmission-connected generators.  But as he points out, there will be scope to remedy any perceived unfairness in the context of Ofgem’s ongoing Targeted Charging Review: Significant Code Review.

Ultimately this is one of those judicial review cases that serves as a reminder of the limits of judicial review as a mechanism for challenging decisions by economic regulators, as the court deferred to the expert regulator and did not appear to have thought that there was anything so bad in the decision under challenge or its results as to justify any attempt to use the essentially procedural categories of judicial review more creatively to strike it down. One can speculate whether the reasoning, if not the result, would have been different if Ofgem’s decision had been one that was subject to review by the Competition and Markets Authority rather than the court (like another recent Ofgem decision on a CUSC modification in the case of EDF Energy (Thermal Generation) Ltd v. Gas and Electricity Markets Authority, but even that process does not amount to a substantive reopening of the decision that is being challenged.

When the CUSC modification was originally proposed, some may have felt that it was an attack on the small embedded generators by those seeking to develop new transmission-connected generation. For them, the Triad revenues of smaller generators enabled the latter to bid down the clearing price in Capacity Market auctions to a level which made it impossible for e.g. new combined cycle gas turbine projects to stay in the auction – thus losing their chance of a subsidy that would allow them to be built.

However, two years on, the most recent Capacity Market auctions have not produced the higher clearing prices that might have been expected if the price was effectively set by small embedded generators and the latter depended to a material extent on the Triad payments they were about to lose as a result of Ofgem’s decision. This would suggest either that small embedded generators had more confidence in the Claimants’ case than appears to have been justified; or that, for whatever reason, Ofgem’s decision may be less harmful to their interests than it may at first have seemed.

Meanwhile, Ofgem’s Targeted Charging Review has a long way to run, and it will be interesting to see whether it reaches its conclusion without legal challenge or two along the way.

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Court rules Ofgem’s “embedded benefits” decision not flawed

Further step towards energy retail price (re-)regulation as tariff cap Bill is introduced into UK Parliament

Legislation to impose a price cap on domestic energy bills was introduced into Parliament on 26 February 2018. The accompanying announcements from the Department for Business, Energy and Industrial Strategy (BEIS) indicate that the new regime will be in place by Winter 2018-19. This may feel like the end of a long story, and in a sense it is, but it is also the beginning of a new phase for GB retail energy markets: one in which, for the first time in many years, price regulation is likely to play a significant role in shaping the domestic energy supply market – albeit on an explicitly temporary basis.

How did we get here?

Theresa May singled out energy companies who “punish loyalty with higher prices” in her Conservative Party conference speech in October 2017, and a draft of the Domestic Gas and Electricity (Tariff Cap) Bill was published shortly afterwards. The House of Commons Select Committee that scrutinises the work of BEIS then examined the draft Bill, and produced a broadly favourable report on it in January 2018 (both the Committee’s report and the feedback on the draft Bill that they gathered from a range of stakeholders can be found here).

Going further back, the Bill represents unfinished business from the Competition and Markets Authority (CMA) investigation of the GB energy supply markets that concluded in 2016. The instigation of that investigation by the sector regulator, the Gas and Electricity Markets Authority (Ofgem), almost four years ago, was itself the culmination of years of public debate about energy prices and the allegedly excessive profits made by GB utilities.

The CMA found “an overarching feature of weak [domestic] customer response which, in turn, gives suppliers a position of unilateral market power concerning their inactive customer base which they are able to exploit through their pricing policies or otherwise”. In particular, huge numbers of customers of the “Big 6” suppliers who showed little interest in or awareness of the possibility of shopping around for a better deal, found themselves on high “standard variable tariffs” (SVTs). As a result, the CMA identified “customer detriment associated with high prices” of “about £1.4 billion a year on average for the period 2012 to 2015 with an upwards trend”. However, the CMA panel that conducted the investigation decided (by a 4:1 majority) not to impose a price cap to address the harm to SVT customers generally – although they did decide in favour of a price cap for customers supplied through a prepayment meter (PPM). For others, the majority of the panel concluded that measures designed to increase the chances of those on SVTs signing up for a better deal were enough.

The CMA’s conclusions failed to satisfy the public and political appetite for dramatic regulatory action. This was partly because in the period following the CMA’s report, average Big 6 SVTs showed little or no sign of decreasing, while their cheapest tariffs seemed to be increasing, and partly because many of those on high SVTs were also economically or digitally disadvantaged. Poorer customers appeared to be subsidising offers of more competitive prices to the more affluent – or perhaps the larger suppliers were just not very efficient. As the impact assessment published alongside the Bill (a more vigorous and forcefully expressed document than many of its kind) puts it: “a majority of people lose out, with disproportionate impact on the vulnerable”. These – and other, more overtly political reasons – made the move towards a cap unstoppable, notwithstanding the counter-argument that protecting those who didn’t shop around would be likely to result in higher prices for those who did, undermining the development of a properly competitive supply market in the longer term. Interestingly, during the course of the Select Committee’s inquiry, more industry voices than might previously have been expected came out in favour of a cap. (For a sober economist’s justification of the cap, see the evidence given by Professor Martin Cave, who was the dissenting member of the original CMA panel, to the Select Committee.) The charts and table below, published (or derived from data published) on Ofgem’s website in December 2017, tell their own story.

Where exactly are we now?

The Bill follows the text of the draft Bill closely. The table below sets out the key features of the tariff cap regime in the draft Bill and the Bill as introduced, and how the substantive changes from the draft correspond to recommendations made by the Select Committee in its report.

Key feature of draft Bill Select Committee recommendation Revised feature in Bill
As soon as practicable after Royal Assent, Ofgem must include conditions in electricity and gas supply licences to cap SVT and “default rates” (tariff cap conditions). The Committee favours an “absolute cap” rather than one expressed in relation to the level of suppliers’ non-SVT / default rate tariffs. The Bill remains silent on the precise form and level of the tariff, which are left to Ofgem to determine.

A new provision emphasises that the cap will apply to all supply licences and contracts, whenever entered into.

Ofgem can subsequently modify, but not abolish, tariff cap conditions. N/a N/a
Ofgem must:

(a) consult, and allow 28 days for feedback, on the proposed tariff cap conditions or any later proposed modifications;

(b) allow at least 56 days between publication of definitive tariff cap conditions / later modifications and their coming into effect.

N/a N/a
Ofgem is to have regard to five matters in setting / modifying tariff cap conditions – the need to:

(a) protect existing and future customers on SVTs and default rates;

(b) incentivise suppliers to be more efficient;

(c) set the cap at a level that enables effective retail competition;

(d) maintain incentives for customers to switch;

(e) ensure that suppliers who operate efficiently can finance their licensed activities.

To deter legal challenge to Ofgem’s decisions, Government should clarify that all five objectives do not have to be satisfied at once.

In particular, Government and Ofgem should minimise the risk of challenge arising from the likely short-term reduction in switching when the cap first comes into force and its (perhaps inevitable) reduction in the incentives for some customers to switch.

Matter (a) is elevated to an overarching objective, in aiming to achieve which, Ofgem is to have regard to matters (b) to (e).

A new sub-section provides that the cap does not include charges that are part of the SVT / default rate, but are not regularly paid by the majority of customers who pay that rate.

Tariff cap conditions do not apply where:

(a) customers benefit from the PPM cap introduced by the CMA or any replacement for it; or

(b) electricity is supplied on a “green tariff” that meets the standards set out in electricity supply licences.

The exemption for green tariffs should be strengthened to avoid gaming by suppliers moving customers onto “loosely defined green tariffs” and should not apply where there was no substantial benefit to the environment or the consumer has not actively chosen the tariff. Green gas tariffs should also get the same treatment. The references to PPM caps and green electricity tariffs have been replaced by more generic wording on:

(a) caps imposed in relation to vulnerable customers; and

(b) SVTs that apply only if chosen by customers and that appear to Ofgem to support the production of electricity or gas from renewable sources.

No doubt partly to acknowledge the fact that there is no current “standard” for green gas tariffs in gas supply licences, Ofgem is given more time to provide for exemption (b).

Starting in 2020, and for as long as the cap remains in place (see below), Ofgem must, by 31 August, annually review “whether conditions are in place for effective competition for domestic supply contracts” and report to BEIS (report to be published by 31 October each year).

The Secretary of State (SoS) must consider the report and publish a statement on whether the SoS considers the conditions for effective supply competition are in place.

The Government should not seek to define what is meant by “effective competition” before a cap is in place, but the SoS’s decisions should be based on “the minimum requirements that overcharging and the differential [between SVTs and cheapest tariffs] are substantially reduced, fairness is improved, and vulnerable customers are protected”. A new provision: at least once every 6 months while the cap remains in place, Ofgem must:

(a) review the level at which the cap is set; and

(b) state whether, as a result of that review, it proposes to change the level at which the cap is set.

The Bill does not include any further definition of “effective competition”.

The cap ceases to have effect at the end of 2020 unless the SoS concludes that conditions of effective supply competition are not yet in place. In that case the cap remains in effect for 2021 and the Ofgem report / SoS statement process is repeated in 2021 and – if the SoS considers conditions of effective competition are still not in place then – again in 2022 (but with a final “sunset” for the cap at the end of 2023 in any event). N/a N/a

 

It will be immediately obvious from the above summary that the Bill leaves Ofgem with the hard work of actually setting the cap and drafting the standard licence conditions that will give it effect, and balancing a number of potentially conflicting objectives as it does so. From first publication of proposed tariff cap conditions to their entry into force is likely to take at least 4 months (allowing for one month to consider feedback from the initial consultation). Consultation that takes place before the Bill receives Royal Assent is permitted.

Accordingly, having the new regime in place by Winter 2018-19 looks achievable. Even with Parliamentary timetables dominated by Brexit legislation, it should not be too difficult to find the relatively short amount of time required to debate this Bill, given the broad consensus behind the cap.

Will Parliament be happy to leave it to Ofgem to come up with the all-important numbers? It should: Ofgem is an independent economic regulator (whose independence from political control remains, at least for the moment, guaranteed by EU law). The potential to disrupt delivery of the cap may lie rather with the energy suppliers themselves, or anyone else who may seek to challenge Ofgem’s eventual decision on the level of the cap or other related licence provisions in the courts.

Some suppliers tried to persuade the Select Committee that Ofgem’s decisions on the cap should be subject to a right of appeal to the CMA, rather than only being challengeable by way of judicial review by a court. Their representations unsurprisingly emphasised the benefits of the CMA’s expertise and faster-track procedures more than what they may have perceived as the higher threshold that has to be satisfied for a court to entertain a challenge by way of judicial review or the narrower administrative law grounds on which a court can determine that a decision that is subject to judicial review is sufficiently flawed to be struck down and remitted to the decision-maker (here Ofgem) to reconsider.

In a number of ways, the legislation has been constructed so as to reduce the risk of a successful challenge: Ofgem has been given a fairly clear (if by no means simple) job to do in a particular context, and a court may well be slow to second-guess e.g. the regulator’s judgments when prioritising the competing objectives it must bear in mind when setting the tariff cap (see above).  But even if JR remains the only route for a challenge in the Bill as enacted, the possibility that a challenge will be launched cannot be ruled out, since if the calculations made by the CMA and others are even half right, there is a lot of money at stake here for some suppliers.

What next?

Whether or not Ofgem has to defend any of its tariff cap decisions in court, this new function is going to be a significant item of work for the regulator over at least the next two and a half – and possibly as many as five – years. This is likely to have a number of consequences.

It is hard to see how Ofgem can make judgments about e.g. how “to ensure that holders of supply licences who operate efficiently are able to finance activities authorised by the licence” without potentially routinely engaging with those suppliers on the commercial costs of their businesses in a degree of detail, and level of intensity, to which they are unaccustomed as part of “business as usual” activity. Consideration of the efficient costs of operation is normally what Ofgem does in relation to the natural monopoly businesses of transmission and distribution, not the competitive business of supply (although of course, it is a founding premise of the tariff cap regime that competition is not working properly in the domestic supply sector). Inevitably, individual suppliers will assert that their businesses do not fit particular assumptions Ofgem may make: yet the legislation explicitly precludes making “different provision for different holders of supply licences”.

Perhaps the only way to avoid this level of regulatory attention would be for suppliers unilaterally to follow in the direction proposed by Centrica during the course of the Select Committee’s inquiry as an alternative to a tariff cap, by not having SVTs or default tariffs; but that in itself would not be without its challenges, not least from a customer engagement perspective.

The partial re-regulation of domestic tariffs is by no means the only significant regulatory development that will occur in the energy supply sector over the period when the tariff cap is in force. Government and others have been at pains to stress that changes such as the rollout of smart meters and the introduction of market-wide half-hourly settlement, that could enhance competition in energy supply markets, are not to be seen as reasons not to have the cap. Recent history suggests that the number of such obligations on suppliers only moves in one direction: up. And unlike in the case of “pass-through” costs such as network operator charges, obligations like market-wide half-hourly settlement may be inescapable, but there is likely to be plenty of scope for argument over how much they should cost suppliers to comply, against a background of reduced SVT revenues. Meanwhile, Ofgem has opened up the whole question of the place of suppliers in the regulatory architecture with a call for evidence (November 2017) on the future of supply market arrangements.

Whatever happens, there is a strong chance that Ofgem’s performance, in the eyes of most politicians and the public, will be seen as overwhelmingly focused through the lens of the tariff cap and its impact on SVT customers’ bills. The next few years will not be easy either for the regulators or the regulated.

UPDATE – 6 MARCH 2018

Ofgem has published a letter setting out its timetable for developing the tariff cap condition, as well as its other ongoing work to protect vulnerable customers from overcharging.  A series of working papers is promised over the next few months, with draft licence conditions being issued in August 2018 and the tariff cap being in force by the end of the year – subject to the progress of the Bill.

UPDATES – OFGEM WORKING PAPERS

12 March 2018: Ofgem has published its first working paper on how it will go about setting the tariff cap, drawing heavily on earlier work in the context of the cap for the protection of vulnerable consumers.

28 March 2018: Ofgem has published its second tariff cap working paper.  This deals with the possible use of a “market basket” of competitive tariffs to set or adjust the tariff cap – and provisionally concludes that such an approach is not one to follow here.

9 April 2018: Ofgem has published its third tariff cap working paper.  This deals with “headroom” – i.e. “an amount above the efficient level of costs, which could be used to enable competition to co-exist with the cap”.

19 April 2018: Ofgem has published two more tariff cap working papers.  The fourth working paper is concerned with how the tariff cap will take account of the economic and social policy costs faced by suppliers.  The fifth working paper considers in more detail one of the reference price methodologies first outlined in the second working paper.

UPDATE – CONSULTATION ISSUED ON 25 MAY 2018

Today Ofgem published a consultation consisting of an “overview” and 14 Appendices (altogether more than 400 pages).  Ofgem explains that the consultation does not propose at what level the cap should be, but explains how it might go about setting the cap.  Once the Bill has received Royal Assent, a further, statutory consultation is expected to be issued in August 2018, enabling the cap to “come into force by the end of this year so that it is place to provide protection to consumers this winter”.

 

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Further step towards energy retail price (re-)regulation as tariff cap Bill is introduced into UK Parliament

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

Extractives companies’ human rights records ranked in Benchmark study

Developments continue apace in human rights responsibilities for businesses. We are seeing persistent implementation of new reporting requirements across EU jurisdictions and beyond, judgments of national courts and international tribunals holding corporations to ever stricter account for their responsibilities in this area and UN negotiations continuing for a global treaty imposing binding international law obligations on businesses.  Staying ahead of the field in this area is crucial.

While the responsibilities imposed by the UN Guiding Principles on Business and Human Rights (the UNGPs) are not in themselves legally binding, governments’ expectations that companies will step up in this area have been made clear through National Action Plans, parliamentary enquiries and the introduction of “hard” legal requirements, such as under the Modern Slavery Act in the UK.

Now, the Corporate Human Rights Benchmark (CHRB) has ranked 98 of the largest publicly traded companies globally on 100 human rights indicators, focusing on the Extractives, Agricultural and Apparel industries.  These areas were specifically selected because of the high human rights risks they carry, the extent of previous work on the issue, and global economic significance.  41 Extractives companies featured.

The CHRB is a collaboration between investors and a number of business and human rights NGOs. It has emphasised this is a pilot assessment and welcomes input on the methodology used.  The study was compiled from publicly available information, with the selected companies also having the opportunity to submit information to the CHRB.  Companies were given scores for the measures they are taking across six themes, grounded in the framework of the UNGPs:

  • Governance and policy commitments.
  • Embedding respect and human rights due diligence.
  • Remedies and grievance mechanisms.
  • Performance: Company human rights practices.
  • Performance: Responses to serious allegations.
  • Transparency.

The selected companies were then banded according to their overall percentage score.  The performance-related criteria carried greater weight than the policy-based heads, with “Embedding respect and human rights due diligence” and “Company human rights practices” counting for 25% and 20% respectively.

Results skew significantly to the lower bands

There was a wide spread in the participants’ performance, with a small number of clear leaders emerging. No company scored above the 60-69% band, with only three companies falling within that band.  A further three scored 50-59% and 12 scored 40-49%.  48 companies fell within the 20-29% band.

Of the companies in the top band, two were in the Extractives sector; a further six Extractives companies fell within the 40-49% band; 19 scored 20-29% and five were found to trail at less than 19%.

The generally low scores across the three industries may be explained by the fact that the impact of some businesses’ human rights processes may still be filtering through. We should expect that in future years the authors of the survey will adopt a more stringent approach and subject low-scoring businesses to greater criticism.

Gap between policies and performance

On the whole, companies tended to perform more strongly on policy commitments, high-level governance arrangements and the early stages of due diligence. They performed less well on actions such as tracking responses to risks, assessing the effectiveness of their actions, remedying harms and undertaking specific practices linked to key industry risks.  There is often a mismatch between board level measures and their granular implementation, as well as between public responses to serious allegations and taking appropriate action.

Of the Extractives companies surveyed, only six companies scored were given a zero score for their policy commitments, whereas this was the case for 17 companies for “Embedding respect and human rights due diligence” and nine for “Company human rights practices”.

On the policy side, some Extractives companies scored points for emerging practices such as regular discussion at board level of the company’s human rights commitments, linking at least one board member’s incentives to aspects of the human rights policy, and committing not to interfere with activities of human rights defenders, even where their campaigns target the company.

In terms of implementation, some participants explained how human rights risks are integrated into their broader risk management systems, how they monitored their commitments across their global operations and business relationships, and how they had systems in place for identifying and engaging with those potentially affected by their operations.

Companies were also scored for their practices in relation to selected human rights specific to each industry. Those in which the Extractives participants featured included freedom of association and collective bargaining, health and safety, land acquisition, water and sanitation and the rights of indigenous people.

Conclusion

The significant interest in the CHRB since it began its work is unsurprising given it provides an opportunity to demonstrate commitment and progress in this area vis-à-vis competitors. The pilot methodology will be refined and ultimately the CHRB will be produced on an annual basis for the top 500 companies globally.  We expect it to contribute to the continued drive of companies across all sectors to proactively manage human rights risks in their own operations and through their expectations of their business partners.

Extractives companies’ human rights records ranked in Benchmark study

UK “early” Capacity Market auction produces cheapest prices yet

The provisional results of the “early” Capacity Market auction held last week have now been published.

This was an auction exclusively of 1-year capacity agreements, primarily to cover Winter 2017/18, after the UK Government decided that it did not want National Grid to carry on ensuring security of supply during Winter periods by means of a Contingency Balancing Reserve (CBR).  The CBR involved auctions open to generators who would not otherwise be operating in a given Winter period and to demand side response providers.  A Government consultation in March 2016 noted that the prices National Grid were paying under the CBR were increasing and that it introduced distortions into the market.

From Winter 2018/19, of course, the Capacity Market itself will ensure security of supply.  Those with capacity agreements beginning in 2018 will be the capacity providers who bid successfully in a four year ahead auction held in 2014, supplemented by those who win capacity agreements in any subsequent one year ahead auction for delivery in 2018.  Last week’s “early” auction was a one-off bridge between the CBR (now operating for the last time to cover Winter 2016/17) and the fully-fledged Capacity Market regime.  The key difference between the CBR and the Capacity Market is that the CBR (or at least the major part of it) focuses on securing capacity that would otherwise not be in the market, to fill the potential gap between existing generation and projected peak demand, whereas the Capacity Market provides a reliability incentive to all eligible generators and demand side response providers on the market.

Commentary on previous Capacity Market auctions (such as this post from December 2016) has tended to focus on the failure of the four year ahead auctions to result in the award of 15 year agreements to meaningful amounts of large-scale new gas-fired generation projects.  With new projects competing against almost all existing thermal generation, and new reciprocating engine projects able to bear much lower Capacity Market clearing prices than a CCGT project, the auctions have produced low clearing prices, but no obvious successors to the existing big coal-fired plants that the Government wants to close by 2025.

How to evaluate the results of the “early” auction, then?  The provisional results indicate capacity agreements going to 54.43 GW of capacity, at £6.95 kW / year, suggesting total costs to bill payers of around £378 million.  This might look like spectacularly good value compared with the results of the last four year ahead auction (for delivery starting in 2020), where the clearing price was £22.50 kW / year for 52.43 GW of capacity.  But that isn’t really a fair comparison, since about a quarter of the capacity that was awarded agreements for 2020 was new build, whereas less than 4 percent of the capacity awarded agreements in the “early” auction falls into this category.  All the rest will be paid £6.95 for just continuing to operate – which presumably most of them would have done anyway. 

An alternative point of comparison might be with the costs of the CBR.  The most recent Winter for which these are available is 2015/16, when National Grid spent just over £31 million on procuring, testing and utilising less than 3 GW of CBR capacity.  Obviously a much inferior system. 

 

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UK “early” Capacity Market auction produces cheapest prices yet