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UK government looks forward to 2030 (and beyond) with CfD consultation

On 2 March 2020, the UK Government issued a consultation on proposed changes to the contracts for difference (CfD) regime of support for renewable electricity generators. The item that attracted most attention was that onshore wind (in GB as a whole, rather than just on Scottish islands) and solar will be allowed to apply for CfDs again in 2021, but there are other points worth noting too. There are proposals to change aspects of the CfD regime relating to offshore wind and biomass conversions, as well as cross-cutting proposals (on areas including negative pricing, non-delivery incentives and “supply chain plans”) that would affect all technologies.

Offshore for net zero

The CfD regime is becoming mature. It was first consulted on in 2010; was legislated for in 2013/2014; saw the first, “FID enabling”, contracts awarded in 2014; and held its first auction in 2015. Already, more than 20 projects with CfDs have been commissioned and are receiving payments under them. They have a combined capacity of more than 4 GW. A further 10 GW is expected to be added by 2026, based on the delivery of projects that were awarded CfDs in the first three auctions. Offshore wind is, increasingly, the dominant technology in the CfD portfolio.

As of June 2019, the UK has a target of net zero emissions by 2050. And before then, the government wants to achieve 30 GW (as per the March 2019 Offshore Wind Sector Deal), or even 40 GW (as per the December 2019 Conservative manifesto) of offshore wind capacity by 2030. The most recent CfD auction saw just under 5.5 GW of offshore capacity awarded CfDs for delivery between 2023 and 2025, but – assuming that this is all delivered – can such levels of activity be sustained? Even if they are, with auctions occurring every two years and projects bidding to deliver in five or six years’ time, it is not certain that the higher of the two 2030 targets would be reached.

Get off the bottom and go with the float

Although the costs of offshore projects have fallen significantly, and it has become feasible to build them much further from the shore than was once the case, there are concerns about whether it will be possible to fulfil the high ambitions for 2030 while relying entirely on monopile, jacket or suction bucket foundations into which the turbine tower is built. These “fixed bottom” arrays cannot readily be deployed in waters more than 60 metres deep. As the industry grows, and occupies more of the available areas of shallower water, the cumulative impact of each new project on e.g. seabird mortality increases, potentially posing more problems under nature conservation legislation. The Crown Estate recently announced a plan-level Habitats Regulations Assessment of its fourth leasing round of sites for offshore wind development, with a view to addressing these issues.  

So the government would like to stimulate more rapid adoption of floating offshore wind technology. Just as the construction of North Sea oil rigs progressed from fixed bottom to floating structures, the expectation is that offshore wind can do the same. If it does so successfully, it will become possible to locate turbines over a wider area. This would reduce cumulative adverse environmental impacts and likely increase security of supply (reducing the risk of loss of generation because the wind happens to have slackened or stopped blowing in the areas where turbines are located). The consultation document also suggests that floating turbines could provide clean electricity for offshore oil and gas infrastructure. Moreover, with an eye to export markets, at a global level, the technology will become much more useful in markets such as Japan and California that do not have shallow coastal waters.

Floating wind can of course already apply for a CfD, but in its current state of development, the technology is unlikely to win against fixed bottom and the other technologies that it would compete against in the “Pot 2” category. At present, the CfD regulations do not recognise floating offshore wind as a separate technology. The government proposes to change that, by introducing a new concept of a “floating offshore wind CfD Unit” – defined as consisting entirely of floating turbines. It would then be possible in future auctions to set a framework that effectively reserved part of the budget to such units – or at least ensured that they were not in direct competition with low-cost fixed bottom developments.

In a class of its own?

The government proposes to retain the current 1500 MW cap on phased offshore wind projects, “to strike a balance between economies of scale and facilitating new entrants to the market”. But a final notable proposal in relation to offshore wind is that in future auctions, offshore wind projects might only compete against each other, rather than – as previously – against other “Pot 2” technologies such as advanced conversion technologies, or against “Pot 1” technologies like onshore wind and solar. Whilst it is arguable that offshore wind no longer fits the “less established” designation of Pot 2, the very large scale of the fixed bottom projects now coming forward does make it somewhat mismatched with other technologies. As the consultation document notes, such a restructuring of the Pots would require “regulatory approval”, but there is plenty of precedent for mechanisms designed to offer support specifically to offshore wind projects being approved under the EU state aid rules, and there is unlikely to be any lack of competition for CfDs in an offshore-wind only category.

Meanwhile, back on dry land…

The extent to which the fortunes of the onshore wind industry have been restored by this consultation should not be overstated. Previous governments took more than one decision that curbed its growth. As well as deciding not to include onshore wind in the second and third CfD allocation rounds (unless they were on remote Scottish islands, in the case of the third round), and accelerating the closure of the previous subsidy regime, the Renewables Obligation (RO see here and here), they adopted a planning policy that restricted the pipeline of new consented projects in England. The promise to include onshore wind and solar in the next allocation round, to be held in 2021, does not change that.

However, it is still likely that a significant number of consented sites have been “awaiting construction” primarily because of the lack of RO or CfD support or any adequate substitute for the revenue stability they provide. There should be plenty of competition for the next auction in Pot 1, not least in Scotland, where there is plenty of wind and there has been no Scottish Government policy similarly restricting the pipelines of consented projects since the closure of the RO. The consultation notes that, although there are unsubsidised “merchant” solar and onshore wind projects being constructed, “there is a risk that if we were to rely on merchant deployment of these technologies alone at this point in time, we may not see the rate and scale of new projects needed in the near term to support decarbonisation of the power sector and meet the net zero commitment at low cost”.

The consultation does not suggest how much money might be offered to the part of any future auction in which onshore wind and solar would compete (“Pot 1”). We note, however, that there are some illustrative figures in the accompanying impact assessment (albeit they are expressly “not an indication of future allocation round parameters”) that seem to envisage that in a future round where about the same amount of offshore wind was awarded CfDs as was the case in the third allocation round (5.5 GW, with strike prices of £45/MWh at 2012 prices), 300 and 700 MW of onshore solar and onshore wind might be similarly successful (with strike prices of £33 and £34/MWh). In the first CfD auction in 2015, the largest successful solar project was 19 MW – today, the whole of a hypothetical 300 MW of solar CfD capacity could be swallowed by a single development.

It’s not just about the clean energy

The consultation also focuses on the importance of renewables projects benefiting local communities. It proposes updating existing guidance and creating a register of projects’ community benefits. It also cites some examples of good practice and asks for further ideas in this area. Previously, it has proved difficult, particularly for larger commercial projects, to deliver what might be the most obvious community benefit (cheap, clean, locally-generated power) directly to the communities that host them, because of the way that the GB electricity industry and its licensing and network charging regimes are structured. But it may be that the commoditisation of battery storage could help going forward.

A key element for CfD projects with a capacity of more than 300 MW has been the requirement to submit a “supply chain plan” as part of the application process. The intention has been to ensure that the development of the renewables industry – and the offshore wind sector in particular – delivers some benefit to the UK industrial base. The consultation notes that Ministers can take account of an applicant’s failure to implement a supply chain plan when considering subsequent applications. Potentially, all partners with a 20% or greater share in a project can find themselves excluded from an allocation round as a result. It further notes that the government wants to ensure that the regime contributes to the Grand Challenges of its Industrial Policy and “advances the low carbon economy in places which stand to benefit the most by boosting productivity, driving regional growth”. It is therefore asking how it could strengthen the supply chain policy so as to ensure it remains “fit for purpose”.

Among the possibilities mentioned in the consultation document are: increasing the quality of supply chain plan commitments and closer monitoring of their implementation; extending the requirement to provide a supply chain plan to projects below the current 300MW threshold; and “considering the carbon intensity within supply chains and how this could be measured and/or reported, and taken into account, as we transition to a net zero economy”. The last of these points reflects a familiar tension between free markets / free trade and environmental policy that the EU Green Deal also seeks to address, and that could, potentially, be resolved by a scheme of carbon pricing that incorporated border adjustments on goods imported from countries with less stringent carbon emissions regimes.

After the end of coal-fired power – the end of its afterlife

A significant chunk of current CfD funding (as of RO funding before it) goes to former coal-fired capacity that has been converted to burn biomass. The CfDs awarded to biomass conversion projects have a shorter duration than other renewable CfDs, being scheduled to end in 2027. The government is “reviewing the role of biomass conversions and…seeks views on the proposal to exclude new biomass conversions from future CfD allocation rounds”. The consultation document points out that “since the government’s 2012 Bioenergy Strategy we have been clear that coal-to-biomass conversions have been supported as a transitional, rather than long-term technology” and that those “which are not otherwise subsidised may apply to participate in the Capacity Market”.

What does this mean? At present, there are only five coal-fired plants remaining in operation in the GB market. Of these, Fiddler’s Ferry and Aberthaw B are scheduled to close by the end of March 2020. Drax recently announced that its remaining coal-fired units would not operate beyond 2022. The operators of West Burton B and Ratcliffe have yet to announce plans to close them before the government’s deadline of the end of 2025 for ceasing GB coal-fired generation. That deadline, although confirmed policy, has yet to be specifically enacted as legislation, although limits imposed by EU law on the eligibility of higher emissions fossil fuel plant to participate in capacity markets are expected to make it hard for them to operate economically (a consultation of July 2019 that sought to address the detail of implementing this restriction has yet to see a government response).

Against this background, one can see why it is possible that some remaining or recently closed coal-fired plants might be interested in the prospects of biomass conversion. The attraction of biomass in the earlier phases of promoting renewable electricity generation, and particularly in the form of conversion from coal, was that it could deliver large amounts of renewable power that was not intermittent (like wind and solar) and made use of existing generation and transmission infrastructure. At the same time, there has always been a debate about how truly sustainable the burning of large amounts of solid biomass can be, particularly if it is imported from e.g. the other side of the Atlantic. Then again, if it is accepted that biomass combustion can be carbon neutral, combining it with carbon capture, use and storage (to make so-called BECCS), offers the prospect of “negative emissions”, as part of the drive to offset some of the hard-to-remove emissions that would otherwise stop us meeting the net zero target.

Since the government is considering the CfD as a mechanism for funding CCUS power projects, would it be legitimate to infer that the government does not expect future BECCS projects to be conversions of coal-fired plant? Not necessarily: the CfD legislation currently treats “biomass conversion” and “CCS” (the latter being defined without reference to the fuel that is used to power it) as distinct categories of “eligible generating station”. So it may be that excluding biomass conversions from future auctions would still leave the way open for a BECCS CfD.

Clearing the road to 2030

The government plans to hold the next allocation round in 2021 and to hold subsequent rounds every two years thereafter. In order to further provide long-term certainty to developers investing in bringing forward new projects and to support the level of ambition needed to meet the 2050 net zero target, it proposes to extend the CfD legislation’s definition of “delivery years” to go as far as 31st March 2030.

It’s never too early to think about decommissioning

There are already almost 2,000 offshore wind turbines in the sea around the UK. Decommissioning costs for those in operation or construction in 2017 alone has been estimated at £1.28bn-£3.64bn (in 2017 prices). Against this background the government wants “to ensure developers give appropriate consideration to decommissioning during the development stage”, so as to minimise the risk to taxpayers of the government having to act as decommissioner of last resort, and it is considering “whether it would be appropriate to include specific decommissioning obligations in the CfD regime”.

Administrative strike prices

The government is considering changing the method that it uses to calculate the administrative strike prices that function as “reserve prices” in CfD auctions. The current method produces administrative strike prices that are too far adrift from auction bids for some technologies.

Never mind the carrot, is the stick big enough?

The government is considering sharpening the incentives to deliver CfD projects, and do so on time. It is concerned that as “prices come down and the greater benefit of CfDs shifts from providing subsidy towards offering the support for successful applicants to secure finance for their projects, there may be an increasing risk that a generator does not proceed to deliver on its contract but considers it preferable to deliver on a merchant or other basis”. This, the government says, would be unfair on other generators who might have wanted to make use of the CfD support if they had had the opportunity. It proposes to extend by three years the period during which the site of a project that has allowed its CfD to lapse or had it terminated is “sterilised” for the purposes of a further auction.

Consultees are invited to suggest other potential mechanisms to guard against non-delivery. One model that is mentioned is that of bid bonds such as are used in the Capacity Market (applicants pay an amount based on the project’s capacity, to be forfeited if it is not delivered under the CfD regime).

Negative pricing

One of the things that has changed over the last five years is the extent to which increasing amounts of intermittent renewable capacity is driving – and is, in the future, expected to drive – negative pricing in wholesale electricity markets. In 2015, the government thought that this might happen 0.5% of the time in 2035. With 30 GW or more of offshore wind, it now thinks it could happen 4.5% of the time.

As part of its clearance of the CfD regime under the state aid rules, the European Commission required that support should be capped at the level of the strike price in periods of negative pricing, and that if these persist for six hours or more, “the difference amount under the CFD Contract will be set to zero for the entirety of that period”. The government would now like to remove any incentive on CfD generators to generate when there is oversupply in the market. It therefore proposes to “extend the existing negative pricing rule so that difference payments are not paid to CfD generators when the Intermittent Market Reference Price is negative”.

What else is in store?

One of the ways that CfD generators might, at least hypothetically, wish to mitigate the risks associated with periods of negative pricing – and one of the ways in which they might be able to play a part in restricting the incidence of such periods – would be if they could generate, but not immediately export (or be treated as having exported) their power, by making use of storage facilities. Storage is, more generally, as the consultation document acknowledges, “a means to mitigate some of the potential negative impacts of intermittent renewable generation on the system”.

The government therefore asks three quite open-ended questions: “What storage solutions could generators wish to co-locate with CfD projects over the lifetime of the CfD contract? What, if any, barriers are there to co-location of electricity storage with CfD projects? What, if anything, could be changed in the CfD scheme to facilitate the colocation of storage with CfD projects?”.

Co-location of storage with renewables projects already takes place in the GB market. Some large wind projects (onshore and offshore) have relatively small associated small storage facilities. Some smaller projects such as solar farms have proportionately larger amounts of associated battery capacity. Their storage facilities can enable these projects to earn supplementary revenues in the ancillary services markets or the Capacity Market, and help to optimise their assets in other ways.

What is arguably missing are incentives for the development of much larger scale facilities that could be capable of absorbing, for example, a significant proportion of several windy nights’ worth of offshore wind generation for which there is no immediate demand. Also useful, perhaps, would be incentives to develop commercial scale electrolysis facilities into which surplus power could be diverted for conversion into “green” hydrogen that could be substituted for hydrocarbons in power, heat or transport applications. But whether the CfD regime would be a suitable vehicle for such incentives (and, if so how it would need to be adapted to provide them), is another question.  

Conclusion

The two most prominent pillars of GB’s early 2010s Electricity Market Reform regime, CfDs and the Capacity Market, are now established features of the landscape. The present CfD consultation, and the recent five year review of the Capacity Market, appear to confirm that no fundamental changes to or replacement of either regime (such as was proposed by Dieter Helm) is planned – although it should be noted that the consultation on effectively replacing CfDs as the subsidy route for new nuclear projects, which would be a significant change to the EMR vision, has yet to be responded to by government (nuclear goes essentially unmentioned in the present consultation document).

At the same time, there is a recognition that – like any element in the complex ecosystem of energy regulation – the performance of the CfD regime needs constant monitoring, and there is a willingness to consider potential improvements. As the regime enters its second decade (counting from the first consultation) or its second five years (counting from the first auction), this is not a bad place to be.

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UK government looks forward to 2030 (and beyond) with CfD consultation

A smart carbon tax: the silver bullet for the (just) energy transition?

There is a broad consensus among economists that, globally, over time, reaching net zero greenhouse gas emissions by 2050 will cost less than not reaching net zero.[1] In that very broad, long-term, high-level sense, it is clear that there is no conflict between carbon neutrality and economic interests. But if everybody thought it was already in their economic interests to aim for net zero today, we would probably not be so far off track from achieving that goal as we currently are.[2]   

Researchers working within the framework set by the Intergovernmental Panel on Climate Change (IPCC) have mapped out four indicative pathways to net zero.[3] They all involve at least halving global consumption of fossil fuels by 2040. That is not quite the future that most oil majors, and governments with a stake in the industry, seem to be planning for.[4] Others argue that net zero in 2050 is compatible with fossil fuels still dominating the global energy sector at that time, but that this would depend on massive shifts in investment – for example, into new technology to reduce the carbon footprint of fossil fuel extraction, hydrocarbon supply chains and use of fossil fuels. The majority of the industry is as yet not visibly committed to such shifts.[5]

To persuade people to take action that seems to be against their economic interests, at least in the short term, you need to change the balance of incentives.

Again, the economists have a straightforward answer: you put a price on carbon. You make it more expensive to produce and/or consume fossil fuels and products with a heavy carbon footprint. People then pay up front for the otherwise unpriced damage caused by their emissions, which means that they have a reason to choose lower carbon products and forms of energy.

There is no shortage of support for the principle of carbon pricing, which has been endorsed by royalty, the European Commission and senior bankers, to name but a few.[6] However, in practice, existing carbon price mechanisms have had limited effect, and there are serious risks in seeking to decarbonise with policy instruments that could impose significant costs on those least able to afford them. Any tax based on consumption risks having a regressive effect, and people with proportionally more carbon-intensive lifestyles often lack the financial means to switch to lower carbon options. The gilets jaunes protests in France began with an increase in carbon taxes.[7]

Carbon pricing may take the form of a straight tax on emissions, or of an emissions trading scheme. The former is arguably the better approach. For example, setting a tax rate is not always easy, but it is easier to make adjustments to a tax than to a market mechanism, where it can be difficult to recover from an initial miscalculation of the optimum number of emissions allowances to issue at the outset, as in the case of the EU Emissions Trading Scheme (EU ETS).

The ideal carbon tax would be economy-wide, and have three further key features. 

  • The price of emissions would start considerably higher than in most current carbon pricing schemes, and increase over time in a carefully calibrated way.[8]  
  • To ensure popular support, government would pay back some or all of the tax receipts in the form of a “carbon dividend” in a fiscally redistributive way.[9]
  • To make it possible to start with a national, rather than a global version of the tax, and to avoid exporting the taxing country’s emissions to countries without a carbon tax, it would be necessary to charge a “border carbon adjustment” tariff on goods imported from jurisdictions with no equivalent tax.

Such an approach has plenty of heavyweight intellectual support.

  • Just over a year ago, the Wall Street Journal carried a self-styled “largest public statement of economists in history” in which no fewer than 3,558 US economists espoused something along these lines that was proposed from a US perspective. This is the “Baker-Schultz” plan, re-branded in February 2020 as the “Bipartisan Climate Roadmap”.[10]
  • In October 2017, leading UK regulatory economist Dieter Helm put a carbon tax at the heart of his report to the UK government on how to address the rising cost of energy in the context of its climate change policy goals.[11]
  • In July 2018, the UK think tank Policy Exchange produced The Future of Carbon Pricing: Implementing an independent carbon tax with dividends in the UK, with a foreword jointly authored by a former Labour Chancellor of the Exchequer and a former Conservative Foreign Secretary.[12]

Of course, any attempt to implement such a tax would need to address a great many issues, both in terms of high level design and practicalities.

  • Do you just tax fossil fuels, or do you also tax products in whose manufacture fossil fuels have been consumed? In the case of fossil fuels, at what point(s) in the chain between the upstream producer and the final downstream user should the tax be levied? For example, you could impose a tax on upstream hydrocarbon producers or refinery operators that was based just on the emissions from their activities, rather than from the presumed activities of end-users of refined petroleum products, such as electricity generators or motorists.
  • At whatever point(s) a tax is applied, at what rate should it be levied? What assumptions about the emissions intensity of downstream processing and/or use should underpin the calculation of that rate? How do you ensure that the imposition of the tax, and any increase in the rate, has the desired effect of incentivising changes in behaviour (i.e. shifts to lower carbon technology)? Will taxing the ultimate consumer more heavily incentivise the upstream or midstream operator to reduce emissions from flaring or fugitive methane? If I fill up my car with fuel from a retailer who promises to offset the emissions that my driving will cause, should I get a rebate on the tax element of my purchase?
  • Tax law has a natural tendency to become complicated. Take for example the Climate Change Levy (CCL) legislation, that supplements the EU ETS in UK domestic law. In outline, this is quite a simple scheme: electricity and certain fossil fuels are “taxable commodities” and a levy is charged on “taxable supplies” of them. But quite quickly, the desire to incentivise, protect, or discourage particular activities turns the scheme into an abstruse and intricate mesh of exemptions, exclusions, and exceptions from exemptions or exclusions.
  • Both fossil fuels and products manufactured using them are traded internationally, but carbon taxing is currently national (or in the case of the EU ETS, regional), and is likely to remain so for the foreseeable future. In order to encourage other countries to adopt similar regimes, and to stop its domestic industry being undercut until they have done so, a taxing country will want to impose a carbon border adjustment on imports. This may involve charging tax at a point further down the value chain than would be the case with domestic industry. For example: you apply a domestic carbon tax on electricity, which increases the costs of aluminium smelters, so you need to apply the carbon border adjustment to imports of aluminium from a country that does not levy a similar carbon tax on electricity or aluminium production.
  • But suppose there are two aluminium producers in the aluminium exporting country: one powered entirely by renewable energy, and the other by a coal-fired power station. And suppose that some of the aluminium that reaches the aluminium importing country arrives in the form of finished products. If two identical stepladders are imported, one made of “brown” aluminium and the other of “green” aluminium, the tariff charged on the latter should be lower.

This prompts some further reflections on the kind of system that is needed. 

  • To work well, our hypothetical carbon tax needs to be very granular. That means handling a lot of data, and mining that data for insights – for example, about how particular applications of the tax affect the behaviour of particular groups or economic sectors.
  • You will also need to be able to keep records. Suppose somebody is awarded a rebate but it turns out they should not have had it. Suppose you want to allow people to borrow against their future carbon dividends in order to invest in making their homes more energy efficient. You may well want to track supply chain emissions – including for the oil & gas industry itself.   
  • Very soon, you are looking at information flows that are too numerous and diverse to be managed by a central counterparty.
  • This points to a system that can facilitate large numbers of transactions automatically, within set parameters – in other words, smart contracts.
  • That system must be very secure, and capable of encouraging parties who do not have direct contact with each other to trust each other.
  • Above all, you need a system that records, in immutable form, every transaction that is made within it.

This sounds like a job for some kind of distributed ledger technology (sometimes, but strictly inaccurately, referred to by the generic label “blockchain”). No jurisdiction in the world has yet implemented the ideal version of a carbon tax. But if and when they do, it should arguably be a data-rich, deeply digitalised, regime that can be integrated with smartphones and the internet of things: capable of tracking individual products through the supply chain, and perhaps distinguishing between hydrocarbons from different sources on the basis of the emissions intensity of the processes by which they have been extracted, transported and refined.

The Policy Exchange paper referred to above highlights the role of “blockchain” in this regard. It also points out that the UK’s withdrawal from the EU provides it with a potential opportunity to strike out on a new course in terms of carbon pricing. Research by the UK energy regulator Ofgem shows that even the UK’s existing carbon pricing tools, the much-criticised EU ETS and its domestic supplement, the Carbon Price Support element of the CCL, have been the single most effective regulatory driver of decarbonisation in the UK power sector.[13]

However, a government consultation issued in May 2019 on the future of UK carbon pricing was essentially focused on how to replace the EU-derived existing regime with something similar but UK-only.[14] It made no reference to the kind of ideas put forward by Policy Exchange, the 3,558 US economists, or Prof. Helm as regards a carbon tax. It is to be hoped that the new government will be prepared to reconsider this approach and look seriously at some of those ideas.[15] At the same time, the UK government will need to think how to respond to the EU’s plans, as part of the European Green Deal proposals of the new European Commission President, Ursula von der Leyen,[16] to establish an EU border carbon adjustment to avoid “carbon leakage” through the importing of cheaper products of energy intensive industries from countries with weaker carbon emissions controls.[17]   

In the energy sector, distributed ledger technology, smart contracts and related innovations are not just of interest to wonkish proponents of better carbon pricing. Oil companies and others in the sector have a keen interest in all these developments, because they have the potential to save them huge amounts of money.[18]

  • By exploiting existing sub-surface data, upstream oil and gas players can make the exploration process less hit-and-miss by identifying good prospects and likely dry holes before drilling. Earlier this year, the UK Oil & Gas Authority released 130 terabytes of data about the North Sea. They think that making good use of this data could reduce exploration costs by 20%.[19] 
  • Using blockchain and smart contracts they can reduce the costs and cost-overruns of building new infrastructure – some would argue, by up to 50%.
  • There is potential to make upstream facilities operate more efficiently by making better use of all the data they gather.  Wood MacKenzie estimate that US shale producers could reduce operating expenses by 10% and add $25 billion of value by putting mature wells on smart production management systems.[20]
  • Physical oil and petroleum product trading can be made much more efficient by replacing the old paper-based trade finance system with a distributed ledger.[21]  

It is perfectly possible to find oil and gas industry veterans who are sceptical of these developments. But their reason is not that they doubt the technology. Their response tends to be more along the lines of: “It sounds great, but when the oil price is high, we don’t need to cut costs, and when it’s low, we have other things to worry about”.

However, a digitalised carbon tax could provide the constant, incremental pressure that is needed to get the industry to exploit the power of digitalisation to decarbonise.   

And the industry needs to do this, because it faces all sorts of other challenges. By some measures, its energy return on investment is declining.[22] It may become vulnerable to climate change litigation. It may face competition from lower carbon alternatives that are cheaper and more effective substitutes for what it offers than are currently available.[23] But if the industry saves costs, it will become less risky, and it will be more able to invest in areas where its expertise will be crucial, like hydrogen and carbon capture and storage, that can give it a longer-term future.

Bring on the smart carbon tax of the future, then, and everyone should be a winner. In the meantime, even if the fully digitalised and personalised kind of platform outlined above lies too far in the future to be relied on as the only way forward, there is still plenty of scope to make more widespread use of carbon pricing, at higher and therefore more incentivising levels, and with redistribution and carbon border adjustment elements – and there is a strong case for doing so urgently.

The author is extremely grateful to the World Energy Council (Austria) and the Organisation for Security and Co-operation in Europe for inviting him to speak on the subject of “carbon neutrality vs. economic interests” at the 2nd Vienna Energy Strategy Dialogue in November 2019 (which was themed around “The Impact of Big Data in Energy, Security and Society”). This article is a version of his contribution on that occasion.


[1] The proposition that, as regards climate change, mitigation of undesirable outcomes before they materialise is cheaper than adaptation to them once they have arrived, was authoritatively stated in the Stern Review of the Economics of Climate Change, commissioned by the UK government and published in 2006. The UK government’s independent advisory body on climate change, the Committee on Climate Change, found in its 2019 report recommending the adoption of a “net zero” target for UK greenhouse gas emissions in 2050 that this would not cost any more than the previous statutory target of an 80% reduction against 1990 levels (itself partly triggered by Stern’s conclusions).

[2] The gap between the emissions trajectories of current and announced policies and what is needed to avert unacceptable adverse impacts of climate change has been highlighted in many places, including the IPCC’s 2018 special report on Global Warming of 1.5ºC and the UN Environment Programme’s 2019 Emissions Gap Report.

[3] See page 90 of the Committee on Climate Change report on net zero for graphics and full citation.

[4] See for example The Production Gap Report (2019), produced by the Stockholm Environment Institute and others.

[5] See for example the International Energy Agency’s 2020 report, The Oil and Gas Industry in Energy Transitions, and a number of publications by consultancy Thunder Said Energy.

[6] See for example the article by Gillian Tett in the Financial Times, UK edition for 24 January 2020, “The world needs a Libor for carbon pricing”.

[7] See for example the article by Philip Stephens in the Financial Times, UK edition for 24 January 2020, “How populism will heat up the climate fight”.

[8] See the Report of the High-Level Commission on Carbon Prices chaired by Joseph Stiglitz and Nicholas Stern (Carbon Pricing Leadership Coalition, May 2017): https://www.carbonpricingleadership.org/report-of-the-highlevel-commission-on-carbon-prices. Among the Commission’s conclusions: “Countries may choose different instruments to implement their climate policies, depending on national and local circumstances and on the support they receive. Based on industry and policy experience, and the literature reviewed, duly considering the respective strengths and limitations of these information sources, this Commission concludes that the explicit carbon-price level consistent with achieving the Paris temperature target is at least US$40–80/tCO2 by 2020 and US$50–100/tCO2 by 2030, provided a supportive policy environment is in place.” (Emphasis added.)

[9] For an analysis of the different ways of implementing a “carbon dividend”, see D. Klenert, L. Mattauch, E. Combet, O. Edenhofer, C. Hepburn, R. Rafaty and N. Stern, “Making Carbon Pricing Work for Citizens”, Nature 8 (2018), 669-677.

[10] The “Economists’ Statement on Carbon Dividends” was signed by, amongst many others, 4 former Chairs of the Federal Reserve, 27 Nobel Laureate Economists and 15 Former Chairs of the Council of Economic Advisers. See now also https://clcouncil.org/Bipartisan-Climate-Roadmap.pdf.

[11] Helm’s report was commissioned by the then Secretary of State for Business, Energy and Industrial Strategy, Greg Clark. At the time of writing, the government had yet to issue a substantive response to it.

[12] See https://policyexchange.org.uk/wp-content/uploads/2018/07/The-Future-of-Carbon-Pricing.pdf.

[13] Ofgem, State of the Energy Market 2019, page 129 (figure 5.10).

[14] See https://www.gov.uk/government/consultations/the-future-of-uk-carbon-pricing.

[15] At the time of writing, a government response had not yet been issued in respect of the majority of this consultation.

[16] See https://ec.europa.eu/info/strategy/priorities-2019-2024/european-green-deal_en.

[17] For commentary, see Sandbag’s report, The A-B-C of BCAs An overview of the issues around introducing Border Carbon Adjustments in the EU. The ultimate relationship between the UK as a whole and the EU ETS remains to be determined, but the agreement between the UK and the EU on the UK’s withdrawal from the EU requires the EU ETS rules to continue to be applied in Northern Ireland as part of the basis for continuing the operation of the Single Electricity Market on the island of Ireland. If the EU border carbon adjustment is implemented as part of the EU ETS regime, the UK may be under pressure to adopt a similar measure.

[18] For a general survey of the distributed ledger technology and its potential applications in the energy sector, see https://www.dentons.com/en/insights/guides-reports-and-whitepapers/2018/october/1/global-energy-game-changers-block-chain-in-the-energy-sector.

[19] See https://www.ogauthority.co.uk/news-publications/news/2019/the-oil-and-gas-authority-launches-one-of-the-largest-ever-public-data-releases/.

[20] See https://www.woodmac.com/press-releases/digitalisation-in-us-lower-48/.

[21] There are various examples in the publication cited in note 19 above, but see also https://www.gazprom-neft.com/press-center/news/gazprom-neft-and-s7-airlines-become-the-first-companies-in-russia-to-move-to-blockchain-technology-i/.

[22] See https://www.sciencedaily.com/releases/2019/07/190711114846.htm.

[23] See https://www.climateliabilitynews.org/2019/12/23/climate-litigation-threat-financial-filings/.

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A smart carbon tax: the silver bullet for the (just) energy transition?

The way towards a competitive bidding process for new offshore wind farms in Belgium

To meet the challenge of the nuclear phase-out scheduled for 2025 as well as ambitious climate change goals, the Belgian federal government has established a new legislative framework aimed at achieving an additional offshore wind energy capacity of at least 1.75 GW.

The amended “Electricity Law” introduced a competitive tender procedure for the construction and operation of offshore renewable sources. The current support mechanism, under which the installation benefits from a subsidy per MWh produced, remains applicable.

Several calls for tenders will be launched in Belgium in the next few years, providing opportunities for new investors.

Read the full article

The way towards a competitive bidding process for new offshore wind farms in Belgium

Europe’s energy regulators work together to tackle market abuse and insider trading

Supported by the market monitoring and coordination activities of the Agency for the Cooperation of Energy Regulators, ACER, in the last few months, Europe’s energy regulators have increasingly used their powers to police behavior in the European wholesale energy market. This article discusses the joint efforts of ACER and Europe’s national energy regulators to ensure compliance with specific market regulations. In the last quarter of 2018 and the first quarter of 2019, we have seen fines and sanctions imposed for alleged abuses in the European wholesale energy market, and a dawn raid in a potential case of insider trading.

REMIT, the EU Regulation on the Wholesale Energy Market Integrity and Transparency, prohibits, inter alia, insider trading and market manipulation in the wholesale energy market in accordance with Articles 3 and 5 respectively.  Willingness to enforce REMIT has been increasingly demonstrated by national regulators in the course of the last few months.

REMIT’s definition of and prohibition of market manipulation (excerpts):
Article 2
Definitions
For the purposes of this Regulation the following definitions shall apply: 1…]
2) ‘market manipulation’ means: :
a) entering into any transaction or issuing any order to trade in wholesale energy products which:
(i) gives, or is likely to give, false or misleading signals as to the supply of, demand for, or price of wholesale energy products;
(ii) secures or attempts to secure, by a person, or persons acting in collaboration, the price of one or several wholesale energy products at an artificial level, unless the person who entered into the transaction or issued the order to trade establishes that his reasons for doing so are legitimate and that that transaction or order to trade conforms to accepted market practices on the wholesale energy market concerned;
1…]
Article 5
Prohibition of market manipulation
Any engagement in, or attempt to engage in, market manipulation on wholesale energy markets shall be prohibited.

REMIT has been in place since the end of 2011. While there were few, if any, proceedings during the first seven years, the situation has now changed, with the means to detect market manipulation becoming more sophisticated and an increase in alerts raised by market participants. Crucial here has been the increased data gathered by national regulators and ACER, Europe’s Agency for the Cooperation of Energy Regulators, since reporting obligations came into effect in 2015/2016.

According to ACER, 60-80 suspicious events have been notified to national energy regulators and the number of cases currently under investigation rose significantly from just three in 2012 to 189 by the end of Q2 2019. Out of the seven cases on market manipulation that have been decided by national regulators, six have been decided since October 2018.

In 2015, in the first decision in this field taken by a national regulatory authority, CNMC, the most active national regulator in REMIT enforcement activities, concluded that a Spanish energy company withheld water at its hydropower plants without legitimate reason and justification and thus manipulated the electricity day-ahead prices resulting in an increased market price.

ACER’s guidance on the application of Regulation (EU) No 1227/2011, REMIT, provides further guidance on the withholding of capacity, now 6.4.1 i) 4th edition:

“Actions undertaken by persons that artificially cause prices to be at a level not justified by market forces of supply and demand, including actual availability of production, storage or transportation capacity, and demand (‘physical withholding’): This is for example the practice where a market participant decides not to offer on the market all the available production, storage or transportation capacity, without justification and with the intention to shift the market price to higher levels, e.g. not offering on the market, without justification, a power plant whose marginal cost is lower than the spot prices, misusing infrastructure, transmission capacities, etc., that would result in abnormally high prices.”

This very early decision of the CNMC in 2015 on market manipulation was followed, starting in October 2018, by a series of decisions from various national regulators, namely the Spanish, French, Danish, German and most recently the UK national regulators, which fined companies for alleged cases of market manipulation. Some of these decisions are under appeal. These cases deal with allegations of transmission capacity withholding, commercially non-rational use of otherwise legitimate trading methods, price setting at artificial levels, exclusion of market participants from trading and placing bids or offers with no intention to execute them, but to buy at a lower or sell at a higher level. National regulators have also decided other cases where prices have been above marginal costs and higher than those of comparable combined cycle plants on the basis of national regulation of the electricity market rather than based on the provisions of REMIT.

In addition to various infringement decisions on market manipulation that have been issued since October 2018, there has also been an increase in action on insider trading. More recently, the Netherlands Authority for Consumers and Markets (ACM) stated that it had conducted a dawn raid at a company active in the electricity sector. Echoing the Danish and the German national regulators, the Director of ACM’s energy department, Remko Bos, made it clear that national energy regulators are making joint efforts in their enforcement activities. Remko Bos was quoted as follows:

“By enforcing compliance with REMIT, we help boost consumer confidence and that of other market participants in the energy market. We do so in cooperation with our fellow European regulators.”

Cooperation between European regulators demonstrated by the rise in policing activities has been assisted by the increased amount of guidance and publications from ACER and national regulators on the topic of REMIT. Recently, ACER published the fourth edition of its Guidance on REMIT (https://documents.acer-remit.eu/wp-content/uploads/20190321 4th-Edition-ACER-Guidance updated- final-published.pdf) and its Guidance on layering and spoofing (https://documents.acer-remit.eu/wp-content/uploads/Guidance-Note Layering-v7.0-Final-published.pdf). The German Federal Network Agency, “BNetzA’” and the German Federal Cartel Authority “BKartA” have published their joint draft guideline on the supervision of antitrust and wholesale energy law abuse in the realm of electricity generation/wholesaling. The object of the document, when finalized, will be to provide market participants with guidance on the permissibility of price peaks in the wholesale market for electricity.

The series of fines imposed on energy companies for market manipulation, the high number of investigations currently pending, the likelihood that fines may become more substantive once sufficient case law has been established and the chance that cases may even result in serious criminal proceedings, demonstrate the importance of REMIT and other market regulations. To the extent that recent supervisory activities by national regulators and publications from ACER and other regulators show the way forward, it is very much in energy companies’ own interests to reexamine the robustness of their current programs, policies and processes. As in other compliance areas, it is critical to implement and maintain effective and sufficiently resourced programs that support employees taking relevant commercial decisions and ensure decision makers have a thorough understanding of violations in terms of scope, prohibitions and consequences. This will help companies avoid investigations, administrative fines, confiscation of earnings and possibly criminal sanctions, both on a corporate and an individual level, not to mention potential claims for damages brought by other market participants, as regularly seen in cartel cases. In short, companies and their decision makers would be well advised to examine whether their current compliance management systems and processes are still fit for the purposes of REMIT and other market regulations.

More to come.

If you have any question about any of the issues raised in this post, we are happy to assist you. Please contact Dr. Gabriele Haas (mailto: Gabriele.Haas@Dentons.com)

Europe’s energy regulators work together to tackle market abuse and insider trading

FER1 Decree 2019: Incentives Regime for Renewable Energy Plants in Italy

On July 8, 2019, the Italian government signed a ministerial decree that will grant new incentives to renewable energy sources (the so-called FER1 Decree).

Six years after the expiry of the fifth Conto Energia, photovoltaic plants can once again benefit from incentives. Other sources benefiting from the scheme include onshore wind, hydroelectric and sewage gases. The scheme will apply until the end of 2021 and will provide new incentives of about €1 billion per year.

The government expects that it will allow for the construction of new plants with a total capacity of about 8,000 MW with investments estimated to be in the region of €10 billion.

Please download below the guide to have more information.

Click here to read the guide

FER1 Decree 2019: Incentives Regime for Renewable Energy Plants in Italy

Unlocking Poland’s Offshore Potential

2018 brought many positive changes in this area. The Polish government secured a favorable state aid decision from the European Commission and amended the key framework regulation on renewable energy sources (RES). This paved the way for the first major auction organized by the Polish National Regulatory Authority – the President of the Energy Regulatory Office.

Nearly 600 onshore projects, most of them smaller sized photovoltaic installations, received approximately €3.28 billion in 15-year contract-for-difference type benefits. Last, but not least, the Minister of Energy presented the draft Energy Policy of Poland 2040, setting out the expected future course of development of the Polish energy mix, which is especially promising for the offshore wind and PV markets.

Download the full insight


Published in the Project Finance International Global Energy Report April 2019 by Refinitiv (formerly the Financial and Risk business of Thomson Reuters)

Unlocking Poland’s Offshore Potential

Chile – a clean energy powerhouse

The authors advise on energy projects at the Chilean law firm Larraín Rencoret Urzúa.  In September 2018 it was announced that, following a vote by the partners of Dentons, it was expected that Larraín Rencoret Urzúa would shortly be combining with Dentons.

In the 1980s, Chile was one of the pioneers of electricity market liberalization. More recently, benefiting from both the strength of its regulatory culture and its exceptional renewable energy resources, its non-hydro renewables sector has enjoyed spectacular growth, particularly in the form of solar projects – and there is more to come.

1.         Policy and law

Chile was the first country to privatize its formerly state-owned electricity industry. Through Decree-Law (DFL) No. 1, enacted in 1982 (the General Law of Electricity Services or LGSE), Chile introduced a deep reform to the electricity sector, obliging vertical and horizontal unbundling of generation, transmission and distribution. This led to large-scale private investment, and introduced competition into the generation sector. A minimum global cost operation model was established, and generation companies were encouraged to enter freely into supply contracts with non-regulated customers and distribution companies (regulated customers).

In recent years, Chile has aggressively pursued an ambitious program to move the country’s energy matrix towards non-conventional renewable resources (NCRE: i.e. renewable electricity generation technologies other than large-scale hydropower). The government’s energy policy encourages supply, security, efficiency and sustainability.

As a first step, in 2004, and as a result of its successful economic development, Chile introduced several legal changes in the industry, which have brought new investment in the electricity generation field and major possibilities for the transmission sector, especially in the interconnection of the two major electricity transmission systems (Central Interconnected System “SIC” and Norte Grande Interconnected System “SING”). As a first critical step, changes to the LGSE, made official in March 2004 through Law No. 19,940, modified several aspects of the market affecting all generators by introducing new elements, especially those applicable to NCRE. In particular, small-scale NCRE generators can now participate more aggressively in the electricity market, as they are partially or totally exempt from transmission charges.

Likewise, Law No. 20,257, better known as the Non-Conventional Renewable Energy Law, which came into force on April 1, 2008, introduced a requirement on all electricity companies selling electricity to final customers to ensure that a certain proportion of the electricity they sell comes from NCRE. A power company unable to comply with this obligation must pay a penalty for each MWh short of this requirement. As of 2013, with the enactment of Law No. 20,698, known as the 20/25 Law, which amended Law No. 20,257, Chile’s objective is that, by 2025, 20 percent of the electricity produced in Chile will come from NCRE sources.

On October 14, 2013, Law No. 20,701 was published in the Official Gazette, amending the LGSE, simplifying the procedure for obtaining an electricity concession (a key step in the development of new substations, electricity network infrastructure and hydroelectric plants: see section 3 below). This new framework was a response to the need for speeding up the procedure and timeframe necessary to obtain an electricity concession, providing more certainty to the system. In summary:

• the process to obtain a provisional electricity concession has been simplified and the timeframe adjusted;

• there is more clarity as to the observations and challenges that those against the project can make;

• the notification process was amended; a simplified and faster judicial procedure has been introduced;

• the process of valuing land or real estate has been amended; and

• potential conflicts between different concessions have been amended.

On February 7, 2014 Law No. 20,726 amended the LGSE, in order to study and promote the interconnection of the SIC and the SING systems. The government stated that this interconnection between SING and SIC would allow the transfer of surpluses produced in the northern part of Chile to its central zones. That interconnection, which was successfully carried out at the end of 2017, should reduce electricity system costs by US$1.1 billion. The interconnection of the two systems is also expected to boost the development of renewable energies and to reduce uncertainty for operators while increasing competition.

ln 2016, Law No. 20,936 (the Transmission Law) redefined the constituent parts of the national transmission system and created the Independent Coordinator of the National Electricity System (the CISEN). Under this law, which was published on July 20, 2016, the Chilean government aims to contribute to the timely expansion of the electricity transmission network. The Transmission Law heightens the role of the government in the electricity sector, granting it greater capacity to execute electricity infrastructure planning, expand the system and determine and manage the creation of land strips for the installation of new structures related to transmission lines. Regarding the CISEN, it has among its duties the coordination of operations, determination of the marginal costs of electricity, to assure open access to the transmission systems, to maintain global safety, and to coordinate economic transactions between agents, determining the marginal cost of electricity and economic transfers among the organizations that it coordinates.

Finally, it is important to mention the project to reform the Water Code that could affect any new hydroelectric project in Chile. The aim of the pending bill would be to reduce water shortages, proposing a series of regulatory changes. Specifically, it proposes an increase in state control, which could affect the legal certainty necessary for the development of economic activities, and would seek to change the legal nature of existing water rights, undermining property rights. This reform aims to change the perpetuity of water rights (DAA). The reform provides that the use of the DAA will have a maximum duration of 30 years, transforming the DAA into a simple administrative concession. In addition, the reform aims to create grounds for revocation, which could affect existing DAAs.

2.         Organization of the market

The electricity market in Chile has been designed in such a way that investment and operation of the electricity infrastructure is carried out by private operators, promoting economic efficiency through competitive markets, in all non-monopolistic segments. Thus, generation, transmission and distribution activities have been separated in the electricity market, each having a different regulatory environment.

The distribution and the transmission segments are both regulated and have service obligations and prices fixed in accordance with efficient cost standards. In the generation sector, a competitive system has been established based on marginal cost pricing (peak load pricing), whereby consumers pay one price for energy and one price for capacity (power) associated with peak demand hours.

According to the National Commission of Energy (CNE), Chile’s power generation for September 2018 was 5,972GWh, comprised of: thermoelectric 57 percent, conventional hydroelectric 23 percent and NCRE 20 percent. It is the fifth-largest consumer of energy in South America.

The wholesale electricity market comprises generation companies that trade energy and capacity between them, depending on the supply contracts they have entered into. Companies capable of generating more than the amount they have committed in contracts sell to companies with a generation capacity below what they have contracted with their customers. The CISEN determines physical and economic transfers (sales and purchases) and – in the case of energy – valued on an hourly basis at the marginal cost resulting from the operation of the system during that hour.

3.         Authorization to construct and operate generation facilities

While no governmental authorization has to be obtained in order to construct and operate generation facilities, power utilities usually obtain electricity concessions to acquire fundamental rights to protect their investment. A classic key right is the imposition of a right of way over the land whose owners are reluctant to grant rights of way through voluntary agreements. These electric concessions, however, are only available for the construction and development of hydropower plants, substations and transmission lines. These rights of way are fundamental to allow the power company to secure the transport of electricity to the national grid. Notwithstanding the above, authorizations under the Environmental Law, the Land Use Planning Law and the Municipality Law may be required when building a power plant or generation facility.

The Environmental Law (Law No. 19,300, as amended by Law No. 20,417, enforceable since January 26, 2010) establishes a regulatory framework applicable to projects with an environmental impact (article 10 of the Environmental Law and article 3 of its regulation determines the projects that must be submitted to the environmental impact assessment process, among which are power plants with output capacity in excess of 3MW). These projects may force the developer to request and obtain an environmental approval resolution (RCA). In the event of infringement of the obligations established in the RCAs, the Environmental Superintendence may impose the following sanctions: verbal warning, fines of up to US$10 million, revocation of the approval or closure of the facilities.

We do not refer to other permits that must be obtained in advance of developing a generation facility project, such as land use planning permits, water rights or geothermal exploration or exploitation concessions.

According to information provided by the CNE, by October 2018, 56 power generation projects were under construction. Together they represent a capacity of 2,838MW and are expected to start operation between July 2017 and October 2022.

4.         Alternative energy sources

According to the CNE, in September 2018, 20 percent of Chile’s power generation came from NCRE. In this respect, Chilean law contains incentives as well as obligations to foster the use of renewable energies. Law No. 19,940, Law No. 20,257 and the regulations contained in Supreme Decree No. 244 (which regulates the NCRE based in small generation units of up to 9MW, known as “PMG” or “PMGD” depending on the type of network to which they are connected) create the conditions necessary for the development of NCRE, encouraging power generation based on alternative energy sources.

Incentives

NCRE power facilities with less than 20MW may sell their output capacity to the spot market without having to pay (totally or partially) tolls to transmission companies (with differentiated treatment for units of up to 9MW and those between 9MW and 20MW). As regards PMG (only if classified as NCRE) and PMGD, Chilean law incentivizes the development of this kind of energy source, granting them the possibility to decide whether to sell energy at the spot market price (marginal cost) or at a fixed price. Another incentive to this kind of projects is that all PMG and PMGD will operate with auto dispatch, meaning that the owner or operator of the respective PMG or PMGD will be responsible for determining the power and energy to be injected into the distribution network to which it is connected (coordinated with the CISEN).

Obligations

As noted above, by Law No. 20,257, all electricity companies selling energy to final customers must ensure that a given percentage (20 percent) of the energy they sell comes from an NCRE source. In fact, this target was met some seven years ahead of schedule, because, in 2018, 20 percent of the withdrawals of the power companies will have been injected into the system from NCRE sources. However, already in 2015, the government had published a long-term energy policy (to 2050), which aims, amongst other things, to reach renewables (NCRE + conventional hydropower) shares of electricity generation of 60 percent by 2035 and at least 70 percent by 2050.

New and exclusive bidding process for NCRE

Since 2015, the Ministry of Energy has been obliged to carry out a public bidding process every year for energy coming from NCRE sources, which will help to reach the quotas of NCRE required by law. This competitive mechanism aims to improve the financing conditions of NCRE, and has the followings characteristics:

• the public bidding process can be implemented separately for each transmission system in up to two bidding periods per year. The amount of energy will depend on the projections for the fulfillment of NCRE quotas for the next three years;

• each participant in the bidding process shall submit an offer including the amount of energy (GWh) and a price (US$/MWh); and

• the project will be awarded to the cheapest bid until the necessary amount of energy is reached, considering a maximum price equal to the average cost of the most efficient generation technology of the electric system that can be installed in the long term.

5.         Other incentives

Two major undertakings have been launched for the purpose of introducing incentives on NCRE: improvement of the regulatory framework of the electricity market and the implementation of direct support mechanisms for investment initiatives in NCRE:

a. The proposed changes to the regulatory framework intend, among other things, to create the conditions to implement a portfolio of NCRE projects to accelerate the development of the market; to eliminate the barriers that frequently impede innovation; and to generate confidence in the electricity market regarding this type of technology. This is partially achieved by the government enacting the law for the development of NCRE (Law No. 20,257 amended by Law No. 20,698).

b. On the other hand, as declared by the current Environment Minister, since the ratifying of the United Nations Framework Convention on Climate Change (UNFCCC) in 1994 and the signature of the Kyoto Protocol in 2002, Chile has actively engaged in the establishment of national policies in response to climate change. In this regard, it is important to mention Law No. 20,780, which established a new annual tax on emissions from CO2, SO2, NOx and particulate matter (PM) sources. It is aimed at facilities with boilers or turbines that, together, add up to a heat output of at least 50 megawatts thermal (MWth). This tax is called a “green tax” since it would be an incentive for the growth of NCRE projects. Specifically, Chile’s green tax targets large factories and the electricity sector, covering an important percentage of the nation’s carbon emissions. In the case of PM, NOx and SO2 emissions into the air, the taxes will be the equivalent of US$0.1 per ton produced or the corresponding proportion of said pollutants, increasing the result by applying a formula that takes into account the social cost of pollution such as costs associated with the health of the population. In the case of CO2 emissions, the tax is equivalent to US$5 for each ton emitted. In order to determine the tax burden, the Chilean Environmental Superintendency will certify in March of each year a number of emissions by each taxpayer or contributor during the previous calendar year. Each taxpayer or contributor who uses any source that results in emissions, for any reason, shall install and obtain certification for a continuous emissions monitoring system for PM, CO2, SO2, and NOx. This tax will be assessed and paid on an annual basis for the emissions of the prior year, beginning in 2018 for the 2017 emissions.

6.         Energy Goals

One remarkable aim in the energy sector, which was included in Law No. 20,936 mentioned in section 1 above, is to define and incorporate electricity storage systems along with generation and transmission facilities, and to organize all the electricity system (including storage) under the CISEN. The Chilean regulatory framework does not currently support electricity storage in a particular way but grants the CISEN broad powers and the ability to allocate permanent funds for research, development and innovation in energy storage. In the coming months, the Chilean authorities must publish the special regulations for the functioning of the CISEN and particularly on how it will use the available funds. In this regard, a new regulatory decree (“Reglamento de Coordinación y Operación”) is already under discussion between the Ministry of Energy and key private players.

The vision of Chile’s energy sector is reflected by its whole legal framework and regulatory system. That vision is also reflected by Chile’s Energy Agenda to 2050. By the year 2050, the vision is to have a reliable, inclusive, competitive and sustainable energy sector. Chile’s development must be respectful of people, of the environment and of productivity, and must ensure continuous improvement of living conditions. The aim is to evolve towards sustainable energy in all its dimensions, on the basis of the attributes of reliability, inclusiveness, competitiveness and environmental sustainability. Chile’s energy infrastructure shall cause low environmental impact. Such impact should be avoided or, if not, then mitigated and compensated. The energy system must stand out as an example of low greenhouse gases emissions and as an instrument to promote and comply with international climate-related agreements.

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Chile – a clean energy powerhouse

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

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)