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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 “net zero” debate: UK General Election 2019 (and beyond)

Climate and energy issues are clearly very important to many voters, even if what the parties say on these issues may be unlikely ultimately to be a decisive factor in determining the outcome of the election.

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The “net zero” debate: UK General Election 2019 (and beyond)

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.

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

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.

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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.

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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

Another interesting year ahead for European renewables

On 5 February 2019, Dentons held its fourth annual workshop on investing in European renewables. Here we outline some of the key messages that emerged.

Setting the scene

At first glance, these should be happy days for the European renewables sector. Energy from renewable sources (RES) is firmly established in the mainstream of the power industry. Installation costs for wind and solar continue to drop: having fallen already by 75 percent in 2010-2017, PV costs are projected to fall by more than half again in 2015-2025. Mindful of their international and in some cases also their domestic commitments, governments have been setting some ambitious renewables targets for 2030 and beyond. Even the IEA, once a notably sceptical voice on renewables, has predicted that wind will be the largest source for power generation in Europe by 2027.

But of course life is never that simple. The days when the industry could sustain strong growth in revenues and profitability just by chasing the fattest feed-in tariffs, surfing the waves of subsidy as they washed across Europe, are long past. With maturity, the sector faces more complex problems. It must grapple with the fundamentals of commodity markets; sell itself to new classes of customers and investors; and work with governments, regulators and system operators to exploit the new technologies that can make whole power systems work in more sustainable and efficient ways. And whilst the broad outlines of the next stages in the energy transition are widely accepted, the details of how best to achieve it remain a matter of debate.

Country snapshots

No two jurisdictions in Europe present the sector with quite the same opportunities or challenges. Dentons lawyers gave brief sketches of the renewables sectors in their home markets, covering 12 of the 20 countries featured in Investing in renewable energy projects in Europe – Dentons’ Guide 2019. We summarise below the key talking points from their presentations (the slides from which can be accessed here).

Germany produced more electricity from renewables than from coal for the first time in 2018. The growth in RES capacity may not be so large in 2019, but if buildout rates are slowing down a little, the Energiewende overall is changing gear rather than coming to a halt. The new financial support mechanisms are functioning well. The recently announced conclusions of the German government’s Coal Commission point the way to a complete phase-out of coal-fired generation. The publication of an action plan for grid expansion further indicates the German government’s continuing commitment to taking the energy transition into its next phase, and interest is strong from other sectors of industry, as the activities of German companies in the e-mobility and hydrogen sectors show.

In France, the government plans to more than double wind and solar capacity by 2023, with a further doubling of solar and 50 percent expansion of wind in the following five years to 2028. Auction mechanisms have succeeded in bringing down the price of supporting RES. Procedural changes should reduce the potential for objectors to delay projects. At the same time, it is worth remembering that the initial trigger for the gilets jaunes protests was an increase in carbon taxes: in France as elsewhere, there is an inevitable tension between the need to adopt policies to avert the “end of the world” and the need of ordinary citizens to survive financially until the “end of the month”.

The market fundamentals for the RES sector in Turkey remain strong – notably, growing demand for power and a strong government commitment to reducing dependence on imported fuel.  At present, the regulatory regime favours either very large (1 GW+) or quite small (up to 1 MW) projects.  For the latter, there is a feed-in tariff / premium support mechanism; for the former, support is based on auctions. It is unfortunate that two of these were cancelled in 2018 – one of which would have included the country’s first offshore wind project – but it is hoped that these will be reinstated.

In Poland, 2019 should be a very busy year for RES projects, as the government focuses on meeting its 2020 RES targets. After a period in which various measures were taken to discourage onshore wind, auctions will be focused on solar and onshore wind. As in many markets, the longer term future depends on electricity market reform to integrate large amounts of intermittent renewable power.

Italy has set itself ambitious plans for increasing its share of RES to 2030, focused on wind and solar. At present, it is a little less clear how these will be supported in terms of any public subsidy. On the other hand, the secondary market remains active, and Italy is one of the jurisdictions where there is considerable excitement around the prospect of subsidy-free developments, possibly financed in part by arrangements with non-utility industrial offtakers (corporate PPAs).

The Czech Republic and Slovakia demonstrate some of the same features as the Italian market, in slightly more extreme form. The boom years were some time ago, and for the moment, these jurisdictions present secondary market, rather than development opportunities. As in Italy and some other jurisdictions, the authorities are now investigating whether the subsidies of some existing projects were properly awarded – did they, for example, commission exactly when they claim to have commissioned? Careful due diligence is therefore required when assessing acquisition opportunities.

In the UK, the renewables industry faces some challenges as a result of Brexit, particular if the UK leaves the EU with no deal. However, the government has recently committed to continue to hold subsidy auctions with a focus on offshore wind every two years, and – with a third of UK power already coming from RES – it is starting to address the decarbonisation of the heat and transport sectors. For those technologies without the prospect of new regulated support (solar and onshore wind), apart from a proposed new “smart export guarantee” for sub-5 MW projects, the position is starting to improve as steps are taken to make grid charging rules work better for storage and progress is made towards developing corporate PPA models that work in a subsidy-free market.

In the Netherlands, the government continues to contest the case brought by the Urgenda Foundation and others (and now twice upheld by the Dutch courts), that it is legally obliged to reduce greenhouse gas emissions by 25 percent against a 1990 baseline by 2020. But it has in any event allocated generous subsidies to RES, including €10 billion under the SDE+ regime this year. As in the UK and Germany, offshore wind is set to grow strongly in the next few years.

Spain is another jurisdiction where interest in corporate PPAs is high, particularly among projects that have not secured support in the auction-based regime that began to operate in 2017. Some projects that did secure such support face a challenge to meet their commissioning deadlines. For those with deep pockets, there are opportunities to secure grid capacity where earlier developers’ rights have expired. There are separate incentives for self-consumption and projects in the Spanish islands.

For the renewables industry in Russia, progress has been slow for many years. Local content requirements and a bureaucratic, highly centralised power regime, have not helped, and the method of procuring RES power, being based on capacity and capital expendture, also sets it apart from other jurisdictions. But there are signs that the pace is starting to pick up. There are good prospects for self-consumption projects up to 25 MW, and for the energy from waste sector.

The renewables sector in Ukraine continues to attract international investment, driven by attractive feed-in tariffs and exemptions from import VAT. This looks set to continue under the new auction-based support regime that will take effect from 2020, but the industry’s resources will be stretched to meet the end-of-2019 deadline for projects to be eligible for subsidies under the old regime.

Alongside our own colleagues, industry stakeholders contributed insights in keynote speeches and a panel discussion (the slides from the keynote speeches can be accessed here and here). 

Conclusions

The broad, long-term direction for the renewables industry appears to be set, and in the right direction. As always, stability of regulation will be an important factor in realising the sector’s potential. But increasingly, its success will depend on the development of new investment approaches – not only to RES projects themselves, but to the development of the grid and of technology to make it work more efficiently, harnessing the power of big data, and facilitating new market models.

If you would like to discuss any of the issues raised in this post, or any other aspect of European renewables, please get in touch with any of the lawyers listed in our guide, or your usual Dentons contact.

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Another interesting year ahead for European renewables

Germany takes the first steps towards the end of coal-fired power

In 2018, the German government appointed a Commission on Growth, Structural Change and Employment, known as the Kohlekommission or Coal Commission with the task of evaluating a roadmap for the phase-out of coal-fired power production in Germany. The Coal Commission’s conclusions have now been published, setting the agenda for the next stage of the German energy transition (Energiewende).

Germany has been a pioneer of the mass deployment of wind and solar power generation. In 2018, its share of electricity generated from renewables (40.3 percent) exceeded that generated from coal (37.5 percent) for the first time. But 37.5 percent is still a lot of coal-fired power. On 26 January 2019, the Coal Commission passed its final (non-binding) resolution accompanied by a 336 page report. We summarise the effect of implementing its recommendations below.

1. Phase-out of coal-fired power production by 2038

The Coal Commission recommends the end of 2038 as the deadline for the phase-out of coal-fired power production in Germany. An integrated “opening clause” enables the phase-out date to be brought forward to 2035 in consultation with the operators if the electricity market, labor market and economic situation allow. This will be reviewed in 2032. In 2023, 2026 and 2029, the phase-out plan will also be evaluated in terms of security of supply, electricity prices, jobs and climate targets.

2. Gradual shutdown of coal power plants

At the end of 2017, Germany had operational coal power plants with a net capacity of 42.6 gigawatts (GW). They are gradually being taken off the grid anyway, however, the phase-out is supposed to be implemented earlier. 12.5 GW are expected to be taken off the grid by 2022, of which 3.1 GW are fed-in by lignite power plants that are particularly harmful to the climate. By 2030, no more than 17.0 GW may remain on the market. By 2038, all coal-fired power plants are to be shut down.

3. Compensation for (potentially) increasing electricity prices for consumers

To compensate for any increase in electricity prices triggered by the phase-out, the Coal Commission recommends reducing grid charges for private households from 2023 on. These grid charges can account for about a fifth of private households’ electricity bills, and the Coal Commission even goes so far as to suggest a subsidy for these network charges. The compensation would amount to approximately EUR 2 billion per year. But there shall be no new levies or taxes.

4. Compensation for (potentially) increasing electricity prices for companies

Energy-intensive industries are to be permanently relieved of costs arising from the price of CO2 pollution rights that coal and gas-fired power plants have to buy under the EU Emissions Trading Scheme (EU allowances). The current relief scheme for these indirect costs will expire in 2020. The government wants to apply to the EU (under state aid rules) for an extension of this compensation. Most recently, the relief amounted to almost EUR 300 million per year. Since EU allowances have become significantly more expensive, the sum will be higher in the future. The so-called electricity price compensation is to be extended until 2030.

5. Financial support for coal mining regions

Coal mining regions affected by the coal phase-out are to receive structural aids (Strukturhilfen) amounting to approximately EUR 40 billion by 2040. In addition to numerous transport projects, the establishment of federal authorities is being encouraged, which could create around 5,000 new jobs within the next ten years. Also, an investment subsidy for entrepreneurs is proposed.

According to the Coal Commission’s proposal, the aid could follow the Berlin/Bonn Act, which mitigated the impact of relocating the capital from Bonn to Berlin. By the end of April 2019, the cornerstones for a law of measures shall be in place that specifies how the German government will precisely promote structural change. Future federal governments of the individual German states are to be bound to it. The Coal Commission estimates the individual costs at EUR 1.3 billion per year over 20 years. In addition, EUR 0.7 billion is to be provided to the federal states that are not tied to specific projects. Furthermore, a special financing programme as well as an immediate programme amounting to EUR 1.5 billion in total will be set to improve the transport system. These expenses are already included in the federal budget until 2021.

6. Compensation for lignite power plants

The Coal Commission recommends contractual arrangements with power plant operators and compensation for decommissioning up to 2030, which should include both compensation for operators and socially acceptable arrangements. The older a lignite power plant is, the less compensation will be paid. If there is no contractual agreement with the operators by July 2020, the exit shall be subject to regulatory law also including compensation.

The Coal Commission also suggests that the amount of compensation should be based on amounts already paid in the past. Lignite power plants have already been taken off the grid and transferred to a reserve for climate protection purposes in the past. At that time, around EUR 600 million were paid per GW output. Of the currently more than 40 GW of coal-fired power plants still connected to the grid, about 21.8 GW are fuelled with lignite.

7. Compensation for hard coal power plants

There shall also be compensation here. However, since these power plants yield less return, a decommissioning premium shall be obtained by a series of tenders. In simple terms, this could work as follows. The German government specifies how much capacity is to be decommissioned. Power plant operators apply for this with bids for compensation. In each tender, whoever demands the lowest compensation or saves the most CO2 by shutting down the power plant will win the contract.

8. Support of coal workers and symbolic preservation of Hambacher Forst

For employees in the coal industry aged 58 and over who have to bridge the time until retirement, there will be an adjustment allowance and compensation for pension losses. Estimated costs amount to up to EUR 5 billion which employers and the state could jointly bear. Terminations of employment for operational reasons are excluded. There should be training and further education for younger employees, placement in other jobs and help with wage losses.

A piece of forest at the Hambach open-cast mine has become a symbol of the anti-coal movement. The report states that the Coal Commission considers it desirable that the Hambach Forest should remain. RWE wants to cut down the forest for brown-coal mining which was stopped by court order. Other villages and areas are also affected by opencast mining. The Coal Commission recommends a dialogue with the affected areas on the resettlements in order to avoid social and economic hardship.

9. Hedge of power supply

In order to avert the risk of blackouts due to a lack of electricity generation, the security of supply should be monitored more closely. The approval of more environmentally friendly gas-fired power plants is to be accelerated. Besides, investment incentives shall be created.

Conclusion

The publication of the Coal Commission’s report is only the start of the process of coal phase-out. In order to implement the recommendations into national and therefore binding law, many details will have to be worked out, and both the German government and parliament have to agree on their adoption. Nevertheless, it marks a hugely important step in the Energiewende, as Germany moves from merely being a champion of renewable power generation to pointing the way towards the kind of net zero carbon economy that climate science shows that we need to achieve sooner rather than later.

Germany takes the first steps towards the end of coal-fired power

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

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

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

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

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

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

What is Big Data?

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

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

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

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

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

Key issues

1. Fairness and transparency

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

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

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

2. Lawful basis for processing

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

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

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

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

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

3. Purpose limitation

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

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

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

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

4. Data minimisation

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

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

5. Individual rights

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

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

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

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

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

6. Accuracy

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

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

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

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

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

7. Security

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

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

Conclusion

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

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

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