Global Energy Blog 

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 2^nd 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.

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[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/.

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

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

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

Read the full article

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

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

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

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

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

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

ACER’s guidance on the application of Regulation (EU) No 1227/2011, REMIT, provides further guidance on the withholding of capacity, now 6.4.1 i) 4th edition: “Actions undertaken by persons that artificially cause prices to be at a level not justified by market forces of supply and demand, including actual availability of production, storage or transportation capacity, and demand (‘physical withholding’): This is for example the practice where a market participant decides not to offer on the market all the available production, storage or transportation capacity, without justification and with the intention to shift the market price to higher levels, e.g. not offering on the market, without justification, a power plant whose marginal cost is lower than the spot prices, misusing infrastructure, transmission capacities, etc., that would result in abnormally high prices.”

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

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

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

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

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

More to come.

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

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

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

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

Please download below the guide to have more information.

Click here to read the guide

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)

German energy assets continue to draw international investors’ interest. However, in Germany as in other EU Member States, foreign investment in critical infrastructure, such as energy facilities, is a sensitive issue for the Government. New rules introduced in 2017 and 2018 come amid rising concerns that such assets are being systemically acquired by foreign investors, particularly from China. The intensity of foreign direct investment (“FDI”) reviews by the German Federal Ministry for Economic Affairs and Energy (Bundesministerium für Wirtschaft und Energie – “BMWi” or “Ministry”) has increased since 2016. The more restrictive approach in Germany has been backed by Regulation (EU) 2019/452 of 19 March 2019 establishing a framework for the screening of foreign direct investments into the Union (“EU framework”). Moreover, the next reform is well underway.

It is essential for foreign investors, sellers and targets’ executives to consider the scope and implications of FDI review. In this article we review the significant regulatory changes to FDI screening and highlight the considerations for those involved in transactions in the energy sector.

I Review tools in Germany

Germany has had formal mechanisms in place to review FDI since 2004. The jurisdictional threshold at which the Ministry can intervene to protect security interests is linked to the shares / voting rights acquired in a German company. The general threshold lies at 25%. Most recently, the German government lowered the threshold to 10% in particularly sensitive areas.

A national security screening mechanism requires that any non-German investor notifies the Ministry of the acquisition of a target company with certain defense and IT security / cryptography products within its portfolio (so-called sector-specific investment review: Sec. 60 – 62 Foreign Trade and Payments Ordinance – Außenwirtschaftsverordnung “AWV”). However, the grounds for screening in Germany are not limited to the protection of essential interests of national security. Indeed, since 2009 BMWi may control and block acquisitions by investors established outside the territory of the EU and EFTA region in any sector, if the transaction would endanger public order or security (cross-sector review: Sec. 55 – 59 AWV). This procedure applies to the energy sector as well. EU Courts have acknowledged that public security may be affected by acquisitions related to issues such as security of supply in the event of a crisis, telecommunications and electricity, or the provision of services of strategic importance.[1] Even though this jurisprudence circumscribes Member States’ discretion regarding the scope of public security reviews, without specific guidance, it is hard to predict which transactions trigger review by the Ministry and which do not.

II. AWV-reform of 2017 – tighter controls on critical infrastructure

1. Substantive amendments

In that regard, the AWV-reform of 2017 brought some clarification. The German government specified in which cases “an endangerment for the public order or security of Germany” likely exists. The amended Sec. 55 AWV requires BMWi to apply heightened scrutiny to certain types of investments, particularly those that could result in foreign control over German critical infrastructure. Federal Economic Minister Peter Altmaier recently stressed, “companies which supply us with electricity, gas and drinking water or which safeguard our telecommunications are of outstanding importance for our society.”[2] This includes German companies, which develop and modify “sector-specific software”, i.e. software that is used for operating and controlling critical infrastructure facilities (Art. 55 para. 1 sentence 2 no. 2 AWV). The concern is that the purchase of such highly significant IT application manufacturers by non‑EU investors could lead to the outflow of security-relevant information about the operation of critical infrastructures. Providers of critical infrastructure may have no or only less trustworthy alternatives available on the market.

In order to determine which companies can be regarded as operating critical infrastructure, reference is made to the German IT Security legal framework. According to the definition in Art. 2 para. 10 of the Act on the Federal Office for Information Security (Gesetz über das Bundesamt für Sicherheit in der Informationstechnik), critical infrastructures are facilities which belong to the energy, information technology, telecommunication, transport and transportation, health, water, nutrition as well as finance and insurance sectors and are of utmost importance for the functioning of the community.

In order to determine which energy facilities provide a significant level of supply for society, three steps should be considered.

First step (see first column of image below): Is the target company engaged in an energy service which is deemed critical (cf. Sec. 2 para. 1 Regulation for Determining Critical Infrastructures – “BSI-KritisV”)?

Second step (see second column of image below): Are categories of facilities involved, which are necessary for providing these services?

Third step (see third column of image below): Finally, crucial for the identification of sensitive transactions in the energy sector is, whether the target company achieves the stipulated threshold values or, whether the relevant software provider has such facilities among its customers. In order to ascertain whether the threshold has been reached, it may be necessary to count several systems together. In general, the thresholds of the BSI-KritisV apply to each system. Several installations may, however, comprise a so-called joint installation, with the consequence that the individual values have to be added together for the threshold calculation. In the energy sector, according to Annex I to the BSI-KritisV, part 2, para. 7, several installations of the same type, which have a close spatial and operational relationship and meet the relevant threshold together, are as joint installation considered critical infrastructure. Common management of installations is a pre-requisite for a close spatial and operational context (cf. Annex I to the BSI-KritisV, part 2, para. 7 lit d).

Source: Federal Ministry of the Interior

If according to the three-step test outlined above, energy assets are subject of the transaction, a filing of the foreign takeover with BMWi is mandatory. Please note, even if the energy facility is not deemed “critical”, the transaction may still be subject to cross-sector review pursuant to the general clause in Art. 55 para. 1 sentence 1 AWV. Therefore, one should always analyze whether the contemplated cross-border transaction bears any (energy) security relevance. It is prudent to explore the reaction of BMWi to the takeover of the particular energy facility. Informal discussion can be carried out without triggering an obligation to file.

2. Procedural amendments

Prior to the AWV-reform of 2017, outside the defense and security sector, foreign investors were not required to notify any transaction. The Ministry was dependent upon information sharing by other public authorities; in particular, the Federal Cartel Office. Now, upon signing of the purchase agreement (schuldrechtlicher Vertrag), the direct acquirer of any German energy company covered by Art. 55 para. 1 sentence 2 AWV is obliged to notify the transaction. The notification sets in motion a time limit of three months for the BMWi to initiate the second phase of the cross-sectoral review procedure (cf. Art. 55 para. 3 AWV). If the investor does not either notify the transaction or apply for a clearance certificate (Unbedenklichkeitsbescheinigung), deal certainty can be obtained no earlier than five years after signing. Only then, is BMWi precluded from reviewing or blocking the transaction. Consequently, even if the transaction is exempted from notification, in cases of doubt, investors should apply for a clearance certificate. A clearance certificate is a formal confirmation of BMWi to the investor that the acquisition does not raise any concerns with respect to public order or security (cf. Sec. 58 AWV). The application shall cite the acquisition, the acquirer and the domestic company to be acquired and outline the fields of business in which the acquirer and the domestic company to be acquired are active. Under the old regime, a clearance certificate was deemed to have been granted if the Ministry did not open an examination procedure within one month after receipt of the application. The AWV-reform of 2017 has extended this period to two months. Additionally, the period for the review procedure itself (second stage) has been extended from two to four months. An issue to be considered is that the periods for any antitrust review of a transaction are very likely to differ from the periods for the review under the amended AWV. Still, the urgency to close a transaction must be balanced against the uncertainty created by not filing. In an era of risk abatement, the offer of safe harbor from post-transaction government action to alter or unwind the transaction is hard to resist.

The 2017 AWV-reform also clarified that EU acquisition vehicles cannot be used to circumvent the cross-sector investment review procedure, cf. Sec. 55 para. 2 AWV.

III. AWV-reform 2018 – German Government lowers review threshold

Shortly before Christmas 2018, the Federal Government adopted further amendments to the rules on FDI screening. Importantly, the Government lowered the review threshold from 25% to 10% in the particularly sensitive areas listed in Sec. 55 para. 1 sentence 2, i.e. critical infrastructure. Accordingly, an FDI review in the energy sector is now triggered if a non-EU investor acquires as little as 10%, rather than 25%, of a company that operates critical infrastructure facilities (cf. the three steps above). Thus, even more energy deals will be in the scope of the Ministry. With this move, the German Government plugs a gap in legislation. Last summer, State Grid Corporation of China (“SGCC”) planned the acquisition of 20% of 50Hertz, one of Germany’s power grid operators. Although 50Hertz qualified as critical infrastructure, BMWi had no authority to officially review or even block the transaction, as it was below the 25% threshold. Eventually, the Government intervened through the German state-owned development bank KfW (Kreditanstalt für Wiederaufbau) to preemptively acquire the 20% stake, and, effectively block SGCC’s proposed investment.

IV. Trend towards greater scrutiny in Germany backed by developments at EU level

Although the German Government was keen to emphasize that the meaning of public security, which derives from EU law, was not changed or even expanded by the 2017 AWV-reform, it sought additional backing for its initiative at EU level. In November 2018, EU legislating bodies reached a political agreement on an EU framework for the screening of FDI. The EU framework officially entered into force on 10 April 2019. Member States’ governments have 18 months to implement the new rules. The Commission, meanwhile, is taking the necessary steps to make the framework operational by October 2020. These steps concern, in particular, the setting up of the new EU-wide mechanism for cooperation, enabling Member States and the Commission to exchange information and raise concerns related to specific foreign investments. While the 2017 AWV-reform anticipated the substantive regulatory changes, procedural amendments to the German screening process will be necessary.

1. EU ramps up scrutiny of foreign investors

The envisaged EU framework employs the screening criterion of public order or security and explicitly describes factors to help Member States and the Commission determine whether an investment is likely to affect public security. The indicative list in Art 4 para. 1 of Regulation (EU) 2019/452 includes the effects of the investment on, inter alia,

1. 1. 1. • critical infrastructure, whether physical or virtual, including energy, as well as land and real estate crucial for the use of such infrastructure;
         • critical technologies and dual use items, including energy storage and nuclear technologies; and
         • supply of critical energy inputs.

Accordingly, the AWV-reform of 2017 in Germany, which aims at protecting critical infrastructure and, hence, the energy sector, is backed by the EU framework. Moreover, the framework (cf. Art 4 para. 2 of Regulation (EU) 2019/452) condones the recent practice of BMWi, which gives consideration to additional aspects in the screening procedure, such as access to sensitive information and whether the foreign investor is state-controlled or state-funded. In other words, even if a standalone investment in the energy sector would not appear to have a significant national security impact per se, BMWi could still apply mitigation measures or ultimately block the transaction, where overall foreign ownership of the investor would present a security concern.

1. Procedural features of the EU framework

While the ultimate decision to allow, condition or block FDI remains with the Member State concerned, the Commission will have greater influence on future screenings of FDI. Furthermore, other Member States may exert political pressure. The Commission will obtain a new competence to screen FDI and issue a non-binding opinion in the event that the investment has the potential to affect the security of projects or programmes of EU interest (cf. Art. 8 of Regulation (EU) 2019/452), such as the “Trans-European Networks for Energy (TEN-E)” or the security of another / other Member State(s). The EU framework also creates a cooperation mechanism between Member States and the Commission. Currently 14 EU Member States[3] have FDI screening mechanisms in place. Differing approaches in terms of scope and design are followed in these countries. To date, no formal coordination among Member States and the Commission exists in this field. In future, Member States will need to inform each other and the Commission of any investment that is undergoing screening by their national authority (cf. Art. 6 of Regulation (EU) 2019/452). Even in cases where a foreign takeover is not undergoing screening but another Member State considers that this investment is likely to affect its security or the Commission considers that the investment is likely to affect the security in more than one Member State, the Commission is empowered to issue an opinion and other Member States may provide comments (cf. Art. 7 of Regulation (EU) 2019/452). In general, comments or opinions have to be addressed to the Member State where the foreign direct investment is planned or has been completed no later than 35 calendar days after receipt of certain relevant information.

Source: European Commission

For the exchange of information and analysis, formal contacts in each Member State will be set up. The screening procedures at national level in Germany will likely be extended to allow for an exchange of opinions with the Commission and other Member States. Consequently, deal timing gets even more important.

V. Next reform is well underway

Most likely, this was not the last reform bill passed to protect domestic companies from foreign takeovers. As part of Germany’s new National Industrial Strategy 2030,[4] Peter Altmaier has called for the creation of a state investment fund that would step in to pre-empt foreign takeovers of German companies.[5] Such a fund, once created, can be considered as a complementary tool to the authority of BMWi. A tangible discomfort around the issue of Chinese investment is even present among German business representatives. The influential German industry group Federation of German Industries (Bundesverband der Deutschen Industrie e.V. – “BDI”) calls for tougher policies against China.[6] However, BDI criticizes the idea of a state investment fund. Instead, it supports a reform of competition law, including EU state aid rules.

VI. Key takeaways – Implications for deal planning

In particular for China, with its “Belt and Road Initiative” and industrial plan “Made in China 2025”, investments in the EU’s energy market remain highly attractive. However, as we experience in our daily practice, the trend of expanding review of FDI does not appear to be going away soon. Foreign investors, in general, have to expect a more rigid approach of authorities compared to the past. Risk and time management at an early stage of the cross-border transaction process are key to project success. There is no doubt, the new rules increase deal uncertainty. Those contemplating investments in German energy facilities should allocate more time, attention and resources to the screening process. Pre-deal considerations should include:

• Timing: Foreign investors, sellers and target companies should be aware of the timing of an investment review. While BMWi is responsible for the implementation of the review procedure, it will involve other federal ministries as the case may be within the scope of their respective authority. Obviously, such consultation and deliberation add to the length of the procedure. The screening procedures at national level in Germany will likely be extended to allow for an exchange of opinions with the Commission and other Member States after the final implementation of the cooperation mechanisms based on the EU framework by October 2020. Therefore, effective management is key to expedite the procedure to meet the timeline needs.
• Know your business (and the one you are investing in): Foreign investors, sellers and target companies must have a thorough understanding of whether the energy facility is to be considered as “critical infrastructure” or bears any other relevance for energy security. Take careful stock in case the target company designs or modifies software for energy facilities. It may be classified as “energy-sector-specific software”, i.e. software that is used for operating and controlling critical energy infrastructure facilities or has access to a large amount of data. In cases of doubt, investors should apply for a clearance certificate (comfort letter). It provides legal certainty to the investor, the seller and the target.
• State-driven takeovers: Consider whether the transaction involves a country of special concern that has demonstrated or declared a strategic goal of acquiring a type of critical technology or critical infrastructure that would affect issues related to national or public security.
• It is not only about Control: Foreign investors, sellers and target companies must be aware of the types of transactions that, while not conferring the potential for control of the business on a foreign investor are now subject to review.

If you have questions about any of the issues raised in this post, our Competition, Antitrust and Regulatory practice group in Germany is happy to assist you – please contact Andreas Haak, Dr. Maria Brakalova or Dr. Barbara Thiemann, LLM.

[1]           The European Court of Justice explicitly recognized in Case C-503/99 (Commission v. Belgium, judgement of 4 June 2002 at para. 46) that “the safeguarding of energy supplies in the event of a crisis, falls undeniably within the ambit of a legitimate public interest”.

[2] BMWi, press release of 19/12/2018, “Strengthening our national security via improved investment screening”.

[3]               Austria, Denmark, Germany, Finland, France, Latvia, Lithuania, Hungary, Italy, the Netherlands, Poland, Portugal, UK and Spain.

[4]           Peter Altmaier presented on the draft of a National Industry Strategy 2030 early February 2019.

[5]           BMWi, 5 February 2019, „Nationale Industriestrategie 2030. Strategische Leitlinien für eine deutsche und europäische Industriepolitik“.

[6]           BDI, January 2019, „BDI-Grundsatzpapier China. Partner und systemischer Wettbewerber – Wie gehen wir mit Chinas staatlich gelenkter Volkswirtschaft um?“

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.

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.

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.