Global Energy Blog 

The consequences of the COVID-19 outbreak for the energy sector have been wide reaching, with issues such as workers self-isolating, rig closures and disrupted supply chains. Several oil and gas companies have become increasingly concerned that this will result in an inability to fulfil their contractual obligations, causing a surge of enquires related to invoking the “force majeure” provision of contracts. As force majeure is a contractual concept under English law (though not under certain civil law regimes), each case has to be regarded on its own individual merits.

In practice, force majeure clauses may have a variety of forms, some of which are further detailed below, but the overarching principle is that an unprecedented event has occurred, which prevents a party from actually performing its contractual obligations (rather than it is more expensive to do so) and typically that force majeure event is the sole cause of the party’s inability to perform. This may clearly be more of an issue where performance is also influenced by the recent crash in the oil price (which would not qualify as force majeure). In addition, the party relying on force majeure would usually have to take steps to mitigate the effects of a force majeure event – the spread of COVID-19, or government announcements regarding the risks, do not in themselves constitute force majeure.

Current events are particularly notable when contrasted against the Ebola outbreak of 2014 where the government controls were similar (and potentially qualified as a change in law causing force majeure) but the impact was much more localised, allowing greater opportunities for international companies in particular to withdraw employees or otherwise mitigate the effects of force majeure.

Force majeure is distinguished from the English common law doctrine of frustration, which requires a more stringent standard of proof to be met, with the requirement being it has become impossible to perform the contract, rather than merely more difficult. For this reason, it is often more feasible to invoke a force majeure provision, provided that the contract allows for it.

There are four considerations to be made when attempting to rely upon a force majeure clause:

• Are there specific references to “epidemic,” “pandemic,” “acts of God” or “acts of government” in the definition of force majeure event?
• What are the conditions that must be met in order to invoke the clause?
• What would the contractual consequences be if the clause were to be invoked? This could include termination of contract, suspension of particular contractual obligations (e.g. take-or-pay liabilities), extensions of time or allocation of losses.
• Is there any interaction with mandatory local law? It is vital to ensure that enforcing any force majeure provisions would not contravene any legislation in the jurisdiction in which the contract is based.

The table below sets out some of the different applications of force majeure in oil and gas industry standard contracts, varying from the “exhaustive list” approach of LOGIC contracts, to the somewhat more restrictive approach of the AIPN JOA, which covers only “lockouts, and other industrial disturbances.”

Force majeure and COVID-19 in various oil and gas industry standard agreements

Agreement	Summary of FM provision	Application to COVID-19 and analysis
AIPN JOA (Article 16) AIPN UUOA (Article 18)	The definition of force majeure in the AIPN JOA and UUOA generally mirrors the associated upstream petroleum contract. The affected party should consider force majeure in line with such agreement.	One of the specific events listed in the optional provision of the AIPN model contract is “lockouts, and other industrial disturbances even if they were not beyond the reasonable control of the Party.” It is arguable on the commonly received meaning of the term that a lockout can only apply in the context of a labour dispute, though an industrial disturbance would likely be of wider application and may be more useful.
South Eastern Africa upstream licence	Any failure to comply, or delay in complying, with any non-payment obligation (in whole or partially) set out in the [licence] by either Party will be justified and to the extent that such failure/delay has been caused by force majeure. Force majeure means any cause or event beyond the reasonable control of the affected Party, which is the cause of the default or delay in compliance. Force majeure events include epidemics, blockages, public order disturbance, labour disturbance, quarantines and government illegal acts.	One of the specific events listed in the [licence] force majeure clauses is an “epidemic.” COVID-19 has been classified by the World Health Organisation as a pandemic, a further level of materiality, though depending on the circumstances it may be that its local effects (and, most importantly, its effect on the claiming Party) are less severe. Other events that may be applicable are “quarantines” or “public order disturbance” i.e. the Concessionaire is unable to carry out minimum work obligations due to the lack of manpower caused by a quarantine order issued by the host government.
Northern Africa upstream licence	Any event delaying or preventing the performance by a Party of its non-financial obligations under the PSC is considered as force majeure provided that the occurrence of such event or circumstances is: irresistible; unforeseeable; and independent of the will of the party invoking force majeure. In exceptional circumstances an extraordinary or supernatural event, foreseeable but irresistible and independent of the will of the invoking Party, may also constitute force majeure.	Whilst the PSA does not contain a list of specified force majeure events, it is drafted very broadly and states that any event causing the delay/preventing the performance of the affected party can be considered as force majeure, provided that such event is irresistible, unforeseeable and independent of the will of the party invoking force majeure.
Energy Charter Treaty	Force majeure means “irresistible compulsion or coercion, unforeseeable course of events, fulfilment of contract.”	In the absence of the express inclusion of relevant events such as “epidemics,” “acts of government” or “quarantines” as force majeure events, it is challenging to establish that the non-fulfilment of contractual obligations is impossible. It may be worth reviewing other applicable provisions in the ECT, such as the stabilisation clause or hardship clause (if applicable). For instance, where a hardship clause is provided, the affected party may be entitled to call for renegotiation of the contract, if the continued performance of the affected party’s obligation has become excessively onerous due to the outbreak of COVID-19.
LOGIC Contract (Clause 12) Leading Oil & Gas Industry Competitiveness	Neither Party is responsible for any failure to fulfil its contractual obligation to the extent that fulfilment has been delayed or temporarily prevented by a force majeure occurrence, which is beyond the control and without the fault or negligence of the affected Party exercising reasonable diligence. Force majeure includes the occurrence of the following: “other natural physical disaster (excluding weather conditions)” and “changes to any general or local Statute, Ordinance, Decree, or other Law, or any regulation or bye-law of any local or other duly constituted authority or the introduction of any such Statute, Ordinance, Decree, Law, regulation or bye-law.”	While the force majeure definition is an exhaustive one, as social distancing is now statutory in a number of countries, to the extent that companies are required to close their operations this may qualify as a change in law.
Beach UK gas sales terms 2015 (Clause 9)	Force majeure means any event/circumstance or combination of both beyond the reasonable control of the affected Party (acting or having acted as a Reasonable and Prudent Operator) which results in or causes the failure (including by delay) or inability by the affected Party to perform its contractual obligations, and such failure/inability could not have been overcome by exercising the standard of a Reasonable and Prudent operator. Force majeure includes: in the case of the Seller, the loss, physical inoperability or failure of the Seller’s Facilities but only to the extent that such loss or physical failure has been caused by an event or circumstance beyond the reasonable control of the operator of the Seller’s Facilities acting and having acted as a Reasonable and Prudent Operator which has resulted in the Seller being unable to satisfy its obligations to supply Natural Gas to any Person; and in the case of the Buyer, the loss, physical inoperability or failure of the National Transmission System and any inability of the National Transmission System to receive at the Delivery Point or transport Natural Gas from the Delivery Point. Force majeure does not include: any failure by the Party to the extent that such failure is attributable to the affected Party’s inability to make a profit or achieve a satisfactory rate of return; or the failure by the Seller to tender for delivery Natural Gas to the Buyer as a result of the inability or geophysical failure of any reservoir to produce Natural Gas or the failure of performance, depletion or exhaustion of any reservoir.	The British government has issued new rules on “social distancing” to address the outbreak of COVID-19. Whilst one of the four reasons that one can leave home is travelling to and from work, this is only permitted where such work cannot be done from home. One potential consequence of these restrictions is a lack of manpower at a Seller’s Facilities, though it is questionable whether, as a Reasonable and Prudent Operator, the Seller would order the complete shutdown of its Facilities. For the Buyer to invoke force majeure relief, the Buyer must establish that the force majeure event (i.e. failure to transport Natural Gas from the Delivery Point) is caused by the outbreak of COVID-19, not due to the reduced downstream demand or lower market price. The Buyer is also required to show that there are no alternative means for performing its obligations and it has taken reasonable steps to mitigate or avoid the effects of the force majeure event i.e. whether the Buyer has taken steps to solve the transportation issue.

Next steps

Given the widespread effects of COVID-19, it is important to clarify whether force majeure is applicable in your contracts and to consider an appropriate legal strategy early. Incorrectly invoking force majeure may itself amount to a repudiatory breach and there might be better contractual ways to deal with the current disruption to your operations. If you are currently negotiating a new contract, or conducting due diligence, you should review carefully any proposed force majeure clause and other contractual terms to consider if risks in respect of COVID-19 are appropriately addressed.

If you have any concerns in relation to your oil and gas contracts or require specific assistance with any of the points noted above, please contact a member of the Dentons Energy team.

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.

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.

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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.